View Filing Data

574,989

566,967

^[1]

595,240

Non-regulated energy operations and maintenance

247,496

251,375

241,995

93,453

71,672

76,137

Gain on sale of operating assets

(8,921)

(25,971)

135,591

126,606

120,938

Taxes - property, production and severance

43,301

33,710

27,592

21,687

Other operating expenses

710

980

1,230

Total operating expenses

1,085,949

1,036,271

1,074,557

Interest expense (including amortization of debt issuance costs, premium and discount, realized settlements on interest rate swaps)

186,239

183,420

124,155

Interest charges -

(116,684)

(105,676)

(89,441)

Allowance for funds used during construction - borrowed

14,041

10,689

5,839

Capitalized interest

11,260

4,381

349

Unrealized (loss) gain on interest rate swaps, net

(42,010)

(15,193)

55,653

Allowance for funds used during construction - equity

2,017

541

923

932

2,996

5,891

Other expense

(817)

(140)

(513)

Other income

2,490

2,733

5,921

Total other income (expense)

(128,771)

(99,669)

(15,378)

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

57,468

83,751

108,777

Equity in earnings (loss) of unconsolidated subsidiaries

1,121

1,559

1,343

Income tax (expense) benefit

(18,224)

(22,169)

(32,851)

Income (loss) from discontinued operations, net of tax

40,365

63,141

77,269

9,365

5,544

4,286

Income (loss) from continuing operations, per share

$ 49,730

$ 68,685

$ 81,555

Income (Loss) Per Share, Basic -

$ 1.01

$ 1.62

$ 2

Income (loss) from discontinued operations, per share

0.24

0.14

0.11

Total Income (loss) per share, basic

1.25

1.76

2.11

Income (Loss) Per Share, Diluted -

Income (loss) from continuing operations, per share

1.01

1.62

Income (loss) from discontinued operations, per share

0.23

0.14

0.11

Total Income (loss) per share, per share, diluted

$ 1.24

$ 1.76

$ 2.11

Weighted average common shares outstanding:

Basic

39,864

38,916

38,614

Diluted

40,081

39,091

38,684

[1]	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).

Consolidated Balance Sheet (Parentheticals) - $ / shares shares in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Common Stock, Par or Stated Value Per Share	$ 1	$ 1	$ 1
Common Stock, Shares, Outstanding	43,957,502	39,280,048	38,977,526
Common Stock, Shares Authorized	100,000,000	100,000,000	100,000,000
Treasury Stock, Shares	32,766	10,962	8,834
Common Stock, Shares, Issued	100,000,000	100,000,000	100,000,000

Statement of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
Statement of Comprehensive Income - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income (loss)	$ 49,730	$ 68,685	$ 81,555
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Benefit plan liability adjustment	(7,934)	(1,521)	4,491
Fair value adjustment on derivatives designated as cash flow hedges, net of tax	(2,831)	1,336	(17,481)
Reclassification adjustment on cash flow hedges settled and included in net income (loss)	1,468	(4,232)	12,609
Reclassification adjustment of cash flow hedges settled and included in regulatory assets or liabilities	0	0	0
Comprehensive Income (Loss), Net of Tax	(9,297)	(4,417)	(381)
Comprehensive Income (Loss)	$ 40,433	$ 64,268	$ 81,174

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the economic entity, including both controlling (parent) and noncontrolling interests. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, including any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-Name Emerging Issues Task Force (EITF)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 10, 15
-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 95
-Paragraph 28, 29, 30
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 5
-Section 03
-Paragraph 19

Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A7
-Appendix A

This element represents Other Comprehensive Income or Loss, Net of Tax, for the period. Includes deferred gains or losses on qualifying hedges, unrealized holding gains or losses on available-for-sale securities, minimum pension liability, and cumulative translation adjustment. While for technical reasons this element has no balance attribute, the default assumption is a credit balance consistent with its label.

Net of tax effect of the reclassification adjustment for accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges included in accumulated comprehensive income that was realized in net income during the period.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 133
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-Number 130
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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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-URI http://asc.fasb.org/extlink&oid=6522872

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-Name Accounting Standards Codification
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Change in accumulated gains and losses from derivative instrument designated and qualifying as the effective portion of cash flow hedges, net of tax effect. The after tax effect change includes an entity's share of an equity investee's Increase or Decrease in deferred hedging gains or losses.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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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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-Name Statement of Financial Accounting Standard (FAS)
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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 10: http://www.xbrl.org/2003/role/presentationRef
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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 21,628	$ 16,437
Restricted cash	9,254	4,260
Accounts receivable, net	156,774	171,816
Materials, supplies and fuel	84,064	62,915
Derivative assets, current	18,583	12,710
Income tax receivable, net	9,344	0
Deferred income tax assets, net, current	37,202	20,664
Regulatory assets, current	59,955	66,429
Other current assets	21,266	14,695
Assets discontinued operations	340,851	314,235
Total current assets	758,921	684,161
Investments	17,261	17,780
Property, plant and equipment	3,724,016	3,353,509
Less accumulated depreciation and depletion	(934,441)	(861,775)
Total property, plant and equipment, net	2,789,575	2,491,734
Other assets:
Goodwill	353,396	353,396
Intangible assets, net	3,843	4,069
Derivative assets, non-current	1,971	2,625
Regulatory assets, non-current	182,175	138,405
Other assets, non-current	19,941	19,339
Total other assets, non-current	561,326	517,834
TOTAL ASSETS	4,127,083	3,711,509
Current liabilities:
Accounts payable	104,748	146,556
Accrued liabilities	151,319	147,643
Derivative liabilities, current	84,367	64,617
Accrued income taxes, net	0	3,348
Regulatory liabilities, current	16,231	3,943
Notes payable	345,000	249,000
Current maturities of long-term debt	2,473	5,181
Liabilities of discontinued operations	173,929	173,323
Total current liabilities	878,067	793,611
Long-term debt, excluding current maturities	1,280,409	1,186,050
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	300,988	275,842
Derivative liabilities, non-current	49,033	17,897
Regulatory liabilities, non-current	108,217	84,611
Benefit plan liabilities	177,480	124,709
Other deferred credits and other liabilities	123,553	128,519
Total deferred credits and other liabilities	759,271	631,578
Common stock equity [Abstract]
Common stock $1 par value; 100,000,000 shares authorized; issued 43,957,502 shares at 2011 and 39,280,048 shares at 2010, respectively	43,958	39,280
Additional paid-in capital	722,623	598,805
Retained earnings	476,603	486,075
Treasury stock at cost – 32,766 shares at 2011 and 10,962 shares at 2010, respectively	(970)	(309)
Accumulated other comprehensive Income (loss)	(32,878)	(23,581)
Total stockholders' equity	1,209,336	1,100,270
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 4,127,083	$ 3,711,509

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

3 Months Ended

12 Months Ended

Dec. 31, 2011

Mar. 31, 2011

Dec. 31, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2008

Operating activities:

(Income) loss from discontinued operations, net of tax

$ 25,593

^[1]

$ 26,910

^[1]

$ 33,520

^[2],[3]

$ 31,434

^[2],[3]

$ 49,730

$ 68,685

$ 81,555

(9,365)

(5,544)

(4,286)

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

18,754

29,068

34,631

28,705

40,365

63,141

77,269

135,591

126,606

120,938

Gain on sale of operating assets

43,301

(8,921)

(25,971)

Stock compensation

5,643

5,637

3,908

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

42,010

15,193

(55,653)

Equity in (earnings) loss of unconsolidated subsidiaries

(1,121)

(1,559)

(1,343)

Allowance for funds used during construction - equity

(932)

(2,996)

(5,891)

Derivative fair value adjustments

(8,693)

13,546

19,083

Deferred income taxes

33,600

17,354

45,610

Employee benefit plans

14,586

16,342

16,349

Other adjustments

10,602

(3,851)

4,539

Changes in certain operating assets and liabilities:

Materials, supplies and fuel

(21,385)

(338)

36,767

Accounts receivable and other current assets

(4,202)

(18,480)

26,593

Accounts payable and other current liabilities

(31,091)

(12,848)

4,404

Regulatory assets

12,691

(21,283)

2,598

Regulatory liabilities

11,198

1,265

Contributions to defined pension plans

(11,050)

(30,015)

(16,945)

Other operating activities

(11,118)

(1,013)

7,091

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

216,694

156,565

303,912

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

7,010

(8,813)

(33,410)

Net cash provided by (used in) operating activities

223,704

147,752

270,502

Investing activities:

Property, plant and equipment additions

(440,698)

(472,292)

(346,650)

Payment for acquisition of assets

(2,250)

Proceeds from sale of ownership interest in operating assets

583

70,357

84,661

Working capital adjustment of purchase price allocation on Aquila assets

7,880

Other investing activities

(4,533)

15,407

(15,494)

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

(444,648)

(388,778)

(269,603)

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

(2,359)

(390)

(220)

Net cash provided by (used in) investing activities

(447,007)

(389,168)

(269,823)

Financing activities:

Dividends paid

(59,202)

(56,467)

(55,151)

Common stock issued

123,041

3,246

4,819

Repayments of Lines of Credit

(821,300)

(770,000)

(1,125,300)

Short-term borrowings - issuances

1,017,300

854,500

586,000

Long-term debt - issuances

200,000

543,069

Long-term debt - repayments

(8,382)

(59,926)

(2,173)

Other financing activities

(1,666)

(8,363)

(5,527)

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

249,791

162,990

(54,263)

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

(158)

(2,037)

(2,047)

Net cash provided by (used in) financing activities

249,633

160,953

(56,310)

Net change in cash and cash equivalents

26,330

(80,463)

(55,631)

Cash and cash equivalents:

Cash and cash equivalents, beginning of period

^[4]

$ 32,438

$ 112,901

32,438

112,901

168,532

Cash and cash equivalents, end of period

^[4]

58,768

32,438

58,768

32,438

112,901

$ 168,532

Discontinued Operation, Additional Disclosures [Abstract]

Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents

$ 37,100

$ 16,000

$ 37,100

$ 16,000

$ 97,500

$ 94,700

[1]	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.
[2]	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively.
[3]	Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 million after-tax in the first, second, third and fourth quarters, respectively.
[4]	Cash and cash equivalents include cash of discontinued operations of $37.1 million, $16.0 million, $97.5 million and $94.7 million at December 31, 2011, 2010, 2009 and 2008, 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, 2008		38,676,054
Stockholders' Equity Attributable to Parent Period Start at Dec. 31, 2008	$ 1,050,536	$ 38,676	$ (1,392)	$ 584,582	$ 447,453	$ (18,783)
Treasury Stock, Shares, Period Start at Dec. 31, 2008			40,183
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available to common stock	81,555	0	$ 0	0	81,555	0
Other comprehensive income (loss), net of tax	(381)	0	0	0	0	(381)
Dividends on common stock, cash	(55,151)	$ 0	$ 0	0	(55,151)	0
Dividends on common stock, shares		0	0
Share-based compensation, shares		158,140	(31,349)
Share-based compensation	6,157	$ 159	$ 1,168	4,830	0	0
Tax effect of share-based compensation	(120)	$ 0	$ 0	(120)	0	0
Dividend reinvestment and stock purchase plan, shares		143,332	0
Dividend reinvestment an stock purchase plan	2,241	$ 143	$ 0	2,098	0	0
Shares, Issued Period End at Dec. 31, 2009		38,977,526
Stockholders' Equity Attributable to Parent Period End at Dec. 31, 2009	$ 1,084,837	$ 38,978	$ (224)	591,390	473,857	(19,164)
Treasury Stock, Shares, Period End at Dec. 31, 2009	8,834,000		8,834
Dividends, Common Stock [Abstract]
Common Stock, Dividends, Per Share	$ 1.42
Net income (loss) available to common stock	$ 68,685	0	$ 0	0	68,685	0
Other comprehensive income (loss), net of tax	(4,417)	0	0	0	0	(4,417)
Dividends on common stock, cash	(56,467)	$ 0	$ 0	0	(56,467)	0
Dividends on common stock, shares		0	0
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)	0	0	(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	10,962,000		10,962
Dividends, Common Stock [Abstract]
Common Stock, Dividends, Per Share	$ 1.44
Net income (loss) available to common stock	$ 49,730	0	$ 0		49,730	0
Other comprehensive income (loss), net of tax	(9,297)	0	0	0	0	(9,297)
Dividends on common stock, cash	(59,202)	$ 0	$ 0		(59,202)	0
Dividends on common stock, shares		0	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	32,766,000		32,766
Dividends, Common Stock [Abstract]
Common Stock, Dividends, Per Share	$ 1.46

Business Description and Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Management's Statement [Abstract]

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, Wyoming and vicinity. Gas Utilities consist of the operating results of the regulated natural gas utility operations of Colorado Gas, Nebraska Gas, Iowa Gas, and Kansas Gas all doing business as Black Hills Energy.

The Non-regulated Energy Group includes our Oil and Gas, Power Generation and Coal Mining segments. 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. Power Generation, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Coal Mining, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. These businesses are aggregated for reporting purposes as Non-regulated Energy.

In January 2012, we entered into a definitive agreement to sell Enserco, our non-regulated Energy Marketing segment, which resulted in this segment being reported as discontinued operations. Our Energy Marketing segment engages in marketing natural gas, crude oil, coal, power and environmental products in the United States and Canada. See Notes 23 and 25 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. Management evaluates its estimates and related assumptions regularly, including, but not limited to, those related to the market value of derivatives, intangible asset valuations and useful lives, long-lived asset values and useful lives, proved oil and gas reserve volumes, actuarially determined employee benefit costs, valuation of deferred taxes and contingencies. 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 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 intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany 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 the jointly owned Black Hills Power transmission tie, the Wyodak power plant, the Wygen I power plant, the Wygen III power plant, and the BHEP gas processing plant. See Note 7 for additional information.

As a result of the pending 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.

Restatement - Subsequent to the issuance of the Company's 2010 consolidated financial statements, the Company's management determined that certain intercompany transactions with our rate regulated operations had not been properly eliminated in consolidation, resulting in an overstatement of Utility and Non-regulated revenue and Fuel, purchased power and cost of gas sold of $59.6 million and $57.5 million in aggregate for the year ended December 31, 2010 and December 31, 2009, respectively. As such, the Consolidated Financial Statements have been restated for the correction of this error. The error did not have an impact on our gross margin, net income, total assets or cash flows.

Cash and Cash Equivalents and Restricted Cash

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

The Black Hills Wyoming project financing requires that cash accounts are maintained 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 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.

Our Utilities Group utilizes master netting agreements which consists 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.

We maintain an allowance for doubtful accounts which reflects our best estimate of potentially 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.

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



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



2010	Accounts Receivable, Trade		Unbilled Revenues		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric	$	51,005	$	19,572	$	(708	)	$	69,869
Gas	41,970		40,376		(1,425		)	80,921
Oil and Gas	6,213		—		(161		)	6,052
Coal Mining	2,420		—		—			2,420
Power Generation	307		—		—			307
Corporate	12,247		—		—			12,247
Total	$	114,162	$	59,948	$	(2,294	)	$	171,816

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, 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. However, the determination of the energy sales to individual customers is based on systematic meter readings throughout a month. Meters that are not read during a given month are estimated and trued-up to actual use in a future period. At the end of each month, amounts of energy delivered to customers since the date of their last meter reading are estimated and the corresponding unbilled revenue is recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets.

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

Materials, Supplies and Fuel

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



	December 31, 2011		December 31, 2010
Materials and supplies	$	40,838	$	31,537
Fuel - Electric Utilities	8,201		9,687
Natural gas in storage - Gas Utilities	35,025		21,691
Total Materials, supplies and fuel	$	84,064	$	62,915

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 at our regulated Gas Utilities primarily represents gas purchased for use by our 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 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 assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived 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, 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, results in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property are charged to operations as incurred.

Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis. 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 treated as adjustments to the cost of the properties with no gain or loss recognized.

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

Under the full cost method, net capitalized costs are subject to a ceiling test which limits these costs to the present value of future net cash flows discounted at 10%, 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. No ceiling test write-down was recorded in 2011 or 2010. As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas long-lived assets included in the Oil and Gas segment. 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

Under accounting standards for goodwill and intangible assets, goodwill and intangible assets with indefinite lives are not amortized but the carrying values are reviewed at least annually for impairment. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform this annual review of goodwill and intangible assets during the fourth quarter of each year (or more frequently if impairment indicators arise).

We performed our annual goodwill impairment tests during the fourth quarter. 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. 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 value of the significant rate base growth opportunities at our electric utility in Colorado.

The substantial majority of our goodwill and intangible assets are contained within the Utilities Group. Goodwill primarily arose from the acquisition of one regulated electric and four regulated gas utilities from Aquila of which 69% was allocated to Colorado Electric and 31% was allocated to the Gas Utilities. Changes to goodwill during the years ended December 31 relating primarily to taxes, were as follows (in thousands):



	Electric Utilities		Gas Utilities		Power Generation		Total
Ending balance at December 31, 2009	$	249,620	$	93,914	$	8,765	$	352,299
Additions (adjustments)	867		230		—		1,097
Ending balance at December 31, 2010	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at December 31, 2011	$	250,487	$	94,144	$	8,765	$	353,396

Intangible assets represent easements, rights-of-way and trademarks and are amortized using a straight-line method using estimated useful lives of 20 years. Changes to intangible assets were as follows (in thousands):



	2011			2010			2009
Intangible assets, net, beginning balance	$	4,069		$	4,309		$	4,884
Additions (adjustments)	—			—			(365		)
Amortization expense	(226		)	(240		)	(210		)
Intangible assets, net, ending balance	$	3,843		$	4,069		$	4,309

_________________


*	Amortization expense for existing intangible assets is expected to be $0.2 million, $0.2 million, $0.2 million, $0.2 million, and $0.2 million for 2012, 2013, 2014, 2015, and 2016, respectively.

Asset Retirement Obligations

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 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

Accounting standards for fair value measurements and accounting for compensation - retirement benefits require, among other things, disclosures regarding assets and liabilities carried at fair value and also provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As permitted under accounting standards for fair value measurements, we utilize a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical expedient for valuing a significant portion of the assets and liabilities measured and reported at fair value.

Disclosures are required based on a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). We are able to classify fair value balances based on the observability of inputs.

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three 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 and 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 their own judgments about the assumptions a market participant would use in pricing the asset or liability.

We utilize several different valuation techniques to measure the fair value of assets and liabilities.

•

Commodity derivatives - Oil and Gas: Our derivative option contracts are valued under the income approach using option pricing models based on data either readily observable in public markets, derived from public markets or provided by counterparties who regularly trade in public markets. Our derivative swap contracts are valued under the income approach using a discounted cash flow model based on data either readily observable or derived from public markets.

•

Commodity derivatives - Utilities: Our gas hedge portfolio for our Utilities generally consists of futures, basis swaps and option contracts. The fair value of these financial instruments is estimated based on market trading information, where available. Absent published market values for an instrument or other asset, management uses observable market data to arrive at its estimates of fair value. These contracts have been classified as Level 2 measurements.

•

Interest rate swaps: The fair value of our interest rate swap contracts are determined using standard valuation models. The significant inputs used in these models are readily available in public markets or can be derived from observable market transactions and; therefore, these derivative contracts have been classified as Level 2. Inputs used in these standard valuation models include the applicable market forward rates and discount rates.

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 we believe 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 term 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 is subject to regulation by various state and federal agencies. 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.

Our financial statements follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various jurisdictions regulating the utilities. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply. Our regulatory assets represent amounts for which we will recover the cost, but are not allowed a return. In the event we determine that Black Hills Power, Cheyenne Light, Colorado Gas, Colorado Electric, Nebraska Gas, Iowa Gas or Kansas Gas no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to the Company 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	As of		As of
	Settlement Period (in years)	December 31, 2011		December 31, 2010
Regulatory assets
Deferred energy and fuel costs adjustments - current	1	$	33,526	$	30,298
Deferred gas cost adjustments and gas price derivatives	1	26,208		39,407
AFUDC	45	12,482		13,391
Employee benefit plans	13	120,708		83,144
Environmental	subject to approval	1,770		2,353
Asset retirement obligations	44	3,097		3,066
Bond issue cost	25	3,704		3,847
Renewable energy standard adjustment	5	20,095		14,254
Flow through accounting	35	12,191		7,491
Other regulatory assets	various	8,349		7,583
		$	242,130	$	204,834

Regulatory liabilities
Deferred energy and gas costs	1	$	16,961	$	1,200
Employee benefit plans	13	59,455		36,155
Cost of removal	44	42,257		39,638
Revenue subject to refund	1	443		1,016
Other regulatory liabilities	various	5,332		10,545
		$	124,448	$	88,554

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 in excess of current rates and which 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 PGA 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.

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 related to over-recovery in purchased power, transmission and natural gas costs charged to Cheyenne Light customers through a PCA and GCA mechanism.

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 for utility plant represents the estimated cumulative net provisions for future removal costs included in depreciation expense for which there is no legal obligation for removal. Liabilities will be settled and trued up following completion of the related activities.

Revenues Subject To Refund - Revenues subject to refund represent a portion of the revenues collected from customers based on approved interim rates which are contingent on the outcome of final rate orders.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Income taxes for consolidated subsidiaries are allocated to the subsidiaries based on separate company computations of taxable income or loss.

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

It is our policy to apply the flow-through method of accounting for investment tax credits. 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 which gave rise to the credits.

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 operations is computed by dividing Income (loss) from continuing operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share gives effect to all dilutive potential common shares outstanding during a period.

A reconciliation of Income (loss) from continuing operations and basic and diluted share amounts is as follows (in thousands):



	December 31, 2011		December 31, 2010		December 31, 2009
Income (loss) from continuing operations	$	40,365	$	63,141	$	77,269

Weighted average shares - basic *	39,864		38,916		38,614
Dilutive effect of:
Stock options	19		14		—
Restricted stock	153		107		66
Equity forward instrument	—		29		—
Other dilutive effects	45		25		4
Weighted average shares - diluted	40,081		39,091		38,684

_______________


*	On November 1, 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):



	December 31, 2011	December 31, 2010	December 31, 2009
Options to purchase common stock	105	158	462
Restricted stock	17	1	3
Other	19	1	45
	141	160	510

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. As of December 31, 2011, 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, 2011
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, ASU No. 2011-05 and ASU 2011-12 FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of reporting of comprehensive income. 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 No. 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. In December 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. We have 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 Measurements and Disclosures, ASC 820 The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosure requirements related to fair value measurements. This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives within our Oil and Gas segment, interest rate swap instruments, and other miscellaneous financial instruments. In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements, disclosure of inputs and techniques used in valuation and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us January 1, 2010, except the disclosures related to purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which were effective January 1, 2011. The guidance requires additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 4. Extractive Activities — Oil and Gas Reserves (SEC Release #33-8995), ASC 932-10-S99 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 December 31, 2009. The implementation of this SEC requirement resulted in additional depletion expense of $1.3 million in the fourth quarter of 2009. Dodd-Frank Wall Street Reform and Consumer Protection Act 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, including swap transactions in the over-the-counter market. Among other things, Dodd-Frank (i) mandates the clearing of some swaps through regulated central clearing organizations and the trading of clearing swaps through regulated exchanges or swap execution facilities, in each case subject to certain key exemptions, and (ii) authorizes regulators to establish collateral and margin requirements for certain swap transactions that are not cleared. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users, and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. 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 as these rules become available. Recently Issued Accounting Pronouncements and Legislation Intangibles - Goodwill and Other, ASU No. 2011-08 In September 2011, the FASB issued an amendment to an existing accounting standard, which provides 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 December 15, 2011. The adoption of this standard will not have a material impact on our financial statements. Fair Value Measurement, ASU No. 2011-04 FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. This amendment changes the wording used to describe fair value and requires additional disclosures. We do not expect this amendment, which is effective for interim and annual periods beginning after December 31, 2011, to have an impact on our financial position, results of operations, or cash flows.

Risk Management Activities

12 Months Ended

Dec. 31, 2011

Risk Management Activities [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 counterparty risk. We have developed policies, processes, systems, and controls to manage and mitigate these risks.

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 and Gas Utilities segments resulting from commodity price changes; and


•	Interest rate risk associated with variable rate credit facilities and project financing floating rate debt and our derivative instruments as described in Notes 4, 5, 8 and 9.

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates, and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

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.

We held a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on the over-the-counter swaps and options. These transactions were designated at inception as cash flow hedges, documented under accounting 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 was reported in Accumulated other comprehensive income (loss) and the ineffective portion was reported in earnings.

We had the following derivatives and related balances (dollars in thousands) as of:



	December 31, 2011					December 31, 2010
	Crude oil swaps/options			Natural gas swaps		Crude oil swaps/options			Natural gas swaps
Notional ^(a)	528,000			5,406,250		424,500			6,821,800
Maximum duration in years ^(b)	1.25			1.75		0.25			0.25
Derivative assets, current	$	729		$	8,010	$	248		$	7,675
Derivative assets, non-current	$	771		$	1,148	$	19		$	2,606
Derivative liabilities, current	$	2,559		$	—	$	3,814		$	—
Derivative liabilities, non-current	$	811		$	7	$	1,301		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(1,928	)	$	9,152	$	(5,313	)	$	10,281
Revenue ^(c)	$	58		$	—	$	465		$	—

________________________


(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 December 31, 2011 market prices, a $5.6 million gain would be reclassified from AOCI during 2012. Estimated and actual realized gains or losses will likely change during future periods as market prices fluctuate.

Utilities

Our gas and electric 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 certain exchange-traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives in accordance with accounting standards for derivatives and hedging and mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets. Gains and losses, as well as option premiums, on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated operations. Accordingly, the earnings impact is recognized in the Consolidated Statements of Income as a component of PGA costs when the related costs are recovered through our rates as part of PGA costs in operating revenue.

The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities were as follows:



	December 31, 2011		December 31, 2010
Natural gas (notional amounts in MMBtu)	Notional	Latest Expiration (months)	Notional	Latest Expiration (months)
Natural gas futures purchased	14,310,000	84	6,670,000	15
Natural gas options purchased	1,720,000	3	1,730,000	3
Natural gas basis swaps purchased	7,160,000	60	—	—

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



	December 31, 2011		December 31, 2010
Derivative assets, current	$	9,844	$	4,787
Derivative assets, non-current	$	52	$	—
Derivative liabilities, current	$	—	$	—
Derivative liabilities, non-current	$	7,156	$	1,620
Net unrealized gain (loss) included in Regulatory assets or Regulatory liabilities	$	17,556	$	8,030
Cash collateral receivable (payable) included in derivative assets/liabilities	$	19,416	$	10,355
Option premium included in Derivative assets, current	$	880	$	842

Financing Activities

We are exposed to interest rate risk associated with fluctuations in interest rates on our variable interest rate debt. To manage this risk, 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:



	December 31, 2011						December 31, 2010
	Interest Rate Swaps			De-designated Interest Rate Swaps^(a)			Interest Rate Swaps			De-designated Interest Rate Swaps^(a)
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	5.0			2.0			6.0			1.0
Derivative assets, current	$	—		$	—		$	—		$	—
Derivative assets, non-current	$	—		$	—		$	—		$	—
Derivative liabilities, current	$	6,513		$	75,295		$	6,823		$	53,980
Derivative liabilities, non-current	$	20,363		$	20,696		$	14,976		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(26,876	)	$	—		$	(21,799	)	$	—
Pre-tax gain (loss) included in Consolidated Statements of Income	$	—		$	(42,010	)	$	—		$	(15,193	)
Cash collateral receivable (payable) included in Consolidated Balance Sheets	$	—		$	—		$	—		$	—

___________________


(a)	The maximum term in years reflects the amended mandatory early termination dates. If the mandatory early termination dates are not extended, the swaps will require cash settlement based on the swap value of the termination date. When extended, de-designated swaps totaling $100.0 million terminate in 7 years and de-designated swaps totaling $150.0 million terminate in 17 years.

$50.0 million of our de-designated swaps has collateral requirements based upon our corporate credit ratings. At our current credit ratings, we would be 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.

Based on December 31, 2011 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $6.5 million would be reclassified from AOCI during the next 12 months. Estimated and realized losses will change during future periods as market interest rates change.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. We adopted the BHCCP for the purpose of establishing guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by our Board of Directors. In addition, we have a Credit Committee that includes senior executives that meets on a regular basis to review our credit activities and monitor compliance with our credit policies.

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

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

As of December 31, 2011, our credit exposure (exclusive of retail customers of the regulated utilities) was concentrated primarily among investment grade companies. Credit exposure with non-investment grade or non-rated counterparties, was supported partially through letters of credit, prepayments or parental guarantees.

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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Financial Instruments, Financial Assets, Balance Sheet Groupings [Abstract]

Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [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.

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 December 31, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	9,885		$	768	$	5	$	—	$	10,658
Commodity derivatives - Utilities	—		(9,520		)	—		—		19,416		9,896
Money market fund	6,005		—			—		—		—		6,005
Total	$	6,005	$	365		$	768	$	5	$	19,416	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	2,207		$	1,165	$	5	$	—	$	3,377
Commodity derivatives - Utilities	—		7,156			—		—		—		7,156
Interest rate swaps	—		122,867			—		—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	—	$	133,400



	As of December 31, 2010
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	10,281		$	266	$	—	$	—	$	10,547
Commodity derivatives - Utilities	—		(5,568		)	—		—		10,355		4,787
Money market fund	8,050		—			—		—		—		8,050
Total	$	8,050	$	4,713		$	266	$	—	$	10,355	$	23,384

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	5,115		$	—	$	—	$	—	$	5,115
Commodity derivatives - Utilities	—		1,620			—		—		—		1,620
Interest rate swaps	—		75,779			—		—		—		75,779
Total	$	—	$	82,514		$	—	$	—	$	—	$	82,514

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



	Commodity Derivatives			Commodity Derivatives
	December 31, 2011			December 31, 2010
Balance at beginning of year	$	266		$	381
Unrealized losses	(1,318		)	(303		)
Unrealized gains	751			188
Purchases	—			—
Issuances	—			—
Settlements	(96		)	—
Transfers into level 3^(a)	—			—
Transfers out of level 3 ^(b)	—			—
Balance at year end	$	(397	)	$	266

Changes in unrealized (losses) gain relating to instruments still held as of year end	$	(101	)	$	(302	)

______________


(a)	Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.


(b)	Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Gains and losses (realized and unrealized) for level 3 commodity derivatives totaling $(0.6) million for the year ended December 31, 2011, are included in Operating revenues on the Consolidated Statements of Income while $0.1 million was recorded through AOCI on the Consolidated Balance Sheets for the year ended December 31, 2011. Commodity derivatives classified as level 3 may be economically hedged as part of a total portfolio of instruments that may be classified in level 1 or 2, or with instruments that may not be accounted for at fair value. Accordingly, gains and losses associated with level 3 balances may not necessarily reflect trends occurring in the underlying business. Further, unrealized gains and losses for the period from level 3 items may be offset by unrealized gains and losses in positions classified in level 1 or 2, as well as positions that have been realized during the period.

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 December 31, 2011 and 2010, 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 agree 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 December 31 (in thousands):



		December 31, 2011					December 31, 2010
	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	$	8,739	$	—		$	7,923	$	—
Commodity derivatives	Derivative assets - non-current	1,919		—			2,625		—
Commodity derivatives	Derivative liabilities - current	—		2,559			—		3,814
Commodity derivatives	Derivative liabilities - non-current	—		818			—		1,301
Interest rate swaps	Derivative liabilities - current	—		6,513			—		6,822
Interest rate swaps	Derivative liabilities - non-current	—		20,363			—		14,976
		$	10,658	$	30,253		$	10,548	$	26,913

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	—	$	9,572		$	—	$	5,567
Commodity derivatives	Derivative assets - non-current	—		(52		)	—		—
Commodity derivatives	Derivative liabilities - current	—		—			—		—
Commodity derivatives	Derivative liabilities - non-current	—		7,156			—		1,621
Interest rate swaps	Derivative liabilities - current	—		75,295			—		53,980
Interest rate swaps	Derivative liabilities - non-current	—		20,696			—		—
		$	—	$	112,667		$	—	$	61,168

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):



	December 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	)		$	—



	December 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			$	—



	December 31, 2009
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	$	12,818		Interest expense	$	(3,292	)		$	—
Commodity derivatives	(21,070		)	Revenue	23,102			Revenue	(1,394		)
Total	$	(8,252	)		$	19,810			$	(1,394	)

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 December 31 was as follows (in thousands):



		December 31, 2011			December 31, 2010			December 31, 2009
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	$	(42,010	)	$	(15,193	)	$	55,653
Interest rate swaps - realized	Interest expense	(13,373		)	(13,312		)	(9,816		)
		$	(55,383	)	$	(28,505	)	$	45,837

Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2011

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

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



	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	21,628	$	21,628	$	16,437	$	16,437
Restricted cash	$	9,254	$	9,254	$	4,260	$	4,260
Total derivative assets	$	20,554	$	20,554	$	15,335	$	15,335
Total derivative liabilities	$	133,400	$	133,400	$	82,514	$	82,514
Notes payable	$	345,000	$	345,000	$	249,000	$	249,000
Long-term debt, including current maturities	$	1,282,882	$	1,464,289	$	1,191,231	$	1,290,519

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Cash and Cash Equivalents

Included in cash and cash equivalents is cash and money market funds. The carrying amount approximates fair value due to the short maturity of these instruments.

Restricted Cash

Restricted cash accounts represent amounts required by Black Hills Wyoming project financing agreements. Of this total, $3.6 million was held in 30-day Guaranteed Investment Certificates at December 31, 2010.

Derivative Financial Instruments

These instruments are carried at fair value. These inputs include unadjusted quoted prices where available; prices published by various third-party providers; and, when necessary, internally developed adjustments. In many cases, the internally developed prices are corroborated with external sources. Certain Company transactions take place in markets with limited liquidity and limited price visibility. Descriptions of the various instruments we use and the valuation methods employed are included in Notes 3 and 4.

Notes Payable

The carrying amount of our notes payable approximates fair value due to their variable interest rates with short reset periods.

Long-Term Debt

The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings.

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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-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 2: 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 3: 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 4: 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 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-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 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 7: 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 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
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Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment Disclosure [Text Block]

PROPERTY, PLANT AND EQUIPMENT

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



Utilities Group	2011			2010			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	$	707,498	49	$	679,165	47	25	80
Electric transmission	170,146		49	154,936		47	40	65
Electric distribution	580,699		45	543,498		43	15	65
Plant acquisition adjustment	4,870		32	4,870		32	32	32
General	136,304		22	103,455		20	3	60
Capital lease - plant in service *	260,874		20	—		—	20	20
Construction work in progress	288,760			234,985
Total electric plant	2,149,151			1,720,909
Less accumulated depreciation and amortization	385,840			357,774
Electric plant net of accumulated depreciation and amortization	$	1,763,311		$	1,363,135

_____________


*	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.



	2011			2010			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	$	35	37	$	35	37	37	37
Gas transmission	15,543		53	15,704		48	53	57
Gas distribution	442,114		46	406,914		45	41	56
General	56,869		19	68,315		19	16	22
Construction work in progress	8,813			11,392
Total gas plant	523,374			502,360
Less accumulated depreciation and amortization	52,249			47,292
Gas plant net of accumulated depreciation and amortization	$	471,125		$	455,068



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

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
Power Generation	135,051		930		35,074		100,907		36	2	40
	$	1,039,379	$	5,271	$	495,228	$	549,422



2010									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

Coal Mining	$	135,157	$	10,228	$	65,465	$	79,920	11	3	40
Oil and Gas	680,407		—		357,979		322,428		26	3	27
Power Generation	134,616		163,291		30,982		266,925		36	2	40
	$	950,180	$	173,519	$	454,426	$	669,273



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



2010									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	$	4,039	$	2,502	$	2,283	$	4,258	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, 2011

Jointly Owned Facilities [Abstract]

JOINTLY OWNED FACILITIES

Oil and Gas

Through our BHEP subsidiary, we own a 44.7% 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. As of December 31, 2011, our investment in the Newcastle Gas Plant included $4.3 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. These items are included in the corresponding categories of revenue and expenses in the accompanying Consolidated Statements of Income.

Utility Plant

•

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

•

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

•

Black Hills Power own 52% of its Wygen III coal-fired generation facility which commenced commercial operation on April 1, 2010. MDU and the City of Gillette each owns an undivided ownership interest in the Wygen III generation facility and are obligated to make payments for costs associated with administrative services and proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations.


•	Black Hills Wyoming owns 76.5% of its Wygen I Plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for 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 facilities is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income.

At December 31, 2011, our interests in jointly-owned generating facilities and transmission systems were (dollars in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,007	$	718	$	46,104
Transmission Tie	19,648		—		4,061
Wygen I	104,854		880		23,046
Wygen III	129,791		249		5,328
	$	363,300	$	1,847	$	78,539

Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG-TERM DEBT

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



	Due Date	Interest Rate	2011			2010
Corporate
Senior unsecured notes due 2013	May 15, 2013	6.5%	$	225,000		$	225,000
Unamortized discount on notes due 2013			(41		)	(70		)
Senior unsecured notes due 2014	May 15, 2014	9.0%	250,000			250,000
Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
Long-term term loan ^(a)	September 30, 2013	1.69%	100,000			—
Total Corporate Debt			774,959			674,930

Electric Utilities
First Mortgage Bonds due 2032	August 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13%	180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039			(115		)	(119		)
Pollution control revenue bonds due 2014	October 1, 2014	4.80%	6,450			6,450
Pollution control revenue bonds due 2024	October 1, 2024	5.35%	12,200			12,200
First Mortgage Bonds due 2037	November 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021, variable rate ^(a)	September 1, 2021	0.14%	7,000			7,000
Industrial development revenue bonds due 2027, variable rate ^(a)	March 1, 2027	0.14%	10,000			10,000
Series 94A Debt ^(a)	June 1, 2024	3.00%	2,855			2,855
Other long-term debt	May 12, 2012	13.66%	72			234
Total Electric Utilities			403,462			403,620

Power Generation
Black Hills Wyoming project financing, variable rate ^(a)	December 9, 2016	3.66%	104,461			112,681

Total long-term debt			1,282,882			1,191,231
Less current maturities			2,473			5,181
Net long-term debt			$	1,280,409		$	1,186,050

_______________


(a)	Variable interest rates, rates presented are as of December 31, 2011.

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



2012	$	2,473
2013	$	328,973
2014	$	262,473
2015	$	6,964
2016	$	85,101
Thereafter	$	597,054

Certain debt instruments of the Company and its subsidiaries contain restrictions and covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2011.

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.

Debt Offering

In July 2010, pursuant to a public offering, we issued $200.0 million aggregate principal of senior unsecured notes due July 15, 2020. The notes were priced at par and carry a fixed interest rate of 5.88%. We received proceeds of $198.7 million, net of underwriting fees. Deferred financing costs are being amortized over the term of the debt. Amortization of deferred financing costs is included in Interest expense.

Long-term Term Loan

Our $100.0 million term loan (the "Loan") with J.P. Morgan and Union Bank was extended through September 30, 2013. The cost of borrowings under the Loan was based on a spread of 1.375% over LIBOR (1.69% at December 31, 2011). The proceeds were used to reduce borrowings on the Revolving Credit Facility. 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 on Balance Sheet at		Amortization Expense for the years ended December 31,
	December 31, 2011		2011		2010		2009
Senior unsecured notes due 2013	$	309	$	218	$	218	$	218
Senior unsecured notes due 2014	$	1,097	$	462	$	462	$	289
Senior unsecured notes due 2020	$	1,428	$	167	$	77	$	—
First mortgage bonds due 2023	$	684	$	33	$	33	$	33
First mortgage bonds due 2039	$	2,113	$	76	$	76	$	12
First mortgage bonds due 2037	$	797	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016	$	4,214	$	1,012	$	1,036	$	60
Other	$	816	$	70	$	74	$	67

Notes Payable

12 Months Ended

Dec. 31, 2011

Notes Payable [Abstract]

Notes Payable

NOTES PAYABLE

Our credit facilities and debt securities contain certain restrictive financial covenants including, among others, interest expense coverage ratios, recourse leverage ratios and consolidated net worth requirements. At December 31, 2011, we were in compliance with all of these financial covenants. None of our facilities or debt securities contain default provisions pertaining to our credit ratings.

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



	As of December 31, 2011				As of December 31, 2010
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	195,000	$	43,700	$	149,000	$	46,865
Term Loan 2011	—		—		100,000		—
Term Loan 2012	150,000		—		—		—
Total	$	345,000	$	43,700	$	249,000	$	46,865

Revolving Credit Facility

Our $500.0 million Revolving Credit Facility expiring April 14, 2013 contained an accordion feature which allowed us, with the consent of the administrative agent, to increase the capacity of the facility to $600.0 million and was used for the issuance of letters of credit, to fund working capital needs and other corporate purposes. Borrowings were available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit was determined based upon our credit ratings. At current year-end credit ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 1.75%, 2.75% and 2.75%, respectively at December 31, 2011. The facility contained a commitment fee to be charged on the unused amount of the Revolving Credit Facility. Based upon current year-end credit ratings, the fee was 0.5%. On February 1, 2012, we entered into a new Revolving Credit Facility replacing the prior Revolving Credit Facility. See Note 25 for additional information.

Deferred financing costs are being amortized over the term of the Revolving Credit Facility and are included in Interest expense on the accompanying Consolidated Statements of Income as follows (in thousands):



	Deferred Financing Costs Remaining on Balance Sheet as of		Amortization Expense for the years ended December 31,
	December 31, 2011		2011		2010		2009
Revolving Credit Facility	$	1,497	$	1,891	$	1,340	$	495

The Revolving Credit Facility includes the following covenants that we must comply with at the end of each quarter (dollars, in thousands). We were in compliance with these covenants as of December 31, 2011.



	Actual			Covenant Requirement
Consolidated net worth	$	1,209,336		$	884,131
Recourse leverage ratio	58.5		%	65.0		%

Corporate Term Loans

In June 2011, we entered into a $150.0 million unsecured, single draw, term loan with CoBank, the Bank of Nova Scotia and U.S. Bank due on June 24, 2012. The cost of borrowing under the loan is based on a spread of 1.25% over LIBOR (1.56% at December 31, 2011). The covenants are substantially the same as those included in the Revolving Credit Facility and we were in compliance with these covenants as of December 31, 2011.

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligation Disclosure [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 liability is then accreted over time by applying an interest method of allocation to the liability. The associated ARO accretion expense is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to accounting standards for regulated operations. 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 and transformers containing polychlorinated biphenyls at the regulated Electric Utilities segment and asbestos at our regulated Gas Utilities segment.

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):



	12/31/10		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates *			12/31/11
Oil and Gas	$	21,663	$	43	$	(627	)	$	1,343	$	—		$	22,422
Coal Mining	17,560		—		—			1,123		(1,525		)	17,158
Electric Utilities	3,039		—		—			25		—			3,064
Gas Utilities	255		—		—			15		—			270
Total	$	42,517	$	43	$	(627	)	$	2,506	$	(1,525	)	$	42,914



	12/31/09		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates *			12/31/10
Oil and Gas	$	21,233	$	570	$	(2,078	)	$	1,280	$	658		$	21,663
Coal Mining	15,285		18,094		(15,207		)	1,246		(1,858		)	17,560
Electric Utilities	2,904		—		—			135		—			3,039
Gas Utilities	241		—		—			14		—			255
Total	$	39,663	$	18,664	$	(17,285	)	$	2,675	$	(1,200	)	$	42,517

_____________________


*	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 asset retirement obligations 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, 2011

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

Common Stock

COMMON STOCK

Equity Issuance

On November 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 November 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 961,476 shares available to grant at December 31, 2011.

Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2011, total unrecognized compensation expense related to non-vested stock awards was $7.1 million and is expected to be recognized over a weighted-average period of 1.8 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follow (in thousands):



	2011		2010		2009
Stock-based compensation expense	$	5,643	$	5,637	$	3,908

Stock Options

We have granted options with an option exercise price equal to the fair market value of the stock on the day of the grant. The options granted vest proportionately over 3 years and expire 10 years after the grant date.

A summary of the status of the stock options at December 31, 2011 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	235		$	32.92
Granted ^(a)	99		32.04
Forfeited/canceled	(6	)	—
Expired	(31	)	53.51
Exercised	(33	)	30.32
Balance at end of period	264		$	30.50	4.5	$	859

Exercisable at end of period	165		$	29.57

______________________


(a)	The grant date fair value of the 2011 awards was $5.80 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.6% risk free interest rate, 29.0% expected price volatility, 4.6% expected dividend yield and a 7 year expected life.

The table below provides details of our option plans (in thousands):



	2011		2010		2009
Summary of Stock Options
Unrecognized compensation expense	$	479	$	—	$	—
Intrinsic value of options exercised^(a)	$	94	$	234	$	255
Net cash received from exercise of options	$	1,009	$	1,034	$	1,740
Tax benefit realized from exercise of shares ^(b)	$	33	$	82	$	89

_____________________


(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, 2011, the unrecognized compensation expense related to non-vested stock options that is expected to be recognized over a weighted-average period of 2.4 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 three 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 December 31, 2011 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	270		$	27.78
Granted	139		30.33
Vested	(113	)	28.43
Forfeited	(18	)	27.36
Restricted Stock and Restricted Stock Units balance at end of period	278		$	28.82

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 December 31 was as follows:



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2011	$	30.33	$	3,211
2010	$	27.30	$	2,212
2009	$	26.76	$	1,799

As of December 31, 2011, there was $4.7 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 1.8 years.

Performance Share Plan

Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group and can range from 0% to 175% of target. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria.

The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $1.9 million at December 31, 2011 would be reclassified as a liability.

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



Grant Date	Performance Period	Target Grant of Shares
January 1, 2009	January 1, 2009 - December 31, 2011	73
January 1, 2010	January 1, 2010 - December 31, 2012	71
January 1, 2011	January 1, 2011 - December 31, 2013	67

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



	Equity Portion				Liability Portion
	Shares		Weighted-Average Grant Date Fair Value		Shares		Weighted-Average December 31, 2011 Fair Value
	(in thousands)				(in thousands)

Performance Shares balance at beginning of period	87		$	29.47	87
Granted	34		25.92		34
Forfeited	(3	)	25.77		(3	)
Vested	(12	)	46.00		(12	)
Performance Shares balance at end of period	106		$	26.47	106		$	20.89

The grant date fair values for the performance shares granted in 2011, 2010 and 2009 were determined by Monte Carlo simulation using a blended volatility of 30%, 31% and 39%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted in the years ended was as follows:



	Weighted Average Grant Date Fair Value
December 31, 2011	$	25.92
December 31, 2010	$	24.26
December 31, 2009	$	29.20

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



Performance Period	Year of Payment	Stock Issued	Cash Paid		Total Intrinsic Value
January 1, 2008 to December 31, 2010	2011	—	$	—	$	—
January 1, 2007 to December 31, 2009	2010	—	$	—	$	—
January 1, 2006 to December 31, 2008	2009	—	$	—	$	—

On January 25, 2012, the Compensation Committee of our Board of Directors determined that the plan criteria for the January 1, 2009 through December 31, 2011 performance period was not met. As a result, the payout for this performance period will be $0.0 million.

As of December 31, 2011, there was $1.9 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.6 years.

Dividend Reinvestment and Stock Purchase Plan

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

A summary of the Dividend Reinvestment and Stock Purchase Plan was as follows (shares in thousands):



	2011		2010
Shares Issued	103		106

Weighted Average Price	$	31.23	$	29.57

Unissued Shares Available at December 31	453		190

Other Plans

We issued 14,111 fully-vested shares of common stock with an intrinsic value of $0.4 million in the year ended December 31, 2011 to certain key employees under the Short-term Annual Incentive Plan, a performance-based plan. The payout was fully accrued at December 31, 2010. We issued 9,625 and 47,331 shares of common stock in 2010 and 2009, respectively, under the Short-term Annual Incentive Plan. In addition, we will issue common stock with an intrinsic value of approximately $0.1 million in 2012 for the 2011 Short-term Annual Incentive Plan.

Dividend Restrictions

Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. See Note 9 for further information on our credit facilities. As of December 31, 2011, we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2011:

•

In connection with the Aquila Transaction, the CPUC, NPSC, IUB and KCC approved orders or settlement agreements providing that, among other things, (i) our utilities in those jurisdictions cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40% of their total capitalization; and (ii) neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. Covenants within Cheyenne Light's financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. In addition to the restrictions described above, each state in which we conduct utility operations imposes restrictions on affiliate transactions, including inter-company loans. Additionally, our utility subsidiaries are generally limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may be subject to further restrictions under the Federal Power Act. As of December 31, 2011, the restricted net assets at our Electric and Gas Utilities were approximately $61.5 million.


•	Pursuant to a covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted assets of $100.0 million. In addition, Black Hills Wyoming holds $9.3 million of restricted cash in accordance with project financing requirements. Black Hills Non-regulated Holdings is the parent of Black Hills Electric Generation, which is the parent of Black Hills Wyoming.

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.

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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 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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Leases of Lessee Disclosure [Text Block]

Impairment of Long-Lived Assets	12 Months Ended
Impairment of Long-Lived Assets	Dec. 31, 2011
Impairment of Long Lived Assets, Goodwill, and Capitalized Development Costs [Abstract]
Asset Impairment Charges [Text Block]	IMPAIRMENT OF LONG-LIVED ASSETS Oil and Gas Segment As a result of lower natural gas prices at March 31, 2009, we recorded a $43.3 million pre-tax non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment. The write-down in the net carrying value of our natural gas and crude oil properties was recorded in Impairment of Long-lived assets on the accompanying Consolidated Statements of Income and was based on the March 31, 2009 NYMEX price of $3.63 per Mcf, adjusted to $2.23 per Mcf at the wellhead, for natural gas, and NYMEX price of $49.66 per barrel, adjusted to $45.32 per barrel at the wellhead, for crude oil.

Operating Leases

12 Months Ended

Dec. 31, 2011

Operating Leases [Abstract]

OPERATING LEASES

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



	2011		2010		2009
Rent expense	$	6,125	$	4,219	$	3,939

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



2012	$	2,799
2013	2,398
2014	2,376
2015	1,912
2016	1,403
Thereafter	3,610
	$	14,498

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, 2011

Income Taxes [Abstract]

INCOME TAXES

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



	2011			2010			2009
Current:
Current federal income tax expense (benefit)	$	(14,539	)	$	678		$	(12,351	)
Current state income tax expense (benefit)	(837		)	4,137			(408		)
	(15,376		)	4,815			(12,759		)
Deferred:
Deferred federal income tax expense (benefit)	30,876			20,186			45,912
Deferred state income tax expense (benefit)	2,970			(2,495		)	66
Tax credit amortization expense (benefit)	(246		)	(337		)	(368		)
	33,600			17,354			45,610

Total income tax expense (benefit)	$	18,224		$	22,169		$	32,851

Tax planning allowed us to defer approximately $185.0 million of income taxes related to the IPP Transaction. In the third quarter of 2010, we reached an agreement with the Appeals Division of the IRS that resulted in a decrease of that amount to approximately $125.0 million. The decrease represents the downward adjustment to tax depreciation allowed on certain assets sold, which resulted in a decrease to the gain realized on the sale of those assets and ultimately a decrease in deferred taxes. The remaining deferred amount relating to the IPP Transaction and the Aquila Transaction continues to be subject to IRS review.

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



	2011			2010
Deferred tax assets, current:
Asset valuation reserves	$	2,605		$	1,448
Mining development and oil exploration	614			594
Unbilled revenue	—			—
Employee benefits	8,175			3,899
Items of other comprehensive income (loss)	2,858			3,076
Derivative fair value adjustments	33,824			19,304
Deferred costs	97			342
Other deferred tax assets, current	4,493			5,607
Total deferred tax assets, current	52,666			34,270

Deferred tax liabilities, current:
Asset valuation reserves	—			(312		)
Prepaid expenses	(2,442		)	(2,431		)
Derivative fair value adjustments	(362		)	(327		)
Items of other comprehensive income (loss)	(3,035		)	(2,754		)
Deferred costs	(6,508		)	(4,621		)
Other deferred tax liabilities, current	(3,117		)	(3,161		)
Total deferred tax liabilities, current	(15,464		)	(13,606		)

Net deferred tax asset, current	$	37,202		$	20,664

Deferred tax assets, non-current:
Employee benefits	$	14,313		$	11,533
Regulatory liabilities	40,642			23,910
Deferred revenue	225			273
Deferred costs	—			—
State net operating loss (net of valuation allowance)	11,538			9,507
Items of other comprehensive income	33,540			22,306
Foreign tax credit carryover	2,801			3,352
Net operating loss	195,834			63,779
Asset impairment	47,033			48,092
Derivative fair value adjustment	5,275			3,038
Other deferred tax assets, non-current	9,453			11,076
Total deferred tax assets, non-current	360,654			196,866

Deferred tax liabilities, non-current:
Accelerated depreciation, amortization and other plant-related differences	(508,261		)	(314,513		)
Regulatory assets	(23,498		)	(16,050		)
Mining development and oil exploration	(94,334		)	(99,709		)
Deferred costs	(9,155		)	(17,615		)
Derivative fair value adjustments	—			—
Items of other comprehensive income	(2,054		)	(4,402		)
State deferred tax liability	(14,611		)	(11,477		)
Other deferred tax liabilities, non-current	(9,729		)	(8,942		)
Total deferred tax liabilities, non-current	(661,642		)	(472,708		)

Net deferred tax liability, net, non-current	$	(300,988	)	$	(275,842	)

Net deferred tax liability	$	(263,786	)	$	(255,178	)

The following table reconciles the change in the net deferred income tax liability from December 31, 2010 to December 31, 2011 to deferred income tax expense (in thousands):



	2011			2010
Net increase (decrease) in net deferred income tax liability for the year	$	8,608		$	414
Deferred taxes associated with other comprehensive loss (income)	2,259			1,915
Deferred taxes related to net operating loss from acquisition	—			(312		)
Deferred taxes related to regulatory assets and liabilities	22,962			25,511
Deferred taxes related to acquisition	—			(784		)
Deferred taxes associated with property basis differences	(14		)	(10,121		)
Other net deferred income tax	(215		)	731

Deferred income tax expense for the period	$	33,600		$	17,354

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



	2011		2010		2009
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	1.8		1.1		(0.3	)
Amortization of excess deferred and investment tax credits	(0.5	)	(0.4	)	(0.3	)
Percentage depletion in excess of cost	(2.5	)	(1.7	)	(0.8	)
Equity AFUDC	(0.5	)	(1.0	)	(1.7	)
Tax credits	—		(3.2	)	—
Accounting for uncertain tax positions adjustment	2.8		1.2		(2.1	)
Flow-through adjustments *	(4.5	)	(4.6	)	—
Other tax differences	(0.5	)	(0.4	)	(0.3	)
	31.1	%	26.0	%	29.5	%

_________________________

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 that was attributable to the 2008 through 2010 tax years. For years prior to 2008, we did not record a regulatory asset for the repairs deduction as the tax benefit was not flowed through to customers.

At December 31, 2011, we have federal and state NOL carryforwards of $534.8 million and $413.6 million, respectively, which will expire at various dates as follows (in thousands):



Expiration Years	Net Operating Loss Carryforward
2014-2019	$	9,306
2020-2025	$	48,229
2026-2031	$	890,861

As of December 31, 2011, the previously recorded valuation allowance against the federal NOL carryforwards was reduced to zero by netting it against the deferred tax asset for acquired NOL carryforwards that are subject to limitation under the Internal Revenue Code. We believe that such adjustment is a more accurate depiction of the acquired NOLs expected to be ultimately utilized within the prescribed carryforward period. We had a $0.8 million valuation allowance against the state NOL carry forwards. 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 at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands):



	Changes in Uncertain Tax Positions
Beginning balance at January 1, 2009	$	120,022
Additions for prior year tax positions	5,752
Reductions for prior year tax positions	(18,686		)
Additions for current year tax positions	—
Settlements	—

Ending balance at December 31, 2009	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 December 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 December 31, 2011	$	49,327



	2011		2010		2009
Uncertain tax positions	$	49,327	$	50,135	$	107,088
Income tax refund receivable related to uncertain tax positions above	—		—		(59,136		)

Net liability for uncertain tax positions	$	49,327	$	50,135	$	47,952

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $1.1 million.

We recognized the following interest expense (benefit), included in Income tax (expense) benefit on the accompanying Consolidated Statements of Income, for the years ended December 31 as follows (in thousands):



	2011		2010		2009
Interest expense (income) included in Income tax (expense) benefit	$	1,400	$	2,300	$	1,200

We had approximately $4.5 million and $3.1 million accrued for interest payable associated with income taxes at December 31, 2011 and 2010, 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 through 2009 tax years. We remain subject to examination by Canadian income tax authorities for tax years as early as 1999.

We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statute of limitations prior to December 31, 2012.

Excess foreign tax credits have been generated and are available to offset United States federal income taxes. At December 31, 2011, we had the following remaining foreign tax credit carryforwards (in thousands):



Foreign Tax Credit Carryforward		Expiration Year
$	26	2014
$	694	2015
$	24	2016
$	1,301	2017
$	214	2020
$	542	2021

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-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 4: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SX 210.4-08.(h))
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Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Comprehensive Income

12 Months Ended

Dec. 31, 2011

Comprehensive Income (Loss)

COMPREHENSIVE INCOME

The following table displays the related tax effects allocated to each component of Other comprehensive income (loss) for the years ended December 31 (in thousands):



2011	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Benefit plan liability adjustments - net gains (losses)	$	(11,744	)	$	4,135		$	(7,609	)
Benefit plan liability adjustments - prior service (costs)	(501		)	176			(325		)
Fair value adjustment of derivatives designated as cash flow hedges	(4,539		)	1,708			(2,831		)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	2,177			(709		)	1,468
Other comprehensive income (loss)	$	(14,607	)	$	5,310		$	(9,297	)



2010	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Benefit plan liability adjustments - net gains (losses)	$	(1,981	)	$	674		$	(1,307	)
Benefit plan liability adjustments - prior service (costs)	(325		)	111			(214		)
Fair value adjustment of derivatives designated as cash flow hedges	1,972			(636		)	1,336
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	(6,730		)	2,498			(4,232		)
Other comprehensive income (loss)	$	(7,064	)	$	2,647		$	(4,417	)



2009	Pre-tax Amount			Tax (Expense) Benefit Plans			Net-of-tax Amount
Benefit plan liability adjustments - net gains (losses)	$	(2,313	)	$	812		$	(1,501	)
Benefit plan liability adjustments - prior service (costs)	9,202			(3,231		)	5,971
Benefit plan liability adjustments - transition obligations	33			(12		)	21
Fair value adjustment of derivatives designated as cash flow hedges	(27,442		)	9,961			(17,481		)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	19,810			(7,201		)	12,609
Other comprehensive income (loss)	$	(710	)	$	329		$	(381	)

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			Amount from Equity-method Investees			Total
As of December 31, 2009	$	(9,462	)	$	(9,636	)	$	(66	)	$	(19,164	)

Other comprehensive income (loss)	(2,975		)	(1,506		)	64			(4,417		)

As of December 31, 2010	$	(12,437	)	$	(11,142	)	$	(2	)	$	(23,581	)

Other comprehensive income (loss)	(1,363		)	(7,934		)	—			(9,297		)

As of December 31, 2011	$	(13,800	)	$	(19,076	)	$	(2	)	$	(32,878	)

The entire disclosure for comprehensive income. Includes, but is not limited to, the following: 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. Components of comprehensive income include: (1) foreign currency translation adjustments; (2) gains (losses) on foreign currency transactions that are designated as, and are effective as, economic hedges of a net investment in a foreign entity; (3) gains (losses) on intercompany foreign currency transactions that are of a long-term-investment nature, when the entities to the transaction are consolidated, combined, or accounted for by the equity method in the reporting enterprise's financial statements; (4) change in the market value of a futures contract that qualifies as a hedge of an asset reported at fair value; (5) unrealized holding gains (losses) on available-for-sale securities and that resulting from transfers of debt securities from the held-to-maturity category to the available-for-sale category; (6) a net loss recognized as an additional pension liability not yet recognized as net periodic pension cost; and (7) the net gain (loss) and net prior service cost or credit for pension plans and other postretirement benefit plans.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 14-26
-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 2: http://www.xbrl.org/2003/role/presentationRef
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-Subparagraph (SX 210.3-04)
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

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-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION



Years ended December 31,	2011			2010			2009
	(in thousands)
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities	$	37,529		$	48,879		$	24,571
Capitalized asset retirement costs	$	1,525		$	1,858		$	6,027

Refunding bond issuance — Industrial Development Revenue Bonds	$	—		$	—		$	17,000

Cash (paid) refunded during the period for-
Interest (net of amount capitalized)	$	(103,110	)	$	(101,947	)	$	(69,317	)
Income taxes, net	$	9,854		$	9,384		$	17,117

Business Segments

12 Months Ended

Dec. 31, 2011

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.

In January 2012, we entered into a definitive agreement to sell our Energy Marketing segment, which resulted in this segment being reported as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the reclassification of this segment to discontinued operations on a consistent basis. Indirect corporate costs and inter-segment interest expenses related to Enserco that have not been reclassified to discontinued operations in accordance with GAAP have been reclassified to our Corporate segment. For further information see Note 23.

Detail for our segments as of and for the year ended December 31 was as follows (in thousands):



	2011		2010
Total assets
Utilities:
Electric Utilities ^(a)	$	2,254,914	$	1,834,019
Gas Utilities	746,444		722,287
Non-regulated Energy:
Oil and Gas	425,970		349,991
Power Generation^(a)	129,121		293,334
Coal Mining	88,704		96,962
Corporate	141,079		100,681
Discontinued Operations	340,851		314,235
Total assets	$	4,127,083	$	3,711,509

__________________


(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, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.



	2011		2010
Capital expenditures and asset acquisitions
Utilities:
Electric Utilities	$	173,078	$	232,466
Gas Utilities	43,954		51,363
Non-regulated Energy:
Oil and Gas	89,672		40,345
Power Generation	98,927		148,191
Coal Mining	10,438		17,053
Corporate	13,279		7,182
Total capital expenditures and asset acquisitions of continuing operations^(a)	429,348		496,600
Total capital expenditures of discontinued operations	2,359		390
Total capital expenditures and asset acquisitions	$	431,707	$	496,990

_________________


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



	2011		2010
Property, plant and equipment
Utilities:
Electric Utilities ^(a)	$	2,149,151	$	1,720,909
Gas Utilities	523,374		502,360
Non-regulated Energy:
Oil and Gas	763,645		680,407
Power Generation ^(a)	135,981		297,907
Coal Mining	145,024		145,385
Corporate	6,841		6,541
Total property, plant and equipment	$	3,724,016	$	3,353,509

_______________


(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, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.



	Consolidating Income Statement
Year ended December 31, 2011	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Intercompany Eliminations			Total
	(in millions)
Revenue	$	600,935		$	554,584		$	4,059		$	32,802		$	79,808		$	—		$	—		$	1,272,188
Intercompany 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 a gain on sale of assets to a related party which was eliminated in consolidation.



	Consolidating Income Statement
Year ended December 31, 2010	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Intercompany Eliminations			Total
	(in millions)
Revenue ^(a)	$	554,617		$	550,707		$	4,297		$	31,285		$	74,164		$	—		$	—		$	1,215,070
Intercompany revenue ^(a)	15,397			—			26,052			26,557			—			140,756			(204,141		)	4,621
Fuel, purchased power and cost of gas sold ^(a)	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 ^(b)	(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)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).


(b)	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).



	Consolidating Income Statement
Year ended December 31, 2009	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Intercompany Eliminations			Total
	(in millions)
Revenue ^(a)	$	511,326		$	580,312		$	4,445		$	31,459		$	70,684		$	—		$	—		$	1,198,226
Intercompany revenue^(a)	9,439			—			26,130			27,031			—			97,010			(159,124		)	486
Fuel, purchased power and cost of gas sold ^(a)	281,009			371,716			—			—			—			1			(57,486		)	595,240
Gross margin	239,756			208,596			30,575			58,490			70,684			97,009			(101,638		)	603,472

Operations and maintenance	125,150			123,296			12,631			40,312			40,224			95,184			(95,748		)	341,049
Gain on sale of operating assets ^(b)	—			—			(25,971		)	—			—			—			—			(25,971		)
Depreciation, depletion and amortization	43,638			30,090			3,860			13,123			29,680			6,933			(6,386		)	120,938
Impairment of long-lived assets ^(c)	—			—			—			—			43,301			—			—			43,301
Operating income	70,968			55,210			40,055			5,055			(42,521		)	(5,108		)	496			124,155

Interest expense	(34,830		)	(17,364		)	(11,244		)	(24		)	(4,683		)	(47,522		)	32,414			(83,253		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			55,653			—			55,653
Interest income	1,818			264			1,856			1,476			10			27,531			(32,032		)	923
Other income (expense), net	7,869			(285		)	1,091			3,475			350			12,201			(12,059		)	12,642
Income tax benefit (expense)	(13,126		)	(13,453		)	(11,097		)	(3,234		)	21,016			(12,957		)	—			(32,851		)
Income (loss) from continuing operations	$	32,699		$	24,372		$	20,661		$	6,748		$	(25,828	)	$	29,798		$	(11,181	)	$	77,269

______________________


(a)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).


(b)	Includes a gain on sale to MEAN of an ownership interest in the Wygen I power generation facility (see Note 22).


(c)	As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets (see Note 12).

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 131
-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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=6534315&loc=d3e8981-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 280
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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Employee Benefit Plans

12 Months Ended

Dec. 31, 2011

Employee Benefit Plans [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

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

Funded Status of Benefit Plans

The funded status of postretirement benefit plans is required to be recognized in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation. Except for our regulated utilities, the unrecognized net periodic benefit cost is recorded within Accumulated other comprehensive income (loss), net of tax. For our regulated utilities, we applied accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost was alternatively recorded as a regulatory asset or regulatory liability, net of tax. The measurement date for all plans is December 31. As of December 31, 2011, the funded status of our Defined Benefit Pension Plan was $104.0 million; the funded status of our Non-Qualified Defined Benefit Retirement Plan was $30.0 million; and the funded status of our Non-Pension Defined Benefit Postretirement Plan was $46.0 million.

Defined Benefit Pension Plan

We have three non-contributory defined benefit pension plans (the Pension Plans). As of January 1, 2012, all Pension Plans have been frozen to new employees and certain employees who did not meet age and service based criteria at the time the Plans were frozen. The benefits for the plans are based on years of service and calculations of average earnings during a specific time period prior to retirement.

In 2011, the Cheyenne Light Pension Plan was amended to freeze the benefits of certain bargaining unit employees. This amendment was effective as of January 1, 2012.

Our Pension Plan funding policy is in accordance with the federal government's funding requirements. The Pension Plans' assets are held in trust and consist primarily of equity and fixed income investments.

The Investment Policy for the Pension Plans is to seek to achieve the following long-term objectives: 1) a rate of return in excess of the annualized inflation rate based on a five year moving average; 2) a rate of return that meets or exceeds the assumed actuarial rate of return as stated in the Plan's actuarial report; 3) a rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates on a moving three year average, and 4) maintenance of sufficient income and liquidity to pay monthly retirement benefits. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets. The policy contains certain prohibitions on transactions in separately managed portfolios in which the Pension Plans may invest, including prohibitions on short sales. The Pension Plans' expected long-term rate of return on assets assumptions are based upon the weighted-average expected long-term rate of return for each individual asset class. The asset class weighting is determined using the target allocation for each class in the Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from adjusted long-term historical returns for the asset class. It is anticipated that long-term future returns will not achieve historical results. Our Pension Plan funding policy is in accordance with the federal government's funding requirements. 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 equity investments was 8.75% and 9.25% for the 2011 and 2010 plan years, respectively.

Plan Assets

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



	2011		2010
Equity	64	%	65	%
Real estate	3		3
Fixed income	32		31
Cash	1		1
Total	100	%	100	%

Supplemental Non-qualified Defined Benefit Retirement 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 a graded vesting schedule at 20% per year over 5 years and are not funded by the Company.

Plan Assets

We fund the NQDC on a cash basis as benefits are paid; therefore, assets of the plan are $0.0 million.

Non-pension Defined Benefit Postretirement Plans

We sponsor retiree healthcare plans (the Healthcare Plans) for all employees who meet certain age and service requirements at retirement and who are entitled to postretirement healthcare benefits. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the plans periodically. A portion of the Healthcare Plan is pre-funded via VEBAs. It has been 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 Plan for those employees outside Kansas and Iowa.

Plan Contributions

Contributions to the Healthcare Plans and the Supplemental Plans are made in the form of benefit payments. Contributions to our employee benefit plans were as follows (in thousands):



	2011		2010
Defined Benefit Plans
Defined Benefit Pension Plans	$	11,050	$	30,015
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	4,963	$	5,198
Supplemental Non-Qualified Defined Benefit Plans	$	956	$	894



	2011		2010
Defined Contribution Plan
Company Retirement Contribution	$	2,440	$	2,022
Matching contributions - Defined Contribution Plans	$	8,916	$	7,900

We expect to make contributions to our employee benefit plans as follows (in thousands):



	2012
Defined Benefit Plans
Defined Benefit Pension Plans	$	12,483
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	4,250
Supplemental Non-Qualified Defined Benefit Plans	$	1,110

Fair Value Measurements

As required by accounting standards for Compensation - Retirement Benefits, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

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



Defined Benefit Pension Plans	December 31, 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 Pension Plans	December 31, 2010
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	—	$	—	$	—	$	—
Registered Investment Companies - Equity	27,070		—		—		27,070
Registered Investment Companies - Fixed Income	27,544		—		—		27,544
103-12 Investment Entities - Equity	—		11,246		—		11,246
Common Collective Trust - Money Market	—		174		—		174
Common Collective Trust - Equity	—		106,786		—		106,786
Common Collective Trust - Fixed Income	—		39,121		—		39,121
Common Collective Trust - Real Estate	—		—		6,126		6,126
Insurance Contracts	—		2,097		—		2,097
Total investments measured at fair value	$	54,614	$	159,424	$	6,126	$	220,164



Non-pension Defined Benefit Postretirement Plans	December 31, 2011
	Level 1		Level 2		Level 3		Total
Common Collective Trust	$	—	$	4,319	$	—	$	4,319
Total investments measured at fair value	$	—	$	4,319	$	—	$	4,319



Non-pension Defined Benefit Postretirement Plan	December 31, 2010
	Level 1		Level 2		Level 3		Total
Common Collective Trust	$	—	$	4,564	$	—	$	4,564
Total investments measured at fair value	$	—	$	4,564	$	—	$	4,564

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plan's level 3 assets for the period ended December 31 (in thousands):



	2011		2010
Balance, beginning of period	$	6,126	$	5,844
Unrealized gain (loss)	917		282
Balance, end of period	$	7,043	$	6,126

Additional information about plan assets, including methods and assumption 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 Plan owns 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.

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
	2011			2010			2011			2010			2011			2010
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	280,623		$	256,400		$	24,725		$	21,611		$	46,304		$	46,396

Service cost	5,421			6,131			1,028			685			1,498			1,509
Interest cost	14,929			15,091			1,298			1,284			2,168			2,446
Actuarial (gain) loss	36,543			13,663			4,128			2,039			3,017			961
Amendments	—			261			—			—			(160		)	(2,239		)
Benefits paid	(11,178		)	(9,949		)	(956		)	(894		)	(4,963		)	(5,198		)
Plan curtailment reduction	(394		)	(974		)	—			—			—			—
Medicare Part D accrued	—			—			—			—			188			559
Plan participants' contributions	—			—			—			—			2,089			1,870

Projected benefit obligation at end of year	$	325,944		$	280,623		$	30,223		$	24,725		$	50,141		$	46,304

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)
	2011			2010			2011		2010		2011			2010
Beginning market value of plan assets	$	220,164		$	176,503		$	—	$	—	$	4,564		$	4,717
Investment income	1,686			23,595			—		—		1			1
Employer contributions	11,050			30,015			—		—		2,087			2,493
Retiree contributions	—			—			—		—		1,366			1,205
Benefits paid	(11,178		)	(9,949		)	—		—		(3,713		)	(3,847		)
Plan administrative expenses	—			—			—		—		14			(5		)

Ending market value of plan assets	$	221,722		$	220,164		$	—	$	—	$	4,319		$	4,564

____________________

(a) Asset of VEBA

Amounts recognized in the Consolidated Balance Sheet consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011		2010		2011		2010
Regulatory asset	$	93,423	$	54,202	$	—	$	—	$	9,161	$	7,896
Current liability	$	—	$	—	$	1,116	$	943	$	3,522	$	2,999
Non-current liability	$	104,214	$	60,451	$	30,953	$	23,782	$	42,313	$	38,561
Regulatory liability	$	—	$	—	$	—	$	—	$	590	$	1,050

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011		2010		2011		2010

Accumulated benefit obligation - Black Hills Corporation	$	106,800	$	90,301	$	23,023	$	19,153	$	14,313	$	12,101
Accumulated benefit obligation - Black Hills Energy	184,345		160,217		446		454		25,842		25,080
Accumulated benefit obligation - Cheyenne Light	5,731		4,462		—		—		9,986		9,121

	$	296,876	$	254,980	$	23,469	$	19,607	$	50,141	$	46,302

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011			2010			2009			2011		2010		2009		2011			2010			2009
Service cost	$	5,421		$	6,131		$	7,587		$	1,028	$	685	$	469	$	1,498		$	1,509		$	1,060
Interest cost	14,929			15,091			14,715			1,298		1,284		1,376		2,168			2,446			2,202
Expected return on assets	(16,955		)	(14,493		)	(14,281		)	—		—		—		(164		)	(208		)	(226		)
Amortization of prior service cost	99			99			127			3		3		1		(479		)	(309		)	(23		)
Amortization of transition obligation	—			—			—			—		—		—		—			—			60
Recognized net actuarial loss (gain)	4,540			3,126			2,720			510		285		589		677			636			(27		)
Curtailment expense	13			57			322			—		—		—		—			—			—
Net periodic expense	$	8,047		$	10,011		$	11,190		$	2,839	$	2,257	$	2,435	$	3,700		$	4,074		$	3,046

Accumulated Other Comprehensive Income

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



	Defined Benefit Pension Plans				Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011		2010		2011			2010
Net (gain) loss	$	11,472	$	6,545	$	6,894	$	4,544	$	2,556		$	2,172
Prior service cost (gain)	98		121		12		14		(1,956		)	(2,276		)
Transition obligation	—		—		—		—		—			—
Total accumulated other comprehensive (income) loss	$	11,570	$	6,666	$	6,906	$	4,558	$	600		$	(104	)

The amounts in accumulated other comprehensive income, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2012 are as follows (in thousands):



	Defined Benefit Pension Plans		Supplemental Nonqualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Plans
Net loss	$	6,560	$	525	$	577
Prior service cost	58		2		(325		)
Transition obligation	—		—		—
Total net periodic benefit cost expected to be recognized during calendar year 2012	$	6,618	$	527	$	252

Assumptions



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
Weighted-average assumptions used to determine benefit obligations:	2011		2010		2009		2011		2010		2009		2011		2010		2009

Discount rate	4.65	%	5.48	%	6.03	%	4.30	%	4.95	%	5.58	%	4.42	%	5.03	%	5.68	%
Rate of increase in compensation levels	3.77	%	3.79	%	4.20	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2011		2010		2009		2011		2010		2009		2011		2010		2009

Discount rate:
Black Hills Corporation	5.50	%	6.05	%	6.25	%	5.00	%	6.10	%	6.20	%	5.00	%	5.90	%	6.10	%
Black Hills Energy	5.40	%	6.00	%	6.25	%	4.40	%	5.05	%	5.00	%	4.60	%	5.15	%	6.10	%
Cheyenne Light	5.55	%	6.05	%	6.20	%	N/A		N/A		N/A		5.50	%	6.00	%	6.10	%

Expected long-term rate of return on assets*	7.75	%	8.00	%	8.50	%	N/A		N/A		N/A		4.00	%	5.00	%	5.00	%
Rate of increase in compensation levels	3.79	%	4.20	%	4.20	%	5.00	%	5.00	%	5.00	%	NA		NA		N/A

_____________________________


*	The expected rate of return on plan assets changed to 7.25% for the calculation of the 2012 net periodic pension cost.

The healthcare benefit obligation was determined at December 31, 2011, using an initial healthcare trend rate of 9.01% trending down to an ultimate rate of 4.50% in 2028, and at December 31, 2010, using an initial healthcare trend rate of 9.51% trending down to an ultimate rate of 4.50% in 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 December 31, 2011 Accumulated Postretirement Benefit Obligation			Impact on 2011 Service and Interest Cost
Increase 1%	$	2,720		$	184
Decrease 1%	$	(2,272	)	$	(150	)

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



	Defined Benefit Pension Plans		Supplemental Nonqualified Defined Benefit Retirement Plan		Non-Pension Defined Benefit Postretirement Plans
2012	$	12,484	$	1,110	$	4,250
2013	$	13,181	$	1,090	$	4,380
2014	$	13,953	$	1,280	$	4,320
2015	$	14,823	$	1,290	$	4,170
2016	$	15,694	$	1,370	$	4,250
2017-2021	$	93,852	$	7,160	$	21,950

The entire disclosure for pension and other postretirement benefits.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
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Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

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 December 31, 2023, for the purchase of 50 MW of electric capacity and energy from PacifiCorp's system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp's coal-fired electric generating plants.


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


•	Cheyenne Light's PPA with Duke Energy's Happy Jack wind site, expiring September 3, 2028, provides up to 30 MW of wind energy from Happy Jack to Cheyenne Light. Under a separate intercompany agreement, Cheyenne Light sells 50% of the facility output to Black Hills Power.


•	Cheyenne Light's PPA with Duke Energy's Silver Sage wind site, expiring September 30, 2029, for up to 30 MW of wind energy. Under a separate intercompany agreement, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to Black Hills Power.


•	Colorado Electric's PPA with PSCo expiring December 31, 2012, whereby Colorado Electric purchases 50 MW of economy energy.


•	Colorado Electric's PPA with Cargill expiring December 31, 2013, whereby Colorado Electric purchases 50 MW of economy energy.

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



	2011		2010		2009
PPA with PacifiCorp	$	12,515	$	12,936	$	11,862
PPA with PSCo^(a)	$	97,988	$	110,575	$	97,899
Transmission services agreement with PacifiCorp	$	1,215	$	1,215	$	1,215
PPA with Happy Jack	$	1,955	$	2,815	$	2,078
PPA with Silver Sage	$	3,281	$	1,723	$	713

_______________________


(a)	This PPA with PSCo expired on December 31, 2011 and was replaced with the facilities constructed by Colorado Electric at our Pueblo Airport Generation site and the facilities constructed by Black Hills Colorado IPP to support a new PPA with Colorado Electric.

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.

Colorado Electric has a firm supply contract through December 31, 2013.

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



2012	$	199,811
2013	$	123,600
2014	$	73,145
2015	$	70,140
2016	$	46,568
Thereafter	$	202,779

Cheyenne Light's PPA for 60 MW of capacity and energy from Black Hills Wyoming's Wygen I generating facility expiring on December 31, 2022, includes an option for Cheyenne Light to purchase Black Hills Wyoming's ownership in the Wygen I facility. The purchase price related to the option is $2.55 million per MW which is the equivalent per MW 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.

Long-Term Power Sales Agreements

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


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

•

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


•	Cheyenne Light has an agreement with Basin Electric whereby Cheyenne Light provides 40 MW of capacity and energy through March 31, 2013 and a separate agreement whereby Cheyenne Light will receive 40 MW of capacity and energy from Basin Electric through March 13, 2013. The agreements became effective March 14, 2011;


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


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

Related Party Lease

Colorado Electric's PPA with Black Hills Colorado IPP expiring on December 31, 2031, provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP's combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable.

Reclamation Liability

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 with an equivalent amount capitalized as part of the carrying amount of the long-lived asset in Property, plant and equipment. See Note 10 for additional information. The asset is depreciated over the appropriate time period. The amount of depreciation expense for the years ended December 31 was as follows (in thousands):



	2011		2010		2009
Depreciation expense on capitalized asset retirement costs	$	5,212	$	6,519	$	1,993

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. As such, costs, if any, that may be incurred in excess of those amounts provided as of December 31, 2011, cannot be reasonably determined and could have a material effect on the results of operations, financial position or cash flows.

The entire disclosure for commitments and contingencies.

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Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Guarantees

12 Months Ended

Dec. 31, 2011

20. 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 (in thousands):



	Maximum Exposure at
Nature of Guarantee	December 31, 2011		Year Expiring
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings ⁽¹⁾	$	70,000	Ongoing
Guarantees for payment obligations arising from purchase contracts for four gas turbines for Black Hills Colorado IPP⁽²⁾	384		2012
Guarantees for payment obligations arising from purchase contracts for two gas turbines for Colorado Electric⁽³⁾	56		2012
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric⁽⁴⁾	33,264		January 15, 2013
Indemnification for subsidiary reclamation/surety bonds ⁽⁵⁾	18,601		Ongoing
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Black Hills Utility Holdings ⁽⁶⁾	10,000		July 31, 2012
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply ⁽⁷⁾	7,500		June 30, 2012
	$	139,805

(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 four guarantees to GE for payment obligations arising from contracts to purchase four LM6000 gas turbines for Black Hills Colorado IPP. These are continuous guarantees which will terminate upon settlement of all obligations.


(3)	We have issued two guarantees to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers. These are continuing guarantees which will terminate upon settlement of all obligations.


(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 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.


(6)	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 agreements.


(7)	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, 2011

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

OIL AND GAS RESERVES (Unaudited)

BHEP has operating and non-operating interests in 1,219 gross developed oil and gas wells in 9 states and holds leases on approximately 328,643 net acres.

Costs Incurred

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



	2011		2010		2009
Acquisition of properties:
Proved	$	673	$	—	$	—
Unproved	8,317		3,846		3,443
Exploration costs	44,384		8,159		5,962
Development costs	38,638		25,264		10,133
Asset retirement obligations incurred	43		1,228		623
Total costs incurred	$	92,055	$	38,497	$	20,161

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, 2011, 2010 and 2009, 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.



	2011						2010						2009
	Oil			Gas			Oil			Gas			Oil			Gas
	(in Mbbls of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	5,940			95,456			5,274			87,660			5,185			154,432
Production ^(a)	(452		)	(8,526		)	(376		)	(8,484		)	(366		)	(9,710		)
Additions - acquisitions (sales)	(84		)	—			(13		)	(377		)	—			—
Additions - extensions and discoveries	927			29,664			1,145			1,710			152			2,560
Revisions to previous estimates ^(b)	(108		)	(20,690		)	(90		)	14,947			303			(59,622		)
Balance at end of year	6,223			95,904			5,940			95,456			5,274			87,660

Proved developed reserves at end of year included above	4,830			71,867			4,434			67,656			4,274			74,911

Proved undeveloped reserves at the end of year included in above	1,393			24,037			1,506			27,800			1,000			12,749

NYMEX prices	$	96.19		$	4.12		$	79.43		$	4.38		$	61.18		$	3.87

Well-head reserve prices	$	88.49		$	3.59		$	70.82		$	3.45		$	53.59		$	2.52

________________________


(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGL's).


(b)	Included in the total revisions are (23.6) Bcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2.3 Bcfe in various basins. Revisions due to cost and commodity pricing were less than 1% Bcfe.

Reserve additions totaled 35.2 Bcfe, replacing 119% of production. Additions resulted from drilling in the Williston, San Juan and Piceance basins. Drilling in Williston Basin (Bakken Shale) accounted for 7.0 Bcfe, San Juan (Mancos Shale) accounted for 11.1 Bcfe and Piceance (Mancos Shale) accounted for 16.5 Bcfe of the additions. Williston Basin drilling is planned through 2014. Capital spending in 2011 was increased to accommodate the Williston Bakken drilling and to evaluate the development potential of the San Juan and Piceance Mancos Shale under our leasehold. Additionally, exploratory investments were made in 2011 to develop future opportunities. Future capital spending rates are anticipated to 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. Most of the revisions to previous estimates were due to five year aging of the proved undeveloped reserves in the Piceance Basin, Wind River Basin and Bear Paw Uplift and were removed from our proved reserves. Revisions were offset by positive revisions in the San Juan Basin of 1.7 Bcfe and some minor performance revisions in Williston Basin (0.4) Bcfe, Powder River Basin (0.7) Bcfe, Piceance 0.5 Bcfe and 1.2 Bcfe in other basins.

•

Companies are required to include a narrative disclosure of the total quantity of PUDs at year end, any material changes in PUDs during the year, and investment and progress made in converting the PUDs during the year. In 2011, we invested approximately $18.9 million to drill and develop 9 PUD locations from our 2010 inventory totaling approximately 4.7 Bcfe in proved developed reserve recognition. 100% of the PUD development in 2011 was in the Williston Basin which resulted in approximately 13 additional PUDs (4.6 net Bcfe) added to our year-end 2011 reserves. Additional PUDs were added in the Piceance (3 gross locations, 12.0 net Bcfe) and San Juan (2 gross locations, 7.5 net Bcfe) basins following 2011 drilling in those basins.


•	Approximately 23.6 Bcfe were dropped from the proved reserves in 2011 due to five year aging of the PUDs. This drop was primarily in the Piceance (21.2 Bcfe, 17 gross locations, $34.7 million future investment), Bear Paw Uplift (0.5 Bcfe, 17 gross locations, $0.8 million future investment), and Wind River Basin (2.0 Bcfe, 25 gross locations, and $3.6 million future investment).


•	As of December 31, 2011, PUD locations, proved reserves and future development costs associated with certain locations are as follows:



	As of December 31, 2011
Basin	Proved Reserves (in Bcfe)	Gross PUD Locations	Future Development Costs (in millions)
Piceance	12.8	4	$	26.7
Williston	10.5	33	46.3
Bear Paw Uplift	1.0	32	2.0
San Juan	8.1	3	15.1
	32.4	72	$	90.1


•	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 December 31 (in thousands):



	2011			2010			2009
Unproved oil and gas properties	$	28,656		$	28,160		$	29,351
Proved oil and gas properties	674,494			592,978			582,276
Gross capitalized costs	703,150			621,138			611,627

Accumulated depreciation, depletion and amortization and valuation allowances	(361,173		)	(334,955		)	(335,605		)
Net capitalized costs	$	341,977		$	286,183		$	276,022

Results of Operations

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



	2011			2010			2009

Revenue	$	79,808		$	74,164		$	70,684

Production costs	23,820			21,922			21,653
Depreciation, depletion and amortization and valuation provisions*	34,415			29,013			72,338
Total costs	58,235			50,935			93,991
Results of operations from producing activities before tax	21,573			23,229			(23,307		)

Income tax benefit (expense)	(7,442		)	(8,014		)	8,041
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	14,131		$	15,215		$	(15,266	)

_________________________


*	Includes pre-tax ceiling test impairment charges of $43.3 million in 2009.

Unproved properties not subject to amortization at December 31, 2011, 2010 and 2009 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 $0.9 million, $0.8 million and $0.3 million of interest during 2011, 2010 and 2009, 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 the next year.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2011 and notes the year in which the associated costs were incurred (in thousands):



	2011		2010		2009		Prior		Total

Leasehold acquisition cost	$	3,451	$	3,442	$	887	$	17,119	$	24,899
Exploration cost	16,745		—		—		—		16,745
Capitalized interest	291		404		55		3,006		3,756
Total	$	20,487	$	3,846	$	942	$	20,125	$	45,400

Standardized Measure of Discounted Future Net Cash Flows

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



	2011			2010			2009
Future cash inflows	$	931,637		$	764,585		$	519,867
Future production costs	(280,910		)	(256,455		)	(207,783		)
Future development costs	(92,233		)	(73,805		)	(34,961		)
Future income tax expense	(157,922		)	(111,666		)	(51,287		)
Future net cash flows	400,572			322,659			225,836
10% annual discount for estimated timing of cash flows	(197,215		)	(154,551		)	(96,728		)
Standardized measure of discounted future net cash flows	$	203,357		$	168,108		$	129,108

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



	2011			2010			2009
Standardized measure - beginning of year	$	168,108		$	129,108		$	179,226
Sales and transfers of oil and gas produced, net of production costs	(52,914		)	(40,282		)	(26,836		)
Net changes in prices and production costs	57,087			57,380			(40,786		)
Extensions, discoveries and improved recovery, less related costs	31,179			17,076			3,324
Changes in future development costs	43,809			(17,125		)	83,000
Development costs incurred during the period	18,940			4,975			4,620
Revisions of previous quantity estimates	(58,211		)	27,513			(104,556		)
Accretion of discount	19,655			13,434			19,596
Net change in income taxes	(23,283		)	(23,233		)	11,520
Purchases of reserves	—			—			—
Sales of reserves	(1,013		)	(738		)	—
Standardized measure - end of year	$	203,357		$	168,108		$	129,108

Changes in the standardized measure from "revisions of previous quantity estimates, changes in production rates, changes in timing and other," 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
Sale of Operating Assets	Dec. 31, 2011
Sale of Operating Assets [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	SALE OF OPERATING ASSETS Sale of Operating Assets Sale of Gas Assets On March 1, 2010, Nebraska Gas sold 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. Partial Sale of Wygen III to City of Gillette, WY On July 14, 2010, Black Hills Power sold a 23% 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 estimated 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 Wygen I to MEAN On January 1, 2009, Black Hills Wyoming sold a 23.5% ownership interest in the Wygen I plant to MEAN for a price of $51.0 million, which was based on the then-current replacement cost for the coal-fired plant. We realized an after-tax gain of $16.9 million on the sale, and our property, plant and equipment was reduced by $25.0 million. We retain responsibility for operations of the plant, and at closing entered into a site lease, and operating agreements with MEAN for coal supply and operations. Partial Sale of Wygen III to MDU On April 9, 2009, Black Hills Power sold a 25% ownership interest in its Wygen III generation facility to MDU. At closing, MDU made a payment to us for its share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received. MDU continued to reimburse Black Hills Power for its proportionate share of the total costs paid to complete the project.

Quarterly Historical Data (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Financial Information Disclosure [Abstract]

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 2011 and 2010.



	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

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

Income (loss) per share for continuing operations - diluted	$	0.73		$	0.09	$	(0.29	)	$	0.44
Income (loss) per share for discontinued operations - diluted	(0.05		)	0.10		0.02			0.16
Income (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.



	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2010
Revenue ^(a)	$	416,728	$	247,443		$	240,521	$	314,999
Operating income^(b)	$	64,698	$	27,170		$	44,695	$	46,857
Income (loss) from continuing operations ^{(b) (c)}	$	28,705	$	(10,688	)	$	10,493	$	34,631
Income (loss) from discontinued operations	$	2,729	$	2,029		$	1,897	$	(1,111	)
Net income (loss) available for common stock ^{(b) (c)}	$	31,434	$	(8,659	)	$	12,390	$	33,520

Income (loss) per share, Basic:
Earnings (loss) per share for continuing operations	$	0.74	$	(0.27	)	$	0.27	$	0.89
Earnings (loss) per share for discontinued operations	0.07		0.05			0.05		(0.03		)
Earnings (loss) per share - basic	$	0.81	$	(0.22	)	$	0.32	$	0.86

Income (loss) per share, Diluted:
Earnings (loss) per share for continuing operations	$	0.74	$	(0.27	)	$	0.27	$	0.88
Earnings (loss) per share for discontinued operations	0.07		0.05			0.05		(0.03		)
Earnings (loss) per share - diluted	$	0.81	$	(0.22	)	$	0.32	$	0.85

Dividends paid per share	$	0.36	$	0.36		$	0.36	$	0.36

Common stock prices - High	$	30.83	$	34.49		$	33.31	$	33.42
Common stock prices - Low	$	25.65	$	27.34		$	27.79	$	29.32

__________________________


(a)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated. See Note 1.


(b)	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively.


(c)	Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 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 Cash Flows [Member]

Subsequent Events (Notes)	12 Months Ended
Subsequent Events (Notes)	Dec. 31, 2011
Subsequent Events [Abstract]
Subsequent Event	SUBSEQUENT EVENTS Sale of Energy Marketing Segment On January 18, 2012, we entered into a definitive agreement to sell the outstanding stock of Enserco, our Energy Marketing segment, to Twin Eagle Resource Management, LLC for expected net cash proceeds of approximately $160 million to $170 million, subject to working capital and other closing adjustments. The transaction is expected to be completed by the end of the first quarter of 2012. As a result, the Consolidated Financial Statements have been reclassified to reflect this business as a discontinued operation for all periods presented. See Note 23 for further details. Revolving Credit Facility On February 1, 2012, we entered into a new $500.0 million Revolving Credit Facility. The new Revolving Credit Facility, now expiring on February 1, 2017, remains at $500.0 million but contains an accordion feature which allows us, with the consent of the administrative agent, to increase the capacity of the facility to $750.0 million and 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 interest costs associated with letters of credit or borrowings under the agreement are determined based upon our credit ratings. At our current credit rating, the margins for base rate borrowings, Eurodollar borrowings and letters of credit are 0.5%, 1.5% and 1.5%. The facility contains a commitment fee to be charged on the unused amount of the Revolving Credit Facility which is 0.25% based on current credit ratings.

Schedule I Disclosures for Parent Company Only

12 Months Ended

Dec. 31, 2011

Condensed Financial Statements, Captions [Line Items]

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

BLACK HILLS CORPORATION (PARENT COMPANY)

STATEMENTS OF CASH FLOWS



Years ended December 31,	2011			2010			2009
	(in thousands)
Operating activities:
Net income (loss)	$	49,730		$	68,685		$	81,555
Loss from discontinued operations, net of tax	—			—			195
Income from continuing operations	49,730			68,685			81,750
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities —
Equity in earnings of subsidiaries	(87,150		)	(88,627		)	(57,394		)
Dividend from subsidiaries	14,500			6,298			—
Stock compensation	5,643			5,637			3,908
Unrealized mark-to-market (gain) loss on certain interest rate swaps	42,010			15,193			(55,653		)
Derivative fair value adjustments	2,291			(6,384		)	1,461
Deferred income taxes	2,599			(34,452		)	19,224
Other adjustments	4,376			2,508			(254		)
Change in operating assets and liabilities —
Accounts receivable and other current assets	(5,141		)	2,198			41,237
Accounts payable and other current liabilities	3,550			4,846			(22,906		)
Other operating activities	550			(2,514		)	1,399
Net cash provided by (used in) operating activities of continuing operations	32,958			(26,612		)	12,772
Net cash used by operating activities of discontinued operations	—			—			(195		)
Net cash provided by (used in) operating activities	32,958			(26,612		)	12,577

Investing activities:
Property, plant and equipment additions	(1,135		)	—			—
Increase in advances to affiliate	(258,117		)	(216,337		)	(115,731		)
Other investing activities	—			—			—
Net cash provided by (used in) investing activities	(259,252		)	(216,337		)	(115,731		)

Financing activities:
Dividends paid on common stock	(59,202		)	(56,467		)	(55,151		)
Common stock issued	123,041			3,246			4,819
Decrease in short-term borrowings	(821,300		)	(770,000		)	(742,500		)
Increase in short-term borrowings	1,017,300			854,500			631,075
Notes payable to affiliate	(25,302		)	14,995			—
Long-term debt — issuance	—			200,000			248,500
Other financing activities	(5,348		)	(5,379		)	1,500
Net cash provided by financing activities	229,189			240,895			88,243
Net change in cash and cash equivalents	2,895			(2,054		)	(14,911		)

Cash and cash equivalents beginning of year	219			2,273			17,184
Cash and cash equivalents end of year	$	3,114		$	219		$	2,273



Supplemental Cash Flow Information
Years ended December 31,	2011			2010			2009
	(in thousands)

Non-cash investing and financing activities-
Non-cash adjustment to notes receivable from affiliate	$	—		$	62,019		$	66,034
Non-cash adjustment to notes payable to affiliate	$	—		$	13,874		$	—
Non-cash dividend from affiliates	$	—		$	—		$	225,000

Cash (paid) refunded during the period for-
Interest	$	(14,667	)	$	(56,464	)	$	(19,878	)
Income taxes	$	23,830		$	(504	)	$	6,667

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

Condensed Statement of 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 INCOME



Years ended December 31,	2011			2010			2009
	(in thousands)

Revenue	$	—		$	—		$	—
Operating expenses	772			735			524
Operating income (loss)	(772		)	(735		)	(524		)

Other income (expense):
Equity income (loss) in earnings of subsidiaries	87,150			88,627			57,394
Interest expense	(15,229		)	(14,985		)	(17,786		)
Unrealized (loss) gain on interest rate swaps, net	(42,010		)	(15,193		)	55,653
Interest income	3			22			10
Other income (expense), net	(42		)	34			28
Total other income (expense)	29,872			58,505			95,299
Income (loss) from continuing operations before income taxes	29,100			57,770			94,775
Income tax benefit (expense)	20,630			10,915			(13,025		)
Income (loss) from continuing operations	49,730			68,685			81,750
Loss from discontinued operations	—			—			(195		)
Net income (loss) available for common stock	$	49,730		$	68,685		$	81,555

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 December 31,	2011		2010
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	3,114	$	219
Accounts receivable — affiliates, current	1,445		869
Notes receivable — affiliates, current	453,216		201,497
Deferred income tax assets, net, current	36,951		21,137
Other current assets	15,831		15,173
Total current assets	510,557		238,895

Property and Equipment	1,135		—

Investments in subsidiaries	1,339,024		1,269,123

Notes receivable — affiliate, non-current	575,000		575,000
Deferred income tax assets, net, non-current	29,454		44,587
Other long-term assets	4,834		3,889
Total other assets, non-current	609,288		623,476

TOTAL ASSETS	$	2,460,004	$	2,131,494

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable -- affiliate, current	$	5,202	$	1,613
Derivative liabilities, current	78,502		57,343
Notes payable	345,000		249,000
Notes payable — affiliate, current	1,754		25,232
Other current liabilities	12,070		12,109
Total current liabilities	442,528		345,297

Derivative liabilities, non-current	31,368		7,360

Long-term debt	774,959		674,930
Note payable — affiliate, non-current	1,813		3,637
Total long-term debt	776,772		678,567

Total stockholders' equity	1,209,336		1,100,270

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	2,460,004	$	2,131,494

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



	2011		2010		2009
Cash Dividends paid to Parent by subsidiaries	$	14,500	$	6,298	$	—
Non-Cash Dividends paid to Parent by subsidiaries	$	—	$	—	$	225,000

(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.

Black Hills Corporation had a Revolving Credit Facility with various banks totaling $500.0 million at December 31, 2011, which expires April 14, 2013. We had $195.0 million of borrowings and $43.7 million of letters of credit and $149.0 million of borrowings and $46.9 million of letters of credit issued under the facility at December 31, 2011 and 2010, respectively. The cost of borrowings or letters of credit issued under the facility is determined based on our credit ratings. At current ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit are 1.75%, 2.75% and 2.75%, respectively at December 31, 2011. The facility contains a commitment fee to be charged on the unused amount of the facility. Based upon current credit ratings, the fee is 0.5%. A new Revolving Credit Facility was entered into on February 1, 2012 replacing the prior Revolving Credit Facility. See Note 25 to Notes to Consolidated Financial Statements on this Annual Report filed on Form 10-K.

Corporate Term Loans

In June 2011, we entered into a $150.0 million unsecured, single draw, term loan with CoBank, the Bank of Nova Scotia and U.S. Bank due on June 24, 2012. The cost of borrowing under the term loan is based on a spread of 1.25% over LIBOR (1.56% at December 31, 2011). The covenants are substantially the same as those included in the Revolving Credit Facility and we were in compliance with these covenants as of December 31, 2011.

(3) LONG-TERM DEBT

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



	Due Date	Interest Rate		2011			2010
Senior unsecured notes due 2013 ^(a)	May 15, 2013	6.50	%	$	225,000		$	225,000
Unamortized discount on notes due 2013				(41		)	(70		)
Senior unsecured notes due 2014 ^(a)	May 15, 2014	9.00	%	250,000			250,000
Senior unsecured notes due 2020 ^(b)	July 15, 2020	5.88	%	200,000			200,000
Long-term term loan	September 30, 2013	1.69	%	100,000			—
Total senior unsecured notes				$	774,959		$	674,930

_______________


(a)	In order to restructure debt and equity capitalization at our utilities, 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.


(b)	In order to restructure debt and equity capitalization at our utilities, $100.0 million of 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.

$200 Million Debt Offering

In July 2010, pursuant to a public offering, we issued $200.0 million aggregate principal of senior unsecured notes. The notes were priced at par and carry a fixed interest rate of 5.88%. We received proceeds of $198.7 million, net of underwriting fees. Deferred financing costs are being amortized over the term of the debt. Amortization of deferred financing costs is included in Interest expense. Proceeds were used to pay down a portion of borrowings on our Revolving Credit Facility and to reduce issued letters of credit.

Long-term Term Loan

Our $100.0 million term loan with J.P. Morgan and Union Bank was extended through September 30, 2013. The cost of borrowings under this term loan was based on a spread of 1.375% over LIBOR (1.69% at December 31, 2011). The proceeds were used to reduce borrowings on the Revolving Credit Facility. The covenants are substantially the same as the Revolving Credit Facility.

Certain debt instruments of the Company contain restrictions and covenants, all of which we were in compliance with at December 31, 2011.

(4) GUARANTEES

As of December 31, 2011, we had the following guarantees in place (in thousands):



	Maximum Exposure at
Nature of Guarantee	December 31, 2011		Year Expiring
Guarantees for payment obligations arising from commodity-related physical and financial transactions by Black Hills Utility Holdings	$	70,000	Ongoing
Guarantees for payment obligations arising from purchase contracts for four gas turbines for Black Hills Colorado IPP	384		2012
Guarantees for payment obligations arising from purchase contracts for two gas turbines for Colorado Electric	56		2012
Guarantees for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric	33,264		2013
Indemnification for subsidiary reclamation/surety bonds	18,601		Ongoing
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Black Hills Utility Holdings	10,000		July 31, 2012
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply	7,500		June 30, 2012
	$	139,805

(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.

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



	December 31, 2011						December 31, 2010
	Interest Rate Swaps			De-designated Interest Rate Swaps			Interest Rate Swaps			De-designated Interest Rate Swaps
Notional *	$	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	5.0			2.0			6.0			1.0
Current derivative assets	$	—		$	—		$	—		$	—
Non-current derivative assets	$	—		$	—		$	—		$	—
Current derivative liabilities	$	3,207		$	75,295		$	3,363		$	53,980
Non-current derivative liabilities	$	10,672		$	20,696		$	7,360		$	—
Pre-tax accumulated other comprehensive (loss)	$	(13,879	)	$	—		$	(15,417	)	$	—
Pre-tax gain (loss)	$	—		$	(42,010	)	$	—		$	(15,193	)
Cash collateral receivable (payable) included in Consolidated Balance Sheets	$	—		$	—		$	—		$	—

________________________

Under the terms of the Black Hills Wyoming project financing, Black Hill 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 were amended 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. As of January 15, 2010, the mark to market liability associated with the two swaps with a notional value of $75.0 million was transferred from the Parent to Black Hills Wyoming. 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, 2011 market interest rates and balances, a loss of approximately $3.2 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.

Fair Value Measures

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 as of December 31 (in thousands):



Liabilities:	Level 1		Level 2		Level 3		Total
December 31, 2011
Interest rate swaps	$	—	$	109,869	$	—	$	109,869

December 31, 2010
Interest rate swaps	$	—	$	64,703	$	—	$	64,703

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



		December 31, 2011		December 31, 2010
	Balance Sheet Location	Fair Value of Liability Derivative
Derivatives designated as hedges:
Interest rate swaps	Derivative liability - current	$	3,207	$	3,363
Interest rate swaps	Derivative liability - non-current	10,672		7,360
		$	13,879	$	10,723

Derivatives not designated as hedges:
Interest rate swaps	Derivative liability - current	$	75,295	$	53,980
Interest rate swaps	Derivative liability - non-current	$	20,696	$	—
		$	95,991	$	53,980

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



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)
December 31, 2011
Interest rate swaps	$	(3,893	)	Interest expense	$	(3,950	)

December 31, 2010
Interest rate swaps	$	(5,352	)	Interest expense	$	(3,662	)

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



		December 31, 2011			December 31, 2010			December 31, 2009
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	$	(42,010	)	$	(15,193	)	$	55,653
Interest rate swaps - realized	Interest expense	(13,373		)	(13,312		)	(9,816		)
		$	(55,383	)	$	(28,505	)	$	45,837

(6) FAIR VALUE OF FINANCIAL INSTRUMENTS

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



	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash	$	3,114	$	3,114	$	219	$	219
Derivative financial instruments - liabilities	$	109,870	$	109,870	$	64,703	$	64,703
Notes payable	$	345,000	$	345,000	$	249,000	$	249,000
Long-term debt	$	774,959	$	851,241	$	674,930	$	743,738

Derivative Financial Instruments

These instruments are carried at fair value. Additional descriptions of these instruments are included in Note 5 of these Condensed Parent Company Financial Statements on Schedule I.

Notes Payable

The carrying amount approximates fair value due to their variable interest rates with short reset periods.

Long-Term Debt

The fair value of our long-term debt is estimated based on quoted market rates for our debt instruments, when available, or debt instruments having similar maturities and similar debt ratings.

(7) COMMON STOCK

Forward Equity Issuance

On November 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. We settled the equity forward instrument on November 1, 2011 by physically delivering the common shares in return for proceeds of $119.6 million.

(8) COMMITMENTS AND CONTINGENCIES

The Company is subject to various legal proceedings, claims and litigation which arise in the ordinary course of operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the financial position, results of operations or cash flows of the Company.

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, 2011

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

SCHEDULE II



BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009

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:
2011	$	2,295	$	—	$	3,042	$	5,369	$	(9,045	)	$	1,661
2010	$	3,683	$	—	$	1,898	$	2,196	$	(5,482	)	$	2,295
2009	$	3,916	$	—	$	4,078	$	3,229	$	(7,540	)	$	3,683

Business Description and Significant Accounting Policies Business Description (Policies)

12 Months Ended

Dec. 31, 2011

Accounting Policies [Abstract]

Segment Reporting, Policy [Policy Text Block]

Business Description

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

Use of Estimates, Policy [Policy Text Block]

Use of Estimates and Basis of Presentation

Consolidation, Policy [Policy Text Block]

Principles of Consolidation

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

Cash and Cash Equivalents and Restricted Cash

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

Trade and Other Accounts Receivable, Policy [Policy Text Block]

Accounts Receivable and Allowance for Doubtful Accounts

Revenue Recognition, Policy [Policy Text Block]

Revenue Recognition

Inventory, Policy [Policy Text Block]

Natural gas in storage at our regulated Gas Utilities primarily represents gas purchased for use by our 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

Industry Specific Policies, Oil and Gas [Policy Text Block]

Oil and Gas Operations

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

Asset Retirement Obligations, Policy [Policy Text Block]

Asset Retirement Obligations

Fair Value of Financial Instruments, Policy [Policy Text Block]

Fair Value Measurements

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

We utilize several different valuation techniques to measure the fair value of assets and liabilities.

•

Additional information is included in Note 4.

Derivatives, Policy [Policy Text Block]

Derivatives and Hedging Activities

Debt, Policy [Policy Text Block]

Deferred Financing Costs

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

Property, Plant and Equipment, Preproduction Design and Development Costs [Policy Text Block]

Development Costs

Legal Costs, Policy [Policy Text Block]

Legal Costs

Public Utilities, Policy [Policy Text Block]

Regulatory Accounting

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



	Maximum Recovery or	As of		As of
	Settlement Period (in years)	December 31, 2011		December 31, 2010
Regulatory assets
Deferred energy and fuel costs adjustments - current	1	$	33,526	$	30,298
Deferred gas cost adjustments and gas price derivatives	1	26,208		39,407
AFUDC	45	12,482		13,391
Employee benefit plans	13	120,708		83,144
Environmental	subject to approval	1,770		2,353
Asset retirement obligations	44	3,097		3,066
Bond issue cost	25	3,704		3,847
Renewable energy standard adjustment	5	20,095		14,254
Flow through accounting	35	12,191		7,491
Other regulatory assets	various	8,349		7,583
		$	242,130	$	204,834

Regulatory liabilities
Deferred energy and gas costs	1	$	16,961	$	1,200
Employee benefit plans	13	59,455		36,155
Cost of removal	44	42,257		39,638
Revenue subject to refund	1	443		1,016
Other regulatory liabilities	various	5,332		10,545
		$	124,448	$	88,554

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

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.

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

Income Tax, Policy [Policy Text Block]

Income Taxes

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.

Earnings Per Share, Policy [Policy Text Block]

Earnings per Share of Common Stock

Discontinued Operations, Policy [Policy Text Block]

Discontinued Operations

Business Description and Significant Accounting Policies Business Description (Tables)

12 Months Ended

Dec. 31, 2011

Receivables [Abstract]

Accounts Receivable and Allowance for Doubtful Accounts

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



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



2010	Accounts Receivable, Trade		Unbilled Revenues		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric	$	51,005	$	19,572	$	(708	)	$	69,869
Gas	41,970		40,376		(1,425		)	80,921
Oil and Gas	6,213		—		(161		)	6,052
Coal Mining	2,420		—		—			2,420
Power Generation	307		—		—			307
Corporate	12,247		—		—			12,247
Total	$	114,162	$	59,948	$	(2,294	)	$	171,816

Materials, Supplies and Fuel

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



	December 31, 2011		December 31, 2010
Materials and supplies	$	40,838	$	31,537
Fuel - Electric Utilities	8,201		9,687
Natural gas in storage - Gas Utilities	35,025		21,691
Total Materials, supplies and fuel	$	84,064	$	62,915

Goodwill

Changes to goodwill during the years ended December 31 relating primarily to taxes, were as follows (in thousands):



	Electric Utilities		Gas Utilities		Power Generation		Total
Ending balance at December 31, 2009	$	249,620	$	93,914	$	8,765	$	352,299
Additions (adjustments)	867		230		—		1,097
Ending balance at December 31, 2010	$	250,487	$	94,144	$	8,765	$	353,396
Additions (adjustments)	—		—		—		—
Ending balance at December 31, 2011	$	250,487	$	94,144	$	8,765	$	353,396

Intangible Assets



	2011			2010			2009
Intangible assets, net, beginning balance	$	4,069		$	4,309		$	4,884
Additions (adjustments)	—			—			(365		)
Amortization expense	(226		)	(240		)	(210		)
Intangible assets, net, ending balance	$	3,843		$	4,069		$	4,309

_________________


*	Amortization expense for existing intangible assets is expected to be $0.2 million, $0.2 million, $0.2 million, $0.2 million, and $0.2 million for 2012, 2013, 2014, 2015, and 2016, respectively.

Regulatory Assets and Liabilities

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



	Maximum Recovery or	As of		As of
	Settlement Period (in years)	December 31, 2011		December 31, 2010
Regulatory assets
Deferred energy and fuel costs adjustments - current	1	$	33,526	$	30,298
Deferred gas cost adjustments and gas price derivatives	1	26,208		39,407
AFUDC	45	12,482		13,391
Employee benefit plans	13	120,708		83,144
Environmental	subject to approval	1,770		2,353
Asset retirement obligations	44	3,097		3,066
Bond issue cost	25	3,704		3,847
Renewable energy standard adjustment	5	20,095		14,254
Flow through accounting	35	12,191		7,491
Other regulatory assets	various	8,349		7,583
		$	242,130	$	204,834

Regulatory liabilities
Deferred energy and gas costs	1	$	16,961	$	1,200
Employee benefit plans	13	59,455		36,155
Cost of removal	44	42,257		39,638
Revenue subject to refund	1	443		1,016
Other regulatory liabilities	various	5,332		10,545
		$	124,448	$	88,554

Earnings Per Share Reconciliation

A reconciliation of Income (loss) from continuing operations and basic and diluted share amounts is as follows (in thousands):



	December 31, 2011		December 31, 2010		December 31, 2009
Income (loss) from continuing operations	$	40,365	$	63,141	$	77,269

Weighted average shares - basic *	39,864		38,916		38,614
Dilutive effect of:
Stock options	19		14		—
Restricted stock	153		107		66
Equity forward instrument	—		29		—
Other dilutive effects	45		25		4
Weighted average shares - diluted	40,081		39,091		38,684

_______________


*	On November 1, 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):



	December 31, 2011	December 31, 2010	December 31, 2009
Options to purchase common stock	105	158	462
Restricted stock	17	1	3
Other	19	1	45
	141	160	510

Tabular disclosure of goodwill by reportable segment and in total. Disclosure details may include, but are not limited to, the carrying amount of goodwill, goodwill acquired during the year, goodwill impairment losses recognized, goodwill written-off due to the sale of a business unit, goodwill not yet allocated, and any other changes to goodwill.

Risk Management Activities Risk Management Activities (Tables)

12 Months Ended

Dec. 31, 2011

Interest rate swaps and related balances

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



	December 31, 2011						December 31, 2010
	Interest Rate Swaps			De-designated Interest Rate Swaps^(a)			Interest Rate Swaps			De-designated Interest Rate Swaps^(a)
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	5.0			2.0			6.0			1.0
Derivative assets, current	$	—		$	—		$	—		$	—
Derivative assets, non-current	$	—		$	—		$	—		$	—
Derivative liabilities, current	$	6,513		$	75,295		$	6,823		$	53,980
Derivative liabilities, non-current	$	20,363		$	20,696		$	14,976		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(26,876	)	$	—		$	(21,799	)	$	—
Pre-tax gain (loss) included in Consolidated Statements of Income	$	—		$	(42,010	)	$	—		$	(15,193	)
Cash collateral receivable (payable) included in Consolidated Balance Sheets	$	—		$	—		$	—		$	—

___________________


(a)	The maximum term in years reflects the amended mandatory early termination dates. If the mandatory early termination dates are not extended, the swaps will require cash settlement based on the swap value of the termination date. When extended, de-designated swaps totaling $100.0 million terminate in 7 years and de-designated swaps totaling $150.0 million terminate in 17 years.

Cash flow heding instruments included in financial statements

We had the following derivatives and related balances (dollars in thousands) as of:



	December 31, 2011					December 31, 2010
	Crude oil swaps/options			Natural gas swaps		Crude oil swaps/options			Natural gas swaps
Notional ^(a)	528,000			5,406,250		424,500			6,821,800
Maximum duration in years ^(b)	1.25			1.75		0.25			0.25
Derivative assets, current	$	729		$	8,010	$	248		$	7,675
Derivative assets, non-current	$	771		$	1,148	$	19		$	2,606
Derivative liabilities, current	$	2,559		$	—	$	3,814		$	—
Derivative liabilities, non-current	$	811		$	7	$	1,301		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(1,928	)	$	9,152	$	(5,313	)	$	10,281
Revenue ^(c)	$	58		$	—	$	465		$	—

________________________


(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 Utilities were as follows:



	December 31, 2011		December 31, 2010
Natural gas (notional amounts in MMBtu)	Notional	Latest Expiration (months)	Notional	Latest Expiration (months)
Natural gas futures purchased	14,310,000	84	6,670,000	15
Natural gas options purchased	1,720,000	3	1,730,000	3
Natural gas basis swaps purchased	7,160,000	60	—	—

Gains and losses recognized in Operating revenue

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



	December 31, 2011		December 31, 2010
Derivative assets, current	$	9,844	$	4,787
Derivative assets, non-current	$	52	$	—
Derivative liabilities, current	$	—	$	—
Derivative liabilities, non-current	$	7,156	$	1,620
Net unrealized gain (loss) included in Regulatory assets or Regulatory liabilities	$	17,556	$	8,030
Cash collateral receivable (payable) included in derivative assets/liabilities	$	19,416	$	10,355
Option premium included in Derivative assets, current	$	880	$	842

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.

Schedule of fair value assets and liabilities measured on recurring basis

Fair Value Measurements Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Instruments, Gain (Loss)

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 December 31, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	9,885		$	768	$	5	$	—	$	10,658
Commodity derivatives - Utilities	—		(9,520		)	—		—		19,416		9,896
Money market fund	6,005		—			—		—		—		6,005
Total	$	6,005	$	365		$	768	$	5	$	19,416	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	2,207		$	1,165	$	5	$	—	$	3,377
Commodity derivatives - Utilities	—		7,156			—		—		—		7,156
Interest rate swaps	—		122,867			—		—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	—	$	133,400



	As of December 31, 2010
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	10,281		$	266	$	—	$	—	$	10,547
Commodity derivatives - Utilities	—		(5,568		)	—		—		10,355		4,787
Money market fund	8,050		—			—		—		—		8,050
Total	$	8,050	$	4,713		$	266	$	—	$	10,355	$	23,384

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	5,115		$	—	$	—	$	—	$	5,115
Commodity derivatives - Utilities	—		1,620			—		—		—		1,620
Interest rate swaps	—		75,779			—		—		—		75,779
Total	$	—	$	82,514		$	—	$	—	$	—	$	82,514

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):



	Commodity Derivatives			Commodity Derivatives
	December 31, 2011			December 31, 2010
Balance at beginning of year	$	266		$	381
Unrealized losses	(1,318		)	(303		)
Unrealized gains	751			188
Purchases	—			—
Issuances	—			—
Settlements	(96		)	—
Transfers into level 3^(a)	—			—
Transfers out of level 3 ^(b)	—			—
Balance at year end	$	(397	)	$	266

Changes in unrealized (losses) gain relating to instruments still held as of year end	$	(101	)	$	(302	)

______________


(a)	Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.


(b)	Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Fair value and balance sheet classification of derivative instruments

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



		December 31, 2011					December 31, 2010
	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	$	8,739	$	—		$	7,923	$	—
Commodity derivatives	Derivative assets - non-current	1,919		—			2,625		—
Commodity derivatives	Derivative liabilities - current	—		2,559			—		3,814
Commodity derivatives	Derivative liabilities - non-current	—		818			—		1,301
Interest rate swaps	Derivative liabilities - current	—		6,513			—		6,822
Interest rate swaps	Derivative liabilities - non-current	—		20,363			—		14,976
		$	10,658	$	30,253		$	10,548	$	26,913

Derivatives not designated as hedges:
Commodity derivatives	Derivative assets - current	$	—	$	9,572		$	—	$	5,567
Commodity derivatives	Derivative assets - non-current	—		(52		)	—		—
Commodity derivatives	Derivative liabilities - current	—		—			—		—
Commodity derivatives	Derivative liabilities - non-current	—		7,156			—		1,621
Interest rate swaps	Derivative liabilities - current	—		75,295			—		53,980
Interest rate swaps	Derivative liabilities - non-current	—		20,696			—		—
		$	—	$	112,667		$	—	$	61,168

Cash Flow Hedging

Derivative Instruments, Gain (Loss)

Gains and losses recognized in income

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):



	December 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	)		$	—



	December 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			$	—



	December 31, 2009
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	$	12,818		Interest expense	$	(3,292	)		$	—
Commodity derivatives	(21,070		)	Revenue	23,102			Revenue	(1,394		)
Total	$	(8,252	)		$	19,810			$	(1,394	)

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 December 31 was as follows (in thousands):



		December 31, 2011			December 31, 2010			December 31, 2009
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	$	(42,010	)	$	(15,193	)	$	55,653
Interest rate swaps - realized	Interest expense	(13,373		)	(13,312		)	(9,816		)
		$	(55,383	)	$	(28,505	)	$	45,837

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, 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, issuances, 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.

Fair Value of Financial Instruments [Abstract]

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

12 Months Ended

Dec. 31, 2011

Fair value of financial instruments

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



	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	21,628	$	21,628	$	16,437	$	16,437
Restricted cash	$	9,254	$	9,254	$	4,260	$	4,260
Total derivative assets	$	20,554	$	20,554	$	15,335	$	15,335
Total derivative liabilities	$	133,400	$	133,400	$	82,514	$	82,514
Notes payable	$	345,000	$	345,000	$	249,000	$	249,000
Long-term debt, including current maturities	$	1,282,882	$	1,464,289	$	1,191,231	$	1,290,519

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 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.

Reference 2: 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 3: 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 4: 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 5: 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 6: 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 7: 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=6947722&loc=d3e13433-108611

Reference 8: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13467-108611

Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 825
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=6947722&loc=d3e13476-108611

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-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 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 820
-SubTopic 10
-Section 50
-Paragraph 2
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6925170&loc=d3e19207-110258

Reference 12: 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

Property, Plant and Equipment [Abstract]

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

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment [Table Text Block]

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



Utilities Group	2011			2010			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	$	707,498	49	$	679,165	47	25	80
Electric transmission	170,146		49	154,936		47	40	65
Electric distribution	580,699		45	543,498		43	15	65
Plant acquisition adjustment	4,870		32	4,870		32	32	32
General	136,304		22	103,455		20	3	60
Capital lease - plant in service *	260,874		20	—		—	20	20
Construction work in progress	288,760			234,985
Total electric plant	2,149,151			1,720,909
Less accumulated depreciation and amortization	385,840			357,774
Electric plant net of accumulated depreciation and amortization	$	1,763,311		$	1,363,135

_____________


*	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.



	2011			2010			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	$	35	37	$	35	37	37	37
Gas transmission	15,543		53	15,704		48	53	57
Gas distribution	442,114		46	406,914		45	41	56
General	56,869		19	68,315		19	16	22
Construction work in progress	8,813			11,392
Total gas plant	523,374			502,360
Less accumulated depreciation and amortization	52,249			47,292
Gas plant net of accumulated depreciation and amortization	$	471,125		$	455,068



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

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
Power Generation	135,051		930		35,074		100,907		36	2	40
	$	1,039,379	$	5,271	$	495,228	$	549,422



2010									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

Coal Mining	$	135,157	$	10,228	$	65,465	$	79,920	11	3	40
Oil and Gas	680,407		—		357,979		322,428		26	3	27
Power Generation	134,616		163,291		30,982		266,925		36	2	40
	$	950,180	$	173,519	$	454,426	$	669,273



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



2010									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	$	4,039	$	2,502	$	2,283	$	4,258	6	2	30

Jointly Owned Facilities Jointly Owned Facilities (Tables)

12 Months Ended

Dec. 31, 2011

Jointly Owned Facilities [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

At December 31, 2011, our interests in jointly-owned generating facilities and transmission systems were (dollars in thousands):



	Plant in Service		Construction Work in Progress		Accumulated Depreciation
Wyodak Plant	$	109,007	$	718	$	46,104
Transmission Tie	19,648		—		4,061
Wygen I	104,854		880		23,046
Wygen III	129,791		249		5,328
	$	363,300	$	1,847	$	78,539

Long-Term Debt Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-term Debt, Unclassified [Abstract]

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

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



	Due Date	Interest Rate	2011			2010
Corporate
Senior unsecured notes due 2013	May 15, 2013	6.5%	$	225,000		$	225,000
Unamortized discount on notes due 2013			(41		)	(70		)
Senior unsecured notes due 2014	May 15, 2014	9.0%	250,000			250,000
Senior unsecured notes due 2020	July 15, 2020	5.88%	200,000			200,000
Long-term term loan ^(a)	September 30, 2013	1.69%	100,000			—
Total Corporate Debt			774,959			674,930

Electric Utilities
First Mortgage Bonds due 2032	August 15, 2032	7.23%	75,000			75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13%	180,000			180,000
Unamortized discount on First Mortgage Bonds due 2039			(115		)	(119		)
Pollution control revenue bonds due 2014	October 1, 2014	4.80%	6,450			6,450
Pollution control revenue bonds due 2024	October 1, 2024	5.35%	12,200			12,200
First Mortgage Bonds due 2037	November 20, 2037	6.67%	110,000			110,000
Industrial development revenue bonds due 2021, variable rate ^(a)	September 1, 2021	0.14%	7,000			7,000
Industrial development revenue bonds due 2027, variable rate ^(a)	March 1, 2027	0.14%	10,000			10,000
Series 94A Debt ^(a)	June 1, 2024	3.00%	2,855			2,855
Other long-term debt	May 12, 2012	13.66%	72			234
Total Electric Utilities			403,462			403,620

Power Generation
Black Hills Wyoming project financing, variable rate ^(a)	December 9, 2016	3.66%	104,461			112,681

Total long-term debt			1,282,882			1,191,231
Less current maturities			2,473			5,181
Net long-term debt			$	1,280,409		$	1,186,050

_______________


(a)	Variable interest rates, rates presented are as of December 31, 2011.

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):



2012	$	2,473
2013	$	328,973
2014	$	262,473
2015	$	6,964
2016	$	85,101
Thereafter	$	597,054

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 on Balance Sheet at		Amortization Expense for the years ended December 31,
	December 31, 2011		2011		2010		2009
Senior unsecured notes due 2013	$	309	$	218	$	218	$	218
Senior unsecured notes due 2014	$	1,097	$	462	$	462	$	289
Senior unsecured notes due 2020	$	1,428	$	167	$	77	$	—
First mortgage bonds due 2023	$	684	$	33	$	33	$	33
First mortgage bonds due 2039	$	2,113	$	76	$	76	$	12
First mortgage bonds due 2037	$	797	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016	$	4,214	$	1,012	$	1,036	$	60
Other	$	816	$	70	$	74	$	67

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
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 835
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-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

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

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Schedule of Short-term Debt

Notes Payable Notes Payable (Tables)

12 Months Ended

Dec. 31, 2011

Line of Credit Facility

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



	As of December 31, 2011				As of December 31, 2010
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	195,000	$	43,700	$	149,000	$	46,865
Term Loan 2011	—		—		100,000		—
Term Loan 2012	150,000		—		—		—
Total	$	345,000	$	43,700	$	249,000	$	46,865

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 on Balance Sheet at		Amortization Expense for the years ended December 31,
	December 31, 2011		2011		2010		2009
Senior unsecured notes due 2013	$	309	$	218	$	218	$	218
Senior unsecured notes due 2014	$	1,097	$	462	$	462	$	289
Senior unsecured notes due 2020	$	1,428	$	167	$	77	$	—
First mortgage bonds due 2023	$	684	$	33	$	33	$	33
First mortgage bonds due 2039	$	2,113	$	76	$	76	$	12
First mortgage bonds due 2037	$	797	$	31	$	31	$	31
Black Hills Wyoming project financing due 2016	$	4,214	$	1,012	$	1,036	$	60
Other	$	816	$	70	$	74	$	67

Credit Facility Covenants



	Actual			Covenant Requirement
Consolidated net worth	$	1,209,336		$	884,131
Recourse leverage ratio	58.5		%	65.0		%

Revolving Credit Facility, Existing [Member]

Line of Credit Facility

Deferred Financing Costs [Table Text Block]



	Deferred Financing Costs Remaining on Balance Sheet as of		Amortization Expense for the years ended December 31,
	December 31, 2011		2011		2010		2009
Revolving Credit Facility	$	1,497	$	1,891	$	1,340	$	495

Asset Retirement Obligations Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [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):



	12/31/10		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates *			12/31/11
Oil and Gas	$	21,663	$	43	$	(627	)	$	1,343	$	—		$	22,422
Coal Mining	17,560		—		—			1,123		(1,525		)	17,158
Electric Utilities	3,039		—		—			25		—			3,064
Gas Utilities	255		—		—			15		—			270
Total	$	42,517	$	43	$	(627	)	$	2,506	$	(1,525	)	$	42,914



	12/31/09		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates *			12/31/10
Oil and Gas	$	21,233	$	570	$	(2,078	)	$	1,280	$	658		$	21,663
Coal Mining	15,285		18,094		(15,207		)	1,246		(1,858		)	17,560
Electric Utilities	2,904		—		—			135		—			3,039
Gas Utilities	241		—		—			14		—			255
Total	$	39,663	$	18,664	$	(17,285	)	$	2,675	$	(1,200	)	$	42,517

_____________________


*	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, 2011

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):



	2011		2010		2009
Stock-based compensation expense	$	5,643	$	5,637	$	3,908

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

A summary of the status of the stock options at December 31, 2011 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	235		$	32.92
Granted ^(a)	99		32.04
Forfeited/canceled	(6	)	—
Expired	(31	)	53.51
Exercised	(33	)	30.32
Balance at end of period	264		$	30.50	4.5	$	859

Exercisable at end of period	165		$	29.57

______________________


(a)	The grant date fair value of the 2011 awards was $5.80 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.6% risk free interest rate, 29.0% expected price volatility, 4.6% expected dividend yield and a 7 year expected life.

The table below provides details of our option plans (in thousands):



	2011		2010		2009
Summary of Stock Options
Unrecognized compensation expense	$	479	$	—	$	—
Intrinsic value of options exercised^(a)	$	94	$	234	$	255
Net cash received from exercise of options	$	1,009	$	1,034	$	1,740
Tax benefit realized from exercise of shares ^(b)	$	33	$	82	$	89

_____________________


(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.

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 December 31, 2011 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	270		$	27.78
Granted	139		30.33
Vested	(113	)	28.43
Forfeited	(18	)	27.36
Restricted Stock and Restricted Stock Units balance at end of period	278		$	28.82

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 December 31 was as follows:



	Weighted-Average Grant Date Fair Value		Total Fair Value of Shares Vested
			(in thousands)
2011	$	30.33	$	3,211
2010	$	27.30	$	2,212
2009	$	26.76	$	1,799

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

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



Grant Date	Performance Period	Target Grant of Shares
January 1, 2009	January 1, 2009 - December 31, 2011	73
January 1, 2010	January 1, 2010 - December 31, 2012	71
January 1, 2011	January 1, 2011 - December 31, 2013	67

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



	Equity Portion				Liability Portion
	Shares		Weighted-Average Grant Date Fair Value		Shares		Weighted-Average December 31, 2011 Fair Value
	(in thousands)				(in thousands)

Performance Shares balance at beginning of period	87		$	29.47	87
Granted	34		25.92		34
Forfeited	(3	)	25.77		(3	)
Vested	(12	)	46.00		(12	)
Performance Shares balance at end of period	106		$	26.47	106		$	20.89



	Weighted Average Grant Date Fair Value
December 31, 2011	$	25.92
December 31, 2010	$	24.26
December 31, 2009	$	29.20

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



Performance Period	Year of Payment	Stock Issued	Cash Paid		Total Intrinsic Value
January 1, 2008 to December 31, 2010	2011	—	$	—	$	—
January 1, 2007 to December 31, 2009	2010	—	$	—	$	—
January 1, 2006 to December 31, 2008	2009	—	$	—	$	—

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

A summary of the Dividend Reinvestment and Stock Purchase Plan was as follows (shares in thousands):



	2011		2010
Shares Issued	103		106

Weighted Average Price	$	31.23	$	29.57

Unissued Shares Available at December 31	453		190

Tabular disclosure of components of a stock option or other award plan under which equity-based compensation is awarded to employees, typically comprised of the amount of unearned compensation (deferred compensation cost), compensation expense, and changes in the quantity and fair value of the shares (or other type of equity) granted, exercised, forfeited, and issued and outstanding pertaining to that plan. Disclosure may also include nature and general terms of such arrangements that existed during the period and potential effects of those arrangements on shareholders, effect of compensation cost arising from equity-based payment arrangements on the income statement, method of estimating the fair value of the goods or services received, or the fair value of the equity instruments granted, during the period, cash flow effects resulting from equity-based payment arrangements and, for registrants that accelerate vesting of out of the money share options, reasons for the decision to accelerate.

Tabular disclosure of the allocation of equity-based compensation costs to a given line item on the balance sheet and income statement for the period. This may include the reporting line for the costs and the amount capitalized and expensed.

Operating Leases of Lessor Disclosure [Text Block]

Operating Leases Operating Leases (Tables)

12 Months Ended

Dec. 31, 2011

Operating Leases [Abstract]



	2011		2010		2009
Rent expense	$	6,125	$	4,219	$	3,939

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):



2012	$	2,799
2013	2,398
2014	2,376
2015	1,912
2016	1,403
Thereafter	3,610
	$	14,498

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

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

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



	2011			2010			2009
Current:
Current federal income tax expense (benefit)	$	(14,539	)	$	678		$	(12,351	)
Current state income tax expense (benefit)	(837		)	4,137			(408		)
	(15,376		)	4,815			(12,759		)
Deferred:
Deferred federal income tax expense (benefit)	30,876			20,186			45,912
Deferred state income tax expense (benefit)	2,970			(2,495		)	66
Tax credit amortization expense (benefit)	(246		)	(337		)	(368		)
	33,600			17,354			45,610

Total income tax expense (benefit)	$	18,224		$	22,169		$	32,851

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 December 31, were as follows (in thousands):



	2011			2010
Deferred tax assets, current:
Asset valuation reserves	$	2,605		$	1,448
Mining development and oil exploration	614			594
Unbilled revenue	—			—
Employee benefits	8,175			3,899
Items of other comprehensive income (loss)	2,858			3,076
Derivative fair value adjustments	33,824			19,304
Deferred costs	97			342
Other deferred tax assets, current	4,493			5,607
Total deferred tax assets, current	52,666			34,270

Deferred tax liabilities, current:
Asset valuation reserves	—			(312		)
Prepaid expenses	(2,442		)	(2,431		)
Derivative fair value adjustments	(362		)	(327		)
Items of other comprehensive income (loss)	(3,035		)	(2,754		)
Deferred costs	(6,508		)	(4,621		)
Other deferred tax liabilities, current	(3,117		)	(3,161		)
Total deferred tax liabilities, current	(15,464		)	(13,606		)

Net deferred tax asset, current	$	37,202		$	20,664

Deferred tax assets, non-current:
Employee benefits	$	14,313		$	11,533
Regulatory liabilities	40,642			23,910
Deferred revenue	225			273
Deferred costs	—			—
State net operating loss (net of valuation allowance)	11,538			9,507
Items of other comprehensive income	33,540			22,306
Foreign tax credit carryover	2,801			3,352
Net operating loss	195,834			63,779
Asset impairment	47,033			48,092
Derivative fair value adjustment	5,275			3,038
Other deferred tax assets, non-current	9,453			11,076
Total deferred tax assets, non-current	360,654			196,866

Deferred tax liabilities, non-current:
Accelerated depreciation, amortization and other plant-related differences	(508,261		)	(314,513		)
Regulatory assets	(23,498		)	(16,050		)
Mining development and oil exploration	(94,334		)	(99,709		)
Deferred costs	(9,155		)	(17,615		)
Derivative fair value adjustments	—			—
Items of other comprehensive income	(2,054		)	(4,402		)
State deferred tax liability	(14,611		)	(11,477		)
Other deferred tax liabilities, non-current	(9,729		)	(8,942		)
Total deferred tax liabilities, non-current	(661,642		)	(472,708		)

Net deferred tax liability, net, non-current	$	(300,988	)	$	(275,842	)

Net deferred tax liability	$	(263,786	)	$	(255,178	)

Reconciliation of Deferred Tax Liability to Deferred Tax Expense [Table Text Block]

The following table reconciles the change in the net deferred income tax liability from December 31, 2010 to December 31, 2011 to deferred income tax expense (in thousands):



	2011			2010
Net increase (decrease) in net deferred income tax liability for the year	$	8,608		$	414
Deferred taxes associated with other comprehensive loss (income)	2,259			1,915
Deferred taxes related to net operating loss from acquisition	—			(312		)
Deferred taxes related to regulatory assets and liabilities	22,962			25,511
Deferred taxes related to acquisition	—			(784		)
Deferred taxes associated with property basis differences	(14		)	(10,121		)
Other net deferred income tax	(215		)	731

Deferred income tax expense for the period	$	33,600		$	17,354

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

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



	2011		2010		2009
Federal statutory rate	35.0	%	35.0	%	35.0	%
State income tax (net of federal tax effect)	1.8		1.1		(0.3	)
Amortization of excess deferred and investment tax credits	(0.5	)	(0.4	)	(0.3	)
Percentage depletion in excess of cost	(2.5	)	(1.7	)	(0.8	)
Equity AFUDC	(0.5	)	(1.0	)	(1.7	)
Tax credits	—		(3.2	)	—
Accounting for uncertain tax positions adjustment	2.8		1.2		(2.1	)
Flow-through adjustments *	(4.5	)	(4.6	)	—
Other tax differences	(0.5	)	(0.4	)	(0.3	)
	31.1	%	26.0	%	29.5	%

_________________________

Summary of Operating Loss Carryforwards [Table Text Block]

At December 31, 2011, we have federal and state NOL carryforwards of $534.8 million and $413.6 million, respectively, which will expire at various dates as follows (in thousands):



Expiration Years	Net Operating Loss Carryforward
2014-2019	$	9,306
2020-2025	$	48,229
2026-2031	$	890,861

Summary of Deferred Tax Liability Not Recognized [Table Text Block]



	Changes in Uncertain Tax Positions
Beginning balance at January 1, 2009	$	120,022
Additions for prior year tax positions	5,752
Reductions for prior year tax positions	(18,686		)
Additions for current year tax positions	—
Settlements	—

Ending balance at December 31, 2009	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 December 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 December 31, 2011	$	49,327

Summary of Income Tax Contingencies [Table Text Block]



	2011		2010		2009
Uncertain tax positions	$	49,327	$	50,135	$	107,088
Income tax refund receivable related to uncertain tax positions above	—		—		(59,136		)

Net liability for uncertain tax positions	$	49,327	$	50,135	$	47,952

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



	2011		2010		2009
Interest expense (income) included in Income tax (expense) benefit	$	1,400	$	2,300	$	1,200

Summary of Other Tax Carryforwards [Table Text Block]



Foreign Tax Credit Carryforward		Expiration Year
$	26	2014
$	694	2015
$	24	2016
$	1,301	2017
$	214	2020
$	542	2021

Comprehensive Income Comprehensive Income (Loss) (Tables)

12 Months Ended

Dec. 31, 2011

Other Comprehensive (Loss) Income [Abstract]

Schedule of Comprehensive Income (Loss) [Table Text Block]

The following table displays the related tax effects allocated to each component of Other comprehensive income (loss) for the years ended December 31 (in thousands):



2011	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Benefit plan liability adjustments - net gains (losses)	$	(11,744	)	$	4,135		$	(7,609	)
Benefit plan liability adjustments - prior service (costs)	(501		)	176			(325		)
Fair value adjustment of derivatives designated as cash flow hedges	(4,539		)	1,708			(2,831		)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	2,177			(709		)	1,468
Other comprehensive income (loss)	$	(14,607	)	$	5,310		$	(9,297	)



2010	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Benefit plan liability adjustments - net gains (losses)	$	(1,981	)	$	674		$	(1,307	)
Benefit plan liability adjustments - prior service (costs)	(325		)	111			(214		)
Fair value adjustment of derivatives designated as cash flow hedges	1,972			(636		)	1,336
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	(6,730		)	2,498			(4,232		)
Other comprehensive income (loss)	$	(7,064	)	$	2,647		$	(4,417	)



2009	Pre-tax Amount			Tax (Expense) Benefit Plans			Net-of-tax Amount
Benefit plan liability adjustments - net gains (losses)	$	(2,313	)	$	812		$	(1,501	)
Benefit plan liability adjustments - prior service (costs)	9,202			(3,231		)	5,971
Benefit plan liability adjustments - transition obligations	33			(12		)	21
Fair value adjustment of derivatives designated as cash flow hedges	(27,442		)	9,961			(17,481		)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	19,810			(7,201		)	12,609
Other comprehensive income (loss)	$	(710	)	$	329		$	(381	)

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			Amount from Equity-method Investees			Total
As of December 31, 2009	$	(9,462	)	$	(9,636	)	$	(66	)	$	(19,164	)

Other comprehensive income (loss)	(2,975		)	(1,506		)	64			(4,417		)

As of December 31, 2010	$	(12,437	)	$	(11,142	)	$	(2	)	$	(23,581	)

Other comprehensive income (loss)	(1,363		)	(7,934		)	—			(9,297		)

As of December 31, 2011	$	(13,800	)	$	(19,076	)	$	(2	)	$	(32,878	)

Supplemental Cash Flow Information Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Disclosure of Cash Flow Information



Years ended December 31,	2011			2010			2009
	(in thousands)
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities	$	37,529		$	48,879		$	24,571
Capitalized asset retirement costs	$	1,525		$	1,858		$	6,027

Refunding bond issuance — Industrial Development Revenue Bonds	$	—		$	—		$	17,000

Cash (paid) refunded during the period for-
Interest (net of amount capitalized)	$	(103,110	)	$	(101,947	)	$	(69,317	)
Income taxes, net	$	9,854		$	9,384		$	17,117

Business Segments Business Segments Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment Reporting Information, Additional Information [Abstract]

Segment information included in Condensed Consolidated Balance Sheets

Detail for our segments as of and for the year ended December 31 was as follows (in thousands):



	2011		2010
Total assets
Utilities:
Electric Utilities ^(a)	$	2,254,914	$	1,834,019
Gas Utilities	746,444		722,287
Non-regulated Energy:
Oil and Gas	425,970		349,991
Power Generation^(a)	129,121		293,334
Coal Mining	88,704		96,962
Corporate	141,079		100,681
Discontinued Operations	340,851		314,235
Total assets	$	4,127,083	$	3,711,509

__________________


(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, assets previously recorded at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.



	2011		2010
Capital expenditures and asset acquisitions
Utilities:
Electric Utilities	$	173,078	$	232,466
Gas Utilities	43,954		51,363
Non-regulated Energy:
Oil and Gas	89,672		40,345
Power Generation	98,927		148,191
Coal Mining	10,438		17,053
Corporate	13,279		7,182
Total capital expenditures and asset acquisitions of continuing operations^(a)	429,348		496,600
Total capital expenditures of discontinued operations	2,359		390
Total capital expenditures and asset acquisitions	$	431,707	$	496,990

_________________


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



	2011		2010
Property, plant and equipment
Utilities:
Electric Utilities ^(a)	$	2,149,151	$	1,720,909
Gas Utilities	523,374		502,360
Non-regulated Energy:
Oil and Gas	763,645		680,407
Power Generation ^(a)	135,981		297,907
Coal Mining	145,024		145,385
Corporate	6,841		6,541
Total property, plant and equipment	$	3,724,016	$	3,353,509

_______________


(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, 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 December 31, 2011	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Intercompany Eliminations			Total
	(in millions)
Revenue	$	600,935		$	554,584		$	4,059		$	32,802		$	79,808		$	—		$	—		$	1,272,188
Intercompany 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 a gain on sale of assets to a related party which was eliminated in consolidation.



	Consolidating Income Statement
Year ended December 31, 2010	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Intercompany Eliminations			Total
	(in millions)
Revenue ^(a)	$	554,617		$	550,707		$	4,297		$	31,285		$	74,164		$	—		$	—		$	1,215,070
Intercompany revenue ^(a)	15,397			—			26,052			26,557			—			140,756			(204,141		)	4,621
Fuel, purchased power and cost of gas sold ^(a)	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 ^(b)	(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)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).


(b)	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).



	Consolidating Income Statement
Year ended December 31, 2009	Electric Utilities			Gas Utilities			Power Generation			Coal Mining			Oil and Gas			Corporate			Intercompany Eliminations			Total
	(in millions)
Revenue ^(a)	$	511,326		$	580,312		$	4,445		$	31,459		$	70,684		$	—		$	—		$	1,198,226
Intercompany revenue^(a)	9,439			—			26,130			27,031			—			97,010			(159,124		)	486
Fuel, purchased power and cost of gas sold ^(a)	281,009			371,716			—			—			—			1			(57,486		)	595,240
Gross margin	239,756			208,596			30,575			58,490			70,684			97,009			(101,638		)	603,472

Operations and maintenance	125,150			123,296			12,631			40,312			40,224			95,184			(95,748		)	341,049
Gain on sale of operating assets ^(b)	—			—			(25,971		)	—			—			—			—			(25,971		)
Depreciation, depletion and amortization	43,638			30,090			3,860			13,123			29,680			6,933			(6,386		)	120,938
Impairment of long-lived assets ^(c)	—			—			—			—			43,301			—			—			43,301
Operating income	70,968			55,210			40,055			5,055			(42,521		)	(5,108		)	496			124,155

Interest expense	(34,830		)	(17,364		)	(11,244		)	(24		)	(4,683		)	(47,522		)	32,414			(83,253		)
Unrealized (loss) gain on interest rate swaps, net	—			—			—			—			—			55,653			—			55,653
Interest income	1,818			264			1,856			1,476			10			27,531			(32,032		)	923
Other income (expense), net	7,869			(285		)	1,091			3,475			350			12,201			(12,059		)	12,642
Income tax benefit (expense)	(13,126		)	(13,453		)	(11,097		)	(3,234		)	21,016			(12,957		)	—			(32,851		)
Income (loss) from continuing operations	$	32,699		$	24,372		$	20,661		$	6,748		$	(25,828	)	$	29,798		$	(11,181	)	$	77,269

______________________


(a)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).


(b)	Includes a gain on sale to MEAN of an ownership interest in the Wygen I power generation facility (see Note 22).


(c)	As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets (see Note 12).

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, 2011

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 December 31 were as follows:



	2011		2010
Equity	64	%	65	%
Real estate	3		3
Fixed income	32		31
Cash	1		1
Total	100	%	100	%

Schedule of Defined Contribution Plans Contributions [Table Text Block]

Contributions to the Healthcare Plans and the Supplemental Plans are made in the form of benefit payments. Contributions to our employee benefit plans were as follows (in thousands):



	2011		2010
Defined Benefit Plans
Defined Benefit Pension Plans	$	11,050	$	30,015
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	4,963	$	5,198
Supplemental Non-Qualified Defined Benefit Plans	$	956	$	894



	2011		2010
Defined Contribution Plan
Company Retirement Contribution	$	2,440	$	2,022
Matching contributions - Defined Contribution Plans	$	8,916	$	7,900

Expected Future Contributions Defined Benefit Plans [Table Text Block]

We expect to make contributions to our employee benefit plans as follows (in thousands):



	2012
Defined Benefit Plans
Defined Benefit Pension Plans	$	12,483
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	4,250
Supplemental Non-Qualified Defined Benefit Plans	$	1,110

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, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):



	As of December 31, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	9,885		$	768	$	5	$	—	$	10,658
Commodity derivatives - Utilities	—		(9,520		)	—		—		19,416		9,896
Money market fund	6,005		—			—		—		—		6,005
Total	$	6,005	$	365		$	768	$	5	$	19,416	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	2,207		$	1,165	$	5	$	—	$	3,377
Commodity derivatives - Utilities	—		7,156			—		—		—		7,156
Interest rate swaps	—		122,867			—		—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	—	$	133,400



	As of December 31, 2010
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	10,281		$	266	$	—	$	—	$	10,547
Commodity derivatives - Utilities	—		(5,568		)	—		—		10,355		4,787
Money market fund	8,050		—			—		—		—		8,050
Total	$	8,050	$	4,713		$	266	$	—	$	10,355	$	23,384

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	5,115		$	—	$	—	$	—	$	5,115
Commodity derivatives - Utilities	—		1,620			—		—		—		1,620
Interest rate swaps	—		75,779			—		—		—		75,779
Total	$	—	$	82,514		$	—	$	—	$	—	$	82,514

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):



	Commodity Derivatives			Commodity Derivatives
	December 31, 2011			December 31, 2010
Balance at beginning of year	$	266		$	381
Unrealized losses	(1,318		)	(303		)
Unrealized gains	751			188
Purchases	—			—
Issuances	—			—
Settlements	(96		)	—
Transfers into level 3^(a)	—			—
Transfers out of level 3 ^(b)	—			—
Balance at year end	$	(397	)	$	266

Changes in unrealized (losses) gain relating to instruments still held as of year end	$	(101	)	$	(302	)

______________


(a)	Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.


(b)	Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

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



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011			2010			2011			2010			2011			2010
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	280,623		$	256,400		$	24,725		$	21,611		$	46,304		$	46,396

Service cost	5,421			6,131			1,028			685			1,498			1,509
Interest cost	14,929			15,091			1,298			1,284			2,168			2,446
Actuarial (gain) loss	36,543			13,663			4,128			2,039			3,017			961
Amendments	—			261			—			—			(160		)	(2,239		)
Benefits paid	(11,178		)	(9,949		)	(956		)	(894		)	(4,963		)	(5,198		)
Plan curtailment reduction	(394		)	(974		)	—			—			—			—
Medicare Part D accrued	—			—			—			—			188			559
Plan participants' contributions	—			—			—			—			2,089			1,870

Projected benefit obligation at end of year	$	325,944		$	280,623		$	30,223		$	24,725		$	50,141		$	46,304

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)
	2011			2010			2011		2010		2011			2010
Beginning market value of plan assets	$	220,164		$	176,503		$	—	$	—	$	4,564		$	4,717
Investment income	1,686			23,595			—		—		1			1
Employer contributions	11,050			30,015			—		—		2,087			2,493
Retiree contributions	—			—			—		—		1,366			1,205
Benefits paid	(11,178		)	(9,949		)	—		—		(3,713		)	(3,847		)
Plan administrative expenses	—			—			—		—		14			(5		)

Ending market value of plan assets	$	221,722		$	220,164		$	—	$	—	$	4,319		$	4,564

____________________

(a) Asset of VEBA

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

Amounts recognized in the Consolidated Balance Sheet consist of (in thousands):



	Defined Benefit Pension Plans				Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011		2010		2011		2010
Regulatory asset	$	93,423	$	54,202	$	—	$	—	$	9,161	$	7,896
Current liability	$	—	$	—	$	1,116	$	943	$	3,522	$	2,999
Non-current liability	$	104,214	$	60,451	$	30,953	$	23,782	$	42,313	$	38,561
Regulatory liability	$	—	$	—	$	—	$	—	$	590	$	1,050

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

Accumulated Benefit Obligation



(in thousands)	Defined Benefit Pension Plans				Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011		2010		2011		2010

Accumulated benefit obligation - Black Hills Corporation	$	106,800	$	90,301	$	23,023	$	19,153	$	14,313	$	12,101
Accumulated benefit obligation - Black Hills Energy	184,345		160,217		446		454		25,842		25,080
Accumulated benefit obligation - Cheyenne Light	5,731		4,462		—		—		9,986		9,121

	$	296,876	$	254,980	$	23,469	$	19,607	$	50,141	$	46,302

Components of net periodic benefit cost

Components of Net Periodic Expense



(in thousands)	Defined Benefit Pension Plans									Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2011			2010			2009			2011		2010		2009		2011			2010			2009
Service cost	$	5,421		$	6,131		$	7,587		$	1,028	$	685	$	469	$	1,498		$	1,509		$	1,060
Interest cost	14,929			15,091			14,715			1,298		1,284		1,376		2,168			2,446			2,202
Expected return on assets	(16,955		)	(14,493		)	(14,281		)	—		—		—		(164		)	(208		)	(226		)
Amortization of prior service cost	99			99			127			3		3		1		(479		)	(309		)	(23		)
Amortization of transition obligation	—			—			—			—		—		—		—			—			60
Recognized net actuarial loss (gain)	4,540			3,126			2,720			510		285		589		677			636			(27		)
Curtailment expense	13			57			322			—		—		—		—			—			—
Net periodic expense	$	8,047		$	10,011		$	11,190		$	2,839	$	2,257	$	2,435	$	3,700		$	4,074		$	3,046

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



	Defined Benefit Pension Plans				Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2011		2010		2011		2010		2011			2010
Net (gain) loss	$	11,472	$	6,545	$	6,894	$	4,544	$	2,556		$	2,172
Prior service cost (gain)	98		121		12		14		(1,956		)	(2,276		)
Transition obligation	—		—		—		—		—			—
Total accumulated other comprehensive (income) loss	$	11,570	$	6,666	$	6,906	$	4,558	$	600		$	(104	)

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



	Defined Benefit Pension Plans		Supplemental Nonqualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Plans
Net loss	$	6,560	$	525	$	577
Prior service cost	58		2		(325		)
Transition obligation	—		—		—
Total net periodic benefit cost expected to be recognized during calendar year 2012	$	6,618	$	527	$	252

Schedule of Assumptions Used [Table Text Block]

Assumptions



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
Weighted-average assumptions used to determine benefit obligations:	2011		2010		2009		2011		2010		2009		2011		2010		2009

Discount rate	4.65	%	5.48	%	6.03	%	4.30	%	4.95	%	5.58	%	4.42	%	5.03	%	5.68	%
Rate of increase in compensation levels	3.77	%	3.79	%	4.20	%	5.00	%	5.00	%	5.00	%	N/A		N/A		N/A



	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2011		2010		2009		2011		2010		2009		2011		2010		2009

Discount rate:
Black Hills Corporation	5.50	%	6.05	%	6.25	%	5.00	%	6.10	%	6.20	%	5.00	%	5.90	%	6.10	%
Black Hills Energy	5.40	%	6.00	%	6.25	%	4.40	%	5.05	%	5.00	%	4.60	%	5.15	%	6.10	%
Cheyenne Light	5.55	%	6.05	%	6.20	%	N/A		N/A		N/A		5.50	%	6.00	%	6.10	%

Expected long-term rate of return on assets*	7.75	%	8.00	%	8.50	%	N/A		N/A		N/A		4.00	%	5.00	%	5.00	%
Rate of increase in compensation levels	3.79	%	4.20	%	4.20	%	5.00	%	5.00	%	5.00	%	NA		NA		N/A

_____________________________


*	The expected rate of return on plan assets changed to 7.25% for the calculation of the 2012 net periodic pension cost.

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 December 31, 2011 Accumulated Postretirement Benefit Obligation			Impact on 2011 Service and Interest Cost
Increase 1%	$	2,720		$	184
Decrease 1%	$	(2,272	)	$	(150	)

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 Nonqualified Defined Benefit Retirement Plan		Non-Pension Defined Benefit Postretirement Plans
2012	$	12,484	$	1,110	$	4,250
2013	$	13,181	$	1,090	$	4,380
2014	$	13,953	$	1,280	$	4,320
2015	$	14,823	$	1,290	$	4,170
2016	$	15,694	$	1,370	$	4,250
2017-2021	$	93,852	$	7,160	$	21,950

Pension Plans, Defined Benefit [Member]

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	December 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 Pension Plans	December 31, 2010
	Level 1		Level 2		Level 3		Total
Money Market Fund	$	—	$	—	$	—	$	—
Registered Investment Companies - Equity	27,070		—		—		27,070
Registered Investment Companies - Fixed Income	27,544		—		—		27,544
103-12 Investment Entities - Equity	—		11,246		—		11,246
Common Collective Trust - Money Market	—		174		—		174
Common Collective Trust - Equity	—		106,786		—		106,786
Common Collective Trust - Fixed Income	—		39,121		—		39,121
Common Collective Trust - Real Estate	—		—		6,126		6,126
Insurance Contracts	—		2,097		—		2,097
Total investments measured at fair value	$	54,614	$	159,424	$	6,126	$	220,164

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

The following table sets forth a summary of changes in the fair value of the Defined Benefit Pension Plan's level 3 assets for the period ended December 31 (in thousands):



	2011		2010
Balance, beginning of period	$	6,126	$	5,844
Unrealized gain (loss)	917		282
Balance, end of period	$	7,043	$	6,126

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	December 31, 2011
	Level 1		Level 2		Level 3		Total
Common Collective Trust	$	—	$	4,319	$	—	$	4,319
Total investments measured at fair value	$	—	$	4,319	$	—	$	4,319



Non-pension Defined Benefit Postretirement Plan	December 31, 2010
	Level 1		Level 2		Level 3		Total
Common Collective Trust	$	—	$	4,564	$	—	$	4,564
Total investments measured at fair value	$	—	$	4,564	$	—	$	4,564

Commitments and Contingencies Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Long-term Purchase Commitment [Table Text Block]

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



	2011		2010		2009
PPA with PacifiCorp	$	12,515	$	12,936	$	11,862
PPA with PSCo^(a)	$	97,988	$	110,575	$	97,899
Transmission services agreement with PacifiCorp	$	1,215	$	1,215	$	1,215
PPA with Happy Jack	$	1,955	$	2,815	$	2,078
PPA with Silver Sage	$	3,281	$	1,723	$	713

_______________________


(a)	This PPA with PSCo expired on December 31, 2011 and was replaced with the facilities constructed by Colorado Electric at our Pueblo Airport Generation site and the facilities constructed by Black Hills Colorado IPP to support a new PPA with Colorado Electric.

Schedule of Asset Retirement Obligaiton Asset [Table Text Block]

The amount of depreciation expense for the years ended December 31 was as follows (in thousands):



	2011		2010		2009
Depreciation expense on capitalized asset retirement costs	$	5,212	$	6,519	$	1,993

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):



2012	$	199,811
2013	$	123,600
2014	$	73,145
2015	$	70,140
2016	$	46,568
Thereafter	$	202,779

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, 2011

20. Guarantees [Abstract]

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



	Maximum Exposure at
Nature of Guarantee	December 31, 2011		Year Expiring
Guarantees of payment obligations arising from commodity-related physical and financial transactions of Black Hills Utility Holdings ⁽¹⁾	$	70,000	Ongoing
Guarantees for payment obligations arising from purchase contracts for four gas turbines for Black Hills Colorado IPP⁽²⁾	384		2012
Guarantees for payment obligations arising from purchase contracts for two gas turbines for Colorado Electric⁽³⁾	56		2012
Guarantee for payment obligations relating to a contract to construct 16 wind turbines at Colorado Electric⁽⁴⁾	33,264		January 15, 2013
Indemnification for subsidiary reclamation/surety bonds ⁽⁵⁾	18,601		Ongoing
Guarantee for payment obligations arising from natural gas transportation, storage and services agreement for Black Hills Utility Holdings ⁽⁶⁾	10,000		July 31, 2012
Guarantee for performance and payment obligation of Black Hills Utility Holdings for natural gas supply ⁽⁷⁾	7,500		June 30, 2012
	$	139,805

(1)


(2)	We have issued four guarantees to GE for payment obligations arising from contracts to purchase four LM6000 gas turbines for Black Hills Colorado IPP. These are continuous guarantees which will terminate upon settlement of all obligations.


(3)	We have issued two guarantees to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers. These are continuing guarantees which will terminate upon settlement of all obligations.


(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 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.


(6)	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 agreements.


(7)	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, 2011

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 December 31 (in thousands):



	2011		2010		2009
Acquisition of properties:
Proved	$	673	$	—	$	—
Unproved	8,317		3,846		3,443
Exploration costs	44,384		8,159		5,962
Development costs	38,638		25,264		10,133
Asset retirement obligations incurred	43		1,228		623
Total costs incurred	$	92,055	$	38,497	$	20,161

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



	2011						2010						2009
	Oil			Gas			Oil			Gas			Oil			Gas
	(in Mbbls of oil and MMcf of gas)
Proved developed and undeveloped reserves:
Balance at beginning of year	5,940			95,456			5,274			87,660			5,185			154,432
Production ^(a)	(452		)	(8,526		)	(376		)	(8,484		)	(366		)	(9,710		)
Additions - acquisitions (sales)	(84		)	—			(13		)	(377		)	—			—
Additions - extensions and discoveries	927			29,664			1,145			1,710			152			2,560
Revisions to previous estimates ^(b)	(108		)	(20,690		)	(90		)	14,947			303			(59,622		)
Balance at end of year	6,223			95,904			5,940			95,456			5,274			87,660

Proved developed reserves at end of year included above	4,830			71,867			4,434			67,656			4,274			74,911

Proved undeveloped reserves at the end of year included in above	1,393			24,037			1,506			27,800			1,000			12,749

NYMEX prices	$	96.19		$	4.12		$	79.43		$	4.38		$	61.18		$	3.87

Well-head reserve prices	$	88.49		$	3.59		$	70.82		$	3.45		$	53.59		$	2.52

________________________


(a)	Production for reserve calculations does not include volumes for natural gas liquids (NGL's).


(b)	Included in the total revisions are (23.6) Bcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2.3 Bcfe in various basins. Revisions due to cost and commodity pricing were less than 1% Bcfe.

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

As of December 31, 2011, PUD locations, proved reserves and future development costs associated with certain locations are as follows:



	As of December 31, 2011
Basin	Proved Reserves (in Bcfe)	Gross PUD Locations	Future Development Costs (in millions)
Piceance	12.8	4	$	26.7
Williston	10.5	33	46.3
Bear Paw Uplift	1.0	32	2.0
San Juan	8.1	3	15.1
	32.4	72	$	90.1

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

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



	2011			2010			2009
Unproved oil and gas properties	$	28,656		$	28,160		$	29,351
Proved oil and gas properties	674,494			592,978			582,276
Gross capitalized costs	703,150			621,138			611,627

Accumulated depreciation, depletion and amortization and valuation allowances	(361,173		)	(334,955		)	(335,605		)
Net capitalized costs	$	341,977		$	286,183		$	276,022

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 December 31, 2011 and notes the year in which the associated costs were incurred (in thousands):



	2011		2010		2009		Prior		Total

Leasehold acquisition cost	$	3,451	$	3,442	$	887	$	17,119	$	24,899
Exploration cost	16,745		—		—		—		16,745
Capitalized interest	291		404		55		3,006		3,756
Total	$	20,487	$	3,846	$	942	$	20,125	$	45,400

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 December 31 (in thousands):



	2011			2010			2009

Revenue	$	79,808		$	74,164		$	70,684

Production costs	23,820			21,922			21,653
Depreciation, depletion and amortization and valuation provisions*	34,415			29,013			72,338
Total costs	58,235			50,935			93,991
Results of operations from producing activities before tax	21,573			23,229			(23,307		)

Income tax benefit (expense)	(7,442		)	(8,014		)	8,041
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$	14,131		$	15,215		$	(15,266	)

_________________________


*	Includes pre-tax ceiling test impairment charges of $43.3 million in 2009.

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 December 31 (in thousands):



	2011			2010			2009
Future cash inflows	$	931,637		$	764,585		$	519,867
Future production costs	(280,910		)	(256,455		)	(207,783		)
Future development costs	(92,233		)	(73,805		)	(34,961		)
Future income tax expense	(157,922		)	(111,666		)	(51,287		)
Future net cash flows	400,572			322,659			225,836
10% annual discount for estimated timing of cash flows	(197,215		)	(154,551		)	(96,728		)
Standardized measure of discounted future net cash flows	$	203,357		$	168,108		$	129,108

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 December 31 (in thousands):



	2011			2010			2009
Standardized measure - beginning of year	$	168,108		$	129,108		$	179,226
Sales and transfers of oil and gas produced, net of production costs	(52,914		)	(40,282		)	(26,836		)
Net changes in prices and production costs	57,087			57,380			(40,786		)
Extensions, discoveries and improved recovery, less related costs	31,179			17,076			3,324
Changes in future development costs	43,809			(17,125		)	83,000
Development costs incurred during the period	18,940			4,975			4,620
Revisions of previous quantity estimates	(58,211		)	27,513			(104,556		)
Accretion of discount	19,655			13,434			19,596
Net change in income taxes	(23,283		)	(23,233		)	11,520
Purchases of reserves	—			—			—
Sales of reserves	(1,013		)	(738		)	—
Standardized measure - end of year	$	203,357		$	168,108		$	129,108

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 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.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 410
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (c)(3)
-URI http://asc.fasb.org/extlink&oid=6392692&loc=d3e7535-110849

Reference 3: 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=6821537&loc=d3e62246-109447

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=6821537&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 27
-URI http://asc.fasb.org/extlink&oid=6821537&loc=d3e62352-109447

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 22
-URI http://asc.fasb.org/extlink&oid=6821537&loc=d3e62094-109447

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-10.(a)(17)(ii),(c)(3)(ii)(A)(1))
-URI http://asc.fasb.org/extlink&oid=6949603&loc=d3e511914-122862

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 55
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6822203&loc=d3e63071-109448

Reference 9: 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=6821537&loc=d3e62299-109447

Reference 10: 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=6821537&loc=d3e62259-109447

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 932
-SubTopic 235
-Section 50
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6821537&loc=d3e62395-109447

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.

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

Discontinued Operations Condensed Income Statement of Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2011

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, our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):



	As of December 31, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	9,885		$	768	$	5	$	—	$	10,658
Commodity derivatives - Utilities	—		(9,520		)	—		—		19,416		9,896
Money market fund	6,005		—			—		—		—		6,005
Total	$	6,005	$	365		$	768	$	5	$	19,416	$	26,559

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	2,207		$	1,165	$	5	$	—	$	3,377
Commodity derivatives - Utilities	—		7,156			—		—		—		7,156
Interest rate swaps	—		122,867			—		—		—		122,867
Total	$	—	$	132,230		$	1,165	$	5	$	—	$	133,400



	As of December 31, 2010
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives - Oil and Gas	$	—	$	10,281		$	266	$	—	$	—	$	10,547
Commodity derivatives - Utilities	—		(5,568		)	—		—		10,355		4,787
Money market fund	8,050		—			—		—		—		8,050
Total	$	8,050	$	4,713		$	266	$	—	$	10,355	$	23,384

Liabilities:
Commodity derivatives - Oil and Gas	$	—	$	5,115		$	—	$	—	$	—	$	5,115
Commodity derivatives - Utilities	—		1,620			—		—		—		1,620
Interest rate swaps	—		75,779			—		—		—		75,779
Total	$	—	$	82,514		$	—	$	—	$	—	$	82,514

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):



	Commodity Derivatives			Commodity Derivatives
	December 31, 2011			December 31, 2010
Balance at beginning of year	$	266		$	381
Unrealized losses	(1,318		)	(303		)
Unrealized gains	751			188
Purchases	—			—
Issuances	—			—
Settlements	(96		)	—
Transfers into level 3^(a)	—			—
Transfers out of level 3 ^(b)	—			—
Balance at year end	$	(397	)	$	266

Changes in unrealized (losses) gain relating to instruments still held as of year end	$	(101	)	$	(302	)

______________


(a)	Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.


(b)	Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Fair Value, by Balance Sheet Grouping [Table Text Block]

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



	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	21,628	$	21,628	$	16,437	$	16,437
Restricted cash	$	9,254	$	9,254	$	4,260	$	4,260
Total derivative assets	$	20,554	$	20,554	$	15,335	$	15,335
Total derivative liabilities	$	133,400	$	133,400	$	82,514	$	82,514
Notes payable	$	345,000	$	345,000	$	249,000	$	249,000
Long-term debt, including current maturities	$	1,282,882	$	1,464,289	$	1,191,231	$	1,290,519

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]

Operating results of the Energy Marketing segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands):



	For the Years Ended
	December 31, 2011			December 31, 2010			December 31, 2009

Revenue	$	41,101		$	27,999		$	13,381

Pre-tax income from discontinued operations	14,838			8,673			1,950
Income tax (expense) benefit	(5,473		)	(3,129		)	(464		)

Income from discontinued operations	$	9,365		$	5,544		$	1,486

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. An estimate of how these costs could have been allocated to segments other than Corporate is as follows (in thousands):



	Years Ended
Business Segment	December 31, 2011		December 31, 2010		December 31, 2009
Electric Utilities	$	1,613	$	1,650	$	1,666
Gas Utilities	1,043		1,092		1,177
Oil and Gas	407		435		538
Power Generation	228		233		231
Coal Mining	127		105		141
	$	3,418	$	3,515	$	3,753

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]

Total assets and liabilities of Enserco have been classified as Current assets of discontinued operations and Current liabilities of discontinued operations on the accompanying Consolidated Balance Sheets at December 31, 2011 and 2010. Net assets of the Energy Marketing segment included in Discontinued operations were as follows (in thousands):



	As of
	December 31, 2011			December 31, 2010
Other current assets	$	280,221		$	257,082
Derivative assets, current and non-current	52,859			50,498
Property, plant and equipment, net	5,828			3,699
Goodwill	1,435			1,435
Other non-current assets	508			1,521
Other current liabilities	(132,951		)	(152,602		)
Derivative liabilities, current and non-current	(26,084		)	(18,014		)
Other non-current liabilities	(14,894		)	(2,707		)

Net assets	$	166,922		$	140,912

Segment, Discontinued Operations [Member]

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

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



	As of
	December 31, 2011			December 31, 2010
Other current assets	$	280,221		$	257,082
Derivative assets, current and non-current	52,859			50,498
Property, plant and equipment, net	5,828			3,699
Goodwill	1,435			1,435
Other non-current assets	508			1,521
Other current liabilities	(132,951		)	(152,602		)
Derivative liabilities, current and non-current	(26,084		)	(18,014		)
Other non-current liabilities	(14,894		)	(2,707		)

Net assets	$	166,922		$	140,912

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 for our Energy Marketing Segment (in thousands):



	December 31, 2011
	Level 1		Level 2		Level 3		Counterparty Netting			Cash Collateral			Total
Assets:
Commodity derivatives - Energy Marketing	$	—	$	789,537	$	6,139	$	(743,154	)	$	337		$	52,859

Liabilities:
Commodity derivatives - Energy Marketing	$	—	$	771,534	$	5,411	$	(743,154	)	$	(7,707	)	$	26,084



	December 31, 2010
	Level 1		Level 2		Level 3		Counterparty Netting			Cash Collateral			Total
Assets:
Commodity derivatives - Energy Marketing	$	—	$	166,405	$	7,976	$	(122,639	)	$	(1,410	)	$	50,332
Foreign currency	—		166		—		—			—			166
Total	$	—	$	166,571	$	7,976	$	(122,639	)	$	(1,410	)	$	50,498

Liabilities:
Commodity derivatives - Energy Marketing	$	—	$	143,537	$	2,463	$	(122,639	)	$	(5,368	)	$	17,993
Foreign currency	—		21		—		—			—			21
Total	$	—	$	143,558	$	2,463	$	(122,639	)	$	(5,368	)	$	18,014

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



	December 31, 2010
	Level 1		Level 2		Level 3		Counterparty Netting			Cash Collateral			Total
Assets:
Commodity derivatives - Energy Marketing	$	—	$	166,405	$	7,976	$	(122,639	)	$	(1,410	)	$	50,332
Foreign currency	—		166		—		—			—			166
Total	$	—	$	166,571	$	7,976	$	(122,639	)	$	(1,410	)	$	50,498

Liabilities:
Commodity derivatives - Energy Marketing	$	—	$	143,537	$	2,463	$	(122,639	)	$	(5,368	)	$	17,993
Foreign currency	—		21		—		—			—			21
Total	$	—	$	143,558	$	2,463	$	(122,639	)	$	(5,368	)	$	18,014

The following tables set forth the roll forward of level 3 assets and liabilities that were accounted for at fair value on a recurring basis for our Energy Marketing Segment (in thousands):



	Commodity Derivatives			Commodity Derivatives
	December 31, 2011			December 31, 2010
Balance at beginning of year	$	5,513		$	(937	)
Unrealized losses	(8,631		)	(2,525		)
Unrealized gains	6,094			7,295
Settlements	(2,248		)	(1,179		)
Transfers in to level 3^(a)	—			1,457
Transfers out of level 3^(b)	—			1,402
Balance at year end	$	728		$	5,513

Changes in unrealized (losses) gains relating to instruments still held as of year end	$	(825	)	$	1,078

(a) Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs

became unobservable.

(b) Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant

input became observable during the peri

Fair Value, by Balance Sheet Grouping [Table Text Block]

The following tables set forth, by the location of our assets and liabilities that were accounted for at fair value on a recurring basis for our Energy Marketing Segment (in thousands):



		December 31, 2011				December 31, 2010
	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	Assets of discontinued operations	$	—	$	—	$	10,952	$	1,452
Commodity derivatives	Assets of discontinued operations	—		—		48		71
Commodity derivatives	Liabilities of discontinued operations	5,256		403		—		45
Commodity derivatives	Liabilities of discontinued operations	—		—		—		—
		$	5,256	$	403	$	11,000	$	1,568

Derivatives not designated as hedges:
Commodity derivatives	Assets of discontinued operations	$	55,413	$	13,740	$	142,013	$	107,795
Commodity derivatives	Assets of discontinued operations	76,629		54,784		9,757		3,099
Commodity derivatives	Liabilities of discontinued operations	691,453		729,309		20,588		39,051
Commodity derivatives	Liabilities of discontinued operations	4,852		9,354		978		4,442
Foreign currency	Assets of discontinued operations	—		—		166		21
		$	828,347	$	807,187	$	173,502	$	154,408

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, 2011

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 2011 and 2010.



	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

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

Income (loss) per share for continuing operations - diluted	$	0.73		$	0.09	$	(0.29	)	$	0.44
Income (loss) per share for discontinued operations - diluted	(0.05		)	0.10		0.02			0.16
Income (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.



	First Quarter		Second Quarter			Third Quarter		Fourth Quarter
	(in thousands, except per share amounts, dividends and common stock prices)
2010
Revenue ^(a)	$	416,728	$	247,443		$	240,521	$	314,999
Operating income^(b)	$	64,698	$	27,170		$	44,695	$	46,857
Income (loss) from continuing operations ^{(b) (c)}	$	28,705	$	(10,688	)	$	10,493	$	34,631
Income (loss) from discontinued operations	$	2,729	$	2,029		$	1,897	$	(1,111	)
Net income (loss) available for common stock ^{(b) (c)}	$	31,434	$	(8,659	)	$	12,390	$	33,520

Income (loss) per share, Basic:
Earnings (loss) per share for continuing operations	$	0.74	$	(0.27	)	$	0.27	$	0.89
Earnings (loss) per share for discontinued operations	0.07		0.05			0.05		(0.03		)
Earnings (loss) per share - basic	$	0.81	$	(0.22	)	$	0.32	$	0.86

Income (loss) per share, Diluted:
Earnings (loss) per share for continuing operations	$	0.74	$	(0.27	)	$	0.27	$	0.88
Earnings (loss) per share for discontinued operations	0.07		0.05			0.05		(0.03		)
Earnings (loss) per share - diluted	$	0.81	$	(0.22	)	$	0.32	$	0.85

Dividends paid per share	$	0.36	$	0.36		$	0.36	$	0.36

Common stock prices - High	$	30.83	$	34.49		$	33.31	$	33.42
Common stock prices - Low	$	25.65	$	27.34		$	27.79	$	29.32

__________________________


(a)	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated. See Note 1.


(b)	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively.


(c)	Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 million after-tax in the first, second, third and fourth quarters, respectively

Business Description and Significant Accounting Policies Principles of Consolidation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009
Intersegment Elimination [Member]
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Overstatement of Utility and Non-regulated revenue and Fuel, purchased power and cost of gas sold in aggregate	$ 59.6	$ 57.5

Business Description and Significant Accounting Policies Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	$ (1,661)	$ (2,294)
Accounts receivable, net	156,774	171,816
Electric Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	(545)	(708)
Accounts receivable, net	63,379	69,869
Gas Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	(1,011)	(1,425)
Accounts receivable, net	77,334	80,921
Oil and Gas [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	(105)	(161)
Accounts receivable, net	11,177	6,052
Coal [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	0	0
Accounts receivable, net	4,056	2,420
Power Generation [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	0	0
Accounts receivable, net	282	307
Corporate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable	0	0
Accounts receivable, net	546	12,247
Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	98,292	114,162
Billed Revenues [Member] \| Electric Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	42,773	51,005
Billed Revenues [Member] \| Gas Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	39,353	41,970
Billed Revenues [Member] \| Oil and Gas [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	11,282	6,213
Billed Revenues [Member] \| Coal [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	4,056	2,420
Billed Revenues [Member] \| Power Generation [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	282	307
Billed Revenues [Member] \| Corporate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	546	12,247
Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	60,143	59,948
Unbilled Revenues [Member] \| Electric Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	21,151	19,572
Unbilled Revenues [Member] \| Gas Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	38,992	40,376
Unbilled Revenues [Member] \| Oil and Gas [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] \| Coal [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] \| Power Generation [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues [Member] \| Corporate [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Trade	$ 0	$ 0

Business Description and Significant Accounting Policies Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Materials and supplies	$ 40,838	$ 31,537
Total Materials, supplies and fuel	84,064	62,915
Electric Utilities [Member]
Fuel - Electric Utilities	8,201	9,687
Gas Utilities [Member]
Natural gas in storage - Gas Utilities	$ 35,025	$ 21,691

Business Description and Significant Accounting Policies Oil and Gas (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
After Tax Future Net Revenue Discount Rate	10.00%
Impairment of long-lived assets	$ 0	$ 0	$ 43,301
Impairment in Value of Asset [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Impairment of long-lived assets	$ 0	$ 0

Business Description and Significant Accounting Policies Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Goodwill [Roll Forward]
Goodwill, Period Start	$ 353,396	$ 352,299
Goodwill Additions (adjustments)	0	1,097
Goodwill, Period End	$ 353,396	353,396
Electric Utilities [Member]
Goodwill [Line Items]
Goodwill Allocation by Segment	69.00%
Goodwill [Roll Forward]
Goodwill, Period Start	$ 250,487	249,620
Goodwill Additions (adjustments)	0	867
Goodwill, Period End	$ 250,487	250,487
Gas Utilities [Member]
Goodwill [Line Items]
Goodwill Allocation by Segment	31.00%
Goodwill [Roll Forward]
Goodwill, Period Start	$ 94,144	93,914
Goodwill Additions (adjustments)	0	230
Goodwill, Period End	94,144	94,144
Power Generation [Member]
Goodwill [Roll Forward]
Goodwill, Period Start	8,765	8,765
Goodwill Additions (adjustments)	0	0
Goodwill, Period End	$ 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 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 2: 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 3: 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 4: 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 5: 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=6905597&loc=d3e13816-109267

Reference 6: 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 7: 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 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.

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Business Description and Significant Accounting Policies Schedule of Intangible Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life, Maximum \| years	20
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 4,069	$ 4,309	$ 4,884
Intangible asset, additions (adjustments)	0	0	365
Intangible assets, amortization expense	(226)	(240)	(210)
Intangible assets, net, ending balance	3,843	$ 4,069	$ 4,309
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

Business Description and Significant Accounting Policies Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 242,130	$ 204,834
Regulatory liabilities	124,448	88,554
Deferred Fuel Costs [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities	$ 16,961	1,200
Regulatory liabilities recovery settlement period	P1Y
Pension Cost [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities	$ 59,455	36,155
Regulatory liabilities recovery settlement period	P13Y
Cost Of Removal [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities	$ 42,257	39,638
Regulatory liabilities recovery settlement period	P44Y
Revenue Subject to Refund [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities	$ 443	1,016
Regulatory liabilities recovery settlement period	P1Y
Other Regulatory Liabilities [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities	$ 5,332	10,545
Regulatory liabilities recovery settlement period	various
Deferred Fuel Costs [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 33,526	30,298
Regulatory assets maximum recovery settlement period	P1Y
Deferred Gas Cost Adjustments and Gas Price Derivatives [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 26,208	39,407
Regulatory assets maximum recovery settlement period	P1Y
Allowance for Cost of Equity Funds Used During Construction [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 12,482	13,391
Regulatory assets maximum recovery settlement period	P45Y
Employee Benefit Plans [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 120,708	83,144
Regulatory assets maximum recovery settlement period	P13Y
Environmental [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 1,770	2,353
Regulatory assets maximum recovery settlement period	subject to approval
Asset Retirement Obligation Costs [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 3,097	3,066
Regulatory assets maximum recovery settlement period	P44Y
Bond Issuance Costs [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 3,704	3,847
Regulatory assets maximum recovery settlement period	P25Y
Renewable Energy Standard Adjustment [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 20,095	14,254
Regulatory assets maximum recovery settlement period	P5Y
Flow Through Accounting [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 12,191	7,491
Regulatory assets maximum recovery settlement period	P35Y
Other Regulatory Assets [Member]
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets	$ 8,349	$ 7,583
Regulatory assets maximum recovery settlement period	various

Business Description and Significant Accounting Policies Earnings per Share (Details) - USD ($)
shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Weighted average shares - basic

$ 18,754

$ (11,163)

$ 3,706

$ 29,068

$ 34,631

$ 10,493

$ (10,688)

$ 28,705

$ 40,365

$ 63,141

$ 77,269

39,864

38,916

38,614

Dilutive effect of:

Stock Options

Restricted stock

153

107

Forward equity issuance

^[1]

Other diluted effects

Weighted average shares - diluted

40,081

39,091

38,684

[1]	On November 1, 2011, we issued shares in conjunction with the settlement of an equity forward agreement. See Note 11 for further information.

This element represents the income or loss from continuing operations attributable to the parent which may also be defined as revenue less expenses and taxes from ongoing operations before extraordinary items but after deduction of those portions of income or loss from continuing operations that are allocable to noncontrolling interests, if any.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 29
-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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 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 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph b(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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 5: 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 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 45
-Paragraph 18
-URI http://asc.fasb.org/extlink&oid=6921628&loc=SL4613673-111683

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.13)
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

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 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 2: 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.

Reference 3: 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 4: 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 5: 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=6920599&loc=d3e1448-109256

Reference 6: 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 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.

Business Description and Significant Accounting Policies Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	141	160	510
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	105	158	462
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	17	1	3
Other Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	19	1	45

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 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 2: 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 3: 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 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 Accounting Standards Codification
-Glossary Diluted Earnings Per Share
-URI http://asc.fasb.org/extlink&oid=6510752

Reference 6: 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 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Antidilution
-URI http://asc.fasb.org/extlink&oid=6505113

Reference 8: 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.

Recently Adopted and Recently Issued Accounting Standards and Legislation Oil and Gas Reserves Calculation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2009 USD ($)
Accounting Standards Update 2010-03 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results	$ 1.3

Risk Management Activities Risk Management Activities (Details)

12 Months Ended

Dec. 31, 2011

USD ($)

Btu

Dec. 31, 2010

USD ($)

Btu

$ 18,583,000

$ 12,710,000

1,971,000

2,625,000

84,367,000

64,617,000

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

49,033,000

17,897,000

6,500,000

Oil and Gas Exploration and Production [Member]

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

5,604,000

Financing Activities [Member] | Interest Rate Swaps, Designated [Member]

Weighted Average Fixed Interest Rate

$ 150,000,000

5.04%

$ 0

6,513,000

6,823,000

Pre-tax accumulated other comprehensive income loss

20,363,000

14,976,000

(26,876,000)

(21,799,000)

Collateral receivable (payable) included in Consolidated Balance Sheet

Pre-tax gain (loss) included in Consolidated Statement of Income

Financing Activities [Member] | Interest Rate Swaps, Dedesignated [Member] | Dedesignated Interest Rate Swap Expiring 2018 [Member]

$ 100,000,000

Financing Activities [Member] | Interest Rate Swaps, Dedesignated [Member] | Dedesignated Interest Rate Swaps Expiring 2028 [Member]

$ 150,000,000

Utilities Group [Member] | Regulated Utilities Hedges [Member]

$ 9,844,000

4,787,000

52,000

Cash collateral (receivable)/payable included in derivative assets/liabilities

7,156,000

1,620,000

19,416,000

10,355,000

Net Unrealized Gain (Loss) Included in Regulatory assets or Regulatory liability

17,556,000

8,030,000

Option Premium Included in Derivative assets, current

$ 880,000

$ 842,000

Utilities Group [Member] | Regulated Utilities Hedges [Member] | Natural Gas [Member] | Future [Member] | Purchase Contract [Member]

Derivative Notional Amount | Btu

14,310,000

6,670,000

Utilities Group [Member] | Regulated Utilities Hedges [Member] | Natural Gas [Member] | Commodity Option [Member] | Purchase Contract [Member]

Derivative Notional Amount | Btu

1,720,000

1,730,000

Utilities Group [Member] | Regulated Utilities Hedges [Member] | Natural Gas [Member] | Basis Swap [Member] | Purchase Contract [Member]

Derivative Notional Amount | Btu

7,160,000

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

Derivative Notional Amount

^[1]

5,406,250

6,821,800

MaximumTerm Hedged in Cash Flow Hedge

1.75

.25

$ 8,010,000

$ 7,675,000

1,148,000

2,606,000

Pre-tax accumulated other comprehensive income loss

7,000

9,152,000

10,281,000

Oil and Gas [Member] | Oil and Gas Exploration and Production [Member] | Crude Oil [Member] | Swaps and Options [Member]

^[2]

$ 0

Derivative Notional Amount

^[1]

528,000

424,500

MaximumTerm Hedged in Cash Flow Hedge

1.25

.25

$ 729,000

$ 248,000

771,000

19,000

2,559,000

3,814,000

Pre-tax accumulated other comprehensive income loss

811,000

1,301,000

(1,928,000)

(5,313,000)

^[2]

58,000

465,000

78,502,000

57,343,000

Parent [Member] | Interest Rate Swaps, Designated [Member]

31,368,000

7,360,000

Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net

3,200,000

Parent [Member] | Financing Activities [Member] | Interest Rate Swaps, Designated [Member]

Weighted Average Fixed Interest Rate

$ 75,000,000

4.97%

$ 0

3,207,000

3,363,000

Pre-tax accumulated other comprehensive income loss

10,672,000

7,360,000

(13,879,000)

(15,417,000)

Derivative, Collateral, Right to Reclaim Cash

Pre-tax gain (loss) included in Consolidated Statement of Income

Parent [Member] | Financing Activities [Member] | Interest Rate Swaps, Dedesignated [Member]

Weighted Average Fixed Interest Rate

$ 250,000,000

5.67%

$ 0

75,295,000

53,980,000

Pre-tax accumulated other comprehensive income loss

20,696,000

Derivative, Collateral, Right to Reclaim Cash

Pre-tax gain (loss) included in Consolidated Statement of Income

(42,010,000)

$ (15,193,000)

Credit Risk [Member] | Interest Rate Swaps, Dedesignated [Member]

Potential Future Exposure on Credit Related Contingent Feature

50,000,000

$ 20,000,000

[1]	(a)Crude in Bbls, gas in MMBtu.
[2]	Represents the amortization of put premiums.

Fair Value Measurements Fair Value Measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money Market Funds	$ 6,005	$ 8,050
Derivative Assets, Total	6,005	8,050
Derivative Liabilities, Total	0	0
Fair Value, Inputs, Level 1 [Member] \| Commodity derivatives [Member] \| Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 1 [Member] \| Commodity derivatives [Member] \| Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 1 [Member] \| Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money Market Funds	0	0
Derivative Assets, Total	365	4,713
Derivative Liabilities, Total	132,230	82,514
Fair Value, Inputs, Level 2 [Member] \| Commodity derivatives [Member] \| Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	9,885	10,281
Derivative, Liabilities, Fair Value Disclosure	2,207	5,115
Fair Value, Inputs, Level 2 [Member] \| Commodity derivatives [Member] \| Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	(9,520)	(5,568)
Derivative, Liabilities, Fair Value Disclosure	7,156	1,620
Fair Value, Inputs, Level 2 [Member] \| Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	122,867	75,779
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money Market Funds	0	0
Derivative Assets, Total	768	266
Derivative Liabilities, Total	1,165	0
Fair Value, Inputs, Level 3 [Member] \| Commodity derivatives [Member] \| Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	768	266
Derivative, Liabilities, Fair Value Disclosure	1,165	0
Fair Value, Inputs, Level 3 [Member] \| Commodity derivatives [Member] \| Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member] \| Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Counterparty Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money Market Funds	0	0
Derivative Assets, Total	5	0
Derivative Liabilities, Total	5	0
Counterparty Netting [Member] \| Commodity derivatives [Member] \| Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	5	0
Derivative, Liabilities, Fair Value Disclosure	5	0
Counterparty Netting [Member] \| Commodity derivatives [Member] \| Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Counterparty Netting [Member] \| Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Cash Collateral [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money Market Funds	0	0
Derivative Assets, Total	19,416	10,355
Derivative Liabilities, Total	0	0
Cash Collateral [Member] \| Commodity derivatives [Member] \| Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Cash Collateral [Member] \| Commodity derivatives [Member] \| Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	19,416	10,355
Derivative, Liabilities, Fair Value Disclosure	0	0
Cash Collateral [Member] \| Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Total Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money Market Funds	6,005	8,050
Derivative Assets, Total	26,559	23,384
Derivative Liabilities, Total	133,400	82,514
Total Estimate of Fair Value, Fair Value Disclosure [Member] \| Commodity derivatives [Member] \| Oil and Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	10,658	10,547
Derivative, Liabilities, Fair Value Disclosure	3,377	5,115
Total Estimate of Fair Value, Fair Value Disclosure [Member] \| Commodity derivatives [Member] \| Utilities Group [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Commodity Derivatives	9,896	4,787
Derivative, Liabilities, Fair Value Disclosure	7,156	1,620
Total Estimate of Fair Value, Fair Value Disclosure [Member] \| Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	$ 122,867	$ 75,779

Fair Value Measurements Fair Value Measurements Changes in Level 3 Recurring Fair Value (Details) - Commodity derivatives [Member] - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Fair Value Assets and Liabilities Measured On Recurring Basis Unobservable Input Reconciliation Calculation RollForward [Roll Forward]

Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period Start

$ 266

$ 381

Unrealized losses

(1,318)

(303)

Unrealized gains

751

188

Purchases

Issuances

Settlements

(96)

Transfers into level 3

^[1]

Transfers out of level 3

^[2]

Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period End

(397)

266

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

(101)

$ (302)

Gain (Loss) Included in Earnings, Level 3 Commodity Derivatives

(600)

Gain (Loss) Included in Other Comprehensive Income (Loss), Level 3 Commodity Derivatives

$ 100

[1]	Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.
[2]	Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Fair Value Measurements Fair Value Measurements Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Designated as Hedging Instrument [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	$ 10,658	$ 10,548
Derivative Liability, Fair Value, Net	30,253	26,913
Derivatives Not Designated as Hedge Instruments [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	0	0
Derivative Liability, Fair Value, Net	112,667	61,168
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	8,739	7,923
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	1,919	2,625
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	2,559	3,814
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	818	1,301
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Assets, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Gross Liability	9,572	5,567
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	(52)	0
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	0
Commodity derivatives [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	7,156	1,621
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	6,513	6,822
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	20,363	14,976
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	75,295	53,980
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	$ 20,696	$ 0

Fair Value Measurements Fair Value Measurements Hedging Activities (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash Flow Hedging
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	$ 1,929	$ (4,539)		$ (8,252)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	6,730	(2,177)		19,810
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0		(1,394)
Cash Flow Hedging \| Commodity derivatives [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	15,456	7,741		(21,070)
Cash Flow Hedging \| Commodity derivatives [Member] \| Revenue
Derivative Instruments, Gain (Loss)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	14,339	5,487		23,102
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0		(1,394)
Cash Flow Hedging \| Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(13,527)	(12,280)		12,818
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0		0
Cash Flow Hedging \| Interest Rate Swap [Member] \| Interest Expense
Derivative Instruments, Gain (Loss)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	$ (7,609)	(7,664)		(3,292)
Derivatives Not Designated as Hedge Instruments [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) on Derivatives Recognized in Income		(55,383)	$ (28,505)	45,837
Parent [Member] \| Cash Flow Hedging \| Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)		(3,893)	(5,352)
Parent [Member] \| Cash Flow Hedging \| Interest Rate Swap [Member] \| Interest Expense
Derivative Instruments, Gain (Loss)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)		(3,950)	(3,662)
Parent [Member] \| Derivatives Not Designated as Hedge Instruments [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) on Derivatives Recognized in Income		(55,383)	(28,505)	45,837
Parent [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Interest Rate Swap [Member] \| Unrealized Gain (Loss) on Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) on Derivatives Recognized in Income		(42,010)	(15,193)	55,653
Parent [Member] \| Derivatives Not Designated as Hedge Instruments [Member] \| Interest Rate Swap [Member] \| Interest Expense
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) on Derivatives Recognized in Income		$ (13,373)	$ (13,312)	$ (9,816)

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, at carrying value	$ 21,628	$ 16,437
Restricted cash, at carrying value	9,254	4,260
Notes payable, at carrying value	345,000	249,000
Long-term debt, including current maturities at carrying value	1,282,882	1,191,231
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, at carrying value	21,628	16,437
Restricted cash, at carrying value	9,254	4,260
Total derivative assets	20,554	15,335
Total derivative liabilities	133,400	82,514
Notes payable, at carrying value	345,000	249,000
Long-term debt, including current maturities at carrying value	1,282,882	1,191,231
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, fair value	21,628	16,437
Restricted cash, fair value	9,254	4,260
Total derivative asset at fair value	20,554	15,335
Total derivative liability, fair value	133,400	82,514
Notes payable, fair value	345,000	249,000
Long-term debt, including current maturities at fair value	$ 1,464,289	1,290,519
Project Financing Debt Due 2016 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Restricted cash, at carrying value		$ 3,600

Property, Plant and Equipment Property, Plant and Equipment (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2011

USD ($)

years

Dec. 31, 2010

USD ($)

years

Accumulated depreciation, depletion and amortization

$ 3,724,016

$ 3,353,509

(934,441)

(861,775)

2,789,575

2,491,734

Accumulated depreciation, depletion and amortization

^[1]

2,149,151

1,720,909

(385,840)

(357,774)

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

1,763,311

1,363,135

Property, plant and equipment excluding construction work in progress

$ 707,498

$ 679,165

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Electric Utilities [Member] | Electric transmission [Member]

Property, plant and equipment excluding construction work in progress

$ 170,146

$ 154,936

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Electric Utilities [Member] | Electric distribution [Member]

Property, plant and equipment excluding construction work in progress

$ 580,699

$ 543,498

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

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

Property, plant and equipment excluding construction work in progress

$ 4,870

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Electric Utilities [Member] | General [Member]

Property, plant and equipment excluding construction work in progress

$ 136,304

$ 103,455

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Electric Utilities [Member] | Assets Held under Capital Leases [Member]

Property, plant and equipment excluding construction work in progress

$ 260,874

^[2]

$ 0

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Electric Utilities [Member] | Construction work in progress [Member]

$ 288,760

$ 234,985

Accumulated depreciation, depletion and amortization

523,374

502,360

(52,249)

(47,292)

Gas Utilities [Member] | General [Member]

471,125

455,068

Property, plant and equipment excluding construction work in progress

$ 56,869

$ 68,315

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

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

Property, plant and equipment excluding construction work in progress

$ 35

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Gas Utilities [Member] | Gas transmission [Member]

Property, plant and equipment excluding construction work in progress

$ 15,543

$ 15,704

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Gas Utilities [Member] | Gas distribution [Member]

Property, plant and equipment excluding construction work in progress

$ 442,114

$ 406,914

Property, Plant and Equipment, Useful Life, Average | years

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Gas Utilities [Member] | Construction work in progress [Member]

Non Regulated Energy Group [Member]

$ 8,813

$ 11,392

Property, plant and equipment excluding construction work in progress

1,039,379

950,180

Accumulated depreciation, depletion and amortization

5,271

173,519

(495,228)

(454,426)

549,422

669,273

Coal Mining [Member]

Property, plant and equipment excluding construction work in progress

140,683

135,157

Accumulated depreciation, depletion and amortization

4,341

10,228

(73,777)

(65,465)

Property, Plant and Equipment, Useful Life, Average | years

$ 71,247

$ 79,920

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Property, plant and equipment excluding construction work in progress

$ 763,645

$ 680,407

Accumulated depreciation, depletion and amortization

763,645

680,407

(386,377)

(357,979)

Property, Plant and Equipment, Useful Life, Average | years

$ 377,268

$ 322,428

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Property, plant and equipment excluding construction work in progress

$ 135,051

$ 134,616

930

163,291

Accumulated depreciation, depletion and amortization

^[1]

135,981

297,907

(35,074)

(30,982)

Property, Plant and Equipment, Useful Life, Average | years

$ 100,907

$ 266,925

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | years

Property, plant and equipment excluding construction work in progress

$ 2,136

$ 4,039

4,705

2,502

Accumulated depreciation, depletion and amortization

6,841

6,541

(1,124)

(2,283)

Property, Plant and Equipment, Useful Life, Average | years

$ 5,717

$ 4,258

Property, Plant and Equipment, Useful Life, Minimum | years

Property, Plant and Equipment, Useful Life, Maximum | 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, 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.

Jointly Owned Facilities Jointly Owned Facilities (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 363,300
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	1,847
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 78,539
Oil and Gas [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	44.70%
Jointly Owned Utility Plant, Net Ownership Amount	$ 4,277,825
Electric Utilities [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share		23.00%	25.00%
Electric Utilities [Member] \| Wyodak Plant [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	20.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 109,007
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	718
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 46,104
Electric Utilities [Member] \| Transmission Tie [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	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	$ 4,061
Electric Utilities [Member] \| Wygen I I I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	52.00%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 129,791
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	249
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 5,328
Power Generation [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share			23.50%
Power Generation [Member] \| Wygen I Generating Facility [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	76.50%
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 104,854
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	880
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	$ 23,046

Long-Term Debt Long-Term Debt (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Long-term Debt, including current maturirities

$ 1,282,882

$ 1,191,231

Long-term Debt, Current Maturities

(2,473)

(5,181)

Long-term debt, excluding current maturities

1,280,409

1,186,050

Utilities Group [Member]

403,462

403,620

Long-term Debt, including current maturirities

774,959

674,930

774,959

674,930

Long-term debt, excluding current maturities

$ 774,959

674,930

Parent [Member] | Senior Unsecured Notes due 2013 [Member]

May 15, 2013

6.50%

^[1]

$ 225,000

225,000

Parent [Member] | Senior Unsecured Notes Due 2014 [Member]

$ (41)

(70)

May 15, 2014

9.00%

Parent [Member] | Senior Unsecured Notes Due 2020 [Member]

^[1]

$ 250,000

250,000

Jul. 15, 2020

5.88%

Parent [Member] | Long Term Term Loan [Member]

^[2]

$ 200,000

200,000

Long-term Debt, Variable Interest, Percentage Rate

Sep. 30, 2013

1.69%

$ 100,000

$ 0

[1]	In order to restructure debt and equity capitalization at our utilities, 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.
[2]	In order to restructure debt and equity capitalization at our utilities, $100.0 million of 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.

Long-Term Debt Aggregate Maturities of Long Term Debt (Details) $ in Thousands	Dec. 31, 2011 USD ($)
Debt Instrument [Line Items]
Long-term Debt, Current Maturities	$ 2,473
Long-term Debt, Maturities, Repayments of Principal in Year Two	328,973
Long-term Debt, Maturities, Repayments of Principal in Year Three	262,473
Long-term Debt, Maturities, Repayments of Principal in Year Four	6,964
Long-term Debt, Maturities, Repayments of Principal in Year Five	85,101
Long-term Debt, Maturities, Repayments of Principal after Year Five	$ 597,054

Long-Term Debt Debt Issuance (Details) - Parent [Member] - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Senior Unsecured Notes Due 2020 [Member]

$ 774,959

$ 674,930

^[1]

$ 200,000

200,000

Jul. 15, 2020

Proceeds from Issuance of Senior Long-term Debt

5.88%

$ 198,700

Long Term Term Loan [Member]

$ 100,000

$ 0

Debt Instrument, Interest Rate Terms

Sep. 30, 2013

1.375%

Long-term Debt, Variable Interest Rate at Period End

1.69%

[1]	In order to restructure debt and equity capitalization at our utilities, $100.0 million of 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.

Long-Term Debt Deferred Financing Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Senior Unsecured Notes due 2013 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	$ 309
Amortization Expense for Deferred Financing Costs	218	$ 218	$ 218
Senior Unsecured Notes Due 2014 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,097
Amortization Expense for Deferred Financing Costs	462	462	289
Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,428
Amortization Expense for Deferred Financing Costs	167	77	0
First Mortgage Bonds Due 2032 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	684
Amortization Expense for Deferred Financing Costs	33	33	33
First Mortgage Bonds Due 2039 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,113
Amortization Expense for Deferred Financing Costs	76	76	12
First Mortgage Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	797
Amortization Expense for Deferred Financing Costs	31	31	31
Project Financing Debt Due 2016 [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	4,214
Amortization Expense for Deferred Financing Costs	1,012	1,036	60
Deferred Financing Costs, Other [Member]
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	816
Amortization Expense for Deferred Financing Costs	$ 70	$ 74	$ 67

Notes Payable Notes Payable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Line of Credit Facility
Notes payable	$ 345,000	$ 249,000
Letters of Credit Outstanding, Amount	43,700	46,865
Consolidated Net Worth, Actual	1,209,336	1,100,270	$ 1,084,837	$ 1,050,536
Line of Credit [Member] \| Revolving Credit Facility, Existing [Member]
Line of Credit Facility
Line of Credit Facility, Maximum Borrowing Capacity	600,000
Deferred Finance Costs Remaining, Noncurrent	1,497
Amortization Expense for Deferred Financing Costs	1,891	1,340	$ 495
Letters of Credit [Member] \| Revolving Credit Facility, Existing [Member]
Line of Credit Facility
Consolidated Net Worth, Actual	1,209,336
Line of Credit, Covenant Requirement, Consolidated Net Worth, Minimum	$ 884,131
Line of Credit Covenant Requirement, Recourse Leverage Ratio, Actual	58.50%
Line of Credit, Covenant Requirement, Recourse Leverage Ratio	65.00%
Parent [Member]
Line of Credit Facility
Notes payable	$ 345,000	249,000
Consolidated Net Worth, Actual	1,209,336	1,100,270
Parent [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member]
Line of Credit Facility
Notes payable	195,000	149,000
Letters of Credit Outstanding, Amount	$ 43,700	46,865
Line of Credit Facility, Expiration Date	4/14/2013
Line of Credit Facility, Commitment Fee Percentage	0.50%
Parent [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member] \| Base Rate Option [Member]
Line of Credit Facility
Line of Credit Facility, Interest Rate at Period End	1.75%
Parent [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member] \| Eurodollar Option [Member]
Line of Credit Facility
Line of Credit Facility, Interest Rate at Period End	2.75%
Parent [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member] \| Letters of Credit [Member]
Line of Credit Facility
Line of Credit Facility, Interest Rate at Period End	2.75%
Parent [Member] \| Loans Payable [Member] \| Corporate Term Loan due in 2011 [Member]
Line of Credit Facility
Notes payable	$ 0	100,000
Letters of Credit Outstanding, Amount	0	0
Parent [Member] \| Loans Payable [Member] \| Corporate Term Loan due June 2012 [Member]
Line of Credit Facility
Notes payable	150,000	0
Letters of Credit Outstanding, Amount	$ 0	$ 0

Notes Payable Notes Payable Corporate Term Loan (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Short-term Debt [Line Items]
Notes payable	$ 345,000	$ 249,000
Parent [Member]
Short-term Debt [Line Items]
Notes payable	345,000	249,000
Parent [Member] \| Loans Payable [Member] \| Corporate Term Loan due June 2012 [Member]
Short-term Debt [Line Items]
Notes payable	$ 150,000	$ 0
Long-term Debt, Maturity Date	Jun. 24, 2012
Debt Instrument, Interest Rate Terms	1.25%
Debt Instrument, Interest Rate at Period End	1.56%

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 42,517

$ 39,663

18,664

(627)

(17,285)

Asset Retirement Obligation, Revision of Prior Estimate

2,506

2,675

^[1]

(1,525)

(1,200)

42,914

42,517

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

21,663

21,233

570

(627)

(2,078)

Asset Retirement Obligation, Revision of Prior Estimate

1,343

1,280

^[1]

658

22,422

21,663

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

17,560

15,285

18,094

(15,207)

Asset Retirement Obligation, Revision of Prior Estimate

1,123

1,246

^[1]

(1,525)

(1,858)

17,158

17,560

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

3,039

2,904

Asset Retirement Obligation, Revision of Prior Estimate

135

^[1]

3,064

3,039

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

255

241

Asset Retirement Obligation, Revision of Prior Estimate

^[1]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

$ 270

$ 255

[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) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) shares
Forward Contract Indexed to Issuer's Equity [Line Items]
Equity Issuance, Date	Nov. 10, 2010
Stock Issued During Period, Value, New Issues \| $	$ 119,630
Parent [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Sale of Stock, Transaction Date	Nov. 01, 2011
Stock Issued During Period, Value, New Issues \| $	$ 119,600
Parent [Member] \| Forward Equity Agreement Over Allotment Shares [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Equity Issuance OverAllotment \| shares	413,519
Parent [Member] \| Forward Equity Agreement [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares \| shares	4,000,000
Common Stock [Member]
Forward Contract Indexed to Issuer's Equity [Line Items]
Stock Issued During Period, Shares, New Issues \| shares	4,413,519
Stock Issued During Period, Value, New Issues \| $	$ 4,414

Common Stock Equity Compensation Plans Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years shares	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity Compensation Plans, Number of Shares Available for Grant \| shares	961,476
Equity Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 7,100
Equity Compensation, Nonvested Awards, Weighted Average Period for Recognition \| years	1.8
Stock-based compensation expense	$ 5,643	$ 5,637	$ 3,908
Parent [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense	$ 5,643	$ 5,637	$ 3,908

Common Stock Stock Option Activity (Details)
$ / shares in Units, shares in Thousands, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

USD ($)

years

$ / shares

Dec. 31, 2011

USD ($)

years

$ / shares

Dec. 31, 2010

USD ($)

$ / shares

Dec. 31, 2009

USD ($)

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number | shares

165

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

Share-based Compensation Award, Options, Exercisable, Weighted Average Exercise Price

$ 29.57

Stock Options, Fair Value Assumptions, Risk Free Interest Rate

2.60%

Stock Options, Fair Value Assumptions, Expected Volatility Rate

29.00%

Stock Options, Fair Value Assumptions, Expected Dividend Rate

4.60%

Stock Options, Fair Value Assumptions, Expected Term | years

Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $

$ 7,100

Employee Stock Option [Member]

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

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

$ 5.8

Share-based Compensation Award, Award Vesting Period, Maximum

P3Y

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, Number Period Start | shares

235

Share-based Compensation, Options, Grants in Period | shares

Share-based Compensation Award, Options, Forfeitures in Period | shares

(6)

Share-based Compensation Award, Options, Expirations in Period | shares

(31)

Share-based Compensation Award, Options, Exercises in Period | shares

(33)

Share-based Compensation Award, Options, Outstanding, Number, Period End | shares

264

235

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

$ 32.92

Share-based Compensation Award, Options, Grants in Period, Weighted Average Exercise Price

^[1]

$ 32.04

32.04

Share-based Compensation Award, Options, Forfeitures in Period, Weighted Average Exercise Price

0.00

Share-based Compensation Award, Options, Expirations in Period, Weighted Average Exercise Price

53.51

Share-based Compensation Award, Options, Exercises in Period, Weighted Average Exercise Price

30.32

Share-based Compensation Award, Options, Outstanding, Weighted Average Exercise Price, Period End

$ 30.50

$ 32.92

Share-based Compensation Award, Options, Exercisable, Weighted Average Remaining Contractual Term | years

4.51

Share-based Compensation Award, Options, Exercisable, Intrinsic Value | $

$ 859

Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized | $

$ 479

479

$ 0

Stock Options, Options, Exercises in Period, Total Intrinsic Value | $

^[2]

234

255

Stock Options, Cash Received from Exercise of Stock Options | $

1,009

1,034

1,740

Stock Options, Tax Benefit Realized from Exercise of Stock Options | $

^[3]

$ 33

$ 82

$ 89

Share-based Compensation Award, Award Vesting Period

2 years 4 months

[1]	The grant date fair value of the 2011 awards was $5.80 based on a Black-Scholes option pricing model. Assumptions used to estimate the fair value were a 2.6% risk free interest rate, 29.0% expected price volatility, 4.6% expected dividend yield and a 7 year expected life.
[2]	The intrinsic value represents the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option.
[3]	The tax benefit realized from the exercise of shares granted was recorded as an increase in equity.

Common Stock Restricted Stock and Restricted Stock Units (Details) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares
Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock Restrcited Stock Units, Weighted Average Price [Roll Forward]
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 7,100
Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Period for Recognition \| years	1.8
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, Equity Instruments Other than Options, Nonvested, Number, Period Start \| shares	270
Restricted Stock and RSUs, Grants in Period \| shares	139
Restricted Stock and RSUs, Vested in Period \| shares	(113)
Restricted Stock and RSUs, Forfeited in Period \| shares	(18)
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Number, Period End \| shares	278	270
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 \| $ / shares	$ 27.78
Restricted Stock and RSUs, Grants in Period, Weighted Average Grant Date Fair Value \| $ / shares	30.33	$ 27.30	$ 26.76
Restricted Stock and RSUs, Vested in Period, Weighted Average Grant Date Fair Value \| $ / shares	28.43
Restricted Stock or RSUs, Forfeitures and Expirations in Period, Weighted Average Exercise Price \| $ / shares	27.36
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End \| $ / shares	$ 28.82	$ 27.78
Restricted Stock and RSUs, Vested in Period, Total Fair Value \| $	$ 3,211	$ 2,212	$ 1,799
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 4,700
Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Period for Recognition \| years	1.8

Common Stock Performance Shares (Details) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) years $ / shares shares	Dec. 31, 2010 USD ($) $ / shares shares	Dec. 31, 2009 USD ($) $ / shares shares	Dec. 31, 2008
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target, Minimum	0.00%
Performance Share Award, Percentage of Target, Maximum	175.00%
Performance Share Award Payout, Cash Percentage	50.00%
Performance Share Award Payout, Shares of Common Stock Percentage	50.00%
Performance Shares Expected Volatility, Historical Cost	50.00%
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares Issued During Period, Shares, Treasury Stock Reissued	0	0	0
Performance Shares, Total Share-based Liabilities Paid \| $		$ 0	$ 0
Performance Shares, Vested in Period, Total Intrinsic Value \| $		$ 0	$ 0
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 7,100
Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Period for Recognition \| years	1.8
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, Period Start	87
Performance Shares, Grants in Period	34
Performance Shares, Forfeited in Period	(3)
Performance Shares, Vested in Period	(12)
Performance Shares, Number of Shares Authorized, Period End	106	87
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 \| $ / shares	$ 29.47
Share-based Compensation Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value \| $ / shares	25.92
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period, Weighted Average Grant Date Fair Value \| $ / shares	25.77
Peformance Shares, Vested in Period, Weighted Average Grant Date Fair Value \| $ / shares	46
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End \| $ / shares	$ 26.47	$ 29.47
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, Period Start	87
Performance Shares, Grants in Period	34
Performance Shares, Forfeited in Period	(3)
Performance Shares, Vested in Period	(12)
Performance Shares, Number of Shares Authorized, Period End	106	87
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Share-based Compensation Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value \| $ / shares	$ 20.89
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Plan, Equity Portion \| $	$ 1,900
Performance Shares, Fair Value Assumptions, Weighted Average Volatility Rate	30.00%	31.00%	39.00%
Performance Shares Expected Volatility, Implied Cost	50.00%
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Period Start	71	67
Performance Shares, Number of Shares Authorized, Period End	73	71	67
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 \| $ / shares	$ 24.26	$ 29.20
Share-based Compensation Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End \| $ / shares	$ 25.92	$ 24.26	$ 29.20
Performance Shares, Award Requisite Service Period	Jan. NaN, 2011	Jan. NaN, 2010	Jan. NaN, 2009	Jan. NaN, 2008
Performance Shares Employee Benefits and Share-based Compensation \| $	$ 0
Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized \| $	$ 1,900
Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Period for Recognition \| years	1.6
Change of Control Event Provision [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award Payout, Cash Percentage	100.00%

Common Stock Dividend Reinvestment and Stock Purchase Plan (Details) - DRIP [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
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	103	106
Share-based Compensation Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 31.23	$ 29.57
Stock Unissued Shares Dividend Reinvestment Plan	453	190

Common Stock Short-Term Incentive Plan (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Short Term Incentive Plan, Vested in Period, Total Intrinsic Value		$ 0	$ 0
Short-term Incentive Plan Expected in Future Year, Total Intrinsic Value	$ 100
Short Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Short-Term Incentive Plan, Shares Issued in Period	14,111	9,625	47,331
Short Term Incentive Plan, Vested in Period, Total Intrinsic Value	$ 400

Common Stock Dividend Restrictions Subsidiaries (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)
Utilities Group [Member]
Restriction to Transfer Funds	No dividend is permitted if it would reduce the equity ratio of Black Hills Energy entities to below 40% of their total capitalization
Amount of Restricted Net Assets for Subsidiaries	$ 61.5
Non Regulated Energy Group [Member]
Amount of Restricted Net Assets for Subsidiaries	100.0
Restricted Cash and Cash Equivalents, Current	$ 9.3
Cheyenne Light [Member]
Debt Instrument, Covenant Description	Debt capitalization requirement of 0.60 to 1.00

Impairment of Long-Lived Assets Impairment of Long-Lived Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) $ / bbl $ / MMcf	Dec. 31, 2010 USD ($) $ / bbl $ / MMcf	Dec. 31, 2009 USD ($) $ / bbl $ / MMcf	Mar. 31, 2009 $ / bbl $ / MMcf
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of long-lived assets \| $	$ 0	$ 0	$ 43,301
Natural Gas Price Per MCF, NYMEX \| $ / MMcf	4.12	4.38	3.87	3.63
Natural Gas Price Per MCF, Wellhead \| $ / MMcf	3.59	3.45	2.52	2.23
Crude Oil Price, per Barrel, NYMEX \| $ / bbl	96.19	79.43	61.18	49.66
Crude Oil Price Per Barrel, Wellhead \| $ / bbl	88.49	70.82	53.59	45.32

Operating Leases Operating Lease (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Operating Leased Assets [Line Items]
Operating Leases, Rent Expense	$ 6,125	$ 4,219	$ 3,939
Operating Leases, Future Minimum Payments Due, Current	2,799
Operating Leases, Future Minimum Payments, Due in Two Years	2,398
Operating Leases, Future Minimum Payments, Due in Three Years	2,376
Operating Leases, Future Minimum Payments, Due in Four Years	1,912
Operating Leases, Future Minimum Payments, Due in Five Years	1,403
Operating Leases, Future Minimum Payments, Due Thereafter	3,610
Operating Leases, Future Minimum Payments Due	$ 14,498

Income Taxes Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Income Tax Expense (Benefit) [Line Items]
Current Federal Tax Expense (Benefit)	$ (14,539)	$ 678	$ (12,351)
Current State Income Tax Expense (Benefit)	(837)	4,137	(408)
Current Income Tax Expense (Benefit)	(15,376)	4,815	(12,759)
Deferred Federal Income Tax Expense (Benefit)	30,876	20,186	45,912
Deferred State Income Tax Expense (Benefit)	2,970	(2,495)	66
Tax Credit Amortization Expense (Benefit)	(246)	(337)	(368)
Deferred income tax expense (benefit)	33,600	17,354	45,610
Income tax expense (benefit)	$ 18,224	22,169	$ 32,851
Like-King Exchange [Member]
Income Tax Expense (Benefit) [Line Items]
Deferred income tax expense (benefit)		$ 125,000		$ 185,000

Income Taxes Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Deferred Tax Assets, Net [Abstract]
Deferred Tax Assets, Asset Valuation Reserve	$ 2,605	$ 1,448
Deferred Tax Asset, Unbilled Revenues	0	0
Deferred Tax Asset, Mining Development and Oil Operations	614	594
Deferred Tax Assets, Employee Benefits	8,175	3,899
Deferred Tax Assets, Other Comprehensive (Loss)	2,858	3,076
Deferred Tax Assets, Derivative Fair Value Adjustments	33,824	19,304
Deferred Tax Assets, Deferred Costs	97	342
Deferred Tax Assets, Other	4,493	5,607
Total Deferred Tax Assets, Gross, Current	52,666	34,270
Deferred Tax Liabilities, Asset Valuation Reserves	0	(312)
Deferred Tax Liability, Prepaid Expenses	(2,442)	(2,431)
Deferred Tax Liabilities, Derivative Fair Value Adjustments	(362)	(327)
Deferred Tax Liabilities, Other Comprehensive Income (Loss)	(3,035)	(2,754)
Deferred Tax Liabilities, Deferred Costs	(6,508)	(4,621)
Deferred Tax Liabilities, Other Current	(3,117)	(3,161)
Total Deferred Tax Liabilities, Current	(15,464)	(13,606)
Net Deferred Tax Assets (Liabilities), Current	37,202	20,664
Deferred Tax Liabilities [Abstract]
Deferred Tax Asset Non-current, Employee Benefits	14,313	11,533
Deferred Tax Assets, Regulatory Assets and Liabilities	40,642	23,910
Deferred Tax Assets, Deferred Revenue	225	273
Deferred Tax Assets Non-current, Deferred Costs	0	0
Deferred Tax Assets Non-current, State Net Operating Loss	11,538	9,507
Deferred Tax Assets non-current, Items of Other Comprehensive Income	33,540	22,306
Deferred Tax Assets, Foreign Tax Credit Carryover	2,801	3,352
Deferred Tax Asset, Non-current, Net Operating Loss	195,834	63,779
Deferred Tax Assets, Non-current, Asset Impairment	47,033	48,092
Deferred Tax Assets Non-current, Derivative Fair Value Adjustment	5,275	3,038
Deferred Tax Assets non-current, Other	9,453	11,076
Total Deferred Tax Assets, Net, Noncurrent	360,654	196,866
Deferred Tax Liabilities Non-current, Accelerated Depreciation, Amortization and Other Plant-Related Differences	(508,261)	(314,513)
Deferred Tax Liabilities Non-current, Regulatory Assets	(23,498)	(16,050)
Deferred Tax Liabilities Non-current, Mining Development and Oil Exploration	(94,334)	(99,709)
Deferred Tax Liabilities Non-current, Deferred Costs	(9,155)	(17,615)
Deferred Tax Liabilities Non-current, erivative Fair Value Adjustments	0	0
Deferred Tax Liability Non-current, Items of Other Comprehensive Income	(2,054)	(4,402)
Deferred Tax Liability Non-current, State Deferred Tax Liability	(14,611)	(11,477)
Deferred Tax Liabilities Non-current, Other Deferred Tax Liabilities	(9,729)	(8,942)
Total Deferred Tax Liabilities, Noncurrent	(661,642)	(472,708)
Net Deferred Tax Liabilities, Net, Noncurrent	(300,988)	(275,842)
Net Deferred Tax Assets (Liabilities)	$ (263,786)	$ (255,178)

Income Taxes Reconciliation of Deferred Tax Liability to Deferred Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of deferred tax liability, net to deferred tax expense [Line Items]
Net Increase (Decrease) in Net Deferred Income Tax Liabilities	$ 8,608	$ 414
Deferred Tax Associated With Other Comprehensive Income	2,259	1,915
Deferred Liability Related to Net Operating Loss from Acquisition	0	(312)
Deferred Tax Liability Related to Regulatory Assets and Liabilities	22,962	25,511
Deferred Taxes Related to Acquisition	0	(784)
Deferred Taxes Associated with Property Basis Differences	(14)	(10,121)
Other Deferred Net Income Tax	(215)	731
Deferred income tax expense (benefit)	$ 33,600	$ 17,354	$ 45,610

The component of income tax expense for the period representing the increase (decrease) in the entity's deferred tax assets and liabilities pertaining to continuing operations.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 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 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 45
-Subparagraph 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 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SAB TOPIC 6.I.7)
-URI http://asc.fasb.org/extlink&oid=6889476&loc=d3e330036-122817

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Deferred Tax Expense (or Benefit)
-URI http://asc.fasb.org/extlink&oid=6510177

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 289
-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 SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 6
-Section I
-Subsection 7

Effective Tax Rate Reconciliation [Line Items]

Income Taxes Effective tax rate differences from statutory tax rates (Details)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Effective Income Tax Rate Reconciliation, Federal Statutory Rate

35.00%

Effective Income Tax Rate Reconciliation, State and Local Income Taxes

1.80%

1.10%

(0.30%)

Effective Income Tax Rate Reconciliation, Amortization Of Excess Deferred and Investment Tax Credits

(0.50%)

(0.40%)

(0.30%)

Effective Income Tax Rate Income Tax Reconciliation, Percentage Depletion In Excess of Cost

(2.50%)

(1.70%)

(0.80%)

Effective Income Tax Rate Reconciliation, Allowance For Other Funds Used During Construction

(0.50%)

(1.00%)

(1.70%)

Effective Income Tax Rate Reconciliation, Tax Credits

0.00%

(3.20%)

0.00%

Effective Income Tax Rate Reconciliation, Accounting for Uncertain Tax Position Adjustments

2.80%

1.20%

(2.10%)

Effective Income Tax Rate Reconciliation, Flow Through Adjustments

^[1]

(4.50%)

(4.60%)

0.00%

Effective Income Tax Rate Reconciliation, Other Tax Differences

(0.50%)

(0.40%)

(0.30%)

Effective Income Tax Rate, Continuing Operations

31.10%

26.00%

29.50%

[1]

Income Taxes Net Operating Loss Carryforwards (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($)
NOL Years Through 2019 [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	2014-2019
NOL 2026 Through 2031 [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	2026-2031
NOL 2020 through 2025 [Member]
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, Expiration Dates	2020-2025
Net Operating Loss Carryforward [Member] \| NOL Years Through 2019 [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	$ 9,306
Net Operating Loss Carryforward [Member] \| NOL 2026 Through 2031 [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	890,861
Net Operating Loss Carryforward [Member] \| NOL 2020 through 2025 [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	48,229
Internal Revenue Service (IRS) [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	534,800
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Asset Operating Loss Carryforward, Federal	413,600
Operating Loss Carryforwards, Valuation Allowance	$ 800

Income Taxes Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 50,135	$ 107,088	$ 120,022
Unrecognized Tax Benefits, Increases Resulting from Additions for Prior Period Tax Positions	2,725	19,592	5,752
Unrecognized Tax Benefits, Decreases Resulting from Reductions for Prior Period Tax Positions	(3,533)	(76,545)	(18,686)
Unrecognized Tax Benefits, Increases Resulting from Additions for Current Year Tax Positions	0	0	0
Unrecognized Tax Benefits, Increases Decreases Resulting from Settlements	0	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	49,327	50,135	107,088
Income Tax Examination, Liability (Refund) Adjustment from Settlement with Taxing Authority	0	0	(59,136)
Liabilities for Uncertain Tax Position, Net	49,327	$ 50,135	$ 47,952
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 1,100

Income Taxes Interest and penalties included in income tax expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Interest Expense in Income Tax Examination [Line Items]
Unrecognized Tax Benefits, Interest Expense (Income) Included in Income Tax (Expense) Benefit	$ 1,400	$ 2,300	$ 1,200
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	$ 4,500	$ 3,100
Income Tax Examination, Year(s) under Examination	2007 through 2009

Income Taxes Foreign Tax Credits (Details) - Foreign Tax Credit Carryforward [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($)
Tax Credit Expiration, More Than Two Years Within Three Years of Balance Sheet [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 26
Tax Credit Carryforward, Expiration Dates	2014
Tax Credit Expiration, More Than Three Years Within Four Years of Balance Sheet [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 694
Tax Credit Carryforward, Expiration Dates	2015
Tax Credit Expiration, More Than Four Years Within Five Years of Balance Sheet [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 24
Tax Credit Carryforward, Expiration Dates	2016
Tax Credit Expiration, More Than Five Years Within Six Years of Balance Sheet [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 1,301
Tax Credit Carryforward, Expiration Dates	2017
Tax Credit Expiration, More Than Eight Years Within Nine Years of Balance Sheet [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 214
Tax Credit Carryforward, Expiration Dates	2020
Tax Credit Expiration, More Than Nine Years Within Ten Years of Balance Sheet [Member]
Tax Credit Carryforward [Line Items]
Other Tax Carryforward, Gross Amount	$ 542
Tax Credit Carryforward, Expiration Dates	2021

Comprehensive Income Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other comprehensive income (loss), net of tax:
Benefit Plan Liability Adjustments - Net Gains (Losses), before Tax	$ (11,744)	$ (1,981)	$ (2,313)
Benefit Plan Liability Adjustments, Accumulated Other Comprehensive Income (Loss), Prior Service (Costs), before Tax	(501)	(325)	9,202
Benefit Plan Liability Adjustment, Transition Obligation, before Tax			33
Fair value adjustment on derivatives designated as cash flow hedges	(4,539)	1,972	(27,442)
Reclassification adjustments on cash flow hedges settled and included in net income (loss)	2,177	(6,730)	19,810
Comprehensive Income (Loss), Before Tax	(14,607)	(7,064)	(710)
Benefit Plan Liability Adjustment, Net Gains (Losses), Tax	4,135	674	812
Benefit Plan Liability Adjustment, Prior Service (Costs), Tax	176	111	(3,231)
Benefit Plan Liability Adjustment, Transition Obligation, Tax			(12)
Fair Value Adjustment of Derivative Designated As CashFlow Hedges, Tax	1,708	(636)	9,961
Reclassification Adjustment of Cash Flow Hedges Settled and Included In Net Income	(709)	2,498	(7,201)
Comprehensive Income (Loss), Tax	5,310	2,647	329
Benefit Plan Liability Adjustments, Net Gains (Losses), Net of Tax	(7,609)	(1,307)	(1,501)
Benefit Plan Liabilities, Prior Service (Costs), Net of Tax	(325)	(214)	5,971
Benefit Plan Liaiblities, Transition Obligation, Net of Tax			21
Fair value adjustment on derivatives designated as cash flow hedges, net of tax	(2,831)	1,336	(17,481)
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax	1,468	(4,232)	12,609
Comprehensive Income (Loss), Net of Tax	$ (9,297)	$ (4,417)	$ (381)

Comprehensive Income Comprehensive Income (Loss) Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (23,581)	$ (19,164)
Comprehensive Income (Loss), Net of Tax	(9,297)	(4,417)	$ (381)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(32,878)	(23,581)	(19,164)
Cash Flow Hedging [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(12,437)	(9,462)
Comprehensive Income (Loss), Net of Tax	(1,363)	(2,975)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(13,800)	(12,437)	(9,462)
Equity Method Investee [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(2)	(66)
Comprehensive Income (Loss), Net of Tax	0	64
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(2)	(2)	(66)
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(11,142)	(9,636)
Comprehensive Income (Loss), Net of Tax	(7,934)	(1,506)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	$ (19,076)	$ (11,142)	$ (9,636)

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.

Supplemental Cash Flow Information Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Property, plant and equipment acquired with accrued liabilities	$ 37,529	$ 48,879	$ 24,571
Non-cash Revision to Capitalized Asset Retirement Costs	1,525	1,858	6,027
Non-cash Refinancing of Debt, Industrial Development Revenue Bonds	0	0	17,000
Interest (net of amounts capitalized)	(103,110)	(101,947)	(69,317)
Income taxes, net	$ 9,854	$ 9,384	$ 17,117

Business Segments Segment Assets (Details) - USD ($)
$ in Thousands

Dec. 31, 2011

Dec. 31, 2010

$ 4,127,083

$ 3,711,509

^[1]

2,254,914

1,834,019

746,444

722,287

425,970

349,991

^[1]

129,121

293,334

88,704

96,962

Discontinued Operation or Asset Disposal [Member]

141,079

100,681

$ 340,851

$ 314,235

[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, 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, 2011

Dec. 31, 2010

Property, Plant and Equipment, Gross, Period Increase (Decrease)

$ 431,707

$ 496,990

Property, Plant and Equipment, Gross, Period Increase (Decrease)

173,078

232,466

Property, Plant and Equipment, Gross, Period Increase (Decrease)

43,954

51,363

Property, Plant and Equipment, Gross, Period Increase (Decrease)

89,672

40,345

Property, Plant and Equipment, Gross, Period Increase (Decrease)

98,927

148,191

Property, Plant and Equipment, Gross, Period Increase (Decrease)

10,438

17,053

Property, Plant and Equipment, Gross, Period Increase (Decrease)

13,279

7,182

Segment, Continuing Operations [Member]

Property, Plant and Equipment, Gross, Period Increase (Decrease)

^[1]

429,348

496,600

Discontinued Operation or Asset Disposal [Member]

Property, Plant and Equipment, Gross, Period Increase (Decrease)

$ 2,359

$ 390

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

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

Dec. 31, 2011

Dec. 31, 2010

$ 3,724,016

$ 3,353,509

^[1]

2,149,151

1,720,909

523,374

502,360

763,645

680,407

^[1]

135,981

297,907

145,024

145,385

$ 6,841

$ 6,541

[1]

Business Segments Information Relating to Segments Statement of Income (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

$ 1,272,188

$ 1,215,070

^[1]

$ 1,198,226

^[2]

4,621

^[1]

486

574,989

566,967

^[1]

595,240

697,199

652,724

603,472

375,369

351,619

341,049

$ (6,200)

$ (2,700)

(8,921)

^[3]

(25,971)

135,591

126,606

120,938

43,301

$ 52,140

$ 39,572

$ 36,160

$ 58,367

$ 46,857

^[4]

44,695

^[4]

$ 27,170

^[4]

64,698

^[4]

186,239

183,420

124,155

(91,383)

(90,606)

(83,253)

(42,010)

(15,193)

55,653

2,017

541

923

3,726

7,148

12,642

(18,224)

(22,169)

(32,851)

$ 18,754

$ (11,163)

$ 3,706

$ 29,068

$ 34,631

$ 10,493

$ (10,688)

$ 28,705

40,365

63,141

77,269

600,935

554,617

^[1]

511,326

^[2]

13,396

15,397

^[1]

9,439

310,352

292,811

^[1]

281,009

303,979

277,203

239,756

142,815

136,873

125,150

(768)

^[5]

(6,238)

^[3]

52,475

47,276

43,638

109,457

99,292

70,968

(53,770)

(43,855)

(34,830)

14,794

6,812

1,818

481

3,215

7,869

(23,271)

(18,012)

(13,126)

47,691

47,452

32,699

554,584

550,707

^[1]

580,312

^[2]

^[1]

331,961

333,717

^[1]

371,716

222,623

216,990

208,596

121,980

125,447

123,296

(2,683)

^[3]

24,307

25,258

30,090

76,336

68,968

55,210

(31,621)

(28,927)

(17,364)

5,645

1,472

264

217

(285)

(16,408)

(14,449)

(13,453)

34,169

27,111

24,372

4,059

4,297

^[1]

4,445

^[2]

27,613

26,052

^[1]

26,130

^[1]

31,672

30,349

30,575

16,538

16,210

12,631

^[3]

(25,971)

^[6]

4,199

4,466

3,860

10,935

9,673

40,055

(8,903)

(9,303)

(11,244)

1,529

1,193

1,856

1,094

854

1,091

(1,644)

(266)

(11,097)

3,011

2,151

20,661

32,802

31,285

^[1]

31,459

^[2]

34,090

26,557

^[1]

27,031

^[1]

66,892

57,842

58,490

56,617

34,028

40,312

^[3]

18,670

19,083

13,123

(8,395)

4,731

5,055

(9)

(177)

(24)

3,897

3,357

1,476

2,192

2,149

3,475

1,891

(2,379)

(3,234)

(424)

7,681

6,748

79,808

74,164

^[1]

70,684

^[2]

^[1]

^[1]

79,808

74,164

70,684

41,380

39,299

40,224

^[3]

35,690

30,283

29,680

^[7]

43,301

2,738

4,582

(42,521)

(5,896)

(5,380)

(4,683)

(216)

722

350

1,651

425

21,016

(1,721)

357

(25,828)

^[1]

^[2]

192,250

140,756

^[1]

97,010

150

^[1]

192,153

140,606

97,009

170,947

129,641

95,184

^[3]

11,205

9,469

6,933

10,000

1,496

(5,108)

(93,314)

(75,406)

(47,522)

(42,010)

(15,193)

55,653

64,299

54,472

27,531

46,510

28,768

12,201

19,289

12,512

(12,957)

Intersegment Elimination [Member]

4,774

6,649

29,798

^[1]

^[2]

(267,349)

(204,141)

^[1]

(159,124)

(67,421)

(59,711)

^[1]

(57,486)

(199,928)

(144,430)

(101,638)

(174,908)

(129,879)

(95,748)

767

^[3]

(10,955)

(9,229)

(6,386)

(14,832)

(5,322)

496

102,130

72,442

32,414

(88,149)

(66,773)

(32,032)

(46,552)

(28,607)

(12,059)

268

Pension Plans, Defined Benefit [Member]

$ (47,135)

$ (28,260)

$ (11,181)

[1]	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).
[2]	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated (see Note 1).
[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]	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively.
[5]	Electric Utilities includes a gain on sale of assets to a related party which was eliminated in consolidation.
[6]	Includes a gain on sale to MEAN of an ownership interest in the Wygen I power generation facility (see Note 22).
[7]	As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets (see Note 12).

Employee Benefit Plans Narrative (Details) $ in Thousands	12 Months Ended
Employee Benefit Plans Narrative (Details) $ in Thousands	Dec. 31, 2011 USD ($) years	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Maximum Annual Contribution Per Employee, Percent	50.00%
Defined Contribution Plan, Requisite Service Period \| years	5
Defined Benefit Plan, Measurement Date	December 31
Not Full Vested [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	20.00%
Fully Vested [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	100.00%
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Funded Status of Plan	$ 104,000
Defined Benefit Plan, Fair Value of Plan Assets	221,722	$ 220,164	$ 176,503
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Funded Status of Plan	$ 30,000
Defined Benefit Plan Annual Vesting Percentage	20.00%
Share-based Compensation Award, Award Vesting Period, Maximum	5
Defined Benefit Plan, Fair Value of Plan Assets	$ 0
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Funded Status of Plan	46,000
Defined Benefit Plan, Fair Value of Plan Assets	$ 4,319	$ 4,564
Cheyenne Light [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan Curtailment Effective Date	Jan. 01, 2012

Employee Benefit Plans Target Plan Assets Allocation (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets	8.75%	9.25%
Defined Benefit Plan, Target Allocation Percentage of Assets, Equity Securities	64.00%	65.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Real Estate	3.00%	3.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Fixed Income	32.00%	31.00%
Defined Benefit Plan, Target Allocation Percentage of Assets, Other	1.00%	1.00%
Defined Benefit Plan, Target Asset Allocations, Total	(100.00%)	(100.00%)

Employee Benefit Plans Plan Contributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	$ 11,050	$ 30,015
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	12,483
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	4,963	5,198
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	4,250
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Contributions	956	894
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	1,110
Defined Contribution Plan, Company Retirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	2,440	2,022
Defined Contribution Plan, 401K [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Cost Recognized	$ 8,916	$ 7,900

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, 2011	Dec. 31, 2010
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period Start	$ 6,126	$ 5,844
Unrealized Gain Loss, Level 3, Defined Benefit Assets	917	282
Unobservable Inputs Reconciliation, Recurring Basis, Asset Value, Period End	$ 7,043	$ 6,126

Employee Benefit Plans Changes in Benefit Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Period Start	$ 280,623	$ 256,400
Defined Benefit Plan, Service Cost	5,421	6,131	$ 7,587
Defined Benefit Plan, Interest Cost	14,929	15,091	14,715
Defined Benefit Plan, Actuarial Net (Gains) Losses	36,543	13,663
Defined Benefit Plan, Plan Amendments	0	261
Defined Benefit Plan, Benefits Paid	(11,178)	(9,949)
Defined Benefit Plan, Curtailments	(394)	(974)
Defined Benefit Plan Medicare Part D	0	0
Defined Benefit Plan, Contributions by Plan Participants	0	0
Defined Benefit Plan, Benefit Obligation, Period End	325,944	280,623	256,400
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Period Start	24,725	21,611
Defined Benefit Plan, Service Cost	1,028	685
Defined Benefit Plan, Interest Cost	1,298	1,284
Defined Benefit Plan, Actuarial Net (Gains) Losses	4,128	2,039
Defined Benefit Plan, Plan Amendments	0	0
Defined Benefit Plan, Benefits Paid	(956)	(894)
Defined Benefit Plan, Curtailments	0	0
Defined Benefit Plan Medicare Part D	0	0
Defined Benefit Plan, Contributions by Plan Participants	0	0
Defined Benefit Plan, Benefit Obligation, Period End	30,223	24,725	21,611
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Defined Benefit Plan, Benefit Obligation, Period Start	46,304	46,396
Defined Benefit Plan, Service Cost	1,498	1,509	1,060
Defined Benefit Plan, Interest Cost	2,168	2,446	2,202
Defined Benefit Plan, Actuarial Net (Gains) Losses	3,017	961
Defined Benefit Plan, Plan Amendments	(160)	(2,239)
Defined Benefit Plan, Benefits Paid	(4,963)	(5,198)
Defined Benefit Plan, Curtailments	0	0
Defined Benefit Plan Medicare Part D	188	559
Defined Benefit Plan, Contributions by Plan Participants	2,089	1,870
Defined Benefit Plan, Benefit Obligation, Period End	$ 50,141	$ 46,304	$ 46,396

Employee Benefit Plans Changes in Plan Assets (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Defined Benefit Plan, Market Value of Plan Assets, Period Start

$ 220,164

$ 176,503

Defined Benefit Plan, Investment Income

1,686

23,595

Defined Benefit Plan, Employer Contributions

11,050

30,015

Defined Benefit Plan, Plan Administrative Expenses

(11,178)

(9,949)

Defined Benefit Plan, Market Value of Plan Assets, Period End

221,722

220,164

Supplemental Employee Retirement Plans, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Defined Benefit Plan, Market Value of Plan Assets, Period End

(956)

(894)

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Defined Benefit Plan, Market Value of Plan Assets, Period Start

4,564

2,089

1,870

Defined Benefit Plan, Market Value of Plan Assets, Period End

(4,963)

(5,198)

4,319

4,564

Defined Benefit Plan VEBA [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Defined Benefit Plan, Market Value of Plan Assets, Period Start

^[1]

4,564

4,717

Defined Benefit Plan, Investment Income

^[1]

Defined Benefit Plan, Employer Contributions

^[1]

2,087

2,493

^[1]

(1,366)

(1,205)

Defined Benefit Plan, Plan Administrative Expenses

^[1]

(3,713)

(3,847)

^[1]

(5)

Defined Benefit Plan, Market Value of Plan Assets, Period End

^[1]

4,319

4,564

Unfunded Benefit Plan [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Defined Benefit Plan, Market Value of Plan Assets, Period Start

Defined Benefit Plan, Investment Income

Defined Benefit Plan, Employer Contributions

Defined Benefit Plan, Plan Administrative Expenses

Defined Benefit Plan, Market Value of Plan Assets, Period End

$ 0

[1]	Asset of VEBA

Employee Benefit Plans Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	$ 242,130	$ 204,834
Non-current Liabilities, Defined Benefit Plans	177,480	124,709
Regulatory Liabilities, Defined Benefit Plans	124,448	88,554
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory Assets, Defined Benefit Plans	93,423	54,202
Current Liabilities, Defined Benefit Plans	0	0
Non-current Liabilities, Defined Benefit Plans	104,214	60,451
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	1,116	943
Non-current Liabilities, Defined Benefit Plans	30,953	23,782
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	9,161	7,896
Current Liabilities, Defined Benefit Plans	3,522	2,999
Non-current Liabilities, Defined Benefit Plans	42,313	38,561
Regulatory Liabilities, Defined Benefit Plans	$ 590	$ 1,050

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.

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Employee Benefit Plans Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Parent [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	$ 106,800	$ 90,301
Parent [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	23,023	19,153
Parent [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	14,313	12,101
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	184,345	160,217
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	446	454
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	25,842	25,080
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	5,731	4,462
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	$ 9,986	$ 9,121

Employee Benefit Plans Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	$ 5,421	$ 6,131	$ 7,587
Defined Benefit Plan, Interest Cost	14,929	15,091	14,715
Expected return on plan assets	(16,955)	(14,493)	(14,281)
Amortization of prior service cost	99	99	127
Amortization of transition obligation	0	0	0
Recognition of net actuarial loss (gain)	4,540	3,126	2,720
Curtailment Expense	13	57	322
Net periodic benefit expense	8,047	10,011	11,190
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	1,498	1,509	1,060
Defined Benefit Plan, Interest Cost	2,168	2,446	2,202
Expected return on plan assets	(164)	(208)	(226)
Amortization of prior service cost	(479)	(309)	(23)
Amortization of transition obligation	0	0	60
Recognition of net actuarial loss (gain)	677	636	(27)
Curtailment Expense	0	0	0
Net periodic benefit expense	3,700	4,074	3,046
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Service Cost	1,028	685	469
Defined Benefit Plan, Interest Cost	1,298	1,284	1,376
Expected return on plan assets	0	0	0
Amortization of prior service cost	3	3	1
Amortization of transition obligation	0	0	0
Recognition of net actuarial loss (gain)	510	285	589
Curtailment Expense	0	0	0
Net periodic benefit expense	$ 2,839	$ 2,257	$ 2,435

Employee Benefit Plans Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Pension Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	$ 11,472	$ 6,545
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Prior Service Cost Credit, After Tax	98	121
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Tranition Assets (Obligations), After Tax	0	0
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	11,570	6,666
Defined Benefit Plan, Amortization of Net Gains (Losses)	6,560
Defined Benefit Plan, Prior Service Cost (Credit)	58
Defined Benefit Plan, Transition Asset (Obligation)	0
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	6,618
Supplemental Employee Retirement Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	6,894	4,544
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Prior Service Cost Credit, After Tax	12	14
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Tranition Assets (Obligations), After Tax	0	0
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	6,906	4,558
Defined Benefit Plan, Amortization of Net Gains (Losses)	525
Defined Benefit Plan, Prior Service Cost (Credit)	2
Defined Benefit Plan, Transition Asset (Obligation)	0
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	527
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gain (Losses), After Tax	2,556	2,172
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Prior Service Cost Credit, After Tax	(1,956)	(2,276)
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Tranition Assets (Obligations), After Tax	0	0
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax	600	$ (104)
Defined Benefit Plan, Amortization of Net Gains (Losses)	577
Defined Benefit Plan, Prior Service Cost (Credit)	(325)
Defined Benefit Plan, Transition Asset (Obligation)	0
Total Net Periodic Benefit Cost Expected to be Recognized in Next Fiscal Year	$ 252

Employee Benefit Plans Defined Benefit Plans Assumptions (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Defined Benefit Plan, Assumptions, Expected Long-term Return on Assets

8.75%

9.25%

Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year

9.01%

9.51%

Defined Benefit Plan, Ultimate Health Care Cost Trend Rate

4.50%

Defined Benefit Plan, Year that Rate Reaches Ultimate Trend Rate

2028

2027

Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation

$ 2,720

Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components

184

Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation

(2,272)

Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components

$ (150)

Pension Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions, Rate of Increase in Compensation Levels

4.65%

5.48%

6.03%

3.77%

3.79%

4.20%

Defined Benefit Plan, Assumptions, Expected Long-term Return on Assets

^[1]

7.75%

8.00%

8.50%

Defined Benefit Plan, Assumptions, Rate of Compensation Increase

3.79%

4.20%

Supplemental Employee Retirement Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions, Rate of Increase in Compensation Levels

4.30%

4.95%

5.58%

5.00%

Defined Benefit Plan, Assumptions, Rate of Compensation Increase

5.00%

Other Postretirement Benefit Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions, Expected Long-term Return on Assets

4.42%

5.03%

5.68%

^[1]

4.00%

5.00%

Parent Company [Member] | Pension Plans, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Parent Company [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

5.50%

6.05%

6.25%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Parent Company [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

5.00%

6.10%

6.20%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Black Hills Energy [Member] | Pension Plans, Defined Benefit [Member]

5.00%

5.90%

6.10%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Black Hills Energy [Member] | Supplemental Employee Retirement Plans, Defined Benefit [Member]

5.40%

6.00%

6.25%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Black Hills Energy [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

4.40%

5.05%

5.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Cheyenne Light [Member] | Pension Plans, Defined Benefit [Member]

4.60%

5.15%

6.10%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Cheyenne Light [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]

5.55%

6.05%

6.20%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Scenario, Forecast [Member]

5.50%

6.00%

6.10%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions, Expected Long-term Return on Assets

7.25%

[1]	The expected rate of return on plan assets changed to 7.25% for the calculation of the 2012 net periodic pension cost.

Employee Benefit Plans Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2011 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	$ 12,484
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	13,181
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	13,953
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	14,823
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	15,694
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	93,852
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	1,110
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1,090
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,280
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,290
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,370
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	7,160
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	4,250
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	4,380
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	4,320
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	4,170
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	4,250
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 21,950

Commitments and Contingencies Commitments and Contingencies (Details)

12 Months Ended

Dec. 31, 2011

USD ($)

Dec. 31, 2010

USD ($)

Dec. 31, 2009

USD ($)

Investment Owned, Subject to Option, Price | $

2.55

Unrecorded Unconditional Purchase Obligation, Due within One Year | $

$ 199,811,000

Unrecorded Unconditional Purchase Obligation, Due within Two Years | $

123,600,000

Unrecorded Unconditional Purchase Obligation, Due within Three Years | $

73,145,000

Unrecorded Unconditional Purchase Obligation, Due within Four Years | $

70,140,000

Unrecorded Unconditional Purchase Obligation, Due within Five Years | $

46,568,000

Unrecorded Unconditional Purchase Obligation, Due after Five Years | $

$ 202,779,000

Cheyenne Light [Member]

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Mar. 31, 2013

Expiration Date of Contracts Maximum

P6Y

PacifiCorp Purchase Power Agreement [Member]

Long-term Contract To Sell Electric Power, Date of Contract Expiration

Dec. 31, 2023

Number of M W Capacity Purchased Under Long-term Contract

PacifiCorp Transmission [Member]

$ 12,515,000

$ 12,936,000

$ 11,862,000

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2023

Number of M W Capacity Purchased Under Long-term Contract

Happy Jack Wind Purchase Power Agreeement [Member]

$ 1,215,000

1,215,000

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Sep. 03, 2028

Number of M W Capacity Purchased Under Long-term Contract

Silver Sage Wind Power Purchase Agreement [Member]

$ 1,955,000

2,815,000

2,078,000

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Sep. 30, 2029

Number of M W Capacity Purchased Under Long-term Contract

Public Service of Colorado Purchase Power Agreement [Member]

$ 3,281,000

1,723,000

713,000

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2012

Number of M W Capacity Purchased Under Long-term Contract

Cargill Power Purchase Agreement [Member]

^[1]

$ 97,988,000

$ 110,575,000

$ 97,899,000

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Dec. 31, 2013

Number of M W Capacity Purchased Under Long-term Contract

Basin Electric [Member]

Long-term Contract for Purchase of Electric Power, Date of Contract Expiration

Mar. 13, 2013

Number of M W Capacity Purchased Under Long-term Contract

Wygen I Generating Facility [Member]

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

M D U, Montana Dakota Utilities [Member] | Wygen I I I [Member]

City Of Gillette [Member] | Wygen I I I [Member]

Basin Electric [Member] | Cheyenne Light [Member]

Purchase Power Contract, 5 M W [Member] | Black Hills Power [Member]

Long-term Contract To Sell Electric Power, Date of Contract Expiration

Apr. 01, 2015

Purchase Power Contract, 5 M W [Member] | M.E.A.N [Member] | Neil Simpson I I [Member]

Purchase Power Contract, 5 M W [Member] | M.E.A.N [Member] | Wygen I I I [Member]

Purchase Power Contract, 10 M W [Member] | Black Hills Power [Member]

Long-term Contract To Sell Electric Power, Date of Contract Expiration

May 31, 2023

Purchase Power Contract, 10 M W [Member] | M.E.A.N [Member] | Neil Simpson I I [Member]

Purchase Power Contract, 10 M W [Member] | M.E.A.N [Member] | Wygen I I I [Member]

Power purchased [Member]

Number of M W Capacity Purchased Under Long-term Contract

200

[1]	This PPA with PSCo expired on December 31, 2011 and was replaced with the facilities constructed by Colorado Electric at our Pueblo Airport Generation site and the facilities constructed by Black Hills Colorado IPP to support a new PPA with Colorado Electric.

Commitments and Contingencies Depreciation expense on asset retirement cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Asset Retirement Obligation Costs [Line Items]
Depreciation Expense On Capitalized Asset Retirement Costs	$ 5,212	$ 6,519	$ 1,993

Guarantees Guarantees (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2011

USD ($)

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 139,805

Parent [Member] | Electric Utilities [Member] | Capital Additions 180 MW Generation Facility Colorado Electric Utility [Member]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 56

^[1]

Parent [Member] | Electric Utilities [Member] | Wind Turbines [Member]

2012

^[1]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 33,264

^[2]

Parent [Member] | Coal [Member] | Surety Bonds [Member]

1/15/2013

^[2]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 18,601

^[3]

Parent [Member] | Power Generation [Member] | Capital Additions 200 MW Generation Facility Colorado IPP [Member]

Ongoing

^[3]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 384

^[4]

Parent [Member] | Gas Utilities [Member] | Natural Gas Storage and Transportation Supplier BP Energy [Member]

2012

^[4]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 70,000

^[5]

Parent [Member] | Gas Utilities [Member] | Natural Gas Transportation and Storage Supplier Colorado interstate [Member]

Ongoing

^[5]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 10,000

^[6]

Parent [Member] | Gas Utilities [Member] | Natural Gas Supplier Cross Timbers [Member]

7/31/2012

^[6]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 7,500

^[7]

6/30/2012

^[7]

[1]	We have issued two guarantees to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers. These are continuing guarantees which will terminate upon settlement of all obligations.
[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 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 have issued four guarantees to GE for payment obligations arising from contracts to purchase four LM6000 gas turbines for Black Hills Colorado IPP. These are continuous guarantees which will terminate upon settlement of all obligations.
[5]	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.
[6]	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 agreements.
[7]	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) Oil and Gas Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 Bcfe PUD_Location Wells Acres States	Dec. 31, 2011 Bcfe PUD_Location Wells Acres States	Dec. 31, 2011 Bcfe PUD_Location Wells Acres States	Dec. 31, 2011 USD ($) Bcfe PUD_Location Wells Acres States	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Reserve Quantities [Line Items]
Wells in Process of Drilling \| Wells	1,219	1,219	1,219	1,219
Gas and Oil Acreage, Leased \| Acres	328,643	328,643	328,643	328,643
Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries	35.2
Reserves Replaced			119.00%
Capital Expenditure for Proved Undeveloped Reserve \| $				$ 18,900
Revisions of Previous Quantity Estimates \| $				$ (58,211)	$ 27,513	$ (104,556)
Proved Developed Reserves (Mcfe)	32.4	32.4	32.4	32.4
Proved Undeveloped Reserve Locations \| PUD_Location	72	72	72	72
Changes in Estimated Future Development Costs \| $				$ 90,100
PUD Locations in Reserves for Five Or More Years \| PUD_Location	0	0	0	0
Developed Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Mcfe)	4.7	4.7	4.7	4.7
Proved Undeveloped Reserve Locations \| PUD_Location	9	9	9	9
Piceance Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	0.5	17
Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries	16.5
PUD Development, PUD location \| PUD_Location		3
PUD Reserves Developed, Volumes	12
Revisions of Previous Quantity Estimates \| $				$ 34,700
Proved Developed Reserves (Mcfe)	12.8	12.8	12.8	12.8
Proved Undeveloped Reserve Locations \| PUD_Location	4	4	4	4
Changes in Estimated Future Development Costs \| $				$ 26,700
Piceance Basin [Member] \| Proved Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(21.2)
Other Basins [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	1.2
Williston Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(0.4)
Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries	7
PUD Development, Percent by Basin			100.00%
PUD Development, PUD location \| PUD_Location		13
PUD Reserves Developed, Volumes	4.6
Proved Developed Reserves (Mcfe)	10.5	10.5	10.5	10.5
Proved Undeveloped Reserve Locations \| PUD_Location	33	33	33	33
Changes in Estimated Future Development Costs \| $				$ 46,300
San Juan Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	1.7
Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries	11.1
PUD Development, PUD location \| PUD_Location		2
PUD Reserves Developed, Volumes	7.5
Proved Developed Reserves (Mcfe)	8.1	8.1	8.1	8.1
Proved Undeveloped Reserve Locations \| PUD_Location	3	3	3	3
Changes in Estimated Future Development Costs \| $				$ 15,100
Powder River Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(0.7)
Wind River Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates \| PUD_Location		25
Revisions of Previous Quantity Estimates \| $				3,600
Wind River Basin [Member] \| Proved Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(2)
Bear Paw Uplift [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates \| PUD_Location		17
Revisions of Previous Quantity Estimates \| $				$ 800
Proved Developed Reserves (Mcfe)	1	1	1	1
Proved Undeveloped Reserve Locations \| PUD_Location	32	32	32	32
Changes in Estimated Future Development Costs \| $				$ 2,000
Bear Paw Uplift [Member] \| Proved Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	(0.5)
Cost And Commodity Price Revisions [Member]
Reserve Quantities [Line Items]
Revisions To Estimate, Percentage			1.00%
Oil and Gas [Member]
Reserve Quantities [Line Items]
Number of States in which Entity Operates \| States	9	9	9	9

Oil and Gas Reserves (Unaudited) Costs Incurred Oil and Gas (Details) - Oil and Gas [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves	$ 673	$ 0	$ 0
Costs Incurred, Acquisition of Oil and Gas Properties, Unproved	8,317	3,846	3,443
Costs Incurred, Exploration Costs	44,384	8,159	5,962
Costs Incurred, Development Costs	38,638	25,264	10,133
Asset Retirement Obligation, Liabilities Incurred	43	1,228	623
Total oil and gas costs incurred	$ 92,055	$ 38,497	$ 20,161

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)

12 Months Ended

Dec. 31, 2011

Bcfe

MBbls

MMcf

$ / bbl

$ / MMcf

Dec. 31, 2010

MBbls

MMcf

$ / bbl

$ / MMcf

Dec. 31, 2009

MBbls

MMcf

$ / bbl

$ / MMcf

Mar. 31, 2009

$ / bbl

$ / MMcf

Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries | Bcfe

35.2

Crude Oil Price Per Barrel, Wellhead | $ / bbl

88.49

70.82

53.59

45.32

Crude Oil Price, per Barrel, NYMEX | $ / bbl

96.19

79.43

61.18

49.66

Natural Gas Price Per MCF, NYMEX | $ / MMcf

4.12

4.38

3.87

3.63

Natural Gas Price Per MCF, Wellhead | $ / MMcf

3.59

3.45

2.52

2.23

Oil Reserves [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Net | MBbls

5,940,000

5,274,000

5,185,000

Proved Developed and Undeveloped Reserves, Production | MBbls

^[1]

(452,000)

(376,000)

(366,000)

Proved Developed and Undeveloped Reserves, Additions, Acquisitions (Sales) | MBbls

(84,000)

(13,000)

Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries | MBbls

927,000

1,145,000

152,000

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MBbls

(108,000)

^[2]

(90,000)

303,000

Proved Developed and Undeveloped Reserves, Net | MBbls

6,223,000

5,940,000

5,274,000

Proved Developed Reserves (Volume) | MBbls

4,830

4,434

4,274

Proved Undeveloped Reserve (Volume) | MBbls

1,393

1,506

1,000

Natural Gas Reserves [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Net | MMcf

95,456,000

87,660,000

154,432,000

Proved Developed and Undeveloped Reserves, Production | MMcf

^[1]

(8,526,000)

(8,484,000)

(9,710,000)

Proved Developed and Undeveloped Reserves, Additions, Acquisitions (Sales) | MMcf

(377,000)

Proved Developed and Undeveloped Reserves, Additions, Extensions, Discoveries | MMcf

29,664,000

1,710,000

2,560,000

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | MMcf

(20,690,000)

^[2]

14,947,000

(59,622,000)

Proved Developed and Undeveloped Reserves, Net | MMcf

95,904,000

95,456,000

87,660,000

Proved Developed Reserves (Volume) | MMcf

71,867

67,656

74,911

Proved Undeveloped Reserve (Volume) | MMcf

24,037

27,800

12,749

Oil and Gas Reserve Revisions, Five Year Aging Limit [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Bcfe

(23.6)

Oil and Gas Reserve Revisions, Performance [Member]

Proved Developed And Undevleoped Reserves [Roll Forward]

Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates | Bcfe

2.3

[1]	Production for reserve calculations does not include volumes for natural gas liquids (NGL's).
[2]	Included in the total revisions are (23.6) Bcfe for dropped PUD locations due to five year aging of reserves which was offset by positive performance revisions of 2.3 Bcfe in various basins. Revisions due to cost and commodity pricing were less than 1% Bcfe.

Oil and Gas Reserves (Unaudited) Capitalized Costs (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Capitalized Costs, Unproved Oil and Gas Properties	$ 28,656	$ 28,160	$ 29,351
Capitalized Costs, Proved Oil and Gas Properties	674,494	592,978	582,276
Gross Capitalized Costs, Oil and Gas Producing Activities	703,150	621,138	611,627
Capitalized Costs, Oil and Gas, Accumulated Depreciation, Depletion, Amortization and Valuation Allowance	(361,173)	(334,955)	(335,605)
Net Capitalized Costs, Oil and Gas Producing Activities	$ 341,977	$ 286,183	$ 276,022

Oil and Gas Reserves (Unaudited) Results of Operations Oil and Gas (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]

Results of Operations, Oil and Gas, Revenue

$ 79,808

$ 74,164

$ 70,684

Results of Operations, Oil and Gas, Production Costs

23,820

21,922

21,653

Results of Operations, Depreciation, Depletion and Amortization, and Valuation Provisions

34,415

29,013

72,338

^[1]

Results of Operations, Total Costs, Oil and Gas Producing Activities

58,235

50,935

93,991

Results of Operations from Oil and Gas Producing Activities, before Tax

21,573

23,229

(23,307)

Results of Operations, Income Tax (Expense) Benefit

(7,442)

(8,014)

8,041

Results of operations from producing activities (excluding general and admistrative costs and interest costs)

14,131

15,215

(15,266)

Commodity derivatives [Member]

$ 0

$ 43,301

[1]	Includes pre-tax ceiling test impairment charges of $43.3 million in 2009.

Oil and Gas Reserves (Unaudited) Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs, Period Cost	$ 24,899
Exploration Costs, Period Cost	16,745
Capitalized Interest Of Cost Excluded From Amortization	3,756
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	45,400
Current Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs, Period Cost	3,451
Exploration Costs, Period Cost	16,745
Capitalized Interest Of Cost Excluded From Amortization	291
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	20,487
Prior Year [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs, Period Cost	3,442
Exploration Costs, Period Cost	0
Capitalized Interest Of Cost Excluded From Amortization	404
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	3,846
More Than One Year, Less Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs, Period Cost	887
Exploration Costs, Period Cost	0
Capitalized Interest Of Cost Excluded From Amortization	55
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	942
More Than Two Years Prior [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition Costs, Period Cost	17,119
Exploration Costs, Period Cost	0
Capitalized Interest Of Cost Excluded From Amortization	3,006
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	20,125
Oil and Gas [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Interest Costs, Capitalized During Period	$ 869	$ 782	$ 322

Oil and Gas Reserves (Unaudited) Standard Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future Cash Flows, Proved Oil and Gas Reserves, Standardized Measure	$ 931,637	$ 764,585	$ 519,867
Future Cash Flows, Proved Oil and Gas Reserves, Future Production Costs	(280,910)	(256,455)	(207,783)
Future Cash Flows, Proved Oil and Gas Reserves, Future Development Costs	(92,233)	(73,805)	(34,961)
Future Cash Flows, Proved Oil and Gas Reserves, Future Income Tax Expense	(157,922)	(111,666)	(51,287)
Future Cash Flows, Proved Oil and Gas Reserves, Future Net Cash Flows	400,572	322,659	225,836
Future Cash Flows, Proved Oil and Gas Reserves, 10 Percent Annual Discount for Estimated Timing of Cash Flows	(197,215)	(154,551)	(96,728)
Standardized Measure of Discounted Future Net Cash Flow, Proved Oil and Gas Reserves, Period Increase (Decrease)	$ 203,357	$ 168,108	$ 129,108

Oil and Gas Reserves (Unaudited) Change in Standard Measure of Discounted Future Cash Net Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
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, Proved Oil and Gas Reserves, Period Start	$ 168,108	$ 129,108	$ 179,226
Sales and Transfers of Oil and Gas Produced, Net of Production Costs	(52,914)	(40,282)	(26,836)
Net Change in Prices and Production Costs	57,087	57,380	(40,786)
Extensions, Discoveries, Additions and Improved Recovery, Less Related Costs	31,179	17,076	3,324
Changes in Future Development Costs	43,809	(17,125)	83,000
Development Costs Incurred During Period	18,940	4,975	4,620
Revisions of Previous Quantity Estimates	(58,211)	27,513	(104,556)
Accretion of Discount	19,655	13,434	19,596
Changes in Income Taxes, Estimates on Future Cash Flows, Proved Oil and Gas Reserves	(23,283)	(23,233)	11,520
Increase Due to Purchases of Reserves	0	0	0
Decrease Due to Sales Reserves	(1,013)	(738)	0
Standardized Measure of Discounted Future Net Cash Flows, Proved Oil and Gas Reserves, Period End	$ 203,357	$ 168,108	$ 129,108

Sale of Operating Assets Sale of Operating Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Significant Acquisitions and Disposals [Line Items]
Disposal Date	first quarter of 2012
Gain (Loss) on Sale of Operating Assets	$ 0	$ 8,921	$ 25,971
Gas Utilities [Member]
Significant Acquisitions and Disposals [Line Items]
Disposal Date		3/1/2010
Proceeds from Sale of Property, Plant, and Equipment		$ 6,100
Gain (Loss) on Sale of Operating Assets		$ 2,700
Electric Utilities [Member]
Significant Acquisitions and Disposals [Line Items]
Disposal Date		7/14/2010	4/9/2009
Jointly Owned Utility Plant, Proportionate Ownership Share		23.00%	25.00%
Proceeds from Sale of Property, Plant, and Equipment		$ 62,000	$ 32,800
Property, Plant and Equipment, Disposals		55,800
Gain (Loss) on Sale of Operating Assets		$ 6,200
Power Generation [Member]
Significant Acquisitions and Disposals [Line Items]
Disposal Date			1/1/2009
Jointly Owned Utility Plant, Proportionate Ownership Share			23.50%
Proceeds from Sale of Property, Plant, and Equipment			$ 51,000
Property, Plant and Equipment, Disposals			25,000
Gain (Loss) on Sale of Operating Assets			$ 16,900

Discontinued Operations Narrative, Discontinued Operations (Details)	12 Months Ended
	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Date	first quarter of 2012

Discontinued Operations Balance Sheet and Income Statement of Discontinued Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]
Income (Loss) from Discontinued Operations, Net of Tax	$ 6,839	$ 638	$ 4,046	$ (2,158)	$ (1,111)	$ 1,897	$ 2,029	$ 2,729
Overhead Of Discontinued Operations									$ 3,418,000	$ 3,515,000	$ 3,753,000
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Assets Discontinued Operation	340,851				314,235				340,851	314,235
Energy Marketing [Member]
Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]
Discontinued Operation, Revenue									41,101	27,999	13,381
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax									14,838	8,673	1,950
Discontinued Operation, Tax Effect of Discontinued Operation									(5,473)	(3,129)	(464)
Income (Loss) from Discontinued Operations, Net of Tax									9,365	5,544	1,486
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Discontinued Operation, Other Current Assets	280,221				257,082				280,221	257,082
Discontinued Operations, Derivative Assets, Current and Non-Current	52,859				50,498				52,859	50,498
Discontinued Operation, Property, Plant, and Equipment, Net	5,828				3,699				5,828	3,699
Discontinued Operation, Goodwill	1,435				1,435				1,435	1,435
Discontinued Operation, Noncurrent	508				1,521				508	1,521
Discontinued Operation, Other Current Liabilities	(132,951)				(152,602)				(132,951)	(152,602)
Discontinued Operations, Derivative Liabilities, Current and Non-Current	(26,084)				(18,014)				(26,084)	(18,014)
Discontinued Operation, Other Noncurrent Liabilities	(14,894)				(2,707)				(14,894)	(2,707)
Assets Discontinued Operation	$ 166,922				$ 140,912				166,922	140,912
Electric Utilities [Member]
Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]
Overhead Of Discontinued Operations									1,613,000	1,650,000	1,666,000
Gas Utilities [Member]
Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]
Overhead Of Discontinued Operations									1,043,000	1,092,000	1,177,000
Oil and Gas [Member]
Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]
Overhead Of Discontinued Operations									407,000	435,000	538,000
Power Generation [Member]
Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]
Income (Loss) from Discontinued Operations, Net of Tax											2,439
Overhead Of Discontinued Operations									228,000	233,000	231,000
Coal Mining [Member]
Disposal Group, Not Discontinued Operation, Income Statement Disclosures [Abstract]
Overhead Of Discontinued Operations									$ 127,000	$ 105,000	$ 141,000

Discontinued Operations Fair Value Measurements of Discontinued Operations (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

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

Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period Start

$ 266

$ 381

Unrealized losses

1,318

303

Unrealized gains

751

188

Settlements

(96)

Transfers Into Level 3

^[1]

Transfers out of Level 3

^[2]

Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period End

(397)

266

Fair Value, Net Measured on Recurring Basis, Change in Unrealized Gain (Loss) Relating to Instruments Still Held as of Period End

(101)

(302)

Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Segment, Discontinued Operations [Member] | Energy Marketing [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]

166,571

Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

143,558

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

7,976

Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member]

2,463

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(122,639)

Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral [Member]

(122,639)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(1,410)

Segment, Discontinued Operations [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

(5,368)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

50,498

Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member]

18,014

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

Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period Start

5,513

(937)

Unrealized losses

(8,631)

(2,525)

Unrealized gains

6,094

7,295

Settlements

(2,248)

(1,179)

Transfers Into Level 3

^[1]

1,457

Transfers out of Level 3

^[2]

1,402

Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Net Value, Period End

728

5,513

Fair Value, Net Measured on Recurring Basis, Change in Unrealized Gain (Loss) Relating to Instruments Still Held as of Period End

(825)

1,078

Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [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]

789,537

166,405

Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

771,534

143,537

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

6,139

7,976

Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member]

5,411

2,463

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

(743,154)

(122,639)

Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral [Member]

(743,154)

(122,639)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

337

(1,410)

Segment, Discontinued Operations [Member] | Commodity derivatives [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

(7,707)

(5,368)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

52,859

50,332

Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]

26,084

17,993

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [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]

166

Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Counterparty Netting [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Cash Collateral [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member] | Energy Marketing [Member] | Fair Value, Measurements, Recurring [Member] | Total Estimate of Fair Value, Fair Value Disclosure [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

166

Designated as Hedging Instrument [Member]

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

10,658

10,548

Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member]

30,253

26,913

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

5,256

11,000

Not Designated as Hedging Instrument [Member]

403

1,568

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

Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member]

112,667

61,168

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

828,347

173,502

Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

807,187

154,408

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

55,413

142,013

Derivative Assets, Current [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

13,740

107,795

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

10,952

Derivative Assets, Noncurrent [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

1,452

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

Derivative Assets, Noncurrent [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

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

76,629

9,757

Derivative Liabilities, Current [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

54,784

3,099

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

5,256

Derivative Liabilities, Current [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

403

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

691,453

20,588

Derivative Liabilities, Current [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Foreign Exchange Contract [Member]

729,309

39,051

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

166

Derivative Liabilities, Noncurrent [Member] | Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

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

Derivative Liabilities, Noncurrent [Member] | Not Designated as Hedging Instrument [Member] | Segment, Discontinued Operations [Member] | Commodity derivatives [Member]

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

4,852

978

Selected Quarterly Financial Information [Line Items]

$ 9,354

$ 4,442

[1]	Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.
[2]	Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Quarterly Historical Data (Unaudited) Quarterly Historical Data (Unaudited) (Details) - USD ($)
$ / shares in Units, $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

$ 361,181

$ 249,523

$ 260,649

$ 400,835

$ 314,999

^[1]

$ 240,521

^[1]

$ 247,443

^[1]

$ 416,728

^[1]

$ 1,272,188

$ 1,219,691

$ 1,198,712

Income (Loss) from Continuing Operations

52,140

39,572

36,160

58,367

46,857

^[2]

44,695

^[2]

27,170

^[2]

64,698

^[2]

186,239

183,420

124,155

18,754

(11,163)

3,706

29,068

34,631

10,493

(10,688)

28,705

40,365

63,141

77,269

Income (Loss) from Discontinued Operations, Net of Tax

6,839

638

4,046

(2,158)

(1,111)

1,897

2,029

2,729

Income (loss) from continuing operations, per share

$ 25,593

^[3]

$ (10,525)

^[3]

$ 7,752

^[3]

$ 26,910

^[3]

$ 33,520

^[2],[4]

$ 12,390

^[2],[4]

$ (8,659)

^[2],[4]

$ 31,434

^[2],[4]

$ 49,730

$ 68,685

$ 81,555

$ 0.45

$ (0.29)

$ 0.09

$ 0.74

$ 0.89

$ 0.27

$ (0.27)

$ 0.74

$ 1.01

$ 1.62

$ 2

Income (loss) from discontinued operations, per share

0.16

0.02

0.11

(0.05)

(0.03)

0.05

0.07

0.24

0.14

0.11

Total Income (loss) per share, basic

0.61

(0.27)

0.2

0.69

0.86

0.32

(0.22)

0.81

1.25

1.76

2.11

Income (loss) from continuing operations, per share

0.44

(0.29)

0.09

0.73

0.88

0.27

(0.27)

0.74

1.01

1.62

Income (loss) from discontinued operations, per share

0.16

0.02

0.1

(0.05)

(0.03)

0.05

0.07

0.23

0.14

0.11

Total Income (loss) per share, per share, diluted

0.6

(0.27)

0.19

0.68

0.85

0.32

(0.22)

0.81

1.24

1.76

2.11

Common Stock, Dividends, Per Share

0.365

0.36

$ 1.46

$ 1.44

$ 1.42

Common Stock Prices Per Share, High

34.47

32.22

34.85

33.64

33.42

33.31

34.49

30.83

Common Stock Price Per Share, Low

$ 29.10

$ 25.83

$ 28.12

$ 29.76

$ 29.32

$ 27.79

$ 27.34

$ 25.65

Increase Decrease in Fair Value of Unhedged Derivative Instrument After Tax

$ (900)

$ (24,900)

$ (5,100)

$ 3,600

$ 17,200

$ (8,900)

$ (16,200)

$ (2,000)

Gain (Loss) on Sale of Operating Assets

6,200

2,700

$ 0

$ 8,921

^[5]

$ 25,971

Gain (Loss) on Disposition of Assets Net of Tax

$ 4,100

$ 1,700

[1]	Revenue has been restated to reflect eliminations of intercompany activities previously not eliminated. See Note 1.
[2]	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, 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]	Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 million after-tax in the first, second, third and fourth quarters, respectively.
[5]	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).

Subsequent Events Subsequent Events (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 18, 2012	Dec. 31, 2011
Discontinued Operation or Asset Disposal [Member]
Subsequent Event [Line Items]
Proceeds From Divesture of Business, Minimum		$ 160.0
Proceeds From Divesture Of Business, Maximum		170.0
Significant Acquisitions and Disposals, Date of Transaction for Acquisition or Disposal	Jan. 18, 2012
Revolving Credit Facility, Renegotiated [Member] \| Revolving Credit Facility, Renegotiated [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 500.0
Line of Credit Facility, Expiration Date		2/1/2017
Line of Credit Accordion Feature		$ 750.0
Line of Credit Facility, Commitment Fee Percentage		0.25%
Revolving Credit Facility, Renegotiated [Member] \| Line of Credit [Member] \| Parent [Member] \| Revolving Credit Facility, Existing [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 500.0
Revolving Credit Facility, Renegotiated [Member] \| Base Rate Option [Member] \| Revolving Credit Facility, Renegotiated [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Interest Rate at Period End		0.50%
Revolving Credit Facility, Renegotiated [Member] \| Eurodollar Option [Member] \| Revolving Credit Facility, Renegotiated [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Interest Rate at Period End		1.50%
Revolving Credit Facility, Renegotiated [Member] \| Letters of Credit [Member] \| Letters of Credit [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Interest Rate at Period End		1.50%

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Statement of Income for Parent Company Only (Details) - USD ($)
$ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Condensed Financial Statements, Captions [Line Items]

Operating expenses

$ 1,085,949

$ 1,036,271

$ 1,074,557

Equity in earnings (loss) in earnings of subsidiaries

$ 52,140

$ 39,572

$ 36,160

$ 58,367

$ 46,857

^[1]

$ 44,695

^[1]

$ 27,170

^[1]

$ 64,698

^[1]

186,239

183,420

124,155

Other income (expense):

1,121

1,559

1,343

(91,383)

(90,606)

(83,253)

(42,010)

(15,193)

55,653

2,017

541

923

Total other income (expense)

3,726

7,148

12,642

(128,771)

(99,669)

(15,378)

(18,224)

(22,169)

(32,851)

Income (loss) from discontinued operations, net of tax

18,754

(11,163)

3,706

29,068

34,631

10,493

(10,688)

28,705

40,365

63,141

77,269

6,839

638

4,046

(2,158)

(1,111)

1,897

2,029

2,729

$ 25,593

^[2]

$ (10,525)

^[2]

$ 7,752

^[2]

$ 26,910

^[2]

$ 33,520

^[1],[3]

$ 12,390

^[1],[3]

$ (8,659)

^[1],[3]

$ 31,434

^[1],[3]

49,730

68,685

81,555

Condensed Financial Statements, Captions [Line Items]

Operating expenses

772

735

524

Equity in earnings (loss) in earnings of subsidiaries

(772)

(735)

(524)

Other income (expense):

87,150

88,627

57,394

(15,229)

(14,985)

(17,786)

(42,010)

(15,193)

55,653

Total other income (expense)

(42)

29,872

58,505

95,299

Income (loss) from continuing operations before income taxes

29,100

57,770

94,775

20,630

10,915

(13,025)

Income (loss) from discontinued operations, net of tax

49,730

68,685

81,750

(195)

$ 49,730

$ 68,685

$ 81,555

[1]	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively.
[2]	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.
[3]	Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 million after-tax in the first, second, third and fourth quarters, respectively.

Schedule I Disclosures for Parent Company Only Schedule I, Condensed Balance Sheet for Parent Company Only (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Current assets:
Cash and cash equivalents	$ 21,628	$ 16,437
Deferred income tax assets, net, current	37,202	20,664
Other current assets	21,266	14,695
Total current assets	758,921	684,161
Property, Plant and Equipment, Net	2,789,575	2,491,734
Deferred Tax Assets, Net, Noncurrent	360,654	196,866
Other assets, non-current	19,941	19,339
Total other assets, non-current	561,326	517,834
TOTAL ASSETS	4,127,083	3,711,509
Current liabilities:
Accounts payable	104,748	146,556
Derivative liabilities, current	84,367	64,617
Notes payable	345,000	249,000
Total current liabilities	878,067	793,611
Derivative liabilities, non-current	49,033	17,897
Long-term debt, excluding current maturities	1,280,409	1,186,050
Stockholders' Equity Attributable to Parent	1,209,336	1,100,270	$ 1,084,837	$ 1,050,536
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	4,127,083	3,711,509
Parent [Member]
Current assets:
Cash and cash equivalents	3,114	219	$ 2,273	$ 17,184
Accounts receivable - affiliates, current	1,445	869
Notes receivable, affiliates, current	453,216	201,497
Deferred income tax assets, net, current	36,951	21,137
Other current assets	15,831	15,173
Total current assets	510,557	238,895
Property, Plant and Equipment, Net	1,135	0
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	1,339,024	1,269,123
Notes Receivable, Related Parties, Noncurrent	575,000	575,000
Deferred Tax Assets, Net, Noncurrent	29,454	44,587
Other assets, non-current	4,834	3,889
Total other assets, non-current	609,288	623,476
TOTAL ASSETS	2,460,004	2,131,494
Current liabilities:
Accounts payable	5,202	1,613
Derivative liabilities, current	78,502	57,343
Notes payable	345,000	249,000
Notes payable - affiliate, current	1,754	25,232
Other liabilities, current	12,070	12,109
Total current liabilities	442,528	345,297
Derivative liabilities, non-current	31,368	7,360
Long-term debt, excluding current maturities	774,959	674,930
Notes payable - affiliates, non-current	1,813	3,637
Total long-term debt	776,772	678,567
Stockholders' Equity Attributable to Parent	1,209,336	1,100,270
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 2,460,004	$ 2,131,494

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, 2011

Sep. 30, 2011

Jun. 30, 2011

Mar. 31, 2011

Dec. 31, 2010

Sep. 30, 2010

Jun. 30, 2010

Mar. 31, 2010

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2009

Dec. 31, 2008

Income (Loss) from Discontinued Operations, Net of Tax

$ 25,593

^[1]

$ (10,525)

^[1]

$ 7,752

^[1]

$ 26,910

^[1]

$ 33,520

^[2],[3]

$ 12,390

^[2],[3]

$ (8,659)

^[2],[3]

$ 31,434

^[2],[3]

$ 49,730

$ 68,685

$ 81,555

(6,839)

(638)

(4,046)

2,158

1,111

(1,897)

(2,029)

(2,729)

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

18,754

$ (11,163)

$ 3,706

$ 29,068

34,631

$ 10,493

$ (10,688)

$ 28,705

40,365

63,141

77,269

Equity in earnings (loss) in earnings of subsidiaries

(1,121)

(1,559)

(1,343)

Stock compensation

5,643

5,637

3,908

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

42,010

15,193

(55,653)

Derivative fair value adjustments

(8,693)

13,546

19,083

Deferred income tax expense (benefit)

33,600

17,354

45,610

Other adjustments

10,602

(3,851)

4,539

Changes in certain operating assets and liabilities:

Accounts receivable and other current assets

(4,202)

(18,480)

26,593

Other operating activities

(11,118)

(1,013)

7,091

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

216,694

156,565

303,912

Cash Provided by (Used in) Operating Activities, Discontinued Operations

(7,010)

8,813

33,410

Net cash provided by (used in) operating activities

(223,704)

(147,752)

(270,502)

Investing activities:

Payments for (Proceeds from) Other Investing Activities

(4,533)

15,407

(15,494)

Net cash provided by (used in) investing activities

(447,007)

(389,168)

(269,823)

Financing activities:

Common stock issued

123,041

3,246

4,819

Long-term debt - issuances

200,000

543,069

Other financing activities

(1,666)

(8,363)

(5,527)

Net cash provided by (used in) financing activities

249,633

160,953

(56,310)

Net change in cash and cash equivalents

26,330

(80,463)

(55,631)

Cash and cash equivalents, at carrying value

21,628

16,437

21,628

16,437

Income Taxes Paid, Net

(9,854)

(9,384)

(17,117)

Income (Loss) from Discontinued Operations, Net of Tax

49,730

68,685

81,555

195

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

49,730

68,685

81,750

Equity in earnings (loss) in earnings of subsidiaries

(87,150)

(88,627)

(57,394)

Cash Dividends Paid to Parent Company by Consolidated Subsidiaries

14,500

6,298

Stock compensation

5,643

5,637

3,908

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

42,010

15,193

(55,653)

Derivative fair value adjustments

2,291

(6,384)

1,461

Deferred income tax expense (benefit)

2,599

(34,452)

19,224

Other adjustments

4,376

2,508

(254)

Changes in certain operating assets and liabilities:

Accounts receivable and other current assets

(5,141)

2,198

41,237

Increase (Decrease) in Accounts Payable and Accrued Liabilities

3,550

4,846

(22,906)

Other operating activities

550

(2,514)

1,399

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

32,958

(26,612)

12,772

Cash Provided by (Used in) Operating Activities, Discontinued Operations

(195)

Net cash provided by (used in) operating activities

32,958

(26,612)

12,577

Investing activities:

Payments to Acquire Property, Plant, and Equipment

(1,135)

Proceeds from (Repayments of) Related Party Debt

(258,117)

(216,337)

(115,731)

Payments for (Proceeds from) Other Investing Activities

Net cash provided by (used in) investing activities

(259,252)

(216,337)

(115,731)

Financing activities:

Payments of Dividends, Common Stock

(59,202)

(56,467)

(55,151)

Common stock issued

123,041

3,246

4,819

Repayments of Short-term Debt

(821,300)

(770,000)

(742,500)

Proceeds from Short-term Debt

1,017,300

854,500

631,075

Increase (Decrease) in Notes Payable, Related Parties

(25,302)

14,995

Long-term debt - issuances

200,000

248,500

Other financing activities

(5,348)

(5,379)

1,500

Net cash provided by (used in) financing activities

229,189

240,895

88,243

Net change in cash and cash equivalents

2,895

(2,054)

(14,911)

Cash and cash equivalents, at carrying value

$ 3,114

$ 219

3,114

219

2,273

$ 17,184

Other Significant Noncash Transaction, Value of Consideration Received

Notes Reduction

62,019

66,034

13,874

Non-cash Dividends Paid to Parent by Subsidiaries

225,000

Interest Paid

(14,667)

(56,464)

(19,878)

Income Taxes Paid, Net

$ 23,830

$ (504)

$ 6,667

[1]	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.
[2]	Includes pre-tax gain on sale of operating assets of $2.7 million ($1.7 million after-tax) and $6.2 million ($4.1 million after-tax) in the first and third quarters, respectively.
[3]	Includes unrealized mark-to-market income (loss) for interest rate swaps of $(2.0) million, $(16.2) million, $(8.9) million and $17.2 million after-tax in the first, second, third and fourth quarters, respectively.

Schedule I Disclosures for Parent Company Only Schedule I, Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2011 USD ($) shares
Condensed Financial Statements, Captions [Line Items]
Equity Issuance, Date	Nov. 10, 2010
Stock Issued During Period, Value, New Issues \| $	$ 119,630
Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Sale of Stock, Transaction Date	Nov. 01, 2011
Stock Issued During Period, Value, New Issues \| $	$ 119,600
Forward Equity Agreement [Member] \| Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Forward Contract Indexed to Issuer's Equity, Shares \| shares	4,000,000
Forward Equity Agreement Over Allotment Shares [Member] \| Parent [Member]
Condensed Financial Statements, Captions [Line Items]
Forward Equity Issuance OverAllotment \| shares	413,519
Common Stock [Member]
Condensed Financial Statements, Captions [Line Items]
Stock Issued During Period, Shares, New Issues \| shares	4,413,519
Stock Issued During Period, Value, New Issues \| $	$ 4,414

Schedule I Disclosures for Parent Company Only Schedule I, Schedule of Dividends Paid to Parent (Details) - Parent [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Dividend Paid to Parent [Line Items]
Cash Dividends Paid to Parent Company by Consolidated Subsidiaries	$ 14,500	$ 6,298	$ 0
Non-cash Dividends Paid to Parent by Subsidiaries	$ 0	$ 0	$ 225,000

Schedule I Disclosures for Parent Company Only Schedule I, Notes Payable (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Short-term Debt [Line Items]
Notes payable	$ 345,000	$ 249,000
Letters of Credit Outstanding, Amount	43,700	46,865
Parent [Member]
Short-term Debt [Line Items]
Notes payable	$ 345,000	249,000
Parent [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Expiration Date	4/14/2013
Notes payable	$ 195,000	149,000
Letters of Credit Outstanding, Amount	$ 43,700	46,865
Line of Credit Facility, Commitment Fee Percentage	0.50%
Parent [Member] \| Loans Payable [Member] \| Corporate Term Loan due June 2012 [Member]
Short-term Debt [Line Items]
Notes payable	$ 150,000	0
Letters of Credit Outstanding, Amount	$ 0	$ 0
Term Loan, Maturity Date	Jun. 24, 2012
Debt Instrument, Basis Spread on Variable Rate	1.25%
Debt Instrument, Interest Rate at Period End	1.56%
Parent [Member] \| Base Rate Option [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End	1.75%
Parent [Member] \| Eurodollar Option [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End	2.75%
Parent [Member] \| Letters of Credit [Member] \| Line of Credit [Member] \| Revolving Credit Facility, Existing [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End	2.75%

Schedule I Disclosures for Parent Company Only Schedule I, Long Term Debt (Details) - Parent [Member] - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

$ 100

Senior Unsecured Notes due 2013 [Member]

$ 774,959

$ 674,930

May 15, 2013

6.50%

^[1]

$ 225,000

225,000

Senior Unsecured Notes Due 2014 [Member]

$ 41

May 15, 2014

9.00%

Senior Unsecured Notes Due 2020 [Member]

^[1]

$ 250,000

250,000

Jul. 15, 2020

5.88%

Proceeds from Issuance of Senior Long-term Debt

^[2]

$ 200,000

200,000

$ 198,700

Long Term Term Loan [Member]

Long-term Debt, Variable Interest, Percentage Rate

Sep. 30, 2013

1.69%

Debt Instrument, Basis Spread on Variable Rate

$ 100,000

$ 0

1.375%

[1]	In order to restructure debt and equity capitalization at our utilities, 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.
[2]	In order to restructure debt and equity capitalization at our utilities, $100.0 million of 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.

Schedule I Disclosures for Parent Company Only Schedule I, Schedule of Guarantor Obligations (Details)
$ in Thousands

12 Months Ended

Dec. 31, 2011

USD ($)

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 139,805

Parent [Member] | Gas Utilities [Member] | Natural Gas Storage and Transportation Supplier BP Energy [Member]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 70,000

^[1]

Parent [Member] | Gas Utilities [Member] | Natural Gas Transportation and Storage Supplier Colorado interstate [Member]

Ongoing

^[1]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 10,000

^[2]

Parent [Member] | Gas Utilities [Member] | Natural Gas Supplier Cross Timbers [Member]

7/31/2012

^[2]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 7,500

^[3]

Parent [Member] | Power Generation [Member] | Capital Additions 200 MW Generation Facility Colorado IPP [Member]

6/30/2012

^[3]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 384

^[4]

Parent [Member] | Electric Utilities [Member] | Capital Additions 180 MW Generation Facility Colorado Electric Utility [Member]

2012

^[4]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 56

^[5]

Parent [Member] | Electric Utilities [Member] | Wind Turbines [Member]

2012

^[5]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 33,264

^[6]

Parent [Member] | Coal [Member] | Surety Bonds [Member]

1/15/2013

^[6]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 18,601

^[7]

Ongoing

^[7]

[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 agreements.
[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 four guarantees to GE for payment obligations arising from contracts to purchase four LM6000 gas turbines for Black Hills Colorado IPP. These are continuous guarantees which will terminate upon settlement of all obligations.
[5]	We have issued two guarantees to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers. These are continuing guarantees which will terminate upon settlement of all obligations.
[6]	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 satisfaction of Colorado Electric's contractual obligations.
[7]	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.

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, 2011	Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivative assets, current	$ 18,583	$ 12,710
Derivative assets, non-current	1,971	2,625
Derivative liabilities, current	84,367	64,617
Derivative Liabilities, Noncurrent	49,033	17,897
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	6,500
Interest Rate Swaps, Designated [Member] \| Financing Activities [Member]
Derivatives, Fair Value [Line Items]
Notional Amount of Interest Rate Derivatives	$ 150,000	$ 150,000
Derivative, Average Fixed Interest Rate	5.04%	5.04%
Derivative assets, current	$ 0	$ 0
Derivative assets, non-current	0	0
Derivative liabilities, current	6,513	6,823
Derivative Liabilities, Noncurrent	20,363	14,976
Accumulated Other Comprehensive Income Loss PreTax	(26,876)	(21,799)
Gain (Loss) on Derivative Instruments, Net, Pretax	0	0
Parent [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, current	78,502	57,343
Derivative Liabilities, Noncurrent	31,368	7,360
Parent [Member] \| Interest Rate Swaps, Designated [Member]
Derivatives, Fair Value [Line Items]
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	3,200
Parent [Member] \| Interest Rate Swaps, Designated [Member] \| Financing Activities [Member]
Derivatives, Fair Value [Line Items]
Notional Amount of Interest Rate Derivatives	$ 75,000	$ 75,000
Derivative, Average Fixed Interest Rate	4.97%	4.97%
Derivative, Maximum Term	5	6
Derivative assets, current	$ 0	$ 0
Derivative assets, non-current	0	0
Derivative liabilities, current	3,207	3,363
Derivative Liabilities, Noncurrent	10,672	7,360
Accumulated Other Comprehensive Income Loss PreTax	(13,879)	(15,417)
Gain (Loss) on Derivative Instruments, Net, Pretax	0	0
Derivative, Collateral, Right to Reclaim Cash	0	0
Parent [Member] \| Interest Rate Swaps, Dedesignated [Member] \| Financing Activities [Member]
Derivatives, Fair Value [Line Items]
Notional Amount of Interest Rate Derivatives	$ 250,000	$ 250,000
Derivative, Average Fixed Interest Rate	5.67%	5.67%
Derivative, Maximum Term	2	1
Derivative assets, current	$ 0	$ 0
Derivative assets, non-current	0	0
Derivative liabilities, current	75,295	53,980
Derivative Liabilities, Noncurrent	20,696	0
Accumulated Other Comprehensive Income Loss PreTax	0	0
Gain (Loss) on Derivative Instruments, Net, Pretax	(42,010)	(15,193)
Derivative, Collateral, Right to Reclaim Cash	0	$ 0
Dedesignated Interest Rate Swaps Expiring 2028 [Member] \| Interest Rate Swaps, Dedesignated [Member] \| Financing Activities [Member]
Derivatives, Fair Value [Line Items]
Notional Amount of Interest Rate Derivatives	$ 150,000
Derivative, Maximum Term	17
Power Generation [Member] \| Interest Rate Swaps, Designated [Member]
Derivatives, Fair Value [Line Items]
Derivative, Inception Date		Jan. 15, 2010
Notional Amount of Interest Rate Derivatives	$ 75,000

Schedule I Disclosures for Parent Company Only Schedule I, Fair Value Assets and Liabilites Measured on Recurring Basis (Details) - Interest Rate Swap [Member] - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	$ 0	$ 0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	122,867	75,779
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Total Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	122,867	75,779
Parent [Member] \| Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Parent [Member] \| Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	109,869	64,703
Parent [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	0	0
Parent [Member] \| Total Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure	$ 109,869	$ 64,703

Schedule I Disclosures for Parent Company Only Schedule I, Derivative Instruments in Statements of Financial Position Fair Value (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010
Designated as Hedging Instrument [Member] \| Parent [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 3,207	$ 3,363
Designated as Hedging Instrument [Member] \| Parent [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	10,672	7,360
Not Designated as Hedging Instrument [Member] \| Parent [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	75,295	53,980
Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	6,513	6,822
Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	20,363	14,976
Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member] \| Parent [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Fair Value Disclosure	13,879	10,723
Interest Rate Swap [Member] \| Not Designated as Hedging Instrument [Member] \| Derivative Liabilities, Current [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	75,295	53,980
Interest Rate Swap [Member] \| Not Designated as Hedging Instrument [Member] \| Derivative Liabilities, Noncurrent [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	20,696	0
Interest Rate Swap [Member] \| Not Designated as Hedging Instrument [Member] \| Parent [Member]
Derivatives, Fair Value [Line Items]
Derivative Liabilities, Fair Value Disclosure	$ 95,991	$ 53,980

Schedule I Disclosures for Parent Company Only Schedule I, Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Details) - Cash Flow Hedging [Member] - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	$ 1,929	$ (4,539)		$ (8,252)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	6,730	(2,177)		19,810
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(13,527)	(12,280)		12,818
Interest Rate Swap [Member] \| Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (7,609)	(7,664)		$ (3,292)
Parent [Member] \| Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)		(3,893)	$ (5,352)
Parent [Member] \| Interest Rate Swap [Member] \| Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		$ (3,950)	$ (3,662)

Schedule I Disclosures for Parent Company Only Schedule I, Derivatives Not Designated as Hedging Instruments Statement of Financial Performance and Financial Position Location (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ (55,383)	$ (28,505)	$ 45,837
Parent [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(55,383)	(28,505)	45,837
Parent [Member] \| Interest Rate Swap [Member] \| Unrealized Gain (Loss) on Interest Rate Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	(42,010)	(15,193)	55,653
Parent [Member] \| Interest Rate Swap [Member] \| Interest Expense [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ (13,373)	$ (13,312)	$ (9,816)

The amount of net gains and losses recognized in income during the period on derivative instruments designated and qualifying as hedging instruments in fair value hedges and related hedged items designated and qualifying in fair value hedges, on derivative instruments designated and qualifying as hedging instruments in cash flow hedges, and on derivative instruments not designated as hedging instruments.

Long-term Debt [Member] | Electric Utilities [Member]

Schedule I Disclosures for Parent Company Only Schedule I, Fair Value by Balance Sheet Grouping (Details) - USD ($) $ in Thousands	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Derivatives, Carrying Amount and Fair Value [Line Items]
Cash and cash equivalents, at carrying value	$ 21,628	$ 16,437
Notes payable	345,000	249,000
Long-term Debt, including current maturities	1,282,882	1,191,231
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Cash and cash equivalents, at carrying value	21,628	16,437
Derivative Liabilities	133,400	82,514
Notes payable	345,000	249,000
Long-term Debt, including current maturities	1,282,882	1,191,231
Total Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Cash and cash equivalents, fair value	21,628	16,437
Notes payable, fair value	345,000	249,000
Long-term debt, including curent maturities at fair value	1,464,289	1,290,519
Parent [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Cash and cash equivalents, at carrying value	3,114	219	$ 2,273	$ 17,184
Derivative Liabilities	109,870	64,703
Notes payable	345,000	249,000
Long-term Debt, including current maturities	774,959	674,930
Parent [Member] \| Total Estimate of Fair Value, Fair Value Disclosure [Member]
Derivatives, Carrying Amount and Fair Value [Line Items]
Cash and cash equivalents, fair value	3,114	219
Derivative Liability, Fair Value, Gross Liability	109,870	64,703
Notes payable, fair value	345,000	249,000
Long-term debt, including curent maturities at fair value	$ 851,241	$ 743,738

Schedule II Consolidated Valuation and Qualifying Accounts Schedule II Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Balance Period Start	$ 2,295	$ 3,683	$ 3,916
Valuation Allowances and Reserves, Adjustments	0	0	0
Valuation Allowances and Reserves, Charged to Cost and Expense	3,042	1,898	4,078
Valuation Allowances and Reserves, Recoveries	5,369	2,196	3,229
Valuation Allowances and Reserves, Deductions	(9,045)	(5,482)	(7,540)
Valuation Allowances and Reserves, Balance Period End	$ 1,661	$ 2,295	$ 3,683

Label

Element

Value

us-gaap_DebtInstrumentMaturityDate

May 12, 2012

us-gaap_DebtInstrumentCarryingAmount

$ 72,000

us-gaap_DebtInstrumentCarryingAmount

$ 234,000

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

us-gaap_DebtInstrumentInterestRateStatedPercentage

13.66%

us-gaap_DebtInstrumentMaturityDate

Nov. 01, 2039

us-gaap_DebtInstrumentCarryingAmount

$ 180,000,000

us-gaap_DebtInstrumentCarryingAmount

180,000,000

us-gaap_DebtInstrumentUnamortizedDiscount

119,000

us-gaap_DebtInstrumentUnamortizedDiscount

$ 115,000

Polution Control Revenue Bonds Due 2024 [Member] | Electric Utilities [Member]

us-gaap_DebtInstrumentInterestRateStatedPercentage

6.13%

us-gaap_DebtInstrumentMaturityDate

Oct. 01, 2024

us-gaap_DebtInstrumentCarryingAmount

$ 12,200,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

us-gaap_DebtInstrumentCarryingAmount

$ 12,200,000

us-gaap_LongTermDebtPercentageBearingVariableInterestRate

5.35%

^[1]

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

us-gaap_DebtInstrumentMaturityDate

Mar. 01, 2027

us-gaap_DebtInstrumentCarryingAmount

$ 10,000,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

us-gaap_DebtInstrumentCarryingAmount

$ 10,000,000

us-gaap_LongTermDebtPercentageBearingVariableInterestRate

0.14%

^[1]

Polution Control Revenue Bonds Due 2014 [Member] | Electric Utilities [Member]

us-gaap_DebtInstrumentMaturityDate

Oct. 01, 2014

us-gaap_DebtInstrumentCarryingAmount

$ 6,450,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

us-gaap_DebtInstrumentCarryingAmount

$ 6,450,000

us-gaap_LongTermDebtPercentageBearingVariableInterestRate

4.80%

^[1]

First Mortgage Bonds Due 2023 [Member] | Electric Utilities [Member]

us-gaap_DebtInstrumentMaturityDate

Aug. 15, 2032

us-gaap_DebtInstrumentCarryingAmount

$ 75,000,000

us-gaap_DebtInstrumentCarryingAmount

$ 75,000,000

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

us-gaap_DebtInstrumentInterestRateStatedPercentage

7.23%

us-gaap_DebtInstrumentMaturityDate

Sep. 01, 2021

us-gaap_DebtInstrumentCarryingAmount

$ 7,000,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

us-gaap_DebtInstrumentCarryingAmount

$ 7,000,000

us-gaap_LongTermDebtPercentageBearingVariableInterestRate

0.14%

^[1]

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

us-gaap_DebtInstrumentMaturityDate

Nov. 20, 2037

us-gaap_DebtInstrumentCarryingAmount

$ 110,000,000

us-gaap_DebtInstrumentCarryingAmount

$ 110,000,000

Project Financing Debt Due 2016 [Member] | Power Generation [Member]

us-gaap_DebtInstrumentInterestRateStatedPercentage

6.67%

us-gaap_DebtInstrumentMaturityDate

Dec. 09, 2016

us-gaap_DebtInstrumentCarryingAmount

$ 104,461,000

Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate

us-gaap_DebtInstrumentCarryingAmount

$ 112,681,000

us-gaap_LongTermDebtPercentageBearingVariableInterestRate

3.66%

^[1]

Bonds Due 2024 [Member] | Electric Utilities [Member]

us-gaap_DebtInstrumentMaturityDate

Jun. 01, 2024

us-gaap_DebtInstrumentCarryingAmount

$ 2,855,000