10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2012
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________.
	Commission File Number 001-31303

Black Hills Corporation
Incorporated in South Dakota	IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant's telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes x No o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer x Accelerated filer o

Non-accelerated filer o Smaller reporting company o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.

Class	Outstanding at April 30, 2012
Common stock, $1.00 par value	44,089,428 shares

TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations	3
PART I.	FINANCIAL INFORMATION	5
Item 1.	Financial Statements	5
	Condensed Consolidated Statements of Income and Comprehensive Income - unaudited
	Three Months Ended March 31, 2012 and 2011	5
	Condensed Consolidated Balance Sheets - unaudited
	March 31, 2012, December 31, 2011 and March 31, 2011	6
	Condensed Consolidated Statements of Cash Flows - unaudited
	Three Months Ended March 31, 2012 and 2011	8
	Notes to Condensed Consolidated Financial Statements - unaudited	9
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	50
Item 4.	Controls and Procedures	55
PART II.	OTHER INFORMATION	56
Item 1.	Legal Proceedings	56
Item 1A.	Risk Factors	56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	56
Item 4.	Mine Safety Disclosures	56
Item 5.	Other Information	56
Item 6.	Exhibits	57
	Signatures	58
	Exhibit Index	59

2

GLOSSARY OF TERMS AND ABBREVIATIONS

AND ACCOUNTING STANDARDS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation
BHEP	Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation	Black Hills Electric Generation, LLC, representing our Power Generation segment, a direct wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business activities of Black Hills Utility Holdings
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Company
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Service Company	Black Hills Service Company, a direct wholly-owned subsidiary of the Company
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu	British thermal unit
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Company
Colorado Electric	Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas	Black Hills Colorado Gas Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado IPP	Black Hills Colorado IPP, a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion Turbine
CVA	Credit Valuation Adjustment
De-designated interest rate swaps	The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but subsequently de-designated.
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DRIP	Dividend Reinvestment and Stock Purchase Plan
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
ECA	Energy Cost Adjustment
Enserco	Enserco Energy Inc., representing our Energy Marketing segment, sold February 29, 2012
Equity Forward Instrument	Equity Forward Agreement with J.P. Morgan connected to a public offering of 4,413,519 shares of Black Hills Corporation common stock

3

FASB	Financial Accounting Standards Board
FDIC	Federal Deposit Insurance Corporation
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles of the United States
Global Settlement	Settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
IFRS	International Financial Reporting Standards
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP	Independent Power Producer
IRS	Internal Revenue Service
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	One thousand standard cubic feet
Mcfe	One thousand standard cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying by 6.
MMBtu	One million British thermal units
MSHA	Mine Safety and Health Administration
MW	Megawatt
MWh	Megawatt-hour
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NGL	Natural Gas Liquids
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OTC	Over-the-counter
PGA	Purchase Gas Adjustment
PPA	Power Purchase Agreement
Revolving Credit Facility	Our $500 million five-year revolving credit facility which commenced on February 1, 2012 and expires on February 1, 2017
S&P	Standard and Poor's
SEC	United States Securities and Exchange Commission
Twin Eagle	Twin Eagle Resource Management, LLC
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

4

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(unaudited)

	Three Months Ended March 31,
	2012			2011
	(in thousands, except per share amounts)
Revenue:
Utilities	$	336,655		$	374,696
Non-regulated energy	29,196			26,139
Total revenue	365,851			400,835
Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	157,183			210,511
Operations and maintenance	64,760			67,409
Non-regulated energy operations and maintenance	22,595			23,474
Depreciation, depletion and amortization	38,559			31,910
Taxes - property, production and severance	11,510			8,198
Other operating expenses	1,196			966
Total operating expenses	295,803			342,468
Operating income	70,048			58,367
Other income (expense):
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premium, discount and realized settlements on interest rate swaps)	(29,914		)	(29,203		)
Allowance for funds used during construction - borrowed	518			3,363
Capitalized interest	161			2,434
Unrealized gain (loss) on interest rate swaps, net	12,045			5,465
Interest income	437			548
Allowance for funds used during construction - equity	277			295
Other income, net	1,472			731
Total other income (expense)	(15,004		)	(16,367		)
Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes	55,044			42,000
Equity in earnings (loss) of unconsolidated subsidiaries	(56		)	993
Income tax benefit (expense)	(19,717		)	(13,925		)
Income (loss) from continuing operations	35,271			29,068
Income (loss) from discontinued operations, net of tax	(5,484		)	(2,158		)
Net income available for common stock	29,787			26,910
Other comprehensive income (loss), net of tax	(166		)	(1,579		)
Comprehensive income (loss)	$	29,621		$	25,331
Income (loss) per share, Basic -
Income (loss) from continuing operations, per share	$	0.81		$	0.74
Income (loss) from discontinued operations, per share	(0.13		)	(0.05		)
Total income (loss) per share, Basic	$	0.68		$	0.69
Income (loss) per share, Diluted -
Income (loss) from continuing operations, per share	$	0.80		$	0.73
Income (loss) from discontinued operations, per share	(0.12		)	(0.05		)
Total income (loss) per share, Diluted	$	0.68		$	0.68
Weighted average common shares outstanding:
Basic	43,731			39,059
Diluted	43,969			39,761
Dividends paid per share of common stock	$	0.37		$	0.365

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

5

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

	March 31, 2012			December 31, 2011			March 31, 2011
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	56,132		$	21,628		$	26,418
Restricted cash	8,960			9,254			3,406
Accounts receivable, net	143,987			156,774			151,524
Materials, supplies and fuel	63,236			84,064			45,635
Derivative assets, current	17,877			18,583			7,812
Income tax receivable, net	10,399			9,344			20,173
Deferred income tax assets, net, current	23,710			37,202			20,491
Regulatory assets, current	56,282			59,955			36,834
Other current assets	26,546			21,266			17,486
Assets of discontinued operations	—			340,851			295,724
Total current assets	407,129			758,921			625,503
Investments	16,451			17,261			17,088
Property, plant and equipment	3,800,011			3,724,016			3,454,179
Less accumulated depreciation and depletion	(980,944		)	(934,441		)	(886,401		)
Total property, plant and equipment, net	2,819,067			2,789,575			2,567,778
Other assets:
Goodwill	353,396			353,396			353,396
Intangible assets, net	3,787			3,843			4,011
Derivative assets, non-current	881			1,971			1,184
Regulatory assets, non-current	186,093			182,175			140,735
Other assets, non-current	21,132			19,941			19,655
Total other assets	565,289			561,326			518,981
TOTAL ASSETS	$	3,807,936		$	4,127,083		$	3,729,350

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

6

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(Continued)

(unaudited)

	March 31, 2012			December 31, 2011			March 31, 2011
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	59,793		$	104,748		$	104,742
Accrued liabilities	151,130			151,319			127,235
Derivative liabilities, current	76,389			84,367			59,972
Regulatory liabilities, current	35,414			16,231			15,004
Notes payable	225,000			345,000			287,000
Current maturities of long-term debt	8,977			2,473			4,254
Liabilities of discontinued operations	—			173,929			163,293
Total current liabilities	556,703			878,067			761,500
Long-term debt, net of current maturities	1,272,016			1,280,409			1,184,830
Deferred credits and other liabilities:
Deferred income tax liabilities, net, non-current	317,369			300,988			301,097
Derivative liabilities, non-current	43,169			49,033			15,790
Regulatory liabilities, non-current	112,516			108,217			90,923
Benefit plan liabilities	157,623			177,480			128,170
Other deferred credits and other liabilities	123,848			123,553			133,893
Total deferred credits and other liabilities	754,525			759,271			669,873
Stockholders' equity:
Common stockholders' —
Common stock $1 par value: 100,000,000 shares authorized: issued 44,151,428; 43,957,502 and 39,434,304 shares, respectively	44,151			43,958			39,434
Additional paid-in capital	725,512			722,623			601,021
Retained earnings	490,114			476,603			498,614
Treasury stock at cost – 65,015; 32,766 and 26,075 shares, respectively	(2,041		)	(970		)	(762		)
Accumulated other comprehensive income (loss)	(33,044		)	(32,878		)	(25,160		)
Total stockholders' equity	1,224,692			1,209,336			1,113,147
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,807,936		$	4,127,083		$	3,729,350

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

7

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended March 31,
	2012			2011
Operating activities:	(in thousands)
Net income (loss)	$	29,787		$	26,910
(Income) loss from discontinued operations, net of tax	5,484			2,158
Income (loss) from continuing operations	35,271			29,068
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	38,559			31,910
Deferred financing cost amortization	2,719			1,528
Derivative fair value adjustments	1,594			2,010
Stock compensation	1,817			2,289
Unrealized mark-to-market (gain) loss on interest rate swaps	(12,045		)	(5,465		)
Deferred income taxes	18,083			25,844
Equity in (earnings) loss of unconsolidated subsidiaries	56			(993		)
Allowance for funds used during construction - equity	(277		)	(295		)
Employee benefit plans	5,246			3,642
Other adjustments, net	2,187			(3,440		)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	20,828			17,280
Accounts receivable and other current assets	9,439			(5,591		)
Accounts payable and other current liabilities	(42,368		)	(44,617		)
Regulatory assets	(776		)	33,966
Regulatory liabilities	18,938			9,984
Contributions to defined benefit pension plans	(25,000		)	—
Other operating activities, net	610			5,301
Net cash provided by operating activities of continuing operations	74,881			102,421
Net cash provided by (used in) operating activities of discontinued operations	21,184			8,850
Net cash provided by operating activities	96,065			111,271
Investing activities:
Property, plant and equipment additions	(67,652		)	(121,615		)
Other investing activities	1,105			786
Net cash provided by (used in) investing activities of continuing operations	(66,547		)	(120,829		)
Proceeds from sale of business operations	108,837			—
Net cash provided by (used in) investing activities of discontinued operations	(824		)	(929		)
Net cash provided by (used in) investing activities	41,466			(121,758		)
Financing activities:
Dividends paid on common stock	(16,276		)	(14,371		)
Common stock issued	764			605
Short-term borrowings - issuances	56,453			210,000
Short-term borrowings - repayments	(176,453		)	(172,000		)
Long-term debt - repayments	(1,897		)	(2,155		)
Other financing activities	(2,758		)	(14		)
Net cash provided by (used in) financing activities of continuing operations	(140,167		)	22,065
Net cash provided by (used in) financing activities of discontinued operations	—			—
Net cash provided by (used in) financing activities	(140,167		)	22,065
Net change in cash and cash equivalents	(2,636		)	11,578
Cash and cash equivalents, beginning of period*	58,768			32,438
Cash and cash equivalents, end of period*	$	56,132		$	44,016

_______________________

* Cash and cash equivalents include cash of discontinued operations of $37.1 million, $17.6 million and $16.0 million at December 31, 2011, March 31, 2011 and December 31, 2010, respectively.

See Note 3 for supplemental disclosure of cash flow information.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

8

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company's 2011 Annual Report on Form 10-K)

(1)     MANAGEMENT'S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation together with our subsidiaries (the "Company," "us," "we," or "our"), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2011 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2012, December 31, 2011 and March 31, 2011 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2012 and March 31, 2011, and our financial condition as of March 31, 2012, December 31, 2011, and March 31, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On February 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. For further information see Note 17.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. Specifically, the Company has reclassified deferred financing cost amortization into a separate line on the Condensed Consolidated Statements of Cash Flow. This reclassification had no effect on total assets, net income, cash flows or earnings per share.

(2)    RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards and Legislation

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending ASC 220, Comprehensive Income, 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 2011-05 requires retrospective application, and it is effective for the fiscal years, and interim periods within those years beginning after December 15, 2011. In December 2011, FASB issued ASU 2011-12 which 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.

9

At December 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements and provided additional details in the notes to the financial statements, but did not have any other impact on our financial statements.

Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04

FASB issued an accounting standards update amending ASC 820, Fair Value Measurements and Disclosures, to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity's use of a non-financial asset that is different from the asset's highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. Additional disclosures are included in Notes 14 and 15.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing of 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 testing performed for fiscal years beginning after December 15, 2011. We perform our annual impairment testing in November of each year. The adoption of this standard will not have an impact on our financial statements.

Recently Issued Accounting Standards and Legislation

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company's netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning January 1, 2013. Management does not believe that the adoption of this standard will have an impact on the Company’s financial position, results of operations or cash flows.

(3)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

	Three Months Ended
	March 31, 2012			March 31, 2011
	(in thousands)
Non-cash investing activities from continuing operations—
Property, plant and equipment acquired with accrued liabilities	$	31,644		$	32,220
Capitalized assets associated with retirement obligations	$	2,826		$	—
Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(16,799	)	$	(11,572	)
Income taxes, net	$	(1,838	)	$	48

10

(4)    MATERIALS, SUPPLIES AND FUEL

The amounts of Materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:

	March 31, 2012		December 31, 2011		March 31, 2011
Materials and supplies	$	44,361	$	40,838	$	34,129
Fuel - Electric Utilities	7,812		8,201		9,307
Natural gas in storage - gas utilities	11,063		35,025		2,199
Total materials, supplies and fuel	$	63,236	$	84,064	$	45,635

(5)    ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable consists primarily of customer trade accounts. The Gas Utilities balance fluctuates primarily due to seasonality. We maintain an allowance for doubtful accounts that reflects our best estimate of probable uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.

Following is a summary of receivables (in thousands) as of:

	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric	$	44,356	$	19,381	$	(585	)	$	63,152
Gas	44,287		18,502		(936		)	61,853
Oil and Gas	15,014		—		(105		)	14,909
Coal Mining	2,578		—		—			2,578
Power Generation	265		—		—			265
Corporate	1,230		—		—			1,230
Total	$	107,730	$	37,883	$	(1,626	)	$	143,987

	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2011	Receivable, Trade		Revenue		Doubtful 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

11

	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric	$	46,077	$	16,196	$	(728	)	$	61,545
Gas	58,665		21,620		(1,763		)	78,522
Oil and Gas	7,503		—		(161		)	7,342
Coal Mining	982		—		—			982
Power Generation	2,050		—		—			2,050
Corporate	1,083		—		—			1,083
Total	$	116,360	$	37,816	$	(2,652	)	$	151,524

(6)    NOTES PAYABLE

Our credit facility and debt securities contain certain restrictive financial covenants. As of March 31, 2012, we were in compliance with all of these covenants.

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

	March 31, 2012				December 31, 2011				March 31, 2011
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	75,000	$	41,200	$	195,000	$	43,700	$	187,000	$	51,000
Term Loan due 2011*	—		—		—		—		100,000		—
Term Loan due 2012	150,000		—		150,000		—		—		—
Total	$	225,000	$	41,200	$	345,000	$	43,700	$	287,000	$	51,000

______________

* The short-term loan was renegotiated to a longer term note, maturing in 2013.

Revolving Credit Facility

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

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

Debt Covenants

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

	As of			Covenant
	March 31, 2012			Requirement
Consolidated Net Worth	$	1,224,692		$	899,024
Recourse Leverage Ratio	56.4		%	65.0		%

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(7)    LONG TERM DEBT

Pollution Control Revenue Bonds

On March 28, 2012, Black Hills Power provided notice to the trustee of its intent to call the Pollution Control Refund Revenue Bonds which were originally due to mature on October 1, 2014. The principal amount due on the bonds has been reclassified to Current maturities of long-term debt on the accompanying Condensed Consolidated Balance Sheets. Repayment of $6.5 million principal and accrued interest will be made on May 15, 2012.

(8)    EARNINGS PER SHARE

Basic earnings (loss) per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted earnings (loss) per share is computed by including all dilutive common shares potentially outstanding during a period. A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Income (loss) from continuing operations	$	35,271	$	29,068
Weighted average shares - basic	43,731		39,059
Dilutive effect of:
Restricted stock	147		132
Stock options	18		17
Equity forward instruments	—		460
Other dilutive effects	73		93
Weighted average shares - diluted	43,969		39,761

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):

	Three Months Ended March 31,
	2012	2011
Stock options	127	83
Restricted stock	31	7
Other stock	16	—
Anti-dilutive shares	174	90

(9)    COMPREHENSIVE INCOME (LOSS)

The following table presents the components of our comprehensive income (loss) (in thousands):

Three Months Ended March 31, 2012	Pre-tax Amount			Tax (Expense) Benefit		Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges	$	521		$	55	$	576
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	(1,187		)	445		(742		)
Other comprehensive income (loss)	$	(666	)	$	500	$	(166	)

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Three Months Ended March 31, 2011	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges	$	(3,785	)	$	1,637		$	(2,148	)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	861			(292		)	569
Other comprehensive income (loss)	$	(2,924	)	$	1,345		$	(1,579	)

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

	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
Balance as of December 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	(166		)	—			(166		)
Ending Balance March 31, 2012	$	(13,968	)	$	(19,076	)	$	(33,044	)
	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
Balance as of December 31, 2010	$	(12,439	)	$	(11,142	)	$	(23,581	)
Other comprehensive income (loss)	(1,579		)	—			(1,579		)
Ending Balance March 31, 2011	$	(14,018	)	$	(11,142	)	$	(25,160	)

(10)     COMMON STOCK

Other than the following transactions, we had no material changes in our common stock during the three months ended March 31, 2012 from the amount reported in Note 11 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Equity Compensation Plans

• We granted 66,690 target performance shares to certain officers and business unit leaders for the January 1, 2012 through December 31, 2014 performance period during the three months ended March 31, 2012. Actual shares are issued after the end of the performance plan period. Performance shares are awarded based on our total stockholder return over the designated performance period as measured against a selected peer group and can range from 0% to 200% 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 the form of cash and 50% in shares of common stock. The grant date fair value was $32.26 per share.

• We granted 139,550 shares of restricted common stock and restricted stock units during the three months ended March 31, 2012. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $4.9 million will be recognized over the vesting period.

• Stock options totaling 41,206 shares were exercised during the three months ended March 31, 2012 at a weighted-average exercise price of $28.28 per share, providing $1.2 million of proceeds.

• We issued 3,690 shares of common stock under our short-term incentive compensation plan during the three months ended March 31, 2012. Pre-tax compensation cost related to the awards was approximately $0.1 million, which was expensed in 2011.

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Stock-based compensation expense for the three months ended March 31, 2012 and 2011 was $1.8 million and $2.3 million, respectively.

As of March 31, 2012, total unrecognized compensation expense related to non-vested stock awards was $12.2 million and is expected to be recognized over a weighted-average period of 2.3 years.

Dividend Reinvestment and Stock Purchase Plan

We have a DRIP under which stockholders 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. We issued 27,155 new shares at a weighted-average price of $33.20 during the three months ended March 31, 2012. Unissued common stock totaling 426,109 shares was available for future offering under the DRIP at March 31, 2012.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of March 31, 2012, we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders 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 March 31, 2012:

• Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of March 31, 2012, the restricted net assets at our Utilities Group were approximately $81.4 million.

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

(11)     EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (the "Pension Plans"). One covers certain eligible employees of the following subsidiaries: Black Hills Service Company, Black Hills Power, WRDC and BHEP, one covers certain eligible employees of Cheyenne Light, and one covers certain eligible employees of Black Hills Energy. The Pension Plan benefits are based on years of service and compensation levels.

The components of net periodic benefit cost for the Pension Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Service cost	$	1,430		$	1,355
Interest cost	3,687			3,732
Expected return on plan assets	(4,084		)	(4,239		)
Prior service cost	22			25
Net loss (gain)	2,408			1,135
Net periodic benefit cost	$	3,463		$	2,008

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor the following retiree healthcare plans (the "Healthcare Plans"): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are

15

entitled to postretirement healthcare benefits.

The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Service cost	$	402		$	375
Interest cost	523			542
Expected return on plan assets	(19		)	(41		)
Prior service cost (benefit)	(125		)	(120		)
Net loss (gain)	222			169
Net periodic benefit cost	$	1,003		$	925

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (the "Supplemental Plans"). The Supplemental Plans are non-qualified defined benefit plans.

The components of net periodic benefit cost for the Supplemental Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Service cost	$	246	$	257
Interest cost	331		324
Prior service cost	1		1
Net loss (gain)	202		127
Net periodic benefit cost	$	780	$	709

Contributions

We anticipate that we will make contributions to the benefit plans during 2012 and 2013. Contributions to the Defined Benefit Plans will be made in cash and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):

	Contributions Made
	Three Months Ended March 31, 2012		Additional Contributions Anticipated for 2012		Contributions Anticipated for 2013
Defined Benefit Pension Plans	$	25,000	$	—	$	4,500
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,063	$	3,188	$	4,380
Supplemental Non-qualified Defined Benefit Plans	$	278	$	833	$	1,090

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(12)     BUSINESS SEGMENTS INFORMATION

Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.

On February 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations reclassified to our Corporate segment. For further information see Note 17.

We conduct our operations through the following five reportable segments:

Utilities Group —

• Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyoming and vicinity; and

• Gas Utilities, which supplies natural gas utility service to areas in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group —

• Oil and Gas, which acquires, explores for, develops and produces crude oil and natural gas interests located in the Rocky Mountain region and other states;

• Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming and Colorado; and

• Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyoming.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Segment information included in the accompanying Condensed Consolidated Statements of Income and Comprehensive Income and Condensed Consolidated Balance Sheets was as follows (in thousands):

Three Months Ended March 31, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	156,133	$	3,036		$	8,746
Gas	180,522		—			15,207
Non-regulated Energy:
Oil and Gas	21,645		—			13
Power Generation	1,178		18,449			6,914
Coal Mining	6,373		8,616			1,000
Corporate (a)(b)	—		—			3,391
Intercompany eliminations	—		(30,101		)	—
Total	$	365,851	$	—		$	35,271

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Three Months Ended March 31, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	144,430	$	3,839		$	10,249
Gas	230,266		—			19,263
Non-regulated Energy:
Oil and Gas	17,906		—			(715		)
Power Generation	687		6,933			1,186
Coal Mining	7,614		7,881			(1,298		)
Corporate (a)(b)	—		—			451
Intercompany eliminations	—		(18,721		)	(68		)
Total	$	400,903	$	(68	)	$	29,068

____________

(a) Income (loss) from continuing operations includes $7.8 million and $3.6 million net after-tax mark-to-market gain on interest rate swaps for the three months ended March 31, 2012 and March 31, 2011, respectively.

(b) Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not classified as discontinued operations but were included in the Corporate segment. See Note 17 for further information.

Total Assets (net of inter-company eliminations)	March 31, 2012		December 31, 2011		March 31, 2011
Utilities:
Electric (a)	$	2,268,524	$	2,254,914	$	1,868,600
Gas	717,185		746,444		683,927
Non-regulated Energy:
Oil and Gas	430,851		425,970		355,357
Power Generation (a)	128,225		129,121		336,827
Coal Mining	87,139		88,704		94,416
Corporate (b)	176,012		141,079		94,499
Discontinued operations (c)	—		340,851		295,724
Total assets	$	3,807,936	$	4,127,083	$	3,729,350

____________

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

(b) Assets of the Corporate segment were restated due to deferred taxes that were not classified as discontinued operations.

(c) See Note 17 for further information relating to discontinued operations.

(13)     RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2011 Annual Report on Form 10-K filed with the SEC.

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Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks:

• 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 segment; and

• Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our derivative instruments.

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.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with investment grade companies and credit quality municipalities and electric cooperatives, 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 March 31, 2012, 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.

We actively manage our exposure to certain market and credit risks as described in Note 3 of the Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income and Comprehensive Income are detailed below and within Note 14.

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, result in commodity price risk and variability to our cash flows.

We hold a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those OTC 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 are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives is reported in Accumulated other comprehensive income (loss) and the ineffective portion, if any, is reported in Revenue.

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

	March 31, 2012					December 31, 2011					March 31, 2011
	Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps
Notional (a)	522,000			5,001,750		528,000			5,406,250		487,500			5,974,800
Maximum terms in years (b)	1.25			1.50		1.25			1.75		1.00			0.25
Derivative assets, current	$	406		$	8,256	$	729		$	8,010	$	108		$	6,649
Derivative assets, non-current	$	46		$	808	$	771		$	1,148	$	—		$	975
Derivative liabilities, current	$	2,904		$	—	$	2,559		$	—	$	4,688		$	—
Derivative liabilities, non-current	$	1,084		$	—	$	811		$	7	$	2,678		$	157
Pre-tax accumulated other comprehensive income (loss)	$	(3,566	)	$	9,064	$	(1,928	)	$	9,152	$	(7,613	)	$	7,467
Revenue (c)	$	30		$	—	$	58		$	—	$	355		$	—

____________

(a) Crude oil in Bbls, gas in MMBtus

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

(c) Represents the amortization of put premiums.

Based on March 31, 2012 market prices, a $4.3 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains will change during future periods as market prices fluctuate.

Utilities

Our utility customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain exchange-traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums and commissions, 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 Condensed Consolidated Statements of Income and Comprehensive Income when the related costs are recovered through our rates.

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

	March 31, 2012		December 31, 2011		March 31, 2011
	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)
Natural gas futures purchased	11,550,000	81	14,310,000	84	4,680,000	24
Natural gas options purchased	670,000	12	1,720,000	3	—	—
Natural gas basis swaps purchased	7,640,000	81	7,160,000	60	—	—

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

	March 31, 2012		December 31, 2011		March 31, 2011
Derivative assets, current	$	9,215	$	9,844	$	1,056
Derivative assets, non-current	$	27	$	52	$	209
Derivative liabilities, non-current	$	6,407	$	7,156	$	—
Net unrealized gain (loss) included in Regulatory assets or liabilities	$	15,223	$	17,556	$	2,455
Included in Derivatives:
Cash collateral receivable (payable)	$	17,651	$	19,416	$	3,720
Option premiums and commissions	$	407	$	880	$	—

Financing Activities

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

	March 31, 2012						December 31, 2011						March 31, 2011
	Designated  Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.75			1.75			5.00			2.00			5.75			0.75
Derivative liabilities, current	$	6,777		$	66,708		$	6,513		$	75,295		$	6,769		$	48,515
Derivative liabilities, non-current	$	18,441		$	17,237		$	20,363		$	20,696		$	12,955		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(25,218	)	$	—		$	(26,876	)	$	—		$	(19,724	)	$	—
Pre-tax gain (loss)	$	—		$	12,045		$	—		$	(42,010	)	$	—		$	5,465
Cash collateral receivable (payable)	$	—		$	—		$	—		$	—		$	—		$	—

_____________

* Maximum terms in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. If extended, de-designated swaps totaling $100 million terminate in 7 years and de-designated swaps totaling $150 million terminate in 17 years.

$50 million of our de-designated swaps have collateral requirements based on our corporate credit ratings. At our current credit ratings, we would be required to post collateral for any amount by which the swaps' negative mark-to-market fair value exceeds $20 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 swaps' negative mark-to-market fair value.

Based on March 31, 2012 market interest rates and balances related to our designated interest rate swaps, a lossof approximately $6.8 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.

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(14)     FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

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

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Valuation Methodologies

Oil and Gas Segment:

• The commodity option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through multiple sources.

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

Utilities Segment:

• The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant.

Corporate Segment:

• The interest rate swaps are valued using the market valuation approach. The company establishes fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

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Recurring Fair Value Measurements

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 March 31, 2012
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	404		$	—	$	—	$	—	$	404
Basis Swaps -- Oil	—		48			—		—		—		48
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		9,064			—		—		—		9,064
Commodity derivatives — Utilities	—		(8,412		)	3		—		17,651		9,242
Repurchase agreement (a)	43,128		—			—		—		—		43,128
Money market funds and term deposits (a)	12,791		—			—		—		—		12,791
Total	$	55,919	$	1,104		$	3	$	—	$	17,651	$	74,677
Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	1,347		$	—	$	—	$	—	$	1,347
Basis Swaps -- Oil	—		2,641			—		—		—		2,641
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		—			—		—		—		—
Commodity derivatives — Utilities	—		6,359			48		—		—		6,407
Interest rate swaps	—		109,163			—		—		—		109,163
Total	$	—	$	119,510		$	48	$	—	$	—	$	119,558

______________

(a) Level 1 assets and liabilities and described at Note 15.

	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 funds	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

23

	As of March 31, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas	$	—	$	7,626		$	106	$	—	$	—	$	7,732
Commodity derivatives — Utilities	—		(2,455		)	—		—		3,720		1,265
Money market funds	9,050		—			—		—		—		9,050
Total	$	9,050	$	5,171		$	106	$	—	$	3,720	$	18,047
Liabilities:
Commodity derivatives — Oil and Gas	$	—	$	7,523		$	—	$	—	$	—	$	7,523
Commodity derivatives — Utilities	—		—			—		—		—		—
Interest rate swaps	—		68,239			—		—		—		68,239
Total	$	—	$	75,762		$	—	$	—	$	—	$	75,762

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

	Fair Value at		Valuation	Unobservable	Range (Weighted
	March 31, 2012		Technique	Input	Average)
ASSETS
Commodity derivatives - Utilities(a)	$	3	Independent price quotes	Long-term natural gas prices	Not applicable
LIABILITIES
Commodity derivatives - Utilities(a)	$	48	Independent price quotes	Long-term natural gas prices	Not applicable

______________________

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

The following tables present the changes in Level 3 recurring fair value for the three months ended March 31, 2012 and 2011, respectively (in thousands):

	Three Months Ended March 31, 2012
Assets:	Commodity Derivatives -- Oil			Commodity Derivatives -- Gas		Commodity Derivatives -- Utilities		Total
Balances as of beginning of period	$	768		$	—	$	—	$	768
Total gain (loss) included in revenue	—			—		—		—
Total gain (loss) included in AOCI	(360		)	—		—		(360		)
Purchases	—			—		3		3
Issuances	—			—		—		—
Settlements	(4		)	—		—		(4		)
Transfers into level 3 (a)	—			—		—		—
Transfers out of level 3(b)(c)	(404		)	—		—		(404		)
Balances at end of period	$	—		$	—	$	3	$	3
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	3	$	3

24

	Three Months Ended March 31, 2012
Liabilities:	Commodity Derivatives -- Oil			Commodity Derivatives -- Gas		Commodity Derivatives -- Utilities		Total
Balances as of beginning of period	$	1,165		$	—	$	—	$	1,165
Total gain (loss) included in revenue	—			—		—		—
Total gain (loss) included in AOCI	182			—		—		182
Purchases	—			—		48		48
Issuances	—			—		—		—
Settlements	—			—		—		—
Transfers into level 3 (a)	—			—		—		—
Transfers out of level 3(b)(c)	(1,347		)	—		—		(1,347		)
Balances at end of period	$	—		$	—	$	48	$	48
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	48	$	48

	Three Months Ended March 31, 2011
	Commodity  Derivatives
Balance as of beginning of period	$	266
Unrealized losses	(160		)
Unrealized gains	—
Settlements	—
Transfers into level 3 (a)	—
Transfers out of level 3(b)	—
Balance at end of period	$	106
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	(159	)

____________

(a) Transfers into Level 3 would occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs.

(b) Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

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

Fair Value Measures

As required by accounting standards for derivatives and hedges, 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 March 31, 2012, December 31, 2011, and March 31, 2011, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 13.

25

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

As of March 31, 2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,662	$	—
Commodity derivatives	Derivative assets — non-current	854		—
Commodity derivatives	Derivative liabilities — current	—		2,904
Commodity derivatives	Derivative liabilities — non-current	—		1,084
Interest rate swaps	Derivative liabilities — current	—		6,777
Interest rate swaps	Derivative liabilities — non-current	—		18,441
Total derivatives designated as hedges		$	9,516	$	29,206
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	8,436
Commodity derivatives	Derivative assets — non-current	—		(27		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		6,407
Interest rate swaps	Derivative liabilities — current	—		66,708
Interest rate swaps	Derivative liabilities — non-current	—		17,237
Total derivatives not designated as hedges		$	—	$	98,761

As of December 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,739	$	—
Commodity derivatives	Derivative assets — non-current	1,919		—
Commodity derivatives	Derivative liabilities — current	—		2,559
Commodity derivatives	Derivative liabilities — non-current	—		818
Interest rate swaps	Derivative liabilities — current	—		6,513
Interest rate swaps	Derivative liabilities — non-current	—		20,363
Total derivatives designated as hedges		$	10,658	$	30,253
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	9,572
Commodity derivatives	Derivative assets — non-current	—		(52		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		7,156
Interest rate swaps	Derivative liabilities — current	—		75,295
Interest rate swaps	Derivative liabilities — non-current	—		20,696
Total derivatives not designated as hedges		$	—	$	112,667

26

As of March 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	6,757	$	—
Commodity derivatives	Derivative assets — non-current	975		—
Commodity derivatives	Derivative liabilities — current	—		4,688
Commodity derivatives	Derivative liabilities — non-current	—		2,835
Interest rate swaps	Derivative liabilities — current	—		6,769
Interest rate swaps	Derivative liabilities — non-current	—		12,955
Total derivatives designated as hedges		$	7,732	$	27,247
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	2,665
Commodity derivatives	Derivative assets — non-current	—		(209		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		—
Interest rate swaps	Derivative liabilities — current	—		48,515
Interest rate swaps	Derivative liabilities — non-current	—		—
Total derivatives not designated as hedges		$	—	$	50,971

A description of our derivative activities is included in Note 13. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income and Comprehensive Income.

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income and Comprehensive Income was as follows (in thousands):

Three Months Ended March 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) 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	$	(762	)	Interest expense	$	(1,822	)		$	—
Commodity derivatives	1,283			Revenue	3,009				—
Total	$	521			$	1,187			$	—

Three Months Ended March 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 Reclassified Gain/(Loss) 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	$	298		Interest expense	$	(1,892	)		$	—
Commodity derivatives	(4,083		)	Revenue	1,031				—
Total	$	(3,785	)		$	(861	)		$	—

27

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedging instruments on our Condensed Consolidated Statements of Income and Comprehensive Income was as follows (in thousands):

		Three Months Ended
		March 31, 2012
Derivatives Not Designated  as Hedging Instruments	Location of Gain/(Loss)  on Derivatives  Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swaps, net	$	12,045
Interest rate swaps - realized	Interest expense	(3,205		)
		$	8,840

		Three Months Ended
		March 31, 2011
Derivatives Not Designated  as Hedging Instruments	Location 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 swaps, net	$	5,465
Interest rate swaps - realized	Interest expense	(3,352		)
		$	2,113

(15)     FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments are as follows (in thousands) as of:

	March 31, 2012				December 31, 2011				March 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	56,132	$	56,132	$	21,628	$	21,628	$	26,418	$	26,418
Restricted cash (a)	$	8,960	$	8,960	$	9,254	$	9,254	$	3,406	$	3,406
Total derivative assets (b)	$	18,758	$	18,758	$	20,554	$	20,554	$	8,996	$	8,996
Total derivative liabilities (b)	$	119,558	$	119,558	$	133,400	$	133,400	$	75,762	$	75,762
Notes payable (a)	$	225,000	$	225,000	$	345,000	$	345,000	$	287,000	$	287,000
Long-term debt, including current maturities (c)	$	1,280,993	$	1,439,724	$	1,282,882	$	1,464,289	$	1,189,084	$	1,260,539

____________

(a) Carrying value approximates fair value due to short-term maturities and therefore is classified in Level 1 in the fair value hierarchy.

(b) See Note 14 for information on classification within the fair value hierarchy.

(c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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, overnight repurchase agreement accounts, money market funds and term deposits. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank.  Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal.  We believe however, the market risk arising from holding these financial instruments is minimal.  The carrying amount for cash and cash equivalents approximates fair value due to the short-term maturity of these instruments.

28

Restricted Cash

Restricted cash represents amounts required by Black Hills Wyoming project financing agreements. Of this total, $4.8 million, $0.0 million and $0.0 million for March 31, 2012, December 31, 2011 and March 31, 2011, respectively, were held in uninsured term deposits held at a Canadian bank.

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 13 and 14.

Notes Payable

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

Long-term Debt

Our debt instruments are marked to fair value using the market valuation approach. The fair value for our fixed rate debt instruments is estimated based on quoted market prices and yields for debt instruments having similar maturities and debt ratings. The carrying amounts of our variable rate debt approximate fair value due to the variable interest rates with short reset periods.

(16)     COMMITMENTS AND CONTINGENCIES

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

(17)     DISCONTINUED OPERATIONS

On February 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds were approximately $166.3 million, subject to final post-closing adjustments that are expected to be settled during the second quarter of 2012. The proceeds represent $108.8 million received from Twin Eagle and $57.5 million cash retained from Enserco prior to closing. We recorded an after-tax loss on sale of $1.6 million, including transaction related costs net of tax of $2.2 million.

The accompanying Condensed Consolidated Financial Statements have been classified to reflect Enserco as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification.

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

	For the Three Months Ended
	March 31, 2012			March 31, 2011
Revenue	$	(604	)	$	2,465
Pre-tax income (loss) from discontinued operations	(5,836		)	(3,174		)
Pre-tax gain (loss) on sale	(2,453		)	—
Income tax (expense) benefit	2,805			1,016
Income (loss) from discontinued operations, net of tax	$	(5,484	)	$	(2,158	)

29

Indirect corporate costs and inter-segment interest expenses totaling $1.6 million and $0.5 million for the three months ended March 31, 2012 and March 31, 2011, respectively, are reclassified from the Energy Marketing segment to the Corporate segment in continuing operations on the accompanying Condensed Consolidated Statements of Income and Comprehensive Income.

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

	December 31, 2011			March 31, 2011
Other current assets	$	280,221		$	243,473
Derivative assets, current and non-current	52,859			45,432
Property, plant and equipment, net	5,828			4,750
Goodwill	1,435			1,435
Other non-current assets	508			631
Other current liabilities	(132,951		)	(129,706		)
Derivative liabilities, current and non-current	(26,084		)	(30,932		)
Other non-current liabilities	(14,894		)	(2,652		)
Net assets	$	166,922		$	132,431

30

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

We are an integrated energy company operating principally in the United States with two major business groups — Utilities and Non-regulated Energy. We report our business groups in the following financial segments:

Business Group	Financial Segment
Utilities	Electric Utilities
	Gas Utilities
Non-regulated Energy*	Oil and Gas
	Power Generation
	Coal Mining

_______________

* In February 2012, we sold Enserco, our Energy Marketing segment, through a stock purchase agreement and therefore classified the segment as discontinued operations.

Our Utilities Group consists of our Electric and Gas Utilities segments. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 201,500 customers in South Dakota, Wyoming, Colorado and Montana and includes the operations of Cheyenne Light and its approximately 34,800 natural gas customers in Wyoming. Our Gas Utilities serve approximately 528,800 natural gas customers in Colorado, Iowa, Kansas and Nebraska. Our Non-regulated Energy Group consists of our Oil and Gas, Power Generation and Coal Mining segments. Our Oil and Gas segment primarily engages in exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy primarily to other utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyoming and sells the coal primarily to on-site, mine-mouth power generation facilities.

Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market prices. In particular, the normal peak usage season for gas utilities is November through March, and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2012 and 2011, and our financial condition as of March 31, 2012, December 31, 2011, and March 31, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 49.

The following business group and segment information does not include intercompany eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated. Information has been revised to remove information related to the operations of our Energy Marketing segment, now classified as discontinued operations, as a result of its sale on February 29, 2012.

31

Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Income from continuing operations for the three months ended March 31, 2012 was $35.3 million, or $0.80 per share, compared to Income from continuing operations of $29.1 million, or $0.73 per share, reported for the same period in 2011. The 2012 Income from continuing operations included a $7.8 million non-cash after-tax unrealized mark-to-market gain on certain interest rate swaps and an after-tax write-off of $1.0 million of deferred financing costs related to the previous Revolving Credit Facility. The 2011 Income from continuing operations included a $3.6 million after-tax unrealized mark-to-market gain on the same interest rate swaps.

Net income was $29.8 million, or $0.68 per share, in 2012 compared to $26.9 million, or $0.68 per share, in 2011.

	Three Months Ended March 31,
	2012			2011			Increase (Decrease)
	(in thousands)
Revenue
Utilities	$	339,691		$	378,535		$	(38,844	)
Non-regulated Energy	56,261			41,021			15,240
Corporate	—			—			—
Intercompany eliminations	(30,101		)	(18,721		)	(11,380		)
	$	365,851		$	400,835		$	(34,984	)
Net income (loss)
Electric Utilities	$	8,746		$	10,249		$	(1,503	)
Gas Utilities	15,207			19,263			(4,056		)
Utilities	23,953			29,512			(5,559		)
Oil and Gas	13			(715		)	728
Power Generation	6,914			1,186			5,728
Coal Mining	1,000			(1,298		)	2,298
Non-regulated Energy	7,927			(827		)	8,754
Corporate and Eliminations (a)	3,391			383			3,008
Income from continuing operations	35,271			29,068			6,203
Income (loss) from discontinued operations, net of tax	(5,484		)	(2,158		)	(3,326		)
Net income (loss)	$	29,787		$	26,910		$	2,877

______________

(a) Financial results of our Energy Marketing segment have been classified as discontinued operations. Certain indirect corporate costs and inter-segment expenses previously charged to our Energy Marketing segment are reclassified to continuing operations and are included in the Corporate segment. See Note 17 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

32

Business Group highlights for 2012 include:

Utilities Group

• Utility results were unfavorably impacted by warmer weather. During 2012, we experienced the warmest March on record for our jurisdictions causing reduced heating degree days. Heating degree days during the period were 13% and 19% lower than weighted average norms for our Electric and Gas Utilities, respectively. When compared to colder than normal weather during the same quarter in 2011, heating degree days were 20% and 24% lower than the same period in 2011 for our Electric Utilities and our Gas Utilities, respectively.

• Colorado Electric’s new $230 million, 180 MW power plant near Pueblo, Colorado began commercial operations and started serving utility customers on January 1, 2012. New rates were effective January 1, 2012 and provided an additional $5.8 million in gross margins at Colorado Electric for the three months ended March 31, 2012.

• On November 1, 2011, Cheyenne Light and Black Hills Power filed a joint request with the WPSC for a CPCN to construct and operate a new $237 million natural gas-fired electric generation facility and related gas and electric transmission in Cheyenne, WY. The proposed facility includes construction of one simple-cycle, 37 MW combustion turbine that will be wholly owned by Cheyenne Light and one combined-cycle, 95 MW unit that would be jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Light would own 40 MW and Black Hills Power would own 55 MW of the combined cycle unit. Pending WPSC approval, and the timely receipt of necessary environmental and industrial siting permits, commercial operation would be expected to commence in 2014. A hearing with the WPSC is scheduled in July 2012.

• Construction by Colorado Electric is progressing on a 29 MW wind turbine project as part of its plan to meet Colorado's Renewable Energy Standard. Colorado Electric's 50% share of this project will cost approximately $26.5 million, and the project is expected to begin serving Colorado Electric customers no later than December 31, 2012. Our 50% of the total expenditures on the project were $15.4 million as of March 31, 2012.

• On April 13, 2012, the Colorado Public Utilities Commission issued its final order denying Colorado Electric's request for a certificate of public convenience and necessity to construct a third utility-owned, 88 MW natural gas-fired turbine at the existing Pueblo Airport generating location. Colorado Electric retains the right under the Colorado Clean Air – Clean Jobs Act to own the 42 megawatts of replacement generation for the W.N. Clark plant that is required to be retired on or before December 13, 2013. Colorado Electric is expected to file an electric resource plan by July 30, 2012 that will identify an alternative replacement resource for the W.N. Clark plant.

Non-regulated Energy Group

• In February 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. Net pre-tax cash proceeds were $166.3 million, subject to final post-closing adjustments that are expected to be settled during the second quarter of 2012. The proceeds represent $108.8 million received from Twin Eagle and $57.5 million cash retained from Enserco prior to close. We recorded an after-tax loss on sale of $1.6 million, including costs to sell of $2.2 million. The activities of the Energy Marketing segment have been reclassified to discontinued operations.

• Colorado IPP’s new $261 million, 200 MW power plant near Pueblo, Colorado began serving customers on Jan. 1, 2012, with its output sold under a 20-year power purchase agreement to Colorado Electric.

Corporate

• On February 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring February 1, 2017 at favorable terms. Deferred financing costs of $1.5 million were written off during the first quarter of 2012 relating to the previous credit facility.

• We recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of $12.0 million for the three months ended March 31, 2012 compared to a $5.5 million unrealized mark-to-market gain on these swaps for the same period in 2011.

33

Utilities Group

We report two segments within the Utilities Group: Electric Utilities and Gas Utilities. The Electric Utilities segment includes the electric operations of Black Hills Power, Colorado Electric and the electric and natural gas operations of Cheyenne Light. The Gas Utilities segment includes the regulated natural gas utility operations of Black Hills Energy in Colorado, Iowa, Kansas and Nebraska.

Electric Utilities

	Three Months Ended March 31,
	2012			2011
	(in thousands)
Revenue — electric	$	146,281		$	134,870
Revenue — Cheyenne Light gas	12,888			13,399
Total revenue	159,169			148,269
Fuel, purchased power and cost of gas — electric	65,598			65,678
Purchased gas — Cheyenne Light gas	8,118			8,396
Total fuel, purchased power and cost of gas	73,716			74,074
Gross margin — electric	80,683			69,192
Gross margin — Cheyenne Light gas	4,770			5,003
Total gross margin	85,453			74,195
Operations and maintenance	39,230			37,114
Depreciation and amortization	18,932			12,824
Total operating expenses	58,162			49,938
Operating income	27,291			24,257
Interest expense, net	(13,220		)	(9,944		)
Other income (expense), net	718			409
Income tax benefit (expense)	(6,043		)	(4,473		)
Income (loss) from continuing operations	$	8,746		$	10,249

34

The following tables summarize revenue, quantities generated and purchased, quantities sold, degree days and power plant availability for our Electric Utilities:

	Three Months Ended March 31,
Revenue - Electric (in thousands)	2012		2011
Residential	$	46,562	$	45,677
Commercial	49,892		46,442
Industrial	18,321		16,243
Municipal	3,788		4,061
Total Retail Revenue - Electric	118,563		112,423
Contract Wholesale - Black Hills Power	4,905		4,620
Off-system Wholesale (a)	14,019		9,840
Other Revenue	8,794		7,987
Total Revenue - Electric	$	146,281	$	134,870

____________

(a) Off-system sales revenue during 2011 was deferred until a sharing mechanism was approved by the CPUC in December 2011, and recognition of 25% of the revenue commenced January 2, 2012. As a result, Colorado Electric deferred $2.9 million in off-system revenue during the three months ended March 31, 2011.

	Three Months Ended March 31,
Quantities Generated and Purchased (in MWh)	2012	2011
Generated —
Coal-fired	684,252	665,884
Gas and Oil-fired	1,995	1,024
Total Generated	686,247	666,908
Total Purchased	1,147,280	1,055,566
Total Generated and Purchased	1,833,527	1,722,474

	Three Months Ended March 31,
Quantity Sold (in MWh)	2012	2011
Residential	376,317	404,633
Commercial	485,423	489,570
Industrial	221,751	213,486
Municipal	35,319	38,493
Total Retail Quantity Sold	1,118,810	1,146,182
Contract Wholesale - Black Hills Power	89,048	89,959
Total Off-system Wholesale	527,547	404,844
Total Losses and Company Use	98,122	81,489
Total Quantity Sold	1,833,527	1,722,474

35

	Three Months Ended March 31,
Degree Days	2012			2011
Heating Degree Days:	Actual	Variance  from 30-Year Average		Actual	Variance  from 30-Year Average
Actual —
Black Hills Power	2,711	(16	)%	3,707	12	%
Cheyenne Light	2,761	(8	)%	3,123	—	%
Colorado Electric	2,294	(13	)%	2,781	5	%
Cooling Degree Days:
Actual —
Black Hills Power	—	—	%	—	—	%
Cheyenne Light	—	—	%	—	—	%
Colorado Electric	—	—	%	—	—	%

Electric Utilities Power Plant Availability	Three Months Ended March 31,
	2012		2011
Coal-fired plants (a)	90.8	%	91.3	%
Other plants	95.0	%	98.6	%
Total availability	92.9	%	93.9	%

_________________________

(a) 2012 includes planned overhauls at Wygen II. 2011 includes a major overhaul and an unplanned outage at the PacifiCorp operated Wyodak plant.

Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities is Cheyenne Light's natural gas distribution system. The following table summarizes certain operating information for these natural gas distribution operations:

	Three Months Ended March 31,
	2012		2011
Revenue - Gas (in thousands):
Residential	$	7,630	$	7,978
Commercial	3,810		3,807
Industrial	1,237		1,276
Other Sales Revenue	211		338
Total Revenue - Gas	$	12,888	$	13,399
Gross Margin (in thousands):
Residential	$	3,226	$	3,388
Commercial	1,173		1,212
Industrial	164		177
Other Gross Margin	207		226
Total Gross Margin	$	4,770	$	5,003
Volumes Sold (Dth):
Residential	969,678		1,068,461
Commercial	580,940		623,723
Industrial	237,140		256,521
Total Volumes Sold	1,787,758		1,948,705

36

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Income from continuing operations for the Electric Utilities was $8.7 million for the three months ended March 31, 2012 compared to $10.2 million for the three months ended March 31, 2011 as a result of:

Gross margin increased $11.3 million primarily due to a $9.3 million increase related to rate adjustments that include a return on significant capital investments specifically at Colorado Electric, and a $0.6 million increase in off-system sales mainly from higher quantities sold, partially offset by a $2.8 million decrease due to lower quantities sold as a result of lower customer demand.

Operations and maintenance increased $2.1 million primarily due to higher property taxes and increased corporate allocations resulting from the generating facility in Pueblo, Colorado, partially offset by lower maintenance costs.

Depreciation and amortization increased $6.1 million primarily due to a higher asset base including additional depreciation associated with the 180 MW generating facility constructed in Pueblo, Colorado and depreciation of the capital lease assets associated with the 200 MW generating facility providing capacity and energy from Colorado IPP.

Interest expense, net increased $3.3 million primarily due to lower capitalized interest associated with the completed construction of the Pueblo generating facility in December 2011.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate increased due to unfavorable state income tax true-up adjustments that may not occur in the future and the impact of research and development credits not being renewed.

Gas Utilities

	Three Months Ended March 31,
	2012			2011
	(in thousands)
Natural gas — regulated	$	172,169		$	223,032
Other — non-regulated services	8,353			7,234
Total revenue	180,522			230,266
Natural gas — regulated	108,116			149,503
Other — non-regulated services	3,869			3,626
Total cost of sales	111,985			153,129
Gross margin	68,537			77,137
Operations and maintenance	31,299			34,560
Depreciation and amortization	6,157			6,021
Total operating expenses	37,456			40,581
Operating income (loss)	31,081			36,556
Interest expense, net	(6,540		)	(6,972		)
Other income (expense), net	11			25
Income tax benefit (expense)	(9,345		)	(10,346		)
Income (loss) from continuing operations	$	15,207		$	19,263

37

The following tables summarize revenue, gross margin, volumes sold and degree days for our Gas Utilities:

Revenue (in thousands)	Three Months Ended March 31,
	2012		2011
Residential	$	118,933	$	156,769
Commercial	40,802		54,730
Industrial	2,008		2,145
Transportation	7,263		8,079
Other Sales Revenue	3,163		1,309
Total Regulated Revenue	172,169		223,032
Non-regulated Services	8,353		7,234
Total Revenue	$	180,522	$	230,266

Gross Margin (in thousands)	Three Months Ended March 31,
	2012		2011
Residential	$	42,592	$	51,396
Commercial	10,766		12,571
Industrial	384		407
Transportation	7,264		8,079
Other Sales Margins	3,048		1,076
Total Regulated Gross Margin	64,054		73,529
Non-regulated Services	4,483		3,608
Total Gross Margin	$	68,537	$	77,137

Volumes Sold (in Dth)	Three Months Ended March 31,
	2012	2011
Residential	13,767,358	17,534,411
Commercial	5,528,225	7,073,483
Industrial	369,492	334,991
Transportation	18,050,184	16,286,552
Other Volumes	24,450	44,985
Total Volumes Sold	37,739,709	41,274,422

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	Three Months Ended March 31, 2012
Heating Degree Days:	Actual	Variance From  Normal
Colorado	2,350	(16	)%
Nebraska	2,400	(21	)%
Iowa	2,799	(20	)%
Kansas (a)	2,040	(18	)%
Combined (b)	2,432	(19	)%

	Three Months Ended March 31, 2011
Heating Degree Days:	Actual	Variance From  Normal
Colorado	2,761	(4	)%
Nebraska	3,281	2	%
Iowa	3,694	—	%
Kansas (a)	2,625	2	%
Combined (b)	3,212	1	%

_______________

(a) Our gross margin in Kansas utilizes normal degree days due to an approved weather normalization mechanism.

(b) The combined heating degree days are calculated based on a weighted average of total customers by state.

Our Gas Utilities are highly seasonal and sales volumes vary considerably with weather and seasonal heating and industrial loads. Over 70% of our Gas Utilities' revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for and certain expenses of these operations fluctuate significantly among quarters. Depending upon the state jurisdiction in which our Gas Utilities operate, the winter heating season begins around November 1 and ends around March 31.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Income from continuing operations for the Gas Utilities was $15.2 million for the three months ended March 31, 2012 compared to Income from continuing operations of $19.3 million for the three months ended March 31, 2011 as a result of:

Gross margin decreased $8.6 million primarily due to a $7.2 million impact from milder weather than in the same period in the prior year. Heating degree days were 24% lower for the three months ended March 31, 2012 compared to the same period in the prior year and 19% lower than normal.

Operations and maintenance decreased $3.3 million primarily due to decreased bad debt costs and cost efficiencies.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net decreased $0.4 million primarily due to lower interest rates.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate increased as a result of an unfavorable state income tax true-up adjustment that may not occur in the future and lower pre-tax net income.  For the period ended March 31, 2011, the effective tax rate was favorably impacted as a result of federal income tax related research and development credits and a flow-through tax adjustment involving Iowa Gas.

39

Regulatory Matters — Utilities Group

The following summarizes our recent state and federal rate case and initial surcharge orders (dollars in millions):                        

Revenue

Revenue

Approved Capital Structure

Type of  Service

Date Requested

Date Effective

Amount Requested

Amount Approved

Return on Equity

Equity

Debt

Nebraska Gas (1)

Gas

12/2009

9/2010

$

12.1

$

8.3

10.1

%

52.0

%

48.0

%

Iowa Gas (2)

Gas

6/2010

2/2011

$

4.7

$

3.4

Global Settlement

Global Settlement

Global Settlement

Colorado Electric (2)

Electric

4/2011

1/2012

$

40.2

$

28.0

9.8% - 10.2%

49.1

%

50.9

%

Cheyenne Light (3)

Electric/Gas

12/2011

Pending

$

8.5

Pending

Pending

Pending

Pending

Black Hills Power (2)

Electric

1/2011

6/2011

Not Applicable

$

3.1

Not Applicable

Not Applicable

Not Applicable

(1) In December 2009, Nebraska Gas filed a rate case with the NPSC and interim rates went into effect on March 1, 2010. In August 2010, NPSC issued a decision approving an annual revenue increase of approximately $8.3 million, based on a return on equity of 10.1% with a capital structure of 52% equity effective on September 1, 2010. A refund to customers for the difference between interim rates and approved rates was completed in the first quarter of 2011. The Nebraska Public Advocate filed an appeal with the District Court which has been denied. Subsequently, the Nebraska Public Advocate filed a notice of appeal in the Court of Appeals. On March 20, 2012 the Court of Appeals affirmed the earlier decision of the District Court. However, the Nebraska Public Advocate petitioned the Nebraska Supreme Court to hear an appeal in April 2012.

(2) These rate cases were previously described in our 2011 Annual Report filed on Form 10-K.

(3) Cheyenne Light filed requests on December 2, 2011, for electric and natural gas revenue increases with the WPSC seeking a $5.9 million increase in annual electric revenue and a $2.6 million increase in annual natural gas revenue. A procedural schedule has been published and a public hearing with the WPSC is scheduled for the week of June 18, 2012.

Non-regulated Energy Group

We report three segments within our Non-regulated Energy Group: Oil and Gas, Coal Mining and Power Generation.

For more than 15 years, we also owned and operated Enserco, an energy marketing business that engages in natural gas, crude oil, coal, power and environmental marketing and trading in the United States and Canada. We sold Enserco on February 29, 2012 which resulted in our Energy Marketing segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations.

Oil and Gas

	Three Months Ended March 31,
	2012			2011
	(in thousands)
Revenue	$	21,645		$	17,906
Operations and maintenance	10,834			10,567
Depreciation, depletion and amortization	9,323			7,321
Total operating expenses	20,157			17,888
Operating income (loss)	1,488			18
Interest expense	(1,605		)	(1,383		)
Other income (expense), net	29			(185		)
Income tax benefit (expense)	101			835
Income (loss) from continuing operations	$	13		$	(715	)

40

The following tables provide certain operating statistics for our Oil and Gas segment:

	Three Months Ended March 31,
	2012	2011
Production:
Bbls of oil sold	145,477	103,550
Mcf of natural gas sold	2,388,475	2,011,167
Gallons of NGL sold	814,585	864,440
Mcf equivalent sales	3,377,706	2,755,958

	Three Months Ended March 31,
	2012		2011
Average price received: (a)
Oil/Bbl	$	77.99	$	66.83
Gas/Mcf	$	3.61	$	4.65
NGL/gallon	$	0.95	$	0.92
Depletion expense/Mcfe	$	2.47	$	2.36

____________

(a) Net of hedge settlement gains and losses

The following is a summary of certain average operating expenses per Mcfe:

	Three Months Ended March 31, 2012									Three Months Ended March 31, 2011
Producing Basin	LOE			Gathering,  Compression  and Processing		Production Taxes		Total		LOE		Gathering,  Compression and Processing		Production Taxes		Total
San Juan	$	0.97		$	0.32	$	0.36	$	1.65	$	1.25	$	0.46	$	0.55	$	2.26
Piceance	(0.03		)	0.49		0.15		0.61		0.68		0.80		0.25		1.73
Powder River	1.38			—		1.31		2.69		1.31		—		1.29		2.60
Williston	0.71			—		1.25		1.96		0.26		—		1.50		1.76
All other properties	1.68			—		0.08		1.76		1.66		—		0.40		2.06
Total weighted average	$	0.89		$	0.21	$	0.60	$	1.70	$	1.18	$	0.28	$	0.74	$	2.20

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Income from continuing operations for the Oil and Gas segment was $0.0 million for the three months ended March 31, 2012 compared to Loss from continuing operations of $0.7 million for the same period in 2011 as a result of:

Revenue increased primarily due to a 17% increase in the average hedged price received for crude oil sales along with a 40% increase in crude oil volume sold. Crude oil production increases reflect volumes from new wells in our ongoing drilling program in the Bakken shale formation. A 17% increase in natural gas and NGL volumes, due mainly to the completion of three Mancos formation test wells in the San Juan and Piceance Basins, was partially offset by a 22% decrease in average hedged price received for natural gas.

Operations and maintenance costs were comparable to the same period in the prior year.

Depreciation, depletion and amortization increased $2.0 million primarily due to a higher depletion rate per Mcfe on higher volumes. The increased depletion rate is primarily driven by higher capital costs for our Bakken oil drilling program.

Interest expense, net was comparable to the same period in the prior year.

41

Other income (expense), net was comparable to the same period in the prior year.

Income tax (expense) benefit: For 2012, the benefit generated by percentage depletion had a greater impact on the effective tax rate compared to the same period in 2011.

Coal Mining

	Three Months Ended March 31,
	2012			2011
	(in thousands)
Revenue	$	14,989		$	15,495
Operations and maintenance	11,478			14,572
Depreciation, depletion and amortization	3,696			4,618
Total operating expenses	15,174			19,190
Operating income (loss)	(185		)	(3,695		)
Interest income, net	755			960
Other income	881			569
Income tax benefit (expense)	(451		)	868
Income (loss) from continuing operations	$	1,000		$	(1,298	)

The following table provides certain operating statistics for our Coal Mining segment (in thousands):

	Three Months Ended March 31,
	2012	2011
Tons of coal sold	1,103	1,370
Cubic yards of overburden moved	2,642	3,455

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Income from continuing operations for the Coal Mining segment was $1.0 million for the three months ended March 31, 2012 compared to Loss from continuing operations of $1.3 million for the same period in 2011, as a result of:

Revenue decreased $0.5 million primarily due to a 19% decrease in tons sold due to the expiration of our train load-out contract and a planned outage at the Wygen II facility, partially offset by a 20% increase in average price per ton and increased volumes sold to the Wyodak plant that experienced an outage in 2011. The higher average sales price reflects the impact of price escalators and expiration of our train load-out contract. Approximately 50% of our coal production was sold under contracts that include price adjustments based on actual mining cost increases.

Operations and maintenance decreased $3.1 million primarily from lower costs related to a train-load out contract that expired at the end of 2011, reducing tons moved.

Depreciation, depletion and amortization decreased $0.9 million primarily due to a lower asset base.

Interest income, net was comparable to the same period in the prior year.

Other income was comparable to the same period in the prior year.

Income tax benefit (expense): The change in the effective tax rate was primarily due to the impact of percentage depletion.

42

Power Generation

	Three Months Ended March 31,
	2012			2011
	(in thousands)
Revenue	$	19,627		$	7,620
Operating, general and administrative costs	7,132			4,188
Depreciation and amortization	1,114			1,064
Total operating expense (income)	8,246			5,252
Operating income	11,381			2,368
Interest expense, net	(4,743		)	(1,791		)
Other (expense) income	5			1,204
Income tax (expense) benefit	271			(595		)
Income (loss) from continuing operations	$	6,914		$	1,186

The following table provides certain operating statistics for our plants within the Power Generation segment:

	Three Months Ended March 31,
	2012		2011
Contracted power plant fleet availability:
Coal-fired plant	100.0	%	100.0	%
Natural gas-fired plants	99.6	%	100.0	%
Total availability	99.7	%	100.0	%

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Income from continuing operations for the Power Generation segment was $6.9 million for the three months ended March 31, 2012 compared to Income from continuing operations of $1.2 million for the same period in 2011 as a result of:

Revenue increased due to the sale of capacity and energy to Colorado Electric upon commencement of commercial operation of our 200 MW generating facility in Pueblo, Colorado.

Operations and maintenance increased $2.9 million primarily due to the costs to operate our 200 MW generating facility in Pueblo, Colorado, which began serving customers on January 1, 2012.

Depreciation and amortization were consistent with prior year. The new generating facility's PPA to supply capacity and energy to Colorado Electric is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net increased due to the decrease in capitalized interest as a result of the completion of construction of our generating facility in Pueblo, Colorado.

Other (expense) income, net in 2011 included earnings from our partnership investment in certain Idaho generating facilities and a gain on sale of our ownership interest in the partnership which did not reoccur in 2012.

Income tax (expense) benefit: The effective tax rate was impacted by a favorable state tax true-up that included certain tax credits. Such credits are the result of meeting certain applicable state requirements including the ability to utilize these incentives. The incentives pertain to qualified plant expenditures related to investment and research and development.

43

Corporate

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011. Income from continuing operations for Corporate was $3.4 million for the three months ended March 31, 2012 compared to Income from continuing operations of $0.5 million for the three months ended March 31, 2011 primarily as a result of an unrealized, non-cash mark-to-market gain on certain interest rate swaps for the quarter ended March 31, 2012 of approximately $12.0 million compared to a $5.5 million unrealized, mark-to-market non-cash gain on these interest rate swaps in the prior year.

Corporate was allocated after-tax costs of $1.6 million related to on-going costs associated with our Energy Marketing segment for the three months ended March 31, 2012 which could not be included in discontinued operations compared to after-tax costs of $0.5 million for the three months ended March 31, 2011.

Discontinued Operations

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011.

On February 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Cash proceeds were approximately $166.3 million, subject to final post-closing adjustments that are expected to be settled during the second quarter of 2012. The proceeds represent $108.8 million received from Twin Eagle and $57.5 million cash retained from Enserco prior to closing. We recorded an after-tax loss on sale of $1.6 million, including transaction related costs of $2.2 million.

Loss from discontinued operations, net of tax was $5.5 million, including an after-tax loss on the sale of $1.6 million, for the three months ended March 31, 2012compared to a loss from discontinued operations, net of tax of $2.2 million for the three months ended March 31, 2011.

Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2011 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting policies, see Part II, Item 7 of our 2011 Annual Report on Form 10-K.

Liquidity and Capital Resources

Cash Flow Activities

The following table summarizes our cash flows for the three months ended March 31, 2012 and 2011 (in thousands):

Cash provided by (used in):	2012			2011			Increase (Decrease)
Operating activities	$	96,065		$	111,271		$	(15,206	)
Investing activities	$	41,466		$	(121,758	)	$	163,224
Financing activities	$	(140,167	)	$	22,065		$	(162,232	)

Year-to-Date 2012 Compared to Year-to-Date 2011

Operating Activities

Net cash provided by operating activities was $15.2 million lower for the three months ended March 31, 2012 than for the same period in 2011 primarily attributable to:

• Cash earnings (net income plus non-cash adjustments) were $7.1 million higher for the three months ended March 31, 2012 than for the same period the prior year.

44

• Net inflows from operating assets and liabilities were $6.1 million for the three months ended March 31, 2012, a decrease of $5.0 million from the same period in the prior year. In addition to normal working capital changes, the decrease primarily related to decreased gas volumes due to warmer weather and to lower gas prices.

• Cash contributions to the defined benefit pension plan were $25.0 million in 2012 compared to $0.0 million in 2011.

Investing Activities

Net cash provided by investing activities was $163.2 million higher for the three months ended March 31, 2012 than in the same period in 2011 reflecting cash proceeds received from the sale of Enserco of $108.8 million and reduced capital expenditures of $54.0 million due to the completion of construction of 180 MW of natural gas-fired electric generation at Colorado Electric and 200 MW of natural gas-fired electric generation at Black Hills Colorado IPP in 2011.

Financing Activities

Net cash used in financing activities was $162.2 million higher for the three months ended March 31, 2012 than in the same period in 2011 primarily due to applying the proceeds from the sale of Enserco to pay down short-term borrowings on the Revolving Credit Facility of approximately $110 million. Cash dividends on common stock of $16.3 million were paid in 2012 compared to cash dividends paid of $14.4 million in 2011.

Dividends

Dividends paid on our common stock totaled $16.3 million for the three months ended March 31, 2012, or $0.37 per share. On April 24, 2012, our Board of Directors declared an additional quarterly dividend of $0.37 per share payable June 1, 2012, which is equivalent to an annual dividend rate of $1.48 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facility and our future business prospects.

Financing Transactions and Short-Term Liquidity

Our principal sources of short-term liquidity are our Revolving Credit Facility and cash provided by operations. In addition to availability under our Revolving Credit Facility described below, as of March 31, 2012, we had approximately $56 million of unrestricted cash.  The net cash proceeds from the Enserco sale were utilized to reduce short-term debt by approximately $110 million with the remainder included in our March 31, 2012 cash balance.

Revolving Credit Facility

Our $500 million Revolving Credit Facility expiring February 1, 2017 can be used for the issuance of letters of credit, to fund working capital needs and for general corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50%, 1.50% and 1.50%, respectively. The facility contains a commitment fee that will be charged on the unused amount of the Facility. Based upon current credit ratings, the fee is 0.25%. The facility contains an accordion feature which allows us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million.

At March 31, 2012, we had borrowings of $75 million and letters of credit outstanding of $41 million on our Revolving Credit Facility. Available capacity remaining was approximately $384 million at March 31, 2012.

The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions, maintenance of certain financial covenants and a recourse leverage ratio not to exceed 0.65 to 1.00. At March 31, 2012, our long-term debt ratio was 50.9%, our total debt leverage ratio (long-term debt and short-term debt) was 55.2%, and our recourse leverage ratio was approximately 56.4%. We were in compliance with these covenants as of March 31, 2012.

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In addition to covenant violations, an event of default under the Revolving Credit Facility may be triggered by other events, such as a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $35 million or more. Subject to applicable cure periods (none of which apply to a failure to timely pay indebtedness), an event of default would permit the lenders to restrict our ability to further access the credit facility for loans or new letters of credit, and could require both the immediate repayment of any outstanding principal and interest and the cash collateralization of outstanding letter of credit obligations.

Corporate Term Loans

In June 2011, we entered into a one-year $150 million unsecured, single draw, term loan due on June 24, 2012. The cost of borrowing under the loan is based on a spread of 1.25% over LIBOR (1.50% at March 31, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of March 31, 2012.

In December 2010, we entered into a one-year $100.0 million term loan with J.P. Morgan and Union Bank due in December 2011. On September 30, 2011, we extended that term loan for two years under the existing terms to September 13, 2013. The cost of borrowing under this Term Loan is based on a spread of 1.375% over LIBOR (1.625% at March 31, 2012). The covenants are substantially the same as those included in the Revolving Credit Facility with an additional requirement to maintain a minimum consolidated net worth. We were in compliance with these covenants as of March 31, 2012.

Repayment of Long-term Debt

On March 28, 2012, Black Hills Power provided notice to the trustee of its intent to call the Pollution Control Refund Revenue Bonds. These bonds were originally due to mature on October 1, 2014. The principal amount due on the bonds has been reclassified to Current maturities of long-term debt on the accompanying Condensed Consolidated Balance Sheets. Repayment of $6.5 million principal and accrued interest will be made on May 15, 2012.

Dividend Restrictions

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 stockholders is derived from these cash flows. As a result of certain statutory limitations or regulatory or financing agreements, we could have restrictions on the amount of distributions allowed to be made by our subsidiaries.

• Our utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory authorities they can pay the utility holding company and also may have further restrictions under the Federal Power Act. As of March 31, 2012, the restricted net assets at our Electric and Gas Utilities were approximately $81.4 million.

• As required by the covenants in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted equity of at least $100.0 million. In addition, Black Hills Wyoming holds $9.0 million of restricted cash associated with the project financing requirements.

Future Financing Plans

We have substantial capital expenditures planned in 2012, which primarily include construction of additional utility generation to serve Black Hills Power and Cheyenne Light customers, wind generation to meet renewable standards in Colorado, environmental upgrades and replacements to existing generation to meet governmental pollution mandates and potential capital deployment in oil and gas drilling to prove-up reserves. Our capital requirements are expected to be financed through a combination of operating cash flows, borrowings on our Revolving Credit Facility, term loans and long-term financings and equity issuances.

In 2012, we may consider refinancing the $225 million of debt due in 2013 and, we are evaluating financing options that include senior unsecured notes, first mortgage bonds, term loans and project financings. We intend to maintain a consolidated debt-to-capitalization level in the range of 50% to 55%; however, due to capital projects, we may exceed this level on a temporary basis. We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and our maintenance capital requirements.

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Hedges and Derivatives

Interest Rate Swaps

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations.

We have interest rate swaps with a notional amount of $250 million that are not designated as hedge instruments. Accordingly, mark-to-market changes in value on these swaps are recorded within the Condensed Consolidated Statements of Income and Comprehensive Income. For the three months ended March 31, 2012, we recorded $12.0 million pre-tax unrealized mark-to-market non-cash gains on the swaps. The mark-to-market value on these swaps was a liability of $83.9 million at March 31, 2012. Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A 0.01% move in the interest rate curves over the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of 7 and 17 years and have amended early termination dates ranging from December 15, 2012 to December 16, 2013. We anticipate extending these agreements upon the early termination dates and have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly as they relate to our planned capital requirements to build gas-fired power generation facilities to serve our Black Hills Power and Cheyenne Light customers, and because of our upcoming holding company debt maturities, which are $225 million and $250 million in years 2013 and 2014, respectively. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended, we will cash settle these swaps for an amount equal to their fair values on the termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of 4.75 years. These swaps have been designated as cash flow hedges, and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $25.2 million at March 31, 2012.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2011 Annual Report on Form 10-K filed with the SEC.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms including collateral requirements. As of March 31, 2012, our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as follows:

Rating Agency	Rating	Outlook
Fitch	BBB-	Stable
Moody's	Baa3	Stable
S&P	BBB-	Stable

In addition, as of March 31, 2012, Black Hills Power's first mortgage bonds were rated as follows:

Rating Agency	Rating	Outlook
Fitch	A-	Stable
Moody's	A3	Stable
S&P	BBB+	Stable

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Capital Requirements

Actual and forecasted capital requirements for maintenance capital and development capital are as follows (in thousands):

	Expenditures for the		Total		Total		Total
	Three Months Ended March 31, 2012		2012 Planned Expenditures		2013 Planned Expenditures		2014 Planned Expenditures
Utilities:
Electric Utilities (1)	$	29,513	$	221,600	$	304,500	$	187,000
Gas Utilities	5,318		46,000		54,700		43,800
Non-regulated Energy:
Oil and Gas (2)	16,444		86,500		83,900		122,600
Power Generation	3,433		2,900		4,900		6,700
Coal Mining	2,202		18,800		7,200		10,800
Corporate	4,856		10,300		6,000		4,700
	$	61,766	$	386,100	$	461,200	$	375,600

____________

(1) Planned expenditures in 2012 and 2013 for the proposed 88 MW of gas-fired generation at Colorado Electric have been removed from the forecasted expenditures reported in our Annual Report filed on Form 10-K as a result of the denial of our request for a CPCN.

(2) Capital expenditures at our Oil and Gas Segment are driven by economics and may vary depending on the pricing environment for crude oil and natural gas. Forecasted expenditures shown above for the Oil and Gas segment have been decreased from the amounts reported in our Annual Report filed on Form 10-K due to delaying our gas drilling program as a result of lower natural gas prices.

We continually evaluate all of our forecasted capital expenditures, and if determined prudent, we may defer some of these expenditures for a period of time. Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.

Contractual Obligations

There have been no significant changes to contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Guarantees

There have been no significant changes to guarantees from those previously disclosed in Note 20 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

New Accounting Pronouncements

Other than the pronouncements reported in our 2011 Annual Report on Form 10-K filed with the SEC and those discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial statements.

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FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking information. All statements, other than statements of historical fact, included in this report that address activities, events, or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. The factors which may cause our results to vary significantly from our forward-looking statements include the risk factors described in Item 1A of our 2011 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q, and other reports that we file with the SEC from time to time, and the following:

• We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and our maintenance capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:

• Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and therefore may not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecasted capital expenditure requirements.

• Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.

• We expect to fund a portion of our forecasted capital requirements through a combination of long-term debt and equity issuances however capital market conditions and market uncertainties related to interest rates may affect our ability to raise capital on favorable terms.

• We expect to make approximately $386.1 million, $461.2 million and $375.6 million of capital expenditures in 2012, 2013 and 2014, respectively. Some important factors that could cause actual expenditures to differ materially from those anticipated include:

• The timing of planned generation, transmission or distribution projects for our Utilities Group is influenced by state and federal regulatory authorities and third parties. The occurrence of events that impact (favorably or unfavorably) our ability to make planned or unplanned capital expenditures could cause our forecasted capital expenditures to change.

• Forecasted capital expenditures associated with our Oil and Gas segment are driven, in part, by current product prices. Changes in crude oil and natural gas prices may cause us to change our planned capital expenditures related to our oil and gas operations.

• Our ability to complete our planned capital expenditures associated with our Oil and Gas segment may be impacted by our ability to obtain necessary drilling permits, and other necessary contract services and equipment such as drilling rigs, hydraulic fracturing services and other support services. Our plans may also be negatively impacted by weather conditions and existing or proposed regulations, including possible hydraulic fracturing regulations.

• Our ability to complete the planning, permitting, construction, start-up and operation of power generation facilities in a cost-efficient and timely manner.

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• We expect contributions to our defined benefit pension plans to be approximately $0.0 million and $4.5 million for the remainder of 2012 and for 2013, respectively. Some important factors that could cause actual contributions to differ materially from anticipated amounts include:

• The actual value of the plans' invested assets.

• The discount rate used in determining the funding requirement.

• The outcome of pending labor negotiations relating to benefit participation of our collective bargaining agreements.

• We expect the goodwill related to our utility assets to fairly reflect the long-term value of stable, long-lived utility assets. Some important factors that could cause us to revisit the fair value of this goodwill include:

• A significant and sustained deterioration of the market value of our common stock.

• Negative regulatory orders, condemnation proceedings or other events that materially impact our Utilities Groups' ability to generate sufficient stable cash flow over an extended period of time.

• The effects of changes in the market including significant changes in the risk-adjusted discount rate or growth rates.

• The timing, volatility, and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets, including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and crude oil reserves.

• Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain or which could mandate or require closure of one or more of our generating units.

• We are evaluating financing options including senior notes, first mortgage bonds, term loans, project financing and equity issuance. Some important factors that could cause actual results to differ materially from those anticipated include:

• Our ability to access the bank loan and debt and equity capital markets depends on market conditions beyond our control. If the capital markets deteriorate, we may not be able to permanently refinance some short-term debt and fund our capital projects on reasonable terms, if at all.

• Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Utilities

Our utility customers are exposed to the effect of volatile natural gas prices. We produce, purchase and distribute power in four states and purchase and distribute natural gas in five states, and we utilize natural gas as fuel at our Electric Utilities. All of our gas utilities have PGA provisions that allow them to pass the prudently-incurred cost of gas and services through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to true-up billed amounts to match the actual natural gas cost we incurred. These adjustments are subject to periodic prudence reviews by the state utility commissions. We have ECA mechanisms in South Dakota, Colorado, Wyoming and Montana for our electric utilities that serve a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs and transmission costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer.

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 volatility of natural gas prices. These transactions are considered derivatives and are marked-to-market. Gains or losses, as well as option premiums on these transactions, are recorded in Regulatory assets or Regulatory liabilities. Once settled, the gains and losses are passed on to our customers through the PGA.

The fair value of our Utilities Group's derivative contracts is summarized below (in thousands):

	March 31, 2012			December 31, 2011			March 31, 2011
Net derivative (liabilities) assets	$	(14,816	)	$	(16,676	)	$	(2,455	)
Cash collateral	17,651			19,416			3,720
	$	2,835		$	2,740		$	1,265

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Activities Other Than Trading

We have entered into agreements to hedge a portion of our estimated 2012, 2013 and 2014 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at March 31, 2012 were as follows:

Natural Gas

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(MMBtu/day)
San Juan El Paso	3/19/2010	Swap	04/12 - 06/12	7,000	$	5.27
CIG	3/19/2010	Swap	04/12 - 06/12	1,500	$	5.17
NWR	3/19/2010	Swap	04/12 - 06/12	1,500	$	5.20
AECO	3/19/2010	Swap	04/12 - 06/12	250	$	5.15
San Juan El Paso	10/31/2011	Swap	04/12 - 06/12	1,000	$	3.58
San Juan El Paso	2/22/2012	Swap	04/12 - 10/12	2,500	$	2.71
San Juan El Paso	6/28/2010	Swap	07/12 - 09/12	3,500	$	5.19
NWR	6/28/2010	Swap	07/12 - 09/12	1,500	$	5.01
CIG	6/28/2010	Swap	07/12 - 09/12	1,500	$	4.98
San Juan El Paso	4/19/2011	Swap	07/12 - 09/12	2,000	$	4.45
San Juan El Paso	10/31/2011	Swap	07/12 - 09/12	1,000	$	3.77
CIG	2/18/2011	Swap	10/12 - 12/12	500	$	4.42
San Juan El Paso	2/18/2011	Swap	10/12 - 12/12	2,500	$	4.46
NWR	2/18/2011	Swap	10/12 - 12/12	1,000	$	4.44
San Juan El Paso	4/19/2011	Swap	10/12 - 12/12	2,000	$	4.62
San Juan El Paso	10/31/2011	Swap	10/12 - 12/12	1,000	$	3.94
San Juan El Paso	12/9/2011	Swap	10/12 - 12/12	1,000	$	3.59
San Juan El Paso	2/22/2012	Swap	11/2012	2,500	$	3.03
San Juan El Paso	2/22/2012	Swap	12/2012	2,500	$	3.32
San Juan El Paso	4/19/2011	Swap	01/13 - 03/13	2,500	$	5.03
San Juan El Paso	6/6/2011	Swap	01/13 - 03/13	2,500	$	5.18
San Juan El Paso	10/31/2011	Swap	01/13 - 03/13	1,000	$	4.32
San Juan El Paso	12/9/2011	Swap	01/13 - 03/13	1,000	$	3.91
NWR	12/9/2011	Swap	01/13 - 03/13	1,000	$	4.02
San Juan El Paso	4/19/2011	Swap	04/13 - 06/13	2,500	$	4.64
San Juan El Paso	10/31/2011	Swap	04/13 - 06/13	1,000	$	4.13
San Juan El Paso	12/9/2011	Swap	04/13 - 06/13	1,000	$	3.77
NWR	12/9/2011	Swap	04/13 - 06/13	1,000	$	3.83
San Juan El Paso	10/31/2011	Swap	07/13 - 09/13	1,000	$	4.27
San Juan El Paso	12/9/2011	Swap	07/13 - 09/13	1,000	$	3.95
NWR	12/9/2011	Swap	07/13 - 09/13	1,000	$	3.97
San Juan El Paso	12/9/2011	Swap	10/13 - 12/13	1,000	$	4.05
NWR	12/9/2011	Swap	10/13 - 12/13	1,000	$	4.08

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Crude Oil

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(Bbls/month)
NYMEX	3/4/2011	Swap	01/12 - 12/12	2,000	$	104.60
NYMEX	3/19/2010	Swap	04/12 - 06/12	5,000	$	84.00
NYMEX	3/31/2010	Put	04/12 - 06/12	5,000	$	75.00
NYMEX	5/13/2010	Swap	04/12 - 06/12	5,000	$	87.85
NYMEX	8/17/2010	Swap	04/12 - 06/12	3,000	$	82.60
NYMEX	6/28/2010	Swap	07/12 - 09/12	5,000	$	83.80
NYMEX	8/17/2010	Swap	07/12 - 09/12	5,000	$	82.85
NYMEX	9/16/2010	Swap	07/12 - 09/12	5,000	$	84.60
NYMEX	4/20/2011	Swap	07/12 - 06/13	2,000	$	106.80
NYMEX	10/17/2011	Put	07/12 - 09/13	2,000	$	80.00
NYMEX	10/17/2011	Call	07/12 - 09/13	2,000	$	95.00
NYMEX	11/9/2010	Swap	10/12 - 12/12	5,000	$	91.10
NYMEX	1/6/2011	Swap	10/12 - 12/12	5,000	$	93.40
NYMEX	2/17/2011	Swap	10/12 - 03/13	5,000	$	97.85
NYMEX	1/20/2011	Swap	01/13 - 03/13	5,000	$	94.20
NYMEX	3/4/2011	Swap	01/13 - 03/13	3,000	$	103.35
NYMEX	11/2/2011	Call	01/13 - 12/13	3,000	$	100.00
NYMEX	11/2/2011	Put	01/13 - 12/13	3,000	$	77.50
NYMEX	6/3/2011	Swap	04/13 - 06/13	5,000	$	100.90
NYMEX	7/27/2011	Swap	04/13 - 06/13	5,000	$	102.72
NYMEX	12/9/2011	Call	04/13 - 06/13	2,000	$	100.50
NYMEX	12/9/2011	Put	04/13 - 06/13	2,000	$	90.00
NYMEX	10/17/2011	Swap	07/13 - 09/13	2,000	$	88.50
NYMEX	12/9/2011	Call	07/13 - 09/13	3,000	$	99.00
NYMEX	12/9/2011	Put	07/13 - 09/13	3,000	$	90.00
NYMEX	7/27/2011	Swap	07/13 - 09/13	5,000	$	102.75
NYMEX	2/22/2012	Swap	07/13 - 09/13	5,000	$	103.02
NYMEX	12/9/2011	Call	10/13 - 12/13	4,000	$	98.00
NYMEX	12/9/2011	Put	10/13 - 12/13	4,000	$	90.00
NYMEX	2/22/2012	Swap	10/13 - 12/13	5,000	$	101.75
NYMEX	2/22/2012	Swap	01/14 - 03/14	10,000	$	100.20

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Financing 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. As of March 31, 2012, we had $150.0 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of 4.75 years. These swaps have been designated as hedges in accordance with accounting standards for derivatives and hedges and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive income (loss) on the Condensed Consolidated Balance Sheets.

We also have interest rate swaps with a notional amount of $250.0 million which were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. The swaps were originally designated as cash flow hedges and the mark-to-market value was recorded in Accumulated other comprehensive income (loss) on the Condensed Consolidated Balance Sheets. Based on credit market conditions that transpired during the fourth quarter of 2008, we determined it was probable that the forecasted long-term debt financings would not occur in the time period originally specified and, as a result, the swaps were no longer effective hedges and the hedge relationships were de-designated. Mark-to-market adjustments on the swaps are now recorded within the Condensed Consolidated Statements of Income and Other Comprehensive Income. For the three months ended March 31, 2012, we recorded pre-tax unrealized mark-to-market gains of $12.0 million. For the three months ended March 31, 2011, we recorded pre-tax unrealized mark-to-market gains of $5.5 million. These swaps are 7 and 17 year swaps which have amended early termination dates ranging from December 2012 to December 2013.

We have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly our upcoming holding company debt maturities, which are $225 million and $250 million in years 2013 and 2014, respectively. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended, we will cash settle these swaps for an amount equal to their fair values on the stated termination dates.

Further details of the swap agreements are set forth in Note 13 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

As of March 31, 2012, December 31, 2011 and March 31, 2011, our interest rate swaps and related balances were as follows (dollars in thousands):

	March 31, 2012						December 31, 2011						March 31, 2011
	Designated  Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.75			1.75			5.00			2.00			5.75			0.75
Derivative liabilities, current	$	6,777		$	66,708		$	6,513		$	75,295		$	6,769		$	48,515
Derivative liabilities, non-current	$	18,441		$	17,237		$	20,363		$	20,696		$	12,955		$	—
Pre-tax accumulated other comprehensive loss included in Condensed Consolidated Balance Sheets	$	(25,218	)	$	—		$	(26,876	)	$	—		$	(19,724	)	$	—
Pre-tax (loss) gain included in Condensed Consolidated Statements of Income and Comprehensive Income	$	—		$	12,045		$	—		$	(42,010	)	$	—		$	5,465
Cash collateral receivable (payable) included in accounts receivable	$	—		$	—		$	—		$	—		$	—		$	—

__________

* Maximum terms in years for our de-designed interest rate swaps reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. When extended annually, de-designated swaps totaling $100 million terminate in 7 years and de-designated swaps totaling $150 million terminate in 17 years.

Based on March 31, 2012 market interest rates and balances for our designated interest rate swaps, a loss of approximately $6.8 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will change during the next 12 months as market interest rates change.

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ITEM 4.CONTROLS AND PROCEDURES

This section should be read in conjunction with Item 9A, "Controls and Procedures" included in our Annual Report on Form 10-K for the year ended December 31, 2011.

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of March 31, 2012 and concluded that, because of the material weakness in our internal control over financial reporting related to accounting for income taxes as previously disclosed in Item 9A, “Controls and Procedures” in our Annual Report on Form 10-K for the year ended December 31, 2011, our disclosure controls and procedures were not effective as of March 31, 2012. Additional review, evaluation and oversight have been undertaken to ensure our unaudited Condensed Consolidated Financial Statements were prepared in accordance with generally accepted accounting principles and as a result, our management, including our Chief Executive Officer and Chief Financial Officer, have concluded that the Condensed Consolidated Financial Statements in this Form 10-Q fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in conformity with accounting principles generally accepted in the United States.

As discussed in our 2011 Annual Report on Form 10-K, management concluded that while we had appropriately designed control procedures for income tax accounting and disclosures, the existence of non-routine transactions, insufficient tax resources, and ineffective communications between the tax department and Controller organization caused us to poorly execute the controls for evaluating and recording income taxes. Management has developed and is implementing a remediation plan to address this material weakness in internal controls surrounding accounting for income taxes. Key aspects of the remediation plan include enhancing resources and skill sets and implementing formal periodic meetings among the Chief Financial Officer, Controller and the tax department.

While we concluded our internal controls surrounding income taxes were not effective as of March 31, 2012, we are remediating the material weakness and will continue to implement our remediation plan and track our performance against the plan.

During the quarter ended March 31, 2012 there have been no other changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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BLACK HILLS CORPORATION

Part II — Other Information

ITEM 1. Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2011 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.

ITEM 1A. Risk Factors

There are no material changes to the Risk Factors previously disclosed in Item 1A of Part I in our Annual Report on Form 10-K for the year ended December 31, 2011.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans for Programs	Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
January 1, 2012 -
January 31, 2012	8,854	$	33.58	—	—
February 1, 2012 -
February 29, 2012	22,180	$	34.77	—	—
March 1, 2012 -
March 31, 2012	—	$	—	—	—
Total	31,034	$	34.43	—	—

____________

(1) Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of restricted stock.

ITEM 4. Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Quarterly Report on Form 10-Q.

ITEM 5. Other Information

None.

56

ITEM 6. Exhibits

Exhibit 10.1	Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012.
Exhibit 10.2 *	Credit Agreement, dated February 1, 2012, among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other banks party thereto (filed as Exhibit 10 to the Registrant's Form 8-K filed on February 3, 2012).
Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
Exhibit 95	Mine Safety and Health Administration Safety Data
Exhibit 101	Financial Statements for XBRL Format

___________

* Previously filed as part of the filing indicated and incorporated by reference herein.

57

BLACK HILLS CORPORATION

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS CORPORATION

		/s/ David R. Emery
		David R. Emery, Chairman, President and
		Chief Executive Officer
		/s/ Anthony S. Cleberg
		Anthony S. Cleberg, Executive Vice President and
		Chief Financial Officer
Dated:	May 4, 2012

58

EXHIBIT INDEX

Exhibit Number	Description
Exhibit 10.1	Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012.
Exhibit 10.2 *	Credit Agreement, dated February 1, 2012, among Black Hills Corporation, as Borrower, U.S. Bank, National Association, in its capacity as administrative agent for the Banks under the Credit Agreement, and as a Bank, and the other banks party thereto (filed as Exhibit 10 to the Registrant's Form 8-K filed on February 3, 2012).
Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
Exhibit 95	Mine Safety and Health Administration Safety Data
Exhibit 101	Financial Statements for XBRL Format

___________

* Previously filed as part of the filing indicated and incorporated by reference herein.

59

EX-10.1

EXHIBIT 10.1

Execution Copy

STOCKPURCHASE AGREEMENT

BY AND BETWEEN

TWIN EAGLE RESOURCE MANAGEMENT, LLC

AND

BLACK HILLS NON-REGULATED HOLDINGS LLC

FOR THE PURCHASE OF CAPITAL STOCK

OF

ENSERCO ENERGY INC.

Dated January 18, 2012

TABLE OF CONTENTS

ARTICLE 1 PURCHASE OF SHARES1

1.1 Sale of Shares1

ARTICLE 2 PURCHASE PRICE AND ADJUSTMENTS1

2.1 Purchase Price Determination1

2.2 Valuation Methodology2

2.3 Estimated Purchase Price4

2.4 Distributable Cash5

2.5 Payment of Estimated Purchase Price    5

2.6 Post-Closing Adjustment    6

2.7 Miscellaneous Purchase Price Provisions    8

2.8 Foreign Tax Credit8

ARTICLE 3 REPRESENTATIONS AND WARRANTIES OF SELLER    8

3.1 Organization and Good Standing8

3.2 Capitalization9

3.3 Authority and Authorization; Conflicts; Consents    10

3.4 Financial Statements and Undisclosed Liabilities    11

3.5 Taxes    12

3.6 Litigation and Orders    13

3.7 Compliance with Law    13

3.8 Contracts    14

3.9 Certain Assets    16

3.10 Certain Accounts    16

3.11 Real Property    16

3.12 Environmental Matters    16

3.13 Intellectual Property    18

3.14 Absence of Certain Events    19

3.15 Insurance    19

3.16 Employee Benefits    19

3.17 Employees and Labor Relations    20

3.18 Credit Support; Pre-Paid Deposits    20

3.19 Commodities    21

3.20 Brokers    22

3.21 Accounts Receivable    22

ARTICLE 4 REPRESENTATIONS AND WARRANTIES OF BUYER22

4.1 Organization and Good Standing22

4.2 Authority and Authorization; Conflicts; Consents22

4.3 Litigation and Orders23

4.4 Availability of Funds23

4.5 Securities23

4.6 Brokers23

ARTICLE 5 CERTAIN COVENANTS24

5.1 Certain Actions to Close Transactions24

5.2 Pre-Closing Conduct of Business24

5.3 HSR Act Compliance; FPA Approval26

5.4 Access to Information.27

5.5 Further Assurances28

5.6 Confidentiality and Publicity28

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5.7 [Intentionally Omitted]29

5.8 Certain Tax Matters29

5.9 Employee Matters31

5.10 Company Credit Support; Company Credit Facility31

5.11 Calgary Lease32

5.12 Sublease for the Denver Office32

5.13 Trading and Support Software32

5.14 Accounts32

5.15 Conversion to an LLC32

5.16 Transition Services Agreement33

ARTICLE 6 CLOSING; CLOSING DELIVERIES; TERMINATION33

6.1 Closing33

6.2 Closing Deliveries by Seller33

6.3 Closing Deliveries by Buyer34

6.4 Termination of Agreement35

6.5 Effect of Termination35

6.6 Failure to Consummate Transactions; Liquidated Damages36

ARTICLE 7 CONDITIONS TO OBLIGATIONS TO CLOSE37

7.1 Conditions to Obligation of Buyer to Close37

7.2 Conditions to Obligation of Seller to Close38

ARTICLE 8 INDEMNIFICATION AND RESOLUTION OF CERTAIN DISPUTES39

8.1 Indemnification by Seller39

8.2 Indemnification by Buyer39

8.3 Certain Limitations and Other Matters Regarding Claims39

8.4 Certain Survival Periods40

8.5 Notice of Claims and Procedures40

8.6 Materiality Qualifiers41

8.7 Reduction for Insurance, Taxes and Other Offsets41

8.8 Effect of Purchase Price Adjustment42

8.9 Indemnification Adjusts Purchase Price for Tax Purposes42

8.10 Certain Disclaimers42

ARTICLE 9 CERTAIN GENERAL TERMS AND OTHER AGREEMENTS42

9.1 Notices42

9.2 Expenses43

9.3 Interpretation; Construction43

9.4 Parties in Interest; Third-Party Beneficiaries44

9.5 Governing Law44

9.6 Sole and Exclusive Remedies45

9.7 Jurisdiction, Venue and Waiver of Jury Trial45

9.8 Entire Agreement; Amendment; Waiver45

9.9 Assignment; Binding Effect46

9.10 Severability46

9.11 Counterparts46

9.12 Schedules46

ii

Annexes, Exhibits, and Schedules

Annexes

Annex A Certain Definitions

iii

STOCKPURCHASE AGREEMENT

THIS STOCKPURCHASE AGREEMENT (this “Agreement”) is entered into as of January 18, 2012, by and between TWIN EAGLE RESOURCE MANAGEMENT, LLC, a Delaware limited liability company (“Buyer”), and Black Hills Non-regulated Holdings, LLC, a South Dakota limited liability company (“Seller”), regarding the purchase of shares of capital stock of enserco energy inc., a South Dakota corporation (the “Company”).

Capitalized terms used in this Agreement that are not otherwise defined herein have the meanings ascribed to such terms in Annex A.

Recitals

A.Seller owns 7,000 shares of common stock of the Company, which represents all of the issued and outstanding shares of capital stock of the Company (the “Shares”).

B.Seller desires to sell, assign and transfer to Buyer, and Buyer desires to purchase from Seller, all of the Shares, upon and subject to the terms herein.

Agreement

In consideration of the foregoing and the representations, warranties, covenants and agreements in this Agreement and other good and valuable consideration, the receipt of which is hereby acknowledged, each Party hereby agrees as follows:

ARTICLE 1

PURCHASE OF SHARES

1.1    Sale of Shares. Upon and subject to the terms herein, at Closing, Seller will sell, assign and transfer to Buyer, and Buyer will purchase from Seller, all of the Shares, free and clear of all Encumbrances (other than restrictions imposed by securities laws applicable to securities generally and rights of Buyer hereunder).

ARTICLE 2

PURCHASE PRICE AND ADJUSTMENTS

2.1    Purchase Price Determination. Buyer will pay to Seller the “Purchase Price,” which will be determined as follows (each of the following in Section 2.1(b) through (f) is sometimes referred to herein as a “Purchase Price Component”):

(a)$49,100,000; plus

(b)the Trade Book Value (which may be a positive or negative number); plus

(c)the amount by which Net Working Capital exceeds the Net Working Capital Baseline (for purposes of clarity, it is understood that the Distributable Cash shall be distributed to Seller prior to Closing and will not be included in Net Working Capital); plus

1

(d)the amount of all capital expenditures, capital leases, and investments in or loans to third parties incurred and funded after the date hereof but prior to Closing, less any return of capital with respect to such capital expenditures, capital leases and investments prior to Closing (the “Investments”), but only to the extent such Investments were approved by Buyer in accordance with Section 5.2 (for the avoidance of doubt, Buyer has approved the Company's anticipated Investment in the Gascoyne rail transloading facilities in an amount not to exceed $800,000 without further approval of Buyer in accordance with Section 5.2); plus

(e)the Net Book Value of Non-Current Assets and Liabilities (which may be a positive or negative number); plus

(f)the Business Curtailment Losses pursuant to Section 5.2, if any; plus

(g)the Conversion Costs pursuant to Section 5.15, if any;

provided, however, in no event will the aggregate Purchase Price payable by Buyer to Seller exceed $175,000,000 (the “Purchase Price Cap”).

2.2    Valuation Methodology. For purposes of the Purchase Price, the following Purchase Price Components will be determined in the following manner:

(a) Trade Book Value.

(1)“Trade Book Value” will be the economic mark-to-market value of each Commodity Transaction as set forth in the Trade Book as of the Closing Date, but specifically excludes (A) the extrinsic value, (B) the crude oil business of the Company and Enserco Midstream, and (C) the Market Value of Commodity Inventory.

(2)The Trade Book and the determination of the Trade Book Value as of November 30, 2011 (the “Reporting Date”) are attached hereto as Annex C. The Trade Book Value as of the Closing Date will be determined in accordance with the valuation principles, methodologies, standards, policies, procedures, and assumptions (“Methodologies”) used in preparing the Trade Book and determining the Trade Book Value set forth in Annex C.For the avoidance of doubt,Annex C will value “Raton”, “Day-Ahead/Real Time” and “NGPL Amarillo” consistent with the Company's traditional Methodologies, subject to any clarifications in Annex C.

(b) Net Working Capital.

(1)    “Net Working Capital” will be an amount equal to the following:

(A)current assets of the Company as of the Closing Date (including the Market Value of Commodity Inventory), excluding the following (to the extent otherwise included in current assets): (i) any current assets distributed by the Company to Seller or any of its Affiliates (other than a Subsidiary of the Company) on the Closing Date; (ii) the Investments; (iii) intercompany accounts other than Commercial Intercompany Accounts;

2

(iv) intangibles; (v) the book value of Commodity Transactions; and (vi) prepaid and deferred taxes retained by Seller; minus

(B)current liabilities of the Company as of the Closing Date, excluding the following (to the extent otherwise included in current liabilities): (i) any current liabilities assumed or paid by Seller or any of its Affiliates (other than the Company or any of its Subsidiaries) on the Closing Date; (ii) intercompany accounts other than Commercial Intercompany Accounts; (iii) intangibles; (iv) the book value of Commodity Transactions; (v) any current liabilities pursuant to the Retention Agreements; (vi) income taxes payable and deferred taxes retained by Seller; (vii) the GAAP mark-to-market incentive accrual; and (viii) accrued payroll and related payroll Tax and benefit accruals.

(2)    “Net Working Capital Baseline” will be (A) $2,600,000, plus (B) the product of (i) the weighted-average Market Value of Commodity Inventory for a barrel of crude oil as of the Closing Date used in the determination of Net Working Capital multiplied by (ii) the actual number of barrels of line pack crude oil inventory on the Closing Date, provided that, for purposes of this calculation only, the number of barrels used in (ii) above will not be greater than 180,000 or less than 160,000.

(3)“Market Value of Commodity Inventory” will be the economic value of Commodity inventory (including park-and-loans and imbalances) as of the Closing Date.

(4)    Net Working Capital will be determined (A) without duplication of anything included in the Trade Book Value, (B) after giving effect to the distribution or payment of Distributable Cash pursuant to Section 2.4, and (C) except where this Agreement specifies an economic valuation, in accordance with GAAP.

(5)    The determinations of Net Working Capital, the Net Working Capital Baseline and the Market Value of Commodity Inventory as of the Reporting Date are attached hereto as Annex D. Net Working Capital, the Net Working Capital Baseline and the Market Value of Commodity Inventory as of the Closing Date will be determined in accordance with the Methodologies used in determining Net Working Capital, the Net Working Capital Baseline and the Market Value of Commodity Inventory set forth in Annex D.

(c) Net Book Value of Non-Current Assets and Liabilities.

(1)    “Net Book Value of Non-Current Assets and Liabilities” will be an amount equal to the following:

(A)non-current assets of the Company as of the Closing Date, excluding the following (to the extent otherwise included in non-current assets): (A) intercompany accounts other than Commercial Intercompany Accounts; (B) intangibles; (C) the book value of Commodity Transactions; (D) the Investments; (E) deferred taxes retained by Seller; and (F) the Foreign Tax Credit; minus

3

(B)non-current liabilities of the Company as of the Closing Date, excluding the following (to the extent otherwise included in non-current liabilities): (A) intercompany accounts other than Commercial Intercompany Accounts; (B) intangibles; (C) the book value of Commodity Transactions; (D) any non-current liabilities pursuant to the Retention Agreements; and (E) deferred taxes retained by Seller.

(2)    The determination of Net Book Value of Non-Current Assets and Liabilities as of the Reporting Date is attached hereto as Annex E. Net Book Value of Non-Current Assets and Liabilities as of the Closing Date will be determined in accordance with the Methodologies used in determining Net Book Value of Non-Current Assets and Liabilities set forth in Annex E.

2.3    Estimated Purchase Price.

(a)    On or before the fifth Business Day before the Closing Date, Seller will deliver to Buyer a written statement (the “Estimated Statement”) showing, in reasonable detail, Seller's determination or estimate of the following in accordance with Sections 2.1 and 2.2 as of the Closing Date:

(1)    the Purchase Price Components;

(2)    an estimate of the Purchase Price, which will not exceed the Purchase Price Cap (the “Estimated Purchase Price”); and

(3)    cash and cash equivalents of the Company to be distributed or otherwise paid to Seller and/or one or more Affiliates of Seller (other than the Company and Enserco Midstream ) pursuant to Section 2.4 (“Distributable Cash”).

(b)    The Estimated Statement will be accompanied by the following (or estimates thereof, where appropriate):

(1)    wire transfer instructions for the payments described in Section 2.5;

(2)    the Electronically Recorded Trade Book for all Commodities as of the Closing Date;

(3)    a schedule listing the Manually Recorded Commodity Transactions for all Commodities as of the Closing Date;

(4)    a reasonably detailed schedule that provides the calculation of the Trade Book Value as of the Closing Date in accordance with the Methodologies used in Annex C;

(5)    bank statements showing Distributable Cash;

4

(6)    a reasonably detailed calculation of Net Working Capital and the Net Working Capital Baseline as of the Closing Date, including the following:

(A)    a schedule of accounts receivable of the Company as of the most recently closed financial period for which such schedule is prepared in the Ordinary Course of Business;

(B)    a schedule showing the Market Value of Commodity Inventory as of the most recently closed financial period for which such schedule is prepared in the Ordinary Course of Business;

(C)    a schedule of any other current assets of the Company used in the calculation of Net Working Capital as of the Closing Date;

(D)    a schedule of accounts payable of the Company used in the calculation of Net Working Capital as of the Closing Date; and

(E)    a schedule of any other current liabilities of the Company used in the calculation of Net Working Capital as of the Closing Date;

(7)    a schedule the Net Book Value of Non-Current Assets and Liabilities as of the Closing Date;

(8)    a schedule of the Investments as of the Closing Date, if any;

(9)    an update of the Credit Support Schedules as of the Closing Date;

(10)    reasonable evidence of the Business Curtailment Losses, if any; and

(11)    reasonable evidence of the Conversion Costs, if any.

2.4    Distributable Cash. Prior to the Closing, the Company shall distribute and/or pay to Seller and/or one or more of its Affiliates (other than the Company and Enserco Midstream) the Distributable Cash.

2.5    Payment of Estimated Purchase Price. For illustrative purposes only, the hypothetical Purchase Price, if Closing had occurred on the Reporting Date, determined in accordance with this Article 2, including Annexes C, D and E, would have been approximately $155,017,015. For purposes of this Section 2.5, “Purchase Price Threshold” means 105% of such hypothetical Purchase Price, or $162,767,866.

(b)    Prior to Closing, Seller and Buyer shall use commercially reasonable efforts to agree on the amount of each of the Purchase Price Components and the Estimated Purchase Price as of the Closing Date. For purposes of effectuating the Closing, the Estimated Purchase Price will be based on the following:

5

(1)    with respect to each Purchase Price Component that Buyer and Seller agree to prior to Closing, such agreed-to Purchase Price Component; and

(2)    with respect to each Purchase Price Component that Buyer and Seller do not agree to prior to Closing, the corresponding Purchase Price Component included in Seller's Estimated Statement.

(c)    If the Estimated Purchase Price is less than the Purchase Price Threshold, at Closing, Buyer will pay the Estimated Purchase Price, less (1) an amount equal to 50% of the HSR Filing Fees and (2) $1,125,000, representing 50% of the incremental BNP Paribas commitment fee (the “Incremental Commitment Fee”), to Seller by wire transfer of immediately available funds to the account(s) designated in the Estimated Statement.

(d)    If the Estimated Purchase Price is greater than the Purchase Price Threshold, at Closing, Buyer will pay an amount equal to the Purchase Price Threshold, less (1) an amount equal to 50% of the HSR Filing Fees and (2) the Incremental Commitment Fee, to Seller by wire transfer of immediately available funds to the account(s) designated in the Estimated Statement.

(e)    The amount paid at Closing pursuant to Section 2.5(c) or (d) is referred to herein as the “Closing Payment.”

2.6    Post-Closing Adjustment. Ninety (90) days after the Closing Date, the Estimated Purchase Price will become final and binding on the Parties unless Buyer delivers to Seller, or Seller delivers to Buyer, a statement (each, a “Post-Closing Statement”) setting forth in reasonable detail Buyer's objection to the Estimated Purchase Price or Seller's revision of the Estimated Purchase Price, as applicable, prior to the expiration of such ninety (90)-day period. At the request of a Party, the other Party and the Company will assist such Party and its representatives in all reasonable respects in preparing a Post-Closing Statement. Each Post-Closing Statement will be prepared in the same manner, and contain at least the same supporting detail, as the Estimated Statement in accordance with Section 2.3. If neither Party delivers a Post-Closing Statement within such ninety (90)-day period, then the Estimated Purchase Price will be the “Final Purchase Price” and there will be no further adjustment to the Estimated Purchase Price pursuant to this Article 2. If either Party timely delivers a Post-Closing Statement, then the “Final Purchase Price” will be determined in accordance with this Section 2.6. If Buyer delivers a Post-Closing Statement, such Post-Closing Statement is referred to herein as the “Buyer's Statement”; if Buyer does not deliver a Post-Closing Statement, the Estimated Statement is referred to herein as the “Buyer's Statement.” If Seller delivers a Post-Closing Statement, such Post-Closing Statement is referred to herein as the “Seller's Statement”; if Seller does not deliver a Post-Closing Statement, the Estimated Statement is referred to herein as the “Seller's Statement.”

(a)    To the extent the valuation of any Purchase Price Component is the same in both the Buyer's Statement and the Seller's Statement, such valuation of such Purchase Price Component shall be final and binding on the Parties. During the ten (10)-day period after timely delivery of a Post-Closing Statement, Seller and Buyer will attempt to resolve any differences between the Buyer's Statement and the Seller's Statement.

6

(b)    If, at the end of such ten (10)-day period, Seller and Buyer have not reached agreement on all differences between the Buyer's Statement and the Seller's Statement, then either Seller or Buyer may demand in writing to the other that the items that remain in dispute be promptly submitted to KPMG LLP (or as otherwise agreed in writing) (the “Purchase Price Mediator”) for review and resolution. If the Purchase Price Mediator cannot or refuses to serve, or KPMG LLP is not then a Qualified Mediator (as defined below), then the Purchase Price Mediator will be selected by lot from a list of two potential Purchase Price Mediators remaining after Seller nominates two, Buyer nominates two, and Seller and Buyer each eliminate one potential Purchase Price Mediator from the other's nominations. All Purchase Price Mediators nominated by Buyer or Seller will be nationally-recognized or other public accounting firms and will not have any past or present business relationship with any of the Parties or any of their respective Affiliates (a “Qualified Mediator”).

(c)    The Purchase Price Mediator will determine procedures and deadlines for such mediation, subject to the terms hereof. The Purchase Price Mediator will render a decision resolving the Purchase Price Component(s) in dispute as soon as possible and, in any event, within thirty (30) days after completion of submissions to the Purchase Price Mediator. The Purchase Price Mediator will determine each Purchase Price Component in dispute in accordance with the terms of this Agreement, solely based on this Agreement, the Buyer's Statement, the Seller's Statement, and such other written submissions requested by the Purchase Price Mediator (and not by independent review), and such determinations of the Purchase Price Mediator shall be final and binding on the parties. The Purchase Price Mediator will not assign a value to any Purchase Price Component that is greater than the highest corresponding value set forth in the Buyer's Statement and the Seller's Statement or that is that is lower than the lowest corresponding value set forth in the Buyer's Statement and the Seller's Statement. Each Party will pay its own fees and expenses regarding such mediation, and Seller and Buyer will each pay half of the fees and expenses of the Purchase Price Mediator.

(d)    The “Final Purchase Price” will be determined in accordance with Section 2.1 based on the final and binding Purchase Price Components determined pursuant to Sections 2.5 and 2.6, but will not exceed the Purchase Price Cap.

(e)    Within one (1) Business Day after the final determination of the Final Purchase Price (the “Adjustment Payment Date”):

(1)    if the Final Purchase Price is greater than the Closing Payment, then the amount by which the Final Purchase Price exceeds the Closing Payment shall be “Excess Purchase Price” payable in accordance with Section 2.6(f); and

(2)    if the Final Purchase Price is less than the Closing Payment, then the amount by which the Final Purchase Price is less than the Closing Payment, together with interest on such balance at a rate equal to 5% per annum (calculated based on the number of actual days elapsed from (but not including) the Closing Date to (and including) the date of payment, divided by 365), shall be paid by Seller to Buyer by wire transfer of immediately available funds to an account designated in writing by Buyer.

7

(f)    All Excess Purchase Price, if any, together with interest on such amount at a rate equal to 5% per annum (calculated based on the number of actual days elapsed from (but not including) the Closing Date to (and including) the date of payment, divided by 365) shall be payable as follows:

(1)    50% of the Excess Purchase Price plus interest thereon shall be paid by Buyer to Seller by wire transfer of immediately available funds to an account designated in writing by Seller on the Adjustment Payment Date; and

(2)    the remaining balance of the Excess Purchase Price plus interest thereon shall be paid by Buyer to Seller by wire transfer of immediately available funds to an account designated in writing by Seller on the date that is ninety (90) days after the Adjustment Payment Date.

2.7    Miscellaneous Purchase Price Provisions.

(a)    All references to the Company in this Article 2 include Enserco Midstream on a consolidated basis.

(b)    In the event any value used in the determination of the Purchase Price is denominated in a currency other than U.S. Dollars, such non-U.S. currencies shall be converted to U.S. Dollars at the conversion rate as of the Closing Date published in the Wall Street Journal.

2.8    Foreign Tax Credit. The Interim Balance Sheet as of the Reporting Date includes a foreign tax credit in the amount of $1,232,908 (as such amount changes from time to time, the “Foreign Tax Credit”). From and after Closing until the Foreign Tax Credit expires, (a) annually, within thirty (30) days after filing the federal Tax return in which the Foreign Tax Credit is utilized, Buyer will certify in writing to Seller the amount of any “Net Tax Savings” (meaning Tax savings less associated costs) resulting from the Foreign Tax Credit during the period covered by such Tax return, (b) at the time of such certification, Buyer will pay Seller, by check or wire transfer to an account specified by Seller, an amount equal to eighty-five percent (85%) of such Net Tax Savings for the period covered by such Tax return, and (c) to the extent Buyer is required to repay such amount upon audit or otherwise, Seller shall within thirty (30) days refund such amount to Buyer.

ARTICLE 3

REPRESENTATIONS AND WARRANTIES OF SELLER

Except as set forth in the Schedules hereto, Seller hereby represents and warrants to Buyer as follows:

3.1    Organization and Good Standing.

(a)    Seller is a duly organized and validly existing limited liability company in good standing under the laws of the State of South Dakota, and is duly qualified and in good standing to do business as a foreign limited liability company in each jurisdiction in which the ownership or leasing of its properties or assets or the conduct of its business requires such

8

qualification, except where the failure to be so qualified or in good standing will not materially and adversely affect Seller's ability to consummate the transactions contemplated herein.

(b)    The Company is a duly organized and validly existing corporation in good standing under the laws of the State of South Dakota, and as of the date hereof is duly qualified and in good standing to do business as a foreign corporation in each jurisdiction set forth in Schedule 3.1(b), which are all of the jurisdictions in which the ownership or leasing of its properties or assets or the conduct of its business requires such qualification, except where the failure to be so qualified or in good standing is not reasonably likely to have a Material Adverse Effect on the Company.

(c)    Enserco Midstream is a duly organized and validly existing limited liability company in good standing under the laws of the State of South Dakota, and as of the date hereof is duly qualified and in good standing to do business as a foreign limited liability company in each jurisdiction set forth in Schedule 3.1(c), which are all of the jurisdictions in which the ownership or leasing of its properties or assets or the conduct of its business requires such qualification, except where the failure to be so qualified or in good standing is not reasonably likely to have a Material Adverse Effect on Enserco Midstream.

(d)    The Company and Enserco Midstream each have full corporate or limited liability company power, as applicable, and authority to own and lease its properties and assets and conduct its business as now conducted. Other than the Company's ownership interest in Enserco Midstream, the Company does not hold any equity interest, directly or indirectly, of any other Person. Enserco Midstream does not hold any equity interest, directly or indirectly, of any other Person. Seller has made available to Buyer a true, correct and complete copy of the Organizational Documents of the Company and Enserco Midstream.

3.2    Capitalization. The authorized capital stock of the Company consists of 18,000 shares of common stock, of which 7,000 shares are issued and outstanding, all of which are owned by Seller. The Shares constitute all of the outstanding capital stock of the Company. All of the Shares are duly authorized, validly issued, fully paid and non‑assessable. No Shares were issued in violation of any Organizational Document of the Company, any Applicable Law or any pre-emptive right (or other similar right) of any Person. Seller has good and valid title to all Shares, free and clear of any Encumbrance (other than restrictions imposed by securities laws applicable to securities generally and rights of Buyer hereunder). Other than rights of Buyer created hereunder, there is no (1) pre-emptive right, option, warrant, put, call, purchase right, subscription right, conversion right, convertible instrument, exchange right or other security, Contract or commitment of any nature whereby any Person has, or has a right to receive, any capital stock of, or right or obligation to acquire any capital stock of, the Company, (2) equity appreciation, phantom stock, profit participation or similar right with respect to the Company, or (3) voting trust, proxy or other Contract with respect to any capital stock of the Company.

(b)    The Company owns one hundred percent (100%) of the outstanding equity interest of Enserco Midstream (the “Membership Interest”). The Membership Interest was not issued in violation of any Organizational Document of Enserco Midstream, any Applicable Law or any pre-emptive right (or other similar right) of any Person. The Company has good and valid title to the Membership Interest, free and clear of any Encumbrance (other than restrictions

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imposed by securities laws applicable to securities generally and rights of Buyer hereunder). Other than rights of Buyer created hereunder, there is no (1) pre-emptive right, option, warrant, put, call, purchase right, subscription right, conversion right, convertible instrument, exchange right or other security, Contract or commitment of any nature whereby any Person has, or has a right to receive, any capital stock, or membership interest of Enserco Midstream, (2) equity appreciation, phantom stock, profit participation or similar right with respect to Enserco Midstream, or (3) voting trust, proxy or other Contract with respect to any membership interest of Enserco Midstream.

3.3    Authority and Authorization; Conflicts; Consents.

(a)    Authority and Authorization. The execution, delivery and performance of this Agreement and each Ancillary Document to which Seller and/or Enserco Midstream, as applicable, is a party have been duly authorized and approved by all necessary corporate or limited liability company action with respect to Seller and/or Enserco Midstream, as applicable, and each such authorization and approval remains in full force and effect. Assuming due authorization, execution and delivery by Buyer of this Agreement and each Ancillary Document to which it is a party, this Agreement is, and each such Ancillary Document at Closing will be, the legal, valid and binding obligation of Seller and Enserco Midstream, as applicable, enforceable against Seller and/or Enserco Midstream, as applicable, in accordance with its terms, except to the extent enforceability may be limited by any applicable bankruptcy, reorganization, insolvency, moratorium or other similar Applicable Law affecting creditors' rights generally and principles governing the availability of equitable remedies.

(b)    Conflicts. Neither the execution nor delivery by Seller of this Agreement or by Seller, the Company and/or Enserco Midstream, as applicable, of any Ancillary Document to which it is a party, nor consummation by Seller, the Company or Enserco Midstream of the transactions contemplated herein or therein does or will (with or without the passage of time or giving of notice) (1) constitute a breach of, violate, conflict with or give rise to or create any right or obligation under any Organizational Document of Seller, the Company or Enserco Midstream, (2) violate any Applicable Law or Order or (3) constitute a breach or violation of or a default under, conflict with or give rise to or create any right of any Person other than Seller and/or Enserco Midstream, as applicable, to accelerate, increase, terminate, modify or cancel any material right or obligation of the Company or Enserco Midstream under, any Major Contract, except where such a breach, violation, default, conflict or right is released or waived pursuant to a Consent delivered or to be delivered at Closing or, with respect to clause (2) or (3) above, has not had and is not reasonably likely to have a Material Adverse Effect on the Company and will not materially and adversely affect Seller's ability to consummate the transactions contemplated herein.

(c)    Consents. No consent or approval by, notification to or filing with any Person is required in connection with Seller's and/or Enserco Midstream's execution, delivery or performance of this Agreement or any Ancillary Document to which it is a party or Seller's and/or Enserco Midstream's, as applicable, consummation of the transactions contemplated herein or therein, except (1) as described in Section 5.3, (2) as described in Schedule 3.3, or (3) for any consent, approval, notice or filing, the absence of which has not had and is not reasonably likely to have a Material Adverse Effect on the Company and will not materially and

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adversely affect Seller's ability to consummate the transactions contemplated herein. “Consent” means each consent, approval, notice or filing described in Schedule 3.3.

3.4    Financial Statements and Undisclosed Liabilities.

(a)    Financial Statements Defined. Schedule 3.4 contains a true, correct and complete copy of the following:

(1)    the (A) audited balance sheet of the Company and Enserco Midstream, on a consolidated basis, as of December 31, 2010, (B) audited statements of operations, stockholders' equity and cash flows of the Company and Enserco Midstream, on a consolidated basis, for the fiscal year ended on December 31, 2010, and (C) notes to the foregoing and the reports thereon of the Company's independent auditors (collectively, the “Annual Financial Statements”); and

(2)    the unaudited (A) balance sheet of the Company and Enserco Midstream, on a consolidated basis, as of the Reporting Date and (B) income statement of the Company and Enserco Midstream, on a consolidated basis, for the fiscal year-to-date period then ended.

(b)    Monthly Financials. Between the date hereof and the Closing, Seller shall provide Buyer with the monthly unaudited balance sheet and income statement of the Company and Enserco Midstream, on a consolidated basis, as they are prepared in the Ordinary Course of Business. The most recent balance sheet attached hereto pursuant to Section 3.4(a)(2) or delivered pursuant to Section 3.4(b) is referred to herein as the “Interim Balance Sheet”; the date of the Interim Balance Sheet is referred to herein as the “Interim Balance Sheet Date”; the Interim Balance Sheet and the most recent income statement attached hereto pursuant to Section 3.4(a)(2) or delivered pursuant to Section 3.4(b) are referred to herein as the “Interim Financial Statements”; and the Interim Financial Statements, together with the Annual Financial Statements, are referred to herein as the “Financial Statements.” The foregoing notwithstanding, if the most recent monthly unaudited balance sheet and income statement is not within thirty (30) days of Closing, then Seller shall deliver a balance sheet and income statement that is within thirty (30) days and that shall be deemed to be the Interim Balance Sheet.

(c)    Financial Statements. The Financial Statements attached hereto pursuant to Section 3.4(a) or delivered pursuant to Section 3.4(b) were prepared in accordance with GAAP and fairly present, in all material respects, the financial condition of the Company and Enserco Midstream at their respective dates and the results of operations of the Company and Enserco Midstream for the respective periods covered thereby, except (1) as otherwise disclosed in any note to the Financial Statements and (2) that the Interim Financial Statements are subject to normal year-end adjustments and do not have notes included therewith.

(d)    Undisclosed Liabilities. The Company and Enserco Midstream do not have any Liabilities, except for Liabilities (1) disclosed in, provided for, adequately reflected in, reserved against or otherwise described in the Financial Statements (including in any note thereto), (2) that are or will be included in the calculations regarding the Purchase Price under Article 2, (3) under any Major Contract or under any Company Plan, (4) that have arisen in the

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Ordinary Course of Business since the Interim Balance Sheet Date, (5) under this Agreement or any Ancillary Document or otherwise in connection with the transactions contemplated herein or therein, or (6) that will not have a Material Adverse Effect on the Company.

3.5     Taxes. All material Tax Returns that are required to be filed by Applicable Law (taking into account all extensions) for any period ending on or before the Closing Date for, by, on behalf of or with respect to the Company and Enserco Midstream have been timely filed with the appropriate foreign, federal, state and local authorities. All such Tax Returns as so filed disclose all Taxes required to be paid for the periods covered thereby. All such Tax Returns are true and correct in all material respects. All Taxes shown to be due and payable on such Tax Returns or related to such Tax Returns have been timely paid in full. All such Tax Returns of the Company and Enserco Midstream and the information and data contained therein reflect all material liabilities for Taxes for the period covered by such Tax Returns.

(b)    Other than as set forth in Schedule 3.5(b), none of such Tax Returns are now under audit or examination by any foreign, federal, state or local authority and there are no agreements, waivers or other arrangements providing for an extension of time with respect to the assessment or collection of any Tax or deficiency of any nature against the Company or Enserco Midstream or their properties, or with respect to any such Tax Return, or any suits or other actions, proceedings, disputes, investigations or claims now pending or Threatened against the Company or Enserco Midstream or their properties with respect to any Tax, or any claims for any additional Tax asserted in writing by any such authority.

(c)    All Taxes due and required to be paid by the Company or Enserco Midstream on or before the Closing (whether or not shown on a Tax Return) or assessed and due and required to be paid by the Company or Enserco Midstream on or before the Closing Date have been timely paid in full.

(d)    All withholding Tax and Tax deposit requirements imposed on the Company or Enserco Midstream for any and all periods ending on or before the Closing Date have been timely satisfied in full on or before the Closing Date.

(e)    The Company and Enserco Midstream have not made any payments, and are not obligated to make any payments that will not be deductible under Section 280G (relating to parachute payments) of the Code.

(f)    The Company and Enserco Midstream each are not a party to any tax allocation or tax sharing agreement other than as set forth on Schedule 3.5(f).

(g)    The Company (1) is a member of an affiliated group filing a consolidated federal income Tax Return, and (2) has no liability for Taxes of any Person (other than Enserco Midstream) under Treasury Regulations § 1.1502-6 (or any similar provision of foreign, state or local law), as a transferee or successor, by contract, or otherwise.

(h)    There are no Liens for Taxes (other than for current Taxes not yet due and payable) upon any assets of the Company or Enserco Midstream.

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(i)    Neither the Company nor Enserco Midstream has been a “United States real property holding corporation” within the meaning of Section 897(c)(2) of the Code during the applicable period specified in Section 897(c)(1)(A)(ii) of the Code.

(j)    The Company and Enserco Midstream have not made an election, and are not required, to treat any of its assets as tax-exempt bond financed property or tax-exempt use property within the meaning of Section 168 of the Code or under any comparable provision of foreign, state or local Tax law.

(k)    The Company and Enserco Midstream have not filed a consent pursuant to the collapsible corporation provisions of Section 341(f) of the Code (or any corresponding provision of foreign, state or local law) or agreed to have Section 341(f) (2) of the Code (or any corresponding provision of state or local law) apply to any disposition of any asset of the Company or Enserco Midstream.

(l)    The Company and Enserco Midstream have not requested or received any ruling regarding Taxes since January 1, 2008 from any foreign, federal, state or local authority, or signed any binding agreement with any such authority (including, without limitation, any advance pricing agreement) since January 1, 2008.

(m)    The amount accrued for Taxes in the Financial Statements by the Company or Enserco Midstream, if any, is sufficient for the payment of all Taxes from the period ending on or before the Closing Date.

(n)    Neither the Company nor Enserco Midstream have entered into a listed or reportable transaction as defined in Section 6707A of the Code.

3.6    Litigation and Orders. There is no Proceeding pending or, to Seller's Knowledge, Threatened against the Company or Enserco Midstream as of the date of this Agreement. As of the date of this Agreement, neither the Company nor Enserco Midstream is specifically identified as a party that is subject to any material restriction or limitation on any of its operations under any Order.

3.7    Compliance with Law. At all times since December 31, 2008 with regard to any Applicable Laws promulgated or enforced by FERC, and at all times since December 31, 2006 with regard to other matters, the Company and Enserco Midstream have been operated in compliance in all material respects with all Applicable Laws, except as described in Schedule 3.7. No written notice has been received by Seller, Enserco Midstream or the Company from December 31, 2008 to the date of this Agreement from FERC or from December 31, 2006 to the date of this Agreement from any other Governmental Authority alleging that the Company or Enserco Midstream is not or was not in compliance in any material respect with any Applicable Law, where the reason for which has not been corrected and the remedy for which has not been fully satisfied.

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3.8    Contracts. Schedule 3.8(a) contains a true and accurate list of the following Contracts, in effect as of the date of this Agreement, to which the Company or Enserco Midstream is a party (each a “Major Contract”):

(1)    any agreement that materially restricts or materially limits the ability of the Company or Enserco Midstream to freely conduct the Business or that imposes on the Company or Enserco Midstream any non-competition, non-solicitation obligation, or other similar limitations or restrictions;

(2)    all agreements that involve or are reasonably expected to involve aggregate payments to or from the Company or Enserco Midstream of more than $250,000 in any twelve-month period or more than $500,000 during the term of such agreement, other than Contracts with respect to Commodity Transactions in the Trade Book;

(3)    all partnership or joint venture agreements or other agreements relating to the management or control of any such partnership or joint venture;

(4)    any agreement between the Company or Enserco Midstream and any of their respective employees relating their employment with the Company or Enserco Midstream (other than those that are or on the Closing Date will be terminable at will by the Company or Enserco Midstream without any Liability to either the Company or Enserco Midstream, except Liability with respect to services rendered before the termination thereof);

(5)    each other Contract not entered into in the Ordinary Course of Business, other than Contracts with respect to Commodity Transactions in the Trade Book;

(6)    the following Contracts with respect to Commodity Transaction identified in the Trade Book:

(A)    each Contract for the physical purchase of natural gas representing at least 1.0% of the aggregate dollar volume of all physical natural gas purchases for the fiscal year-to-date period ended on the Reporting Date, which Contracts, in the aggregate, represent at least 70% of the aggregate dollar volume of all physical natural gas purchases for the fiscal year-to-date period ended on the Reporting Date;

(B)    each Contract for the physical sale of natural gas representing at least 1.0% of the aggregate dollar volume of all physical natural gas sales for the fiscal year-to-date period ended on the Reporting Date, which Contracts, in the aggregate, at least 75% of the aggregate dollar volume of all physical natural gas sales for the fiscal year-to-date period ended on the Reporting Date;

(C)    each Contract for the financial purchase or sale of natural gas as of the Reporting Date;

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(D)    each Contract for the physical purchase of crude oil representing at least 1.0% of the aggregate dollar volume of all physical crude oil purchases for the fiscal year-to-date period ended on the Reporting Date, which Contracts, in the aggregate, represent at least 90% of the aggregate dollar volume of all physical crude oil purchases for the fiscal year-to-date period ended on the Reporting Date;

(E)    each Contract for the physical sale of crude oil representing at least 1.0% of the aggregate dollar volume of all physical crude oil sales for the fiscal year-to-date period ended on the Reporting Date, which Contracts, in the aggregate, represent at least 85% of the aggregate dollar volume of all physical crude oil sales for the fiscal year-to-date period ended on the Reporting Date;

(F)    each Contract for the physical purchase of coal representing at least 1.0% of the aggregate dollar volume of all physical coal purchases for the fiscal year-to-date period ended on the Reporting Date, which Contracts, in the aggregate, represent at least 90% of the aggregate dollar volume of all physical coal purchases for the fiscal year-to-date period ended on the Reporting Date;

(G)    each Contract for the physical sale of coal representing at least 1.0% of the aggregate dollar volume of all physical coal sales for the fiscal year-to-date period ended on the Reporting Date, which Contracts, in the aggregate, represent at least 90% of the aggregate dollar volume of all physical coal sales for the fiscal year-to-date period ended on the Reporting Date;

(H)    each Contract for the financial purchase or sale of coal as of the Reporting Date;

(I)    each contract for the physical purchase or sale of power as of the Reporting Date; and

(J)    each Contract for the financial purchase or sale of power as of the Reporting Date.

(b)    Seller has made available to Buyer a copy of each Major Contract, together with all amendments or modifications thereto through and including the date hereof, and each such copy is correct and complete. Except as set forth in Schedule 3.8(b), each Major Contract is in full force and effect and is valid, binding and enforceable (subject to applicable bankruptcy, reorganization, insolvency, moratorium or similar laws affecting creditors' rights generally and equitable principles of general application), and all Counterparties to all Major Contracts (other any agreements with current or former employees or consultants) are all commercial, institutional, or governmental entities, and except for required board approvals each Major Contract has been entered into in the Ordinary Course of Business (other than those listed in Schedule 3.8(a) pursuant to Section 3.8(a)(5)).

(c)    Except as set forth in Schedule 3.8(c), to the Knowledge of Seller, no other party to any Major Contract is in material breach thereof or default thereunder and Seller

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has not received any written notices of termination, cancellation, breach or default under any Major Contract.

3.9    Certain Assets. Except as described in Schedule 3.9(a), and subject to any term to the contrary in any Major Contract, the Company and/or Enserco Midstream, as applicable, has good title to, or a valid leasehold interest in or valid license for, each material tangible asset that is personal property used by it, shown on the Interim Balance Sheet or acquired by it after the Interim Balance Sheet Date, free and clear of any Encumbrance other than any Permitted Encumbrance, except for (1) any asset disposed of in its Ordinary Course of Business since the Interim Balance Sheet Date and (2) cash collateral securing obligations to Counterparties in the Ordinary Course of Business.

(b)    All of the assets of the crude oil business operated by the Company and/or Enserco Midstream that were in the past held by Black Hills Midstream, LLC or any other Affiliate of Seller have been assigned in full to the Company and/or Enserco Midstream prior to the date hereof.

(c)    Schedule 3.9(c) lists all such material property, plant and equipment having a value in excess of $10,000. All property, plant and equipment shown on the Interim Balance Sheet is good and usable in the Ordinary Course of Business.

3.10    Certain Accounts. Schedule 3.10 lists each bank account, cash account, brokerage account and other similar account in which the Company has any interest (designating the authorized signatory and the level of each signatory's authorization) with addresses of the respective financial institutions.

3.11    Real Property. Neither the Company nor Enserco Midstream owns any Real Property or fixtures attached to Real Property. Schedule 3.11 contains a complete list of all real property leased or sub-leased (as lessee or lessor) by the Company or Enserco Midstream (the “Leased Real Property”). Seller has provided Buyer with complete and accurate copies of each of the leases or sub-leases for the Leased Real Property (the “Real Property Leases”). With respect to each Real Property Lease: (a) the Real Property Lease is in full force and effect; (b) neither the Company or Enserco Midstream, nor to Seller's Knowledge, any other party to the Real Property Lease is in breach or default of such Real Property Lease, nor has any party Threatened to breach or default under such Real Property Lease; and (c) neither the Company nor Enserco Midstream, nor to Seller's Knowledge, any other party to a Real Property Lease has repudiated any material provision thereof.

3.12    Environmental Matters.

(a)    Definitions. For the purposes of this Section 3.12, the following terms have the following meanings:

(1)    “Environment” shall mean soil, land surface or subsurface strata, surface waters (including navigable water, ocean waters, streams, ponds, drainage basins, and wetlands), ground water, sediments, ambient air (including indoor air), plant, animal, and human life, and any other environmental medium or natural resource.

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(2)    “Environmental Liabilities” shall mean any costs, damages, claims, expenses, fines, liabilities or obligations, including investigatory and remediation costs and consultant, expert, and attorney's fees, (whether disclosed, undisclosed, direct, indirect, absolute, contingent, accrued or otherwise) relating to the use, operation, possession, lease or ownership of any of the assets of the Company or Enserco Midstream and arising from any violation or alleged violation of any federal, state or local environmental law or any requirement of any Governmental Authority related thereto, including, without limitation, the Comprehensive Environmental Response, Compensation and Liability Act of 1980, 42 U.S.C. §9601, et seq. (“CERCLA”), the Resource Conservation and Recovery Act, 42 U.S.C. §6901, et seq. (“RCRA”), the Clean Water Act, 33 U.S.C. §1251 et seq., the Toxic Substances Control Act, 15 U.S.C. §2601, et seq., the Clean Air Act, 42 U.S.C. §7401, et seq., the Safe Drinking Water Act, 42 U.S.C. §300f et seq., the Hazardous Materials Transportation Uniform Safety Act, 49 App. U.S.C. §2001, et seq., and the Federal Insecticide, Fungicide & Rodenticide Act, 7 U.S.C. §136, et seq., and any other law relating to protection of the Environment, including those laws relating to the storage, handling, use, manufacture, generation, processing, treatment, transport, disposal, release, discharge or emission of Hazardous Materials (“Environmental Laws”) or any federal, state or local law or any legally enforceable requirement of any Governmental Entity related thereto relating to the protection of employees, including, without limitation, the Occupational Health and Safety Act, 29 U.S.C. §651, et seq. (“Health and Safety Laws”).

(3)    “Hazardous Material” shall mean any hazardous substance or waste, solid waste, pollutant, or contaminant, and any other material or substance with respect to which notification, storage, handling, use, manufacture, generation, processing, treatment, transport, disposal, release, discharge, emission or remedial obligations may be imposed under any Environmental Law or which is defined or regulated as a hazardous substance or hazardous waste under any Environmental Law, including, without limitation, asbestos, polychlorinated biphenyls and petroleum, oil, or natural gas liquids.

(b)    Representations and Warranties.

(1)    The Company and Enserco Midstream are, and at all times since January 1, 2008 have been, in compliance with, and have not been and are not in violation of, Environmental Law or any Health and Safety Law in all material respects, whether or not resulting in any Proceeding against the Company pertaining to the Business.

(2)    The Company and Enserco Midstream have not incurred or become liable for or subject to any material Environmental Liabilities pertaining to the Business.

(3)    There has been no release of any Hazardous Material at or from any of the assets during ownership, lease or operation by the Company or Enserco Midstream into the Environment, except in compliance with all then applicable

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Environmental Laws in all material respects and so as not to create any material Environmental Liabilities.

(4)    The Company and Enserco Midstream have not received any written communication from any Person with respect to the Business which alleges (A) any actual or potential violation or failure to comply with any Environmental Law or Health and Safety Law, (B) any actual, pending or Threatened obligation to undertake or bear the cost of any Environmental Liabilities or (C) any actual, pending or Threatened Proceeding.

(5)    The Company and Enserco Midstream hold no Permits pertaining to the Business pursuant to Environmental Law.

(6)    Seller has given Buyer access to all material environmental studies and inspection reports pertaining to the Real Property, which copies are complete and conform to the originals of such studies and reports, and summarize the environmental condition of such Real Property as of the date of such studies and reports.

3.13    Intellectual Property.

(a)    Schedule 3.13 sets forth a complete and correct list of the following: (1) all patented or registered Intellectual Property owned by the Company or Enserco Midstream, including, without limitation, internet domain name registrations; (2) all pending patent applications or other applications for registration of Intellectual Property owned by the Company or Enserco Midstream; (3) all trade names and unregistered marks owned and used by the Company or Enserco Midstream; (4) all computer software owned, licensed or otherwise used by the Company or Enserco Midstream that is material to the Business, other than commercially available, off-the-shelf software (“Company Software”); and (5) all other material copyrights or mask works owned by the Company or Enserco Midstream, whether or not registered or subject to registration.

(b)    To Seller's Knowledge, the Company and/or Enserco Midstream, as applicable, owns or will own on the Closing Date (free and clear of all Encumbrances, other than any Permitted Encumbrance), or has the right to use or will have the right to use on the Closing Date without payment of a royalty, license fee or similar fee (other than pursuant to a Major Contract or a Contract not required to be disclosed in the Schedules hereto to avoid a breach under Section 3.8), the Intellectual Property used by the Company in the operation of the Business, except as described in Schedule 3.9(a) or where the failure of the Company or Enserco Midstream to so own or have the right to use any such Intellectual Property has not had a Material Adverse Effect on the Company.

(c)    The Company has not received written notice that any registered Intellectual Property has been declared unenforceable or otherwise invalid by any Governmental Authority. The Company has not received any written charge, complaint, claim, demand or notice since December 31, 2008 alleging that any use, sale or offer to sell any good or service of the Company infringes upon, misappropriates or violates any Intellectual Property right of any other Person, including any claim that the Company must license or refrain from using any

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Intellectual Property right of any other Person or any offer by any other Person to license any Intellectual Property right of any other Person.

(d)    Notwithstanding the foregoing, no representation or warranty is made in this Agreement regarding any infringement, misappropriation or violation with, upon, of, by or otherwise relating to any (1) license for Intellectual Property embedded in any equipment or fixture, (2) non-exclusive implied license of Intellectual Property or (3) non-exclusive license for the use of any commercially available off-the-shelf software.

3.14    Absence of Certain Events. Since the date hereof, (a) there has not been any Material Adverse Effect on the Company and (b) the Company has been operated in its Ordinary Course of Business in all material respects, except for anything approved by Buyer in accordance with Section 5.2.

3.15    Insurance. Seller provides or causes to be provided for the Company and Enserco Midstream fire, casualty, business interruption and directors and officers liability insurance policies with extended coverage, sufficient in amount and content to reasonably protect the Business (subject to reasonable deductibles) consistent with past practices, and shall maintain such insurance in full force and effect until Closing.

3.16    Employee Benefits.

(a)    The Company is not a Plan Sponsor of any Company Plan. Schedule 3.16(a) lists all Company Plans to which the Company contributes or has contributed, or in which any employee of the Company participates or has participated.

(b)    Each Company Plan is in compliance in all material respects with its terms and with all applicable requirements of the Code and ERISA. None of the Company or any ERISA Affiliate nor any director, officer or employee of the Company or of any ERISA Affiliate has engaged in any unresolved Prohibited Transaction or committed any breach of fiduciary responsibility under ERISA, except for any Prohibited Transaction for which a specific exemption is provided under or pursuant to ERISA or the Code.

(c)    Each Company Plan that is intended to be qualified under section 401 of the Code has been determined by the IRS to be qualified under the Code.

(d)    Each (if any) ERISA Affiliate-sponsored Title IV Plans is adequately funded under ERISA funding rules and all PBGC premiums (if any) have been timely made and no such Title IV Plan (if any) has been declared insolvent or surrendered to the PBGC.

(e)    The Company has not contributed to a Multiemployer Plan that is subject to Title IV of ERISA within the immediately preceding six-year period. To the extent any ERISA Affiliate has contributed to such a Multiemployer Plan, all contributions have been timely made by the applicable ERISA Affiliate and any withdrawal Liability owed by an ERISA Affiliate has either been fully satisfied and discharged or is being timely paid through stated installment payments in full compliance with the Multi-Employer Pension Plan Amendments Act of 1980, as amended. The Company does not have any obligation to pay any contribution to

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any funded Pension Plan currently or previously maintained by such Company or any ERISA Affiliate that will not have been satisfied in connection with or before Closing.

(f)    No Company Plan provides for continuing benefits or coverage for any participant or any beneficiary of a participant after such participant's termination of employment, except as may be required by COBRA (or similar state law) at such participant's or such beneficiary's expense. The requirements of section 4980B of the Code and Part 6 of Subtitle B of Title I of ERISA relating to COBRA continuation of health coverage have been satisfied with respect to each Company Plan that is subject to such requirements.

3.17    Employees and Labor Relations. Neither the Company nor Enserco Midstream is a party to or is bound by any collective bargaining agreement or other similar Contract with any labor union representing employees of the Company or Enserco Midstream, as applicable. No labor strike, lockout or material labor dispute or work stoppage has occurred or, to Seller's Knowledge, been Threatened with respect to employees of the Company or Enserco Midstream. To Seller's Knowledge, no union organizing campaign exists or has occurred with respect to employees of the Company or Enserco Midstream. Seller has provided Buyer with a schedule listing the name, position, base compensation (as of the date hereof) and, for calendar year 2010, total compensation for each employee of the Company.

3.18    Credit Support; Pre-Paid Deposits.

(a)    Schedule 3.18(a) contains a complete and accurate list and summary description as of the Reporting Date of all guaranties, letters of credit, comfort letters, surety bonds, cash and other credit support in favor of any counterparty to any Commodity Transaction (each, a “Counterparty”) provided by or on behalf of the Company or its Affiliates in support of the obligations of the Company or its Affiliates under such Commodity Transactions (collectively, “Company Credit Support”). The Company has not defaulted or otherwise created a circumstance that triggers the right of any Counterparty to make a claim under any Company Credit Support and there are no pending disputes with respect to any Company Credit Support.

(b)    Schedule 3.18(b) contains a complete and accurate list and summary description as of the Reporting Date of all pre-paid obligations, pre-paid cash deposits or deposits of marketable securities in favor of any Counterparty provided by the Company or its Affiliates in support of the obligations of the Company under any Commodity Transaction (collectively, “Company Pre-Paid Deposits”). The Company has not defaulted or otherwise created a circumstance that triggers the right of any Counterparty to make a claim against or otherwise seize all or any portion of any Company Pre-Paid Deposits and there are no pending disputes with respect to any Company Pre-Paid Deposits.

(c)    Schedule 3.18(c) contains a complete and accurate list and summary description as of the Reporting Date of all guaranties, letters of credit, comfort letters, surety bonds, cash and other credit support in favor of the Company or Enserco Midstream provided by or on behalf of any Counterparty or affiliate thereof in support of the obligations of such Counterparty under any Commodity Transaction (collectively, “Counterparty Credit Support”). No counterparty is in default or has otherwise created a circumstance that triggers the right of the

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Company to make a claim under any Counterparty Credit Support and there are no pending disputes with respect to any Counterparty Credit Support.

(d)    Schedule 3.18(d) contains a complete and accurate list and summary description as of the Reporting Date of all pre-paid obligations, pre-paid cash deposits or deposits of marketable securities on behalf of the Counterparties deposited with the Company or Enserco Midstream in support of the obligations of the Counterparties under any Commodity Transaction (collectively, “Counterparty Pre-Paid Deposits”). The Company has not alleged or claimed a circumstance that triggers the right of any party to make a claim against or otherwise seize all or any portion of any Counterparty Pre-Paid Deposits nor are there any pending disputes with respect to any Counterparty Pre-Paid Deposits.

(e)    Prior to Closing, the Company will update Schedules 3.18(a), (b), (c) and (d) (the “Credit Support Schedules”) on a monthly basis on or before the 15^th day of each calendar month and in accordance with Section 2.3(b).

3.19    Commodities.

(a)    Valuation Policy. Subject to amounts reserved for Commodities, the values at which all Commodities and Commodity Transactions are carried in the Company's financial statements reflect the historical valuation policy of the Company. The Company and Enserco Midstream have title or rights to the Commodities and transmission, pipeline and transportation agreements sufficient to operate the Business in all material respects as it is presently conducted.

(b)    Trade Confirmations. The Company's binding trade confirmations (whether written or oral) with respect to each Commodity Transaction are properly recorded in the Trade Book.

(c)    Risk Policy and Credit Policy. The Company has at all times during calendar year 2011 through the date of this Agreement been in material compliance with the requirements of the Risk Policy and Credit Policy.

(d)    Inventory. The inventory shown on the Interim Balance Sheet is a true, complete and accurate estimate of the inventory of the Company and Enserco Midstream as of such date. The inventory levels are consistent with past practices of the Company and Enserco Midstream and all such inventory is good and usable for its intended purposes in the Ordinary Course of Business.

(e)    Electronically Recorded Trade Book. The Electronically Recorded Trade Book to be delivered in accordance with Section 2.3(b)(2) is a true, accurate and complete list maintained consistent with past practices of the Company. Taken as a whole, the values ascribed by Seller to the Electronically Recorded Trade Book are fair and accurate in all material respects.

(f)    BNPP Reconciliation. Except as set forth on Schedule 3.19(f), as of November 30, 2011, the Company's BNPP futures contract merchant account shall tie in all material respects to the Trade Book in both volume and mark to market value (“BNPP Reconciliation”).

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3.20    Brokers. Neither the Company nor Enserco Midstream has any obligation or other Liability to any broker, finder or similar intermediary in connection with the transactions contemplated herein that would cause Buyer, the Company or Enserco Midstream to become liable for payment of any fee or expense with respect thereto.

3.21    Accounts Receivable. The accounts receivable shown on the Financial Statements are valid, genuine and existing, arose out of bona fide sales and deliveries of goods, performance of services or other legitimate business transactions in the Ordinary Course of Business. Except as set forth on Schedule 3.21, as of the date of this Agreement, all accounts receivable were less than ninety (90) days old and, to Seller's Knowledge, there is no existing dispute regarding the collectability of any such accounts receivable.

ARTICLE 4

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer hereby represents and warrants to Seller as follows:

4.1    Organization and Good Standing. Buyer is a duly organized and validly existing limited liability company in good standing under the laws of Delaware. Buyer is duly qualified and in good standing to do business as a foreign limited liability company in each jurisdiction in which the ownership and leasing of its properties and assets or the conduct of its business requires such qualification, except where the failure to be so qualified or in good standing will not materially and adversely affect its ability to consummate the transactions contemplated herein. Buyer has full limited liability company power and authority to own and lease its properties and assets and conduct its business, except where the failure to have such power or authority will not materially and adversely affect its ability to consummate the transactions contemplated herein and in the Ancillary Documents.

4.2    Authority and Authorization; Conflicts; Consents.

(a)    The execution, delivery and performance by Buyer of this Agreement and each Ancillary Document to which it is a party have been duly authorized and approved by all necessary limited liability company action with respect Buyer, and each such authorization and approval remains in full force and effect. Assuming due authorization, execution and delivery by Seller of this Agreement and each Ancillary Document to which it is a party, this Agreement is, and each Ancillary Document to which Buyer is a party at Closing will be, the legal, valid and binding obligation of Buyer, enforceable against Buyer in accordance with its terms, except to the extent enforceability may be limited by any applicable bankruptcy, reorganization, insolvency, moratorium or similar other Applicable Law affecting creditors' rights generally and principles governing the availability of equitable remedies. Buyer has all requisite limited liability company power and authority to enter into this Agreement and each Ancillary Document to be executed and delivered by it and to consummate the transactions contemplated herein and therein.

(b)    Neither the execution nor delivery by Buyer of this Agreement or any Ancillary Document to which it is a party nor consummation by Buyer of the transactions contemplated herein or therein does or will (with or without the passage of time or giving of notice) (1) constitute a breach of, violate, conflict with or give rise to or create any right or

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obligation under any Organizational Document of Buyer, (2) violate any Applicable Law or Order, or (3) constitute a breach or violation of or a default under, conflict with or give rise to or create any right of any Person other than Buyer to accelerate, increase, terminate, modify or cancel any right or obligation under, any Contract to which Buyer is a party, except where such breach, violation, default, conflict or right described in clause (2) or (3) above will not materially and adversely affect Buyer's ability to consummate the transactions contemplated herein.

(c)    No consent or approval by, notification to or filing with any Person is required in connection with Buyer's execution, delivery or performance of this Agreement or any Ancillary Document to which it is a party or Buyer's consummation of the transactions contemplated herein or therein, except (1) as described in Section 5.3 and (2) for any consent, approval, notice or filing, the absence of which will not materially and adversely affect Buyer's ability to consummate the transactions contemplated herein and in the Ancillary Documents.

4.3    Litigation and Orders. There is no Proceeding pending or, to Buyer's Knowledge, Threatened against Buyer or to which Buyer is a party, nor is there any Order to which Buyer is subject, that will materially and adversely affect Buyer's ability to consummate the transactions contemplated herein and in the Ancillary Documents.

4.4    Availability of Funds. On the date hereof, Buyer has (a) available cash, (b) existing available borrowing and letter of credit capacity under committed borrowing facilities, (c) commitment letters from BNP Paribas for borrowing and letter of credit capacity, (d) commitment letters for the provision of equity capital, or (e) some combination of the foregoing that is sufficient to enable Buyer to consummate the transactions contemplated herein and in the Ancillary Documents. All such debt or equity commitment letters are attached hereto as Annex F. There are no conditions precedent to the funding obligations of BNP Paribas in the Fee Letter (as such term is defined in its commitment letter). At Closing, Buyer will have available cash that is sufficient to enable Buyer to consummate the transactions contemplated herein and in the Ancillary Documents. Buyer's obligations hereunder are not contingent upon procuring any financing.

4.5    Securities. Buyer is acquiring the Shares hereunder for investment, solely for Buyer's own account and not with a view to, or for resale in connection with, any distribution or other disposition thereof in violation of the Securities Act or any applicable state securities law. Buyer acknowledges that none of the Shares may be resold in the absence of registration, or the availability of an exemption from such registration, under the Securities Act or any applicable state securities law. Buyer is an “accredited investor” as defined in Rule 501 promulgated under the Securities Act and has such knowledge and experience in financial and business matters as to be capable of evaluating the merits and risks of an investment in the Shares. Buyer has had access to sufficient information regarding the Company and its business and condition to make an informed decision to acquire the Shares.

4.6    Brokers. Neither Buyer nor any of its Affiliates has any obligation or other Liability to any broker, finder or similar intermediary in connection with the transactions contemplated herein that would cause Seller to become liable for payment of any fee or expense with respect thereto.

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ARTICLE 5

CERTAIN COVENANTS

5.1    Certain Actions to Close Transactions. Subject to the terms of this Agreement, each Party will use commercially reasonable efforts to fulfill, and to cause to be satisfied, the conditions in Article 7 (but with no obligation to waive any such condition) and to consummate and effect the transactions contemplated herein, including to cooperate with and assist each other in all reasonable respects in connection with the foregoing. Without limiting the generality of the foregoing, Seller will use commercially reasonable efforts to give any required notices to, and make any required filings with, other Persons and to obtain each Consent before Closing, and Buyer will cooperate with Seller in all reasonable respects in connection therewith.

5.2    Pre-Closing Conduct of Business.

(a)    Business Operations Committee. Between the date hereof and Closing, Seller and Buyer will form a committee (the “Business Operations Committee”) consisting of four (4) representatives of Seller and the Company and two (2) representatives of Buyer for the purpose of discussing and advising the Company and Enserco Midstream on the conduct of business between the date hereof and Closing. Seller's and the Company's representatives on the Business Operations Committee will initially consist of Garner Anderson, Cindi Doeschot, Victoria Campbell and Patrick Joyce and Buyer's representatives on the Business Operations Committee will initially consist of Jeremy Davis and Eric Watts. The Business Operations Committee will meet at least twice per week between the date hereof and Closing. For the avoidance of doubt, (i) the Business Operations Committee will exist solely to consult with and advise Seller, the Company and Enserco Midstream, (ii) all management of the Company and Enserco Midstream will continue to be vested in Seller, the Company and Enserco Midstream, and (iii) any decisions or recommendations of the Business Operations Committee will not be binding on Seller, the Company and Enserco Midstream.

(b)    Certain Restrictions.

(1)    Prior to Closing, Seller will use commercially reasonable efforts to cause the Company to consult with the Business Operations Committee with respect to all material Business decisions.

(2)    Except as expressly contemplated herein or as otherwise consented to in writing by Buyer (which consent will not be unreasonably withheld, conditioned or delayed), from the date hereof through Closing, Seller will cause the Company and Enserco Midstream to operate in the Ordinary Course of Business and in accordance with the Risk Policy and Credit Policy.

(3)    Between the date hereof and the Closing, Seller shall cause the Company to provide complete updated mark-to-market results of the Trading Book (A) for all Commodities other than crude oil not less than weekly and (B) for crude oil not less than twice per calendar month.

(4)    Buyer shall be entitled to have one or more of its executives on site at the Company's facilities during normal business hours; provided that such executives

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will comply with the reasonable directions of Seller with respect thereto and will not disrupt the Business. At Buyer's request, between the date hereof and Closing, as Buyer develops integration plans, Seller agrees to provide information and reasonable support necessary for the development of such plans.

(5)    Except as provided in Section 5.2(e), Seller shall use its commercially reasonable efforts to preserve intact the Business and (solely with respect to the Business) the relationships of the Company and Enserco Midstream with the employees, suppliers, counterparties and others having relationships with the Company or Enserco Midstream.

(c)    Certain Permitted Actions. This Agreement will not prevent or otherwise restrict Seller or any of its Affiliates (including the Company) from making, or causing the Company to make, any dividend or other distribution of cash or cash equivalents, including any sweep of cash from any account of the Company at any time before the Closing.

(d)    No Change in Accounting Methodologies. The Company shall not make any changes to its financial accounting methods, except as required by Applicable Law or by GAAP to the extent failure to adopt such changes would cause such financial accounting methods not to be in accordance with GAAP or the Risk Policy from the date hereof through the Closing. The Company shall conduct its operations in material compliance with the Credit Policy and the Risk Policy as applied on a consistent basis and in accordance with past practice.

(e)    Business Curtailment. After the date hereof, the Business Operations Committee will promptly develop a plan to accomplish the following prior to Closing, and Seller (in consultation with the Business Operations Committee) will use commercially reasonable efforts to cause the Company to implement such plan prior to Closing:

(1)    reduce Prop Trading (as hereinafter defined) so that the value at risk for all Prop Trading positions is $500,000 or less (95% confidence interval and one-day time horizon), calculated using historical market trends, prices, volatility and correlations;

(2)    reduce the Company's Prop Trading so that the value at risk for all Prop Trading positions for the period after April 1, 2012 forward is $100,000 or less (95% confidence interval and one-day time horizon), calculated using historical market trends, prices, volatility and correlations;

(3)    reduce the Company's aggregate Net Working Capital (excluding cash) from the Company's Net Working Capital (excluding cash) as of the Reporting Date of $137,535,775 by a minimum of $35,000,000 to $102,535,775 or less; and

(4)    (A) reduce the amount of borrowings outstanding at Closing under the Company Credit Facility to zero and (B) reduce the aggregate face value of letters of credit issued under the Company Credit Facility and outstanding at Closing to $125,000,000 or less.

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“Prop Trading” means the Company's proprietary natural gas financial trading and proprietary power financial trading, but does not include any customer-related or asset-related (including transportation and storage) trading.

“Business Curtailment Losses” means losses of the Company and Enserco Midstream realized on execution of trades related to (1) Seller's exercise of commercially reasonable efforts in implementing the value at risk thresholds and reductions set forth in Sections 5.2(e)(1) and (2) above and (2) any standing orders entered into pursuant to Section 5.2(f) below; provided, however, any execution at the Company's mark on the prior day's close will not be considered to give rise to Business Curtailment Losses. It is specifically agreed that Business Curtailment Losses resulting from Sections 5.2(e)(1) and (2) above will not be incurred without the prior written approval of Buyer. Notwithstanding the foregoing, nothing in Section 5.2(e) or (f) will require Seller, the Company or Enserco Midstream to suffer Business Curtailment Losses in the aggregate between the date hereof and Closing in excess of $1.0 million. The aggregate Business Curtailment Losses suffered by the Company and Enserco Midstream between the date hereof and Closing in an amount not to exceed $1.0 million will be added to the Purchase Price pursuant to Article 2.

For the avoidance of doubt, it is not a condition precedent to Buyer's obligation to Close that Seller, the Company and Enserco Midstream actually achieve the business curtailment objectives in Section 5.2(e)(1) through (4).

(f)    Standing Orders. In order to reduce Prop Trading value at risk, unless the Business Operations Committee unanimously determines otherwise, Seller will cause the Company to enter into standing orders with counterparties or exchanges to enter in to transactions at the values at which the Prop Trading positions were marked on the prior day's close.

(g)    Prop Trading Positions. After the date hereof, the Company shall not enter into any Prop Trading commitments, other than offsetting trades intended to reduce or maintain the Prop Trading value at risk in compliance with Section 5.2.

(h)    Demand Payments and Capital Expenditures. Prior to the Closing, Seller will not permit the Company or Enserco Midstream to enter into any Contracts in a cumulative amount in excess of $5,000,000 for (1) transportation, storage, or other commitments requiring demand payments or (2) capital expenditures, other than  Contracts entered into with the prior written consent of Buyer. Specifically, Seller will not permit the Company to extend or otherwise enter into any new agreement with Northern Border Pipeline Company with respect to natural gas transport without the prior written consent of Buyer.

5.3    HSR Act Compliance; FPA Approval.

(a)    With respect to the transactions contemplated herein, each Party will (or will cause its applicable Affiliate to), within five (5) Business Days after the date hereof (or sooner, to the extent required by Applicable Law), file with the United States Federal Trade Commission (the “FTC”) and the United States Department of Justice (the “DOJ”) the required notification and report form pursuant to the HSR Act and related requirements. Thereafter, each

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Party will (or will cause its applicable Affiliate to) submit and otherwise provide any supplemental information requested in connection therewith pursuant to such Applicable Laws. Such actions will comply, in all material respects, with such Applicable Laws. Buyer will pay all filing and submission fees under the HSR Act (“HSR Filing Fees”). Each Party will furnish, or cause to be furnished, to the other any necessary information and reasonable assistance as the other may request in connection with its preparation of any filing or submission necessary under such Applicable Laws. Each Party will keep the other Party reasonably informed, to the extent permitted by Applicable Laws, of the status of any communications with, and inquiries or requests for additional information from, the FTC, DOJ or any other Governmental Authority, and will use its commercially reasonable efforts to (and, if applicable, cause its appropriate Affiliate to) promptly comply with any such inquiry or request and to defend against any action of the FTC, DOJ or any other Governmental Authority that attempts to enjoin the sale of the Shares to Buyer. Each Party will (and, if applicable, will cause its appropriate Affiliate to) use its commercially reasonable efforts to cause the expiration or early termination of the waiting period required under the HSR Act.

(b)    Seller and Buyer shall use reasonable best efforts to prepare and file, as promptly as practicable after the date of this Agreement, an appropriate filing pursuant to Section 203 of the FPA for the approval by the FERC for the transactions contemplated by this Agreement and to supply as promptly as practicable to the appropriate Governmental Authorities any additional information and documentary material that may be requested by a Governmental Authority. With respect to any such filings, including filings that will be submitted pursuant to the FPA, the Parties shall cooperate with respect to information necessary for such filings and shall give each other reasonable opportunity to comment on and revise drafts of any such filings before such filings are submitted to the appropriate Governmental Authority. Seller shall cause the Company and Enserco Midstream to refrain from taking any action that causes the Company or Enserco Midstream to be regulated by or under any Governmental Authority that they are not regulated by or under as of the date hereof.

5.4    Access to Information.

(a)    Pre-Closing Access for Buyer. From the date hereof through Closing, subject to the Confidentiality Agreement and Seller's reasonable confidentiality precautions, including those based on the confidential nature of this Agreement and the Ancillary Documents and the transactions contemplated herein and therein, Seller will (1) cause Buyer and Buyer's representatives to have reasonable access during normal business hours and upon reasonable notice from Buyer, to the facilities, personnel, books and records of the Company for the opportunity to investigate the Company and (2) furnish to Buyer and Buyer's representatives such additional financial and operating data and other information relating to the Company as Buyer reasonably requests. Buyer and Buyer's representatives will conduct such investigation in a manner that does not interfere with the operations of Seller or the Company. Buyer will keep confidential, and Buyer will cause its representatives to keep confidential, all confidential information that Buyer or any of Buyer's representatives receives from or on behalf of Seller or the Company in the course of the actions contemplated in this Section, and Buyer will not, and Buyer will cause its representatives not to, use any of such confidential information except in connection with this Agreement and, if this Agreement is terminated for any reason whatsoever, will return to Seller or destroy all embodiments (and all copies) of such confidential information

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(including all reports, analyses and other derivatives therefrom) that are in or under Buyer's or any of its representatives' possession or control.

(b)    Post Closing Access for Buyer. Throughout the three-year period after Closing, subject to Seller's reasonable confidentiality precautions, Seller will, during normal business hours and upon reasonable notice from Buyer, provide access to all books, records and data of the Company that remain in the possession of Seller.

(c)    Post-Closing Access for Seller. Throughout the three-year period after Closing (or until the expiration of the Foreign Tax Credit with respect to Section 5.4(c)(1)(F) below only), subject to Buyer's reasonable confidentiality precautions, Buyer will, during normal business hours and upon reasonable notice from Seller (1) cause Seller and Seller's representatives to have reasonable access to the books and records (including financial and Tax records, Tax Returns, files, papers and related items) of the Company, and to the personnel responsible for preparing and maintaining such books and records, in each case to the extent necessary or reasonably desirable to (A) defend or pursue any Proceeding, (B) defend or pursue indemnification matters hereunder, (C) prepare or audit financial statements, (D) prepare or file Tax Returns, (E) address other Tax, accounting, financial or legal matters or respond to any investigation or other inquiry by or under the control of any Governmental Authority, and (F) with respect to Section 2.8 only, confirm the Net Tax Savings resulting from the Foreign Tax Credit in accordance with Section 2.8, and (2) permit Seller and Seller's representatives to make copies of such books and records for the foregoing purposes, at Seller's expense.

(d)    Post-Closing Retention of Information by Seller. At and after Closing, Seller may retain in Seller's (or any of its Affiliates') possession, subject to Buyer's reasonable confidentiality precautions, any copies of any books or records of such types described in Section 5.4(c)(1) that are in Seller's possession or control, in each case for any purpose described in Section 5.4(c)(1).

5.5    Further Assurances. If after Closing any further action is necessary, proper or desirable to carry out any purpose of this Agreement, then each Party will take such further action (including the execution and delivery of further documents) as the other Party reasonably requests to carry out such purpose. The foregoing will be at the expense of such requesting Party, except to the extent such requesting Party is entitled to indemnification therefor or to the extent this Agreement otherwise allocates such expense to any other Party.

5.6    Confidentiality and Publicity.

(a)    Confidentiality Agreement. Subject to the other terms of this Section 5.6, the Confidentiality Agreement between Black Hills Corporation and Buyer dated September 12, 2011 (the “Confidentiality Agreement”), will remain in full force and effect pursuant to its terms, except that, after the Closing Date, Confidential Information (as defined in the Confidentiality Agreement), for purposes of the obligations of Buyer under the Confidentiality Agreement, will be deemed not to refer to any information then solely relating to the Company.

(b)    Confidentiality. At all times after Closing, Seller will, and Seller will cause its Affiliates to, keep confidential and not disclose and not use, any confidential,

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proprietary or other non-public information of the Company, except to the extent permitted by Section 5.4(c) and (d).

(c)    Publicity. Except as stated in this Section 5.6(c), no Party will make, and each Party will prevent its Affiliates from making, any public release or announcement regarding this Agreement, any Ancillary Document or any of the transactions contemplated herein or therein without the prior written approval thereof of each Party (which will not be unreasonably withheld).

(d)    Certain Permitted Disclosures. Notwithstanding the foregoing, nothing in this Section 5.6 will prevent any of the following at any time: (1) a Party disclosing any information to the extent required under Applicable Law or under the rules and regulations of any national securities exchange (to the extent such Party or any of its Affiliates has any of its securities traded or listed thereon); (2) before Closing, Seller informing other potential acquirers of the Company that a definitive agreement has been entered into, without identifying Buyer or any of its Affiliates; (3) before Closing, Seller communicating with any of its suppliers or customers on a need to know basis regarding the transactions contemplated herein, including regarding any change to any document, requirement or process relating to any product or service of Seller or the Company or any Consent; (4) a Party or any of its Affiliates making a statement or disclosure (A) as part of its or any of its Affiliate's financial statements or Tax Returns or (B) to the extent reasonably necessary to enforce or comply with this Agreement; or (5) a Party making a statement or disclosure to (A) such Party's (or any of its Affiliate's) paid legal, accounting and financial advisers to the extent reasonably necessary for any such adviser to perform its paid legal, accounting and financial services, respectively, for such Party (or such Affiliate), or (B) any lender or prospective lender of such Party (or such Affiliate) to the extent reasonably required as part of such lending relationship; provided that such Party will cause each Person to whom such statement or disclosure is made under this clause (5) to keep confidential and not disclose to any other Person any information in such statement or disclosure.

5.7    [Intentionally Omitted]

5.8    Certain Tax Matters.

(a)    Tax Periods Ending On or Before the Closing Date. Seller will prepare and timely file (or cause to be prepared and timely filed) all (1) Tax Returns with respect to the Company required to be filed on or before the Closing Date (after taking into account extensions therefor) and (2) consolidated, combined or unitary Tax Returns that include Seller and the Company that are required to be filed before, on or after the Closing Date. All such Tax Returns shall be prepared in accordance with past practice insofar as they relate to the Company.

(b)    Straddle Periods. Buyer shall prepare or cause to be prepared and file or cause to be filed any Tax Returns of the Company for any period that begins before the Closing Date and ends after the Closing Date (a “Straddle Period” and “Straddle Tax Returns”). Seller shall satisfy (or cause to be satisfied) all Taxes with respect to any Pre-Closing Tax Period (“Pre-Closing Taxes”). In the case of any Straddle Period, any Taxes shall be calculated as though the taxable year of the Company terminated as of the close of business on the Closing Date; provided, however, in the case of a Tax not based on income, receipts, proceeds, profits or

29

similar items, Pre-Closing Taxes shall be equal to the amount of Tax for the Straddle Period multiplied by a fraction, the numerator of which shall be the number of days from the beginning of the Straddle Period through the Closing Date and the denominator of which shall be the number of days in the Straddle Period. All determinations necessary to give effect to the foregoing allocations shall be made in a manner consistent with prior practice of the Company.

(c)    Payment of Taxes. With respect to Straddle Period Returns, Buyer shall provide Seller with a copy of such completed Straddle Tax Returns and a statement (with which Buyer will make available supporting schedules and information) certifying the amount of Tax shown on such Tax Return that is allocable to Seller at least thirty (30) days prior to the due date (including any extension thereof) for filing of such Straddle Tax Return. For a Straddle Period, Seller shall pay Buyer the portion set forth on the Straddle Tax Returns attributable to Seller for any Pre-closing Tax Period, on or before two (2) days of the due date. With respect to any Straddle Tax Return which Buyer is to prepare and file under this Section 5.8, Buyer shall make the Straddle Tax Return and related Tax work papers available for review by Seller.

(d)    Cooperation on Tax Matters.

(1)    The Parties shall cooperate fully, as and to the extent reasonably requested by the other party, in connection with the filing of Tax Returns pursuant to this Section 5.8 and any audit, litigation or other proceeding with respect to Taxes. Such cooperation shall include signing any Tax Return, amended Tax Returns, claims or other documents necessary to settle any Tax controversy, the retention and (upon the other party's request) the provision of records and information which are reasonably relevant to any such audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. Buyer agrees to retain all books and records with respect to Tax matters pertinent to the Company relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations (and, to the extent notified by Seller, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any relevant taxing authority and to give Seller reasonable written notice prior to transferring, destroying or discarding any such books and records.

(2)    Seller shall have the right to participate in and to direct Buyer in respect of any Tax proceeding to the extent it (A) relates to a Pre-Closing Tax Period or a Pre-Closing Tax of the Company and (B) could increase Seller's liability hereunder; provided, however, Buyer shall not be required to follow Seller's direction in any case in which the consequence could reasonably be expected to increase the Tax liability of the Company or Buyer for which Seller would have no obligation to indemnify in full.

(3)    Buyer and Seller further agree, upon reasonable request by the other, to use their commercially reasonable best efforts to obtain any certificate or other document from any governmental authority or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed (including, but not limited to, with respect to the transactions contemplated hereby).

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(e)    Transfer Taxes. Seller and Buyer will cooperate in timely making all Tax Returns, filings, returns, reports and forms as may be required to comply with the provisions of Applicable Law relating to Transfer Taxes. Notwithstanding Section 5.8(a), each Party will pay half of all Transfer Taxes that would have been payable had the Company not been converted to a limited liability company; all incremental Transfer Taxes resulting from such conversion to a limited liability company shall be the sole responsibility of Buyer.

5.9    Employee Matters. Buyer has delivered to Seller a list of individuals employed by the Company or Black Hills Service Company, LLC (“BH Service Co”) who have entered into retention agreements with the Company at the request of Buyer (“Retention Agreements”). Within twenty (20) Business Days after the date hereof, Buyer will deliver to Seller a confidential list of any other individuals employed by the Company or BH Service Co who (i) Buyer intends to cause the Company to retain or hire following the Closing (such individuals, together with the individuals party to Retention Agreements, are the “Retained Employees”) and (ii) Buyer does not intend to cause the Company to retain or hire following the Closing and who BH Service Co will retain or hire from the Company and make available to the Company following the Closing pursuant to the Transition Services Agreement. Buyer and Seller will coordinate the disclosure to employees of the Company and Enserco Midstream of information relating to the retention or severance of any employee of the Company or Enserco Midstream. Except as provided in the foregoing sentence, without the prior written consent of Buyer, Seller will not disclose to any employee of the Company or Enserco Midstream any information contained in any list of Retained Employees attached hereto or delivered by Buyer to Seller or otherwise relating to the retention or severance of any employee of the Company or Enserco Midstream.

(b)    Any employee of the Company who is not a Retained Employee or who declines employment with the Company, Enserco Midstream or Buyer following Closing shall be terminated by the Company or hired or retained by Seller or one or more of its Affiliates, at Seller's option, immediately before Closing, and, in such event, Seller shall provide any such terminated employee(s) with the severance to which they are entitled in accordance with the Company's policies at Seller's expense and shall indemnify Buyer accordingly.

(c)    All payments pursuant to the Retention Agreements shall be the responsibility of Buyer and Buyer shall indemnify Seller accordingly. All Retained Employees shall be the responsibility of Buyer and if any such employees leaves the employ of the Company, Enserco Midstream or Buyer after Closing, any severance obligations to such former employees shall be borne by Buyer and Buyer shall indemnify Seller accordingly.

5.10    Company Credit Support; Company Credit Facility. Buyer will cause the Company and each of its Affiliates to be unconditionally released from all non-cash Company Credit Support. Subject to Buyer's performance of the obligations set forth in the foregoing sentence, Seller will cause the Company to do the following at or prior to Closing: (a) pay all outstanding Liabilities (if any) pursuant to that certain Third Amended and Restated Credit Agreement, dated as of May 8, 2009, as amended (the “Company Credit Facility”), among the Company, BNP Paribas, as administrative agent, Societe Generale, U.S. Bank National Association, The Bank of Tokyo Mitsubishi UFJ, Ltd, and the other financial instructions party thereto (collectively, the “Lenders”), (b) terminate the Company Credit Facility, and (c) cause

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the Lenders to release all Encumbrances on any of the equity interests or assets of the Company and Enserco Midstream.

5.11    Calgary Lease. Prior to Closing, Seller shall legally terminate or otherwise assign that certain Lease of Office Space, dated as of December 21, 2010, as amended, between the Company and Bow Valley Leaseholds Limited (“Calgary Lease”), and Buyer shall have no obligations thereunder or liability therefor.

5.12    Sublease for the Denver Office. At Closing Seller and Buyer shall enter in a sublease for the Company's current office space, substantially in the form attached hereto as Exhibit B (the “Denver Sublease”). In the event that the landlord with respect to the Company's current office space does not consent to the Denver Sublease or the modifications to the premises contemplated therein, Seller will reimburse Buyer for all actual and reasonable incremental out-of-pocket costs associated with transitioning to and leasing other reasonably equivalent office space over and above the actual, out-of-pocket costs Buyer would have incurred had it subleased the Company's current office space pursuant to the terms of the Denver Sublease.

5.13    Trading and Support Software. Prior to Closing, Seller and its Affiliates shall assign to the Company all of their right, title and interest in and to the Company Software that is designated on Schedule 3.9(a) with the notation “To Be Assigned” to the extent it is assignable in accordance with the terms of the applicable Contract(s) pursuant to an assignment substantially in the form attached hereto as Exhibit C (the “Software Assignment”). Prior to Closing, Seller and its Affiliates shall use best efforts to obtain all necessary third-party consents to the assignment to the Company of their right, title and interest in and to the Company Software that is designated on Schedule 3.9(a) with the notation “To Be Assigned” but is not assignable in accordance with the terms of the applicable Contract(s), and with respect to such Company Software for which such third-party consents are obtained, Seller and its Affiliates shall assign to the Company all of their right, title and interest in and to such Company Software pursuant to a Software Assignment.

5.14    Accounts. Immediately prior to Closing, Seller shall release (and cause its Affiliates to release) the Company and Enserco Midstream of any and all obligations pursuant to, or otherwise terminate, all intercompany accounts other than Commercial Intercompany Accounts.

5.15    Conversion to an LLC. Within twenty (20) Business Days after the date hereof, Seller shall give Buyer an estimate of all the costs and expenses and any increase in Taxes (including Transfer Taxes) that would be incurred by Seller in connection with the conversion of the Company into a Delaware limited liability company. Subject to Buyer's written approval of the costs described in the prior sentence, immediately prior to Closing, Seller shall cause such conversion to be effectuated. Neither such conversion nor anything resulting from such conversion shall be deemed to be a breach of any representation or warranty of Seller herein. Buyer shall reimburse Seller for all costs and expenses reasonably incurred by Seller or the Company in connection with such conversion (“Conversion Costs”). Buyer shall indemnify and reimburse Seller for any increase in Taxes (including Transfer Taxes) payable by Seller as a result of such conversion. In the event the Company is converted to a limited liability company prior to the Closing pursuant to this Section, then all references in this Agreement to “Shares”

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shall be deemed to be the Company's newly issued limited liability company membership interests.

5.16    Transition Services Agreement. Buyer and Seller shall use commercially reasonable efforts to (a) continue to negotiate the transition services agreement attached hereto as Exhibit D (the “Transition Services Agreement”) and (b) enter into at Closing such Transition Services Agreement, with such changes as have been agreed to by the parties; provided that Buyer and Seller shall be reasonably compensated for the performance of their respective obligations thereunder and their respective obligations thereunder shall not survive beyond 180 days after the Closing Date.

ARTICLE 6

CLOSING; CLOSING DELIVERIES; TERMINATION

6.1    Closing. Subject to any earlier termination hereof, closing of the transactions contemplated herein (“Closing”) will take place at the offices of Faegre & Benson LLP (or its predecessor) at 3200 Wells Fargo Center, 1700 Lincoln Street, Denver, CO 80202, beginning at 9:00 a.m. local time on the second Business Day after the satisfaction or waiver of all conditions to the obligations of the Parties to consummate such transactions (other than conditions that by their nature are to be satisfied at Closing, but subject to the satisfaction or waiver of such conditions at Closing) or such other date or time as Buyer and Seller mutually determine (the actual date Closing occurs being the “Closing Date”). Closing will be effective as of 11:59 p.m. on the Closing Date. All actions to be taken and all documents to be executed or delivered at Closing will be deemed to have been taken, executed and delivered simultaneously, and no action will be deemed taken and no document will be deemed executed or delivered until all have been taken, delivered and executed, except in each case to the extent otherwise stated in this Agreement or any such other document.

6.2    Closing Deliveries by Seller. At Closing, Seller will deliver, or cause to be delivered, to Buyer (or as Buyer or this Agreement otherwise directs), the following:

(a)    all stock certificates representing the Shares, each duly endorsed in blank or accompanied by a duly executed stock power, dated the Closing Date and executed by Seller, in a form suitable for transferring the Shares to Buyer in the records of the Company;

(b)    Approval of the FERC under Section 203 of the FPA;

(c)    a duly executed copy of the Non-Competition Agreement;

(d)    subject to Section 5.16, a duly executed copy of the Transition Services Agreement;

(e)    a certificate of a duly authorized officer of Seller, in a form approved in advance by Buyer (such approval not to be unreasonably withheld), dated the Closing Date and executed by such officer, certifying that attached thereto is a true, correct and complete (1) certified copy of the Articles of Organization of Seller and Certificate of Incorporation of the Company, and a true, correct and complete copy of the Operating Agreement of Seller and By-Laws of the Company, in each case as are then in full force and effect, and (2) copy of the

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resolutions of the members or managers (as required) of Seller, authorizing the execution, delivery and performance of this Agreement and each Ancillary Document to which Seller is a party and the transactions contemplated herein and therein, in each case as are then in full force and effect;

(f)    subject to Section 5.12, a duly executed copy of the Denver Sublease;

(g)    duly executed copies of the Software Assignments in accordance with Section 5.13;

(h)    resignation letters from all of the officers and directors of the Company and Enserco Midstream who are not being retained in their current position;

(i)    evidence of the conversion of the Company to a Delaware limited liability company, if applicable;

(j)    evidence of the termination or assignment of the Calgary Lease to the satisfaction of Buyer;

(k)    a certificate of a duly authorized officer of Seller, in a form approved in advance by Buyer (such approval not to be unreasonably withheld), dated the Closing Date and executed by such officer, certifying (1) that each of Seller's representations and warranties in this Agreement was accurate in all respects as of the Closing Date, and (2) certifying a complete list of the officers and directors of the Company and Enserco Midstream, respectively, and the signature of each such person;

(l)    the BNPP Reconciliation statement as of the Closing Date; and

(m)    all other documents and items required by this Agreement to be delivered, or caused to be delivered, by Seller at Closing.

6.3    Closing Deliveries by Buyer. At Closing, Buyer will deliver, or cause to be delivered, to Seller (or as Seller or this Agreement otherwise directs), the following:

(a)    payment of the Estimated Purchase Price pursuant to Article 2;

(b)    a duly executed copy of the Non-Competition Agreement;

(c)    subject to Section 5.16, a duly executed copy of the Transition Services Agreement;

(d)    officer's certificates of a duly authorized officer of Buyer, in a form approved in advance by Seller (such approval not to be unreasonably withheld), dated the Closing Date and executed by such officer, certifying (1) that attached thereto is a true, correct and complete copy of the Organizational Documents of Buyer as are then in full force and effect, and (2) that attached thereto is a true, correct and complete copy of the resolutions of the Board of Directors, Managers or Members of Buyer, as applicable, authorizing the execution, delivery

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and performance of this Agreement and each Ancillary Document of Buyer and the transactions contemplated herein and therein, in each case as are then in full force and effect;

(e)    subject to Section 5.12, a duly executed copy of the Denver Sublease;

(f)    a certificate of a duly authorized officer of Buyer, in a form approved in advance by Seller (such approval not to be unreasonably withheld), dated the Closing Date and executed by such officer, certifying (1) that each of Buyer's representations and warranties in this Agreement was accurate in all respects as of the Closing Date, and (2) certifying the signature of each officer of Buyer authorized to sign this Agreement and the other documents delivered herewith; and

(g)    all other documents and items required by this Agreement to be delivered, or caused to be delivered, by Buyer at Closing.

6.4    Termination of Agreement. The sole and exclusive rights to terminate this Agreement before Closing (and the Party that has any such right) are as follows:

(a)    by mutual written consent of the Parties;

(b)    by either Party, if Closing has not occurred on or before March 31 , 2012 (the “Termination Date”);

(c)    by Buyer, if Seller commits a material breach of any term of this Agreement and such breach is not cured within fifteen (15) days after the date on which Buyer gives to Seller written notice of such breach, which notice must describe such breach with reasonable specificity and reference this Section, provided that Buyer has not waived such breach; or

(d)    by Seller, if Buyer commits a material breach of any term of this Agreement and such breach is not cured within fifteen (15) days after the date on which Seller gives to Buyer written notice of such breach, which notice must describe such breach with reasonable specificity and reference this Section, provided that Seller has not waived such breach.

A termination of this Agreement under any of the preceding clauses (b) through (d) will be effective two Business Days after the Party seeking termination gives to the other Party written notice of such termination. Notwithstanding any term in this Section 6.4, a Party will not have the right to terminate this Agreement (except by mutual written consent pursuant to Section 6.4(a)) if the failure to satisfy any condition to Closing or consummate the transactions contemplated herein results in any material respect from the breach by such Party of any of its representations, warranties, covenants or agreements herein.

6.5    Effect of Termination. If this Agreement is terminated pursuant to Section 6.4, then this Agreement will be of no further force or effect, except for the terms of Section 5.6 (captioned, “Confidentiality and Publicity”), Section 9.2 (captioned, “Expenses”), Section 9.3 (captioned “Interpretation; Construction”), Section 9.4 (captioned “Parties in Interest; Third-Party Beneficiaries”), Section 9.5 (captioned, “Governing Law”), Section 9.6 (captioned “Sole

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and Exclusive Remedies”), Section 9.7 (captioned, “Jurisdiction, Venue and Waiver of Jury Trial”), and this Section 6.5. Upon any termination pursuant to Section 6.4, no Party will have any further obligation or other Liability hereunder, except pursuant to a Section listed in the immediately preceding sentence or for any pre-termination fraud or willful or intentional breach by such Party.

6.6    Failure to Consummate Transactions; Liquidated Damages. If (1) the conditions under Sections 7.1 hereof have been satisfied or waived and nonetheless the transactions contemplated herein have not been consummated on or before the Termination Date, such failure is due to the actions or inactions of Buyer, and Seller rightfully terminates this Agreement pursuant to Section 6.4(b), or (2) Seller rightfully terminates this Agreement pursuant to Section 6.4(d), then Buyer will pay to Seller as a termination fee (the “Seller Termination Fee”) and as the sole remedy of Seller the amount of $5,000,000. The payment pursuant to this Section 6.6(a) will be made within one Business Day after the date of Seller's termination of this Agreement by wire transfer of immediately available funds to an account designated by Seller. Buyer acknowledges that the agreements in this Section 6.6(a) are an integral part of the transactions contemplated by this Agreement, and that, without these agreements, Seller would not enter into this Agreement; accordingly, if Buyer fails to pay or cause to be paid the Seller Termination Fee when due, and, in order to obtain such payment, Seller commences a Proceeding that results in a judgment against Buyer for the Seller Termination Fee, then Buyer will pay to Seller the reasonable costs and expenses (including attorneys' fees and expenses) of Seller in connection with such Proceeding, together with interest on the amount thereof at the prime rate as published in the Wall Street Journal on the date such payment was required to be made. If Seller is paid the Seller Termination Fee, then Seller may not exercise any other remedy against Buyer, at law or in equity or otherwise (except as contemplated by this Section). In the circumstance where the Seller Termination Fee is payable to Seller, such Seller Termination Fee shall be the sole and exclusive remedy of Seller against BNP Paribas and any of its current, former or future Affiliates or representatives and in no event shall BNP Paribas or any of its current, former or future Affiliates or representatives be subject to (nor shall Seller or any of its Affiliates seek to recover) damages in excess of the Seller Termination Fee in the aggregate for all losses, liabilities, debts and obligations arising from or in connection with any claim or cause of action that Seller or any of its Affiliates may have against BNP Paribas in connection herewith, including for a breach of Article 6 hereof as a result of financing by BNP Paribas to Buyer not being available to be drawn down or otherwise arising from the commitment letter from BNP Paribas to Buyer.

(b)    If (1) the conditions under Sections 7.2 hereof have been satisfied or waived and nonetheless the transactions contemplated herein have not been consummated on or before the Termination Date, such failure is due to the actions or inactions of Seller, and Buyer rightfully terminates this Agreement pursuant to Section 6.4(b), or (2) Buyer rightfully terminates this Agreement pursuant to Section 6.4(c), then Seller will pay to Buyer as a termination fee (the “Buyer Termination Fee”) and as the sole remedy of Buyer the amount of $3,500,000. The payment pursuant to this Section 6.6(b) will be made within one Business Day after the date of Buyer's termination of this Agreement by wire transfer of immediately available funds to an account designated by Buyer. Seller acknowledges that the agreements in this Section 6.6(b) are an integral part of the transactions contemplated by this Agreement, and that, without these agreements, Buyer would not enter into this Agreement; accordingly, if Seller fails to pay or cause to be paid the Buyer Termination Fee when due, and, in order to obtain such

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payment, Buyer commences a Proceeding that results in a judgment against Seller for the Buyer Termination Fee, then Seller will pay to Buyer the reasonable costs and expenses (including attorneys' fees and expenses) of Buyer in connection with such Proceeding, together with interest on the amount thereof at the prime rate as published in the Wall Street Journal on the date such payment was required to be made. If Buyer is paid the Buyer Termination Fee, then Buyer may not exercise any other remedy against Seller, at law or in equity or otherwise (except as contemplated by this Section).

ARTICLE 7

CONDITIONS TO OBLIGATIONS TO CLOSE

7.1    Conditions to Obligation of Buyer to Close. The obligation of Buyer to effect the closing of the transactions contemplated herein is subject to the satisfaction at or before Closing of all of the following conditions, any one or more of which may be waived by Buyer in its sole discretion:

(a)    Accuracy of Representations and Warranties. Each representation and warranty of Seller in Article 3 that contains a Materiality Qualifier is true and correct, and each representation and warranty of Seller in Article 3 that does not contain a Materiality Qualifier is true and correct in all material respects, as of the date of this Agreement and as of the Closing Date as if made on the Closing Date (or, in each case, if any such representation and warranty is expressly stated to have been made as of a specific date, then, for such representation and warranty, as of such specific date).

(b)    Observance and Performance. Seller will have performed, and complied with, in all material respects, all covenants and agreements required by this Agreement to be performed by Seller on or before the Closing Date.

(c)    Consents. Seller will have obtained and delivered to Buyer each Consent, each dated on or before the Closing Date, or in the case of Company Software, complied with Section 5.13.

(d)    HSR Act; FERC. The applicable waiting period, and any extension thereof, under the HSR Act will have expired or been duly terminated, if applicable, and the approval of the transactions contemplated herein by the FERC under Section 203 of the FPA has been received.

(e)    No Material Adverse Effect. Since the date of this Agreement, there will not have been any Material Adverse Effect on the Company or Enserco Midstream.

(f)    No Legal Actions. No Governmental Authority of competent jurisdiction will have instituted any Proceeding to restrain, prohibit or otherwise challenge the legality or validity of the transactions contemplated herein that has not been dismissed or otherwise resolved in a manner that does not materially and adversely affect the transactions contemplated herein and no injunction, order or decree of any Governmental Authority will be in effect that restrains or prohibits the purchase or sale of the Shares or the consummation of the other transactions contemplated herein.

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If any of the foregoing conditions to Closing is not satisfied at or before Closing and Buyer elects to consummate the transactions contemplated herein despite such failure, then Buyer will be deemed to have waived any and all claims for Losses arising out of, relating to or resulting from such failure and Buyer will have no right to be indemnified therefor.

7.2    Conditions to Obligation of Seller to Close. The obligation of Seller to effect the closing of the transactions contemplated herein is subject to the satisfaction at or before Closing of all of the following conditions, any one or more of which may be waived by Seller, in Seller's sole discretion:

(a)    Accuracy of Representations and Warranties. Each representation and warranty of Buyer in Article 4 that contains a Materiality Qualifier is true and correct, and each representation and warranty of Buyer in Article 4 that does not contain a Materiality Qualifier is true and correct in all material respects, as of the date of this Agreement and as of the Closing Date as if made on the Closing Date (or, in each case, if any such representation and warranty is expressly stated to have been made as of a specific date, then, for such representation and warranty, as of such specific date).

(b)    Observance and Performance. Buyer will have performed, and complied with, in all material respects, all covenants and agreements required by this Agreement to be performed by Buyer on or before the Closing Date.

(c)    Consents. Seller will have obtained each Consent, each dated on or before the Closing Date and in a form reasonably satisfactory to Seller.

(d)    HSR Act; FERC. The applicable waiting period, and any extension thereof, under the HSR Act will have expired or been duly terminated, if applicable, and the approval of the transactions contemplated herein by the FERC under Section 203 of the FPA has been received.

(e)    No Legal Actions. No Governmental Authority of competent jurisdiction will have instituted any Proceeding to restrain, prohibit or otherwise challenge the legality or validity of the transactions contemplated herein that has not been dismissed or otherwise resolved in a manner that does not materially and adversely affect the transactions contemplated herein and no injunction, order or decree of any Governmental Authority will be in effect that restrains or prohibits the purchase or sale of the Shares or the consummation of the other transactions contemplated herein.

If any of the foregoing conditions to Closing is not satisfied at or before Closing and Seller elects to consummate the transactions contemplated herein despite such failure, then Seller will be deemed to have waived any and all claims for Losses arising out of, relating to or resulting from such failure and Seller will have no right to be indemnified therefor.

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ARTICLE 8

INDEMNIFICATION AND RESOLUTION OF CERTAIN DISPUTES

8.1    Indemnification by Seller. Subject to the other terms of this Article 8, Seller will indemnify Buyer from and against all Losses of Buyer and each of Buyer's Other Indemnified Persons, to the extent proximately caused by any (a) breach of any representation or warranty made by Seller herein or in any Ancillary Document to which Seller is a party, (b) breach of any covenant or agreement of Seller herein or in any Ancillary Document to which Seller is a party, or (c) Proceeding incident to any of the foregoing.

8.2    Indemnification by Buyer. Subject to the other terms of this Article 8, Buyer will indemnify Seller from and against all Losses of Seller and each of Seller's Other Indemnified Persons, to the extent proximately caused by any (a) breach of any representation or warranty made by Buyer herein or in any Ancillary Document to which Buyer is a party, (b) breach of any covenant or agreement of Buyer herein or in any Ancillary Document to which Buyer is a party; or (c) Proceeding incident to any of the foregoing.

8.3    Certain Limitations and Other Matters Regarding Claims.

(a)    Deductible. Subject to the other terms of this Article 8, no Party will have any obligation under Article 8 unless and until the aggregate amount of Losses for which such Party is obligated thereunder exceeds $1,000,000 (the “Deductible”), and then only for the amount of such Losses in excess of the Deductible.

(b)    Cap. Subject to the other terms of this Article 8, no Party's obligations under Article 8 in the aggregate will exceed an amount equal to $5,000,000 (the “Cap”); provided, however, the Cap for any Trade Book Claim shall be $15,000,000.

(c)    Certain Treatment of Special Representations. Notwithstanding the foregoing terms of this Section 8.3, (1) the Deductible and Cap will not limit any Liability with respect to any Special Representation and (2) the amount of Losses hereunder with respect to any Special Representation will not be used in determining if the Deductible or Cap has been reached or exceeded. “Special Representation” means (A) with respect to Seller, any representation or warranty in Section 3.1 (captioned “Organization and Good Standing”) in Section 3.2 (captioned “Capitalization”), Section 3.3(a) (captioned “Authority and Authorization”), Section 3.5 (captioned “Taxes”), or Section 3.19 (captioned “Brokers”), (B) with respect to Buyer, any representation or warranty in Section 4.2(a) (under the heading “Authority and Authorization; Conflicts; Consents”), Section 4.4 (captioned “Availability of Funds”), or Section 4.7 (captioned “Brokers”), or (C) with respect to any Party, any representation or warranty that is fraudulently made.

(d)    No Special Losses. Notwithstanding any other term herein, no Party will be obligated to any other Person for any consequential, incidental, indirect, special, exemplary or punitive damages or Losses based thereon, including regarding loss of future revenue, income or profits, diminution of value or loss of business reputation or opportunity, and no Party will be obligated to any other Person for any Loss determined as a multiple of income, revenue or the like, relating to the breach of any representation, or warranty, covenant or agreement herein or in

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any Ancillary Document; provided that the foregoing will not apply to Seller's rights under Section 6.6 or to recover any Losses if Buyer fails to effect the Closing in breach hereof.

8.4    Certain Survival Periods.

(a)    Survival of Representations and Warranties. Subject to Section 8.4(b), each representation or warranty herein or in any Ancillary Document will survive the execution and delivery of this Agreement and remain in full force and effect until the date that is eighteen (18) months after the Closing Date; provided, however, that the representations and warranties made pursuant to Sections 3.1, 3.2, 3.3, 3.20, 4.1 and 4.6 shall survive indefinitely and Sections 3.5 and 3.12 shall survive until sixty (60) days following the expiration of the applicable statute of limitations (after giving effect to any extensions or waivers thereof). Neither the period of survival nor the liability of any Party hereto with respect to such Party's representations and warranties shall be reduced by any investigation made at any time by or on behalf of the other Party.

(b)    Survival of Representations and Warranties Until Final Determination. Notwithstanding Section 8.4(a), for each claim for indemnification hereunder regarding a representation or warranty that is validly made before the expiration of such representation or warranty, such claim and associated right to indemnification (including any right to pursue such indemnification, including via any Proceeding) will not terminate until final determination and satisfaction of such claim.

(c)    Survival of Covenants and Agreements. Each covenant and agreement (other than representations and warranties) made herein or in any Ancillary Document, and all associated rights to indemnification, will survive Closing until the expiration of the applicable statute of limitations.

8.5    Notice of Claims and Procedures.

(a)    Notice of Claims. A Party may assert a claim for indemnification hereunder (the “Claiming Party”) by giving the Party or Parties responsible for such indemnification (the “Indemnifying Party”) prompt notice of any claim for which such Claiming Party demands indemnification specifying the amount and nature of such claim (to the extent known). If the claim involves a Person that is not a Party nor an Other Indemnified Person (such a claim, including any Tax Claim, being a “Third-Party Claim”), the Claiming Party will give the Indemnifying Party, promptly after the Claiming Party's (or any of its applicable Other Indemnified Person's) receipt thereof, copies of all documents (including court papers) received by the Claiming Party (or any such Other Indemnified Person) relating to any such Third-Party Claim. The failure to promptly give such notice or to promptly give such copies will not relieve the Indemnifying Party of any Liability hereunder, except if the Indemnifying Party was prejudiced thereby, but only to the extent that the Indemnifying Party demonstrates that it was prejudiced thereby.

(b)    Access and Cooperation. Each Party will, and will cause its Other Indemnified Persons to, cooperate and assist in all reasonable respects regarding any Third-Party Claim, including by promptly making available to such other Party (and its legal counsel and

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other professional advisers with a reasonable need to know) all books and records of such Person relating to such Third-Party Claim, subject to reasonable confidentiality precautions.

(c)    Defense and Participation Regarding Third-Party Claims. Promptly after receiving notice of a Third-Party Claim pursuant to Section 8.5(a) (“Initial Claim Notice”), the Indemnifying Party will have the option to (1) conduct the Defense of such Third-Party Claim or (2) permit the Claiming Party to conduct the Defense of such Third-Party Claim. To elect to conduct such Defense, the Indemnifying Party must give written notice of such election to the Claiming Party within ten (10) days (or within the shorter period, if any, during which a Defense must be commenced for the preservation of rights) after the Claiming Party gives the corresponding Initial Claim Notice to the Indemnifying Party. Regardless of which Party conducts the Defense of such Third-Party Claim (the “Defending Party”), (A) the other Party (the “Non-Defending Party”) may participate, at its own expense, in such Defense (including any Proceeding regarding such Third-Party Claim) and will have the right to receive copies of all notices, pleadings or other similar submissions regarding such Defense, (B) each Party will keep the other Party reasonably informed of all matters material to such Defense and Third-Party Claim at all stages thereof, (C) no Party will or will permit its Other Indemnified Persons to admit Liability with respect to, or compromise or settle, such Third-Party Claim without the prior written consent of the other Party (which consent will not be unreasonably withheld) and (D) the Defending Party will not compromise or settle such Third-Party Claim, without the consent of the Non-Defending Party (which consent will not be unreasonably withheld).

8.6    Materiality Qualifiers. For purposes of this Article 8, in determining the amount of Losses arising out of, relating to or resulting from a breach of a representation or warranty in this Agreement or in any Ancillary Document (or any Proceeding arising out of, relating to or resulting from such a breach), but not for purposes of determining whether a breach occurred, all Materiality Qualifiers will be ignored and each such representation and warranty will be read and interpreted without regard to any Materiality Qualifier.

8.7    Reduction for Insurance, Taxes and Other Offsets.

(a)    The obligations of each Indemnifying Party hereunder regarding any Loss will be reduced, including retroactively, by the amount of any insurance proceeds, benefit regarding Taxes (a “Tax Benefit”) or other amount or benefit received, directly or indirectly, by the Claiming Party (or any of its Other Indemnified Persons) regarding such Loss. Without limiting the generality of the foregoing, if (1) the Claiming Party (or such Other Indemnified Person) receives from or on behalf of an Indemnifying Party, or an Indemnifying Party pays on behalf of the Claiming Party (or such Other Indemnified Person), a payment regarding a Loss, and (2) the Claiming Party (or such Other Indemnified Person) subsequently receives, directly or indirectly, any insurance proceeds, Tax Benefit or other amount or benefit regarding such Loss, then such Claiming Party (for itself or on behalf of such Other Indemnified Person, as applicable) will promptly pay to the Indemnifying Party the amount of such insurance proceeds, Tax Benefit or other amount or benefit, or, if less, the amount of such payment. The amount of such insurance proceeds, Tax Benefit or other amount or benefit received will be net of any costs and expenses incurred by the Claiming Party (or such Other Indemnified Person) in procuring the same and after giving effect to the impact of such recovery on insurance premiums or other costs of insurance.

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(b)    In computing the amount of any such Tax Benefit, the Claiming Party (or such Other Indemnified Person) will be deemed to fully utilize, at the highest marginal Tax rate then in effect under Applicable Law, all Tax items arising from the incurrence or payment of any indemnified Losses. To permit the Parties to fully resolve the claim regarding such Loss at one time, for any such Tax Benefit that is reasonably likely to be received in the future by the Claiming Party (or such Other Indemnified Person), the indemnification owed regarding such Loss will be reduced (without duplication) by the Parties' agreed upon determination of the present value of such future Tax Benefit (such agreement not to be unreasonably withheld).

(c)    Seller will only be liable to Buyer for Taxes to the extent that such Taxes hereunder exceed the sum of (1) the amount, if any, of estimated Taxes paid for such Taxes on or before the Closing Date plus (2) the amount, if any, accrued for such Taxes in Final Net Working Capital.

8.8    Effect of Purchase Price Adjustment. Any Loss for which a Party would otherwise be obligated to provide indemnification hereunder will be offset to the extent (but only to the extent) such Loss is reflected in the adjustments to the Purchase Price under Article 2.

8.9    Indemnification Adjusts Purchase Price for Tax Purposes. Each Party will, including retroactively, treat indemnification payments under this Agreement as adjustments to the Purchase Price (without regard to the Purchase Price Cap) for Tax purposes to the extent permitted under Applicable Law.

8.10    Certain Disclaimers. Notwithstanding any other term herein, other than as expressly made by Seller in Article 3 or Buyer in Article 4, neither Seller nor Buyer has made (and no Person on behalf of Seller or Buyer has made), and neither Seller nor Buyer (or any other Person) shall have or be subject to any Liability arising out of, relating to or resulting from, any representation or warranty or similar assurance (whether direct or indirect, written or oral, or statutory, express or implied), including in each case regarding the effect of any of the transactions contemplated herein on the business of Buyer, the Company or Enserco Midstream or the reaction thereto of any Person.

ARTICLE 9

CERTAIN GENERAL TERMS AND OTHER AGREEMENTS

9.1    Notices. All notices or other communications required or permitted to be given hereunder will be in writing and will be (a) delivered by hand, (b) sent by United States registered or certified mail, (c) sent by nationally recognized overnight delivery service for next Business Day delivery, or (d) sent by facsimile transmission or electronic mail, followed by United States mail, in each case as follows:

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If to Seller, to:		with copies to:
Black Hills Non-regulated Holdings LLC		Black Hills Corporation
PO Box 1400		PO Box 1400
625 Ninth Street		625 Ninth Street
Rapid City, SD 57709		Rapid City, SD 57709
Attn:	Richard W. Kinzley, Vice President -	Attn:	Steven J. Helmers, Senior Vice
	Strategic Planning and Development		President and General Counsel
Fax:	(605) 721-2599	Fax:	(605) 721-2550
E-mail:	Rich.Kinzley@blackhillscorp.com	E-mail:	Steven.Helmers@blackhillscorp.com
		and
		Faegre Baker Daniels LLP
		1470 Walnut Street, Suite 300
		Boulder, CO 80302
		Attn:	John R. Marcil
		Fax:	(303) 447-7800
		Email:	john.marcil@faegrebd.com

if to Buyer, to:
Twin Eagle Resource Management, LLC
5120 Woodway, Suite 10010
Houston, TX 77056
Attn:	Griffin E. Jones, President and
	Chief Executive Officer
Fax:	(713) 341-7324
E-Mail:	gjones@termna.com

Such notices or communications will be deemed given (A) if so delivered by hand, when so delivered, (B) if so sent by mail, three Business Days after mailing, (C) if so sent by overnight delivery service, one Business Day after delivery to such service, (D) if so sent by facsimile transmission or electronic mail (followed by United States mail), when actually received by the addressee thereof. A Party may change the address to which such notices and other communications are to be given by giving the other Party notice thereof in the foregoing manner.

9.2    Expenses. Except as is expressly stated otherwise herein, each Party will bear its own costs and expenses incurred in connection with the transactions contemplated herein. Seller also will bear all such costs and expenses of the Company, except Buyer will bear any out-of-pocket cost or expense incurred by the Company in connection with any financing arranged by Buyer in connection with the transactions contemplated herein (including that no such cost or expense in connection with such financing will be a liability of the Company in adjusting the Net Working Capital under Article 2).

9.3    Interpretation; Construction. In this Agreement, (a) the table of contents, headings and section captions are for convenience of reference only and will not affect the meaning or interpretation of this Agreement, (b) the words “herein,” “hereunder,” “hereby” and

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similar words refer to this Agreement as a whole (and not to the particular sentence, paragraph or Section where they appear), (c) terms used in the plural include the singular, and vice versa, unless the context clearly requires otherwise, (d) unless expressly stated herein to the contrary, reference to any document means such document as amended or modified and as in effect from time to time in accordance with the terms thereof, (e) unless expressly stated herein to the contrary, reference to any Applicable Law means such Applicable Law as amended, modified, codified, replaced or reenacted, in whole or in part, and as in effect from time to time, including any rule or regulation promulgated thereunder, (f) the words “including,” “include” and variations thereof are deemed to be followed by the words “without limitation,” (g) the word “or” is used in the sense of “and/or”; “any” is used in the sense of “any or all”; and “with respect to” any item includes the concept “of” such item or “under” such item or any similar relationship regarding such item, (h) unless expressly stated herein to the contrary, reference to a document, including this Agreement, will be deemed to also refer to each annex, addendum, exhibit, schedule or other attachment thereto, (i) unless expressly stated herein to the contrary, reference to an Article, Section, Annex, Schedule or Exhibit is to an article, section, schedule or exhibit, respectively, of this Agreement, (j) all dollar amounts are expressed in United States dollars and will be paid in cash (unless expressly stated herein to the contrary) in United States currency, (k) when calculating a period of time, the day that is the initial reference day in calculating such period will be excluded and, if the last day of such period is not a Business Day, such period will end on the next day that is a Business Day, (l) with respect to all dates and time periods in or referred to in this Agreement, time is of the essence, (m) the phrase “the date hereof” means the date of this Agreement, as stated in the first paragraph hereof, and (n) the word “shall” denotes a directive and obligation, and not an option. The Parties participated jointly in the negotiation and drafting of this Agreement and the documents relating hereto, and each Party was represented by legal counsel in connection with this Agreement and such other documents and each Party and each Party's counsel has reviewed and revised (or had ample opportunity to review and revise) this Agreement and such other documents; therefore, if an ambiguity or question of intent or interpretation arises, then this Agreement and such other documents will be construed as if drafted jointly by the Parties and no presumption or burden of proof will arise favoring or disfavoring any Party by virtue of the authorship of any of the terms hereof or thereof.

9.4    Parties in Interest; Third-Party Beneficiaries. There is no Third-Party beneficiary hereof and nothing in this Agreement (whether express or implied) will or is intended to confer any right or remedy under or by reason of this Agreement on any Person (including any Other Indemnified Person or any employee), except each Party and their respective permitted successors and assigns; provided that BNP Paribas and any of its current, former or future Affiliates or representatives shall each be considered a third party beneficiary with respect to Section 6.6, this Section 9.4, Section 9.5(b), Section 9.7(b) and Section 9.10.

9.5    Governing Law. Subject to Section 9.5(b), this Agreement will be construed and enforced in accordance with the substantive laws of the State of Colorado without reference to principles of conflicts of law.

(b)    With respect to Section 6.6, Section 9.4, this Section 9.5(b), Section 9.7(b) and Section 9.10 as they pertain to any right of BNP Paribas, this Agreement will be construed and enforced in accordance with the substantive laws of the State of New York without reference to principles of conflicts of law.

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9.6    Sole and Exclusive Remedies. Notwithstanding any other term herein, the sole and exclusive remedies of the Parties arising out of, relating to or resulting from this Agreement or any Ancillary Document will be strictly limited to those contained in Section 6.4 (with respect to the termination of this Agreement under the circumstances set forth therein) and Article 8.

9.7    Jurisdiction, Venue and Waiver of Jury Trial.

(a)SUBJECT TO SECTION 2.6(c) AND SECTION 9.7(b), EACH PARTY HEREBY IRREVOCABLY SUBMITS TO THE EXCLUSIVE JURISDICTION OF ANY STATE OR FEDERAL COURT SITTING IN DENVER, COLORADO IN ANY PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY ANCILLARY DOCUMENT AND TO the RESPECTIVE COURT TO WHICH AN APPEAL OF THE DECISIONS OF ANY SUCH COURT MAY BE TAKEN, AND EACH PARTY AGREES NOT TO COMMENCE, OR COOPERATE IN OR ENCOURAGE THE COMMENCEMENT OF, ANY SUCH PROCEEDING, EXCEPT IN SUCH A COURT. EACH PARTY HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT IT MAY DO SO, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE THEREIN OF SUCH A PROCEEDING. EACH PARTY HEREBY AGREES THAT A FINAL JUDGMENT IN ANY SUCH PROCEEDING WILL BE CONCLUSIVE AND MAY BE ENFORCED IN ANY JURISDICTION BY SUIT ON THE JUDGMENT OR BY ANY OTHER MANNER PROVIDED BY APPLICABLE LAW. EACH PARTY HEREBY EXPRESSLY WAIVES ANY RIGHT IT MAY HAVE TO A JURY TRIAL IN ANY SUCH PROCEEDING.

(b)EACH PARTY HEREBY IRREVOCABLY SUBMITS TO THE EXCLUSIVE JURISDICTION OF ANY NEW YORK STATE COURT SITTING IN NEW YORK CITY OR THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF NEW YORK IN ANY PROCEEDING BY OR AGAINST BNP PARIBAS ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY ANCILLARY DOCUMENT AND TO THE RESPECTIVE COURT TO WHICH AN APPEAL OF THE DECISIONS OF ANY SUCH COURT MAY BE TAKEN, AND EACH PARTY AGREES NOT TO COMMENCE, OR COOPERATE IN OR ENCOURAGE THE COMMENCEMENT OF, ANY SUCH PROCEEDING, EXCEPT IN SUCH A COURT. EACH PARTY HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT IT MAY DO SO, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE THEREIN OF SUCH A PROCEEDING. EACH PARTY HEREBY AGREES THAT A FINAL JUDGMENT IN ANY SUCH PROCEEDING WILL BE CONCLUSIVE AND MAY BE ENFORCED IN ANY JURISDICTION BY SUIT ON THE JUDGMENT OR BY ANY OTHER MANNER PROVIDED BY APPLICABLE LAW. EACH PARTY HEREBY EXPRESSLY WAIVES ANY RIGHT IT MAY HAVE TO A JURY TRIAL IN ANY SUCH PROCEEDING.

9.8    Entire Agreement; Amendment; Waiver. This Agreement, including the Schedules, constitutes the entire Agreement between the Parties pertaining to the subject matter herein and supersedes any prior representations, warranties, covenants, agreements and understandings of the Parties regarding such subject matter. No supplement, modification or amendment hereof will be binding unless expressed as such and executed in writing by each Party. Except to the extent as may otherwise be stated herein, no waiver of any term hereof will be binding unless expressed as such in a document executed by the Party making such waiver.

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No waiver of any term hereof will be a waiver of any other term hereof, whether or not similar, nor will any such waiver be a continuing waiver beyond its stated terms. Except to the extent as may otherwise be stated herein, failure to enforce strict compliance with any term hereof will not be a waiver of, or estoppel with respect to, any existing or subsequent failure to comply.

9.9    Assignment; Binding Effect. Neither this Agreement nor any right or obligation hereunder will be assigned, delegated or otherwise transferred (by operation of law or otherwise) by either Party without the prior written consent of the other Party (which consent will not be unreasonably withheld). This Agreement will be binding on and inure to the benefit of the respective permitted successors and assigns of the Parties. Any purported assignment, delegation or other transfer not permitted by this Section is void.

9.10    Severability. The terms of this Agreement will, where possible, be interpreted and enforced so as to sustain their legality and enforceability, read as if they cover only the specific situation to which they are being applied and enforced to the fullest extent permissible under Applicable Law. If any term of this Agreement is determined by a court of competent jurisdiction to be invalid, illegal or incapable of being enforced, then all other terms of this Agreement will nevertheless remain in full force and effect, and such term automatically will be amended so that it is valid, legal and enforceable to the maximum extent permitted by Applicable Law, but as close to the Parties' original intent as is permissible.

9.11    Counterparts. This Agreement may be executed in counterparts, each of which will be deemed an original, but all of which together will constitute one and the same instrument. Such counterparts may be executed and delivered by facsimile or other electronic means by any of the Parties, and the receiving Party may rely on the receipt of such document so executed and delivered as if the original had been received.

9.12    Schedules. Certain information is contained in the Schedules solely for informational purposes, may not be required to be disclosed pursuant hereto and will not imply that such information or any other information is required to be disclosed. Inclusion of such information will not establish any level of materiality or similar threshold or be an admission that any of such information is material to the business, assets, Liabilities, financial position, operations or results of operations of any Person or otherwise material regarding such Person. Each matter disclosed in any Schedule, representation or warranty in a manner that makes its relevance to one or more other Schedules, representations or warranties reasonably apparent on the face of such disclosure will be deemed to have been appropriately included in each such other Schedule, representation or warranty (notwithstanding the presence or absence of any reference in or to any Schedule, representation or warranty).

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IN WITNESS WHEREOF, each Party has executed this Stock Purchase Agreement effective as of the date first written above.

BUYER: TWIN EAGLE RESOURCE MANAGEMENT, LLC By: /s/ Griffen E. Jones Name: Griffin E. Jones Its: President and Chief Executive Officer SELLER: Black Hills Non-regulated Holdings, LLC By: /s/ David R. Emery Name: David R. Emery Its: President and Chief Executive Officer

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Annex A

to

Stock Purchase Agreement

CERTAIN DEFINITIONS

“Adjustment Payment Date” is defined in Section 2.6(e).

“Affiliate” means, with respect to any Person, any other Person that directly, or indirectly through one or more intermediaries, controls, is controlled by or is under common control with, such Person. For purposes of this definition, “control,” “controlled by” and “under common control with,” as applied to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that Person, whether through the ownership of voting securities, by Contract or otherwise. No individual is an Affiliate of any other individual.

“Agreement” is defined in the Preamble to this Agreement.

“Ancillary Document” means, with respect to a Person, any document executed and delivered by such Person, in connection with the execution and delivery of this Agreement or Closing, pursuant to the terms of this Agreement (but not including this Agreement).

“Annual Financial Statements” is defined in Section 3.4(a)(1).

“Applicable Law” means any applicable provision of any constitution, treaty, statute, law (including the common law), rule, regulation, ordinance, code or order enacted, adopted, issued or promulgated by any Governmental Authority.

“BH Service Co” is defined in Section 5.9.

“BNPP Reconciliation” is defined in Section 3.19(f).

“Business” means the ongoing business of the Company and Enserco Midstream as currently conducted.

“Business Curtailment Losses” is defined in Section 5.2(e).

“Business Day” means any day, other than a Saturday or Sunday and other than a day that banks in the States of Colorado, South Dakota or Texas are generally authorized or required by Applicable Law to be closed.

“Business Operations Committee” is defined in Section 5.2(a).

“Buyer” is defined in the Preamble to this Agreement.

“Buyer's Statement” is defined in Section 2.6.

“Buyer Termination Fee” is defined in Section 6.6(b).

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“Calgary Lease” is defined in Section 5.11.

“Cap” is defined in Section 8.3(b).

“CERCLA” is defined in Section 3.12(a).

“Claiming Party” is defined in Section 8.5(a).

“Closing” is defined in Section 6.1.

“Closing Date” is defined in Section 6.1.

“Closing Payment” is defined in Section 2.5(e).

“COBRA” means the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended.

“Code” means the Internal Revenue Code of 1986, as amended.

“Commercial Intercompany Accounts” means intercompany accounts or agreements between the Company or Enserco Midstream, on the one hand, and Seller or any Affiliate of Seller (other than the Company and Enserco Midstream), on the other hand, included in the Trade Book.

“Commodity” means the Company's and its Subsidiaries' right, title and interest in and to natural gas, natural gas liquids, coal, crude oil, distillates for crude blending, electricity and energy in any form (including capacity, installed capacity, or any other ancillary service) related to electricity, and Environmental Products.

“Commodity Transactions” means spot, forward, futures, option, park and loan, swap, exchange, sale, purchase and repurchase transactions, tolling transactions, energy conversion agreements, rights relating to the transportation, transmission or storage of any Commodity, ancillary products, foreign currency contracts used to mitigate currency exposure related to commodity purchases and sales denominated in U.S. dollars, and any combination of the foregoing and similar transactions involving Commodities and other commodities the price of which is substantially related to the price or availability of natural gas or electricity (including financial derivative products relating to the foregoing).

“Company” is defined in the Preamble to this Agreement.

“Company Credit Facility” is defined in Section 5.10.

“Company Credit Support” is defined in Section 3.18(a).

“Company Plan” means a Plan of which the Company or any Subsidiary is or was a Plan Sponsor, or to which the Company or any Subsidiary otherwise contributes or has contributed, or in which any employee of the Company or any Subsidiary otherwise participates or has participated.

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“Company Pre-Paid Deposits” is defined in Section 3.18(b).

“Company Software” is defined in Section 3.13(a).

“Confidentiality Agreement” is defined in Section 5.6(a).

“Consent” is defined in Section 3.3(c).

“Contract” means any contract, agreement, purchase order, warranty or guarantee, license, use agreement, lease (whether for real estate, a capital lease, an operating lease or other), instrument or note, in each case that creates a legally binding obligation, and in each case whether oral or written.

“Conversion Costs” is defined in Section 5.15.

“Counterparty” is defined in Section 3.18(a).

“Counterparty Credit Support” is defined in Section 3.18(c).

“Counterparty Pre-Paid Deposits” is defined in Section 3.18(d).

“Credit Policy” means Black Hills Corporation's Corporate Credit Policy and in effect as of April 18, 2011 through the date of this Agreement.

“Credit Support Schedules” is defined in Section 3.18(e).

“Deductible” is defined in Section 8.3(a).

“Defending Party” is defined in Section 8.5(c).

“Defense” means legal defense (which may include related counterclaims) reasonably conducted by reputable legal counsel of good standing selected with the written consent of the Claiming Party (which consent will not be unreasonably withheld).

“Denver Sublease” is defined in Section 5.12.

“Distributable Cash” is defined in Section 2.3(a)(3).

“DOJ” is defined in Section 5.3(a).

“Electronically Recorded Trade Book” means the Company's detailed listing of electronically recorded Commodity Transactions of the Company.

“Encumbrance” means any mortgage, claim, pledge, security interest, charge, lien, option or other right to purchase, restriction or reservation or any other encumbrance whatsoever.

“Enserco Midstream” means Enserco Midstream, LLC, a South Dakota limited liability company.

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“Environment” is defined in Section 3.12(a).

“Environmental Laws” is defined in Section 3.12(a).

“Environmental Liabilities” is defined in Section 3.12(a).

“Environmental Products” means (i) renewable energy certificates, credits, allowances, green tags, or other transferable indicia, however entitled, each indicating generation of one megawatt hour or other specified amount of energy from a renewable energy source, including any energy source that is not fossil carbon-based, non-renewable or radioactive, and including without limitation solar, wind, biomass, anaerobic digester, hydrogen fuel cell, geothermal, landfill gas, or wave, tidal and thermal ocean technologies, (ii) emissions allowances, certificates, credits, benefits, reductions, offsets, or other transferable indicia, however entitled, each representing either one metric ton or other specified amount of carbon dioxide (or carbon dioxide with other greenhouse gas, including without limitation methane, nitrous oxide, hydroflurocarbons, perflurocarbons, and sulphur hexafluoride) emissions or the sequestration, reduction or avoidance of emissions, and (iii) emissions allowances, certificates, credits, benefits, reductions, offsets, or other transferable indicia, however entitled, each representing one ton or other specified amount of sulfur dioxide or nitrogen oxide emissions or the sequestration, reduction or avoidance of emissions.

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

“ERISA Affiliate” means any (if any) corporation, trade or business (whether or not incorporated) that is under common control with the Company pursuant to section 414(b) and (c) of the Code.

“Estimated Purchase Price” is defined in Section 2.3(a)(2).

“Estimated Statement” is defined in Section 2.3(a).

“Excess Purchase Price” is defined in Section 2.6(e).

“FERC” means the Federal Energy Regulatory Commission.

“FERC Order Authorizing the Disposition of Jurisdictional Facilities Under Section 203 of the FPA” means that certain filing made by Seller and Buyer as required pursuant to Section 203 of the FPA to the FERC authorizing the indirect disposition of jurisdictional facilities as described therein and receipt of final approval from the FERC, unless otherwise waived by the Parties in writing.

“Final Purchase Price” is defined in Section 2.6(d).

“Financial Statements” is defined in Section 3.4(b).

“Foreign Tax Credit” is defined in Section 2.8.

“FPA” means the United States Federal Power Act, as amended.

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“FTC” is defined in Section 5.3(a).

“GAAP” means generally accepted United States accounting principles as have been consistently applied by the Company.

“Governmental Authority” means any (a) nation, state, county, city, district or other similar jurisdiction of any nature, (b) federal, state, local or foreign government; (c) governmental or quasi‑governmental authority of any nature (including any governmental agency, branch, commission, bureau, instrumentality, department, official, entity, court or tribunal), (d) multi‑national organization or body, or (e) body or other Person entitled by Applicable Law (or by Contract with the Parties) to exercise any arbitrative, administrative, executive, judicial, legislative, police, regulatory or Taxing authority or power.

“Hazardous Material” is defined in Section 3.12(a).

“Health and Safety Laws” is defined Section 3.12(a).

“HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

“HSR Filing Fees” is defined in Section 5.3(a).

“Incremental Commitment Fee” is defined in Section 2.5(c).

“Indemnifying Party” is defined in Section 8.5(a).

“Initial Claim Notice” is defined in Section 8.5(c).

“Intellectual Property” means any trademark, service mark, trade name, trade dress, goodwill, patent, copyright, design, logo, formula, invention (whether or not patentable or reduced to practice), concept, domain name, website, trade secret, know‑how, confidential information, mask work, product right, software, technology or other intangible asset of any nature, whether in use, under development or design or inactive (including any registration, application or renewal regarding any of the foregoing).

“Interim Balance Sheet” is defined in Section 3.4(b).

“Interim Balance Sheet Date” is defined in Section 3.4(b).

“Interim Financial Statements” is defined in Section 3.4(b).

“Investments” is defined in Section 2.1(d).

“IRS” means the United States' Internal Revenue Service.

“Knowledge” has the following meaning: (a) a natural person will have “Knowledge” of a particular fact or other matter if such individual is actually consciously aware of such fact or matter or should have known after a reasonable inquiry; and (b) a Person, other than a natural person, will have “Knowledge” of a particular fact or other matter if any individual who is

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serving as an officer or director of such Person currently has Knowledge, as stated in clause (a), of such fact or other matter.

“Leased Real Property” is defined in Section 3.11.

“Lenders” is defined in Section 5.10.

“Liability” means any existing liability or obligation (which includes any obligation under any Contract).

“Loss” means any claim, demand, loss, fine, interest, penalty, assessment, cost or expense (including reasonable attorneys' fees or expenses), damage or any other Liability.

“Major Contract” is defined in Section 3.8(a).

“Manually Recorded Commodity Transactions” means the Company's detailed listing of Commodity Transactions of the Company.

“Market Value of Commodity Inventory” is defined in Section 2.2(b).

“Material Adverse Effect” means, with respect to any Person, any event or condition that, individually or in the aggregate, has had a materially adverse effect on the business of such Person and its Subsidiaries, taken as a whole, except that none of the following will be deemed to constitute, and none of the following will be taken into account in determining the occurrence (or possible occurrence) of a Material Adverse Effect: (a) the reaction (including subsequent actions) of any Person not a Party to any transaction contemplated herein resulting from the public announcement of this Agreement, any transaction contemplated herein or otherwise; (b) any event or condition generally affecting any of the industries in which such Person operates, the United States economy as a whole or any foreign economy in any location where, or with respect to which, such Person has material operations, including, without limitation, changes in Commodity prices or volumes or the equity or debt markets; (c) any national or international political or social event or condition, including the engagement by the United States in hostilities, whether or not pursuant to the declaration of a national emergency or war, or the occurrence of any military or terrorist attack upon the United States or any of its territories, possessions or diplomatic or consular offices or upon any military installation, equipment or personnel of the United States; (d) any financial, banking or securities market (including any disruption thereof or any decline in the price of any security or any market index); (e) the payment of any amount due to, or the provision of any other benefit (including employee benefit or payment to employees) to, any officer or employee under any employment contract, non-competition agreement, employee benefit plan, severance arrangement or other arrangement in existence on the date hereof; (f) compliance with any term of, or the taking of any action required by, this Agreement; (g) any existing event or condition with respect to which Buyer has Knowledge as of the date hereof; (h) any change in GAAP or other accounting requirement or principle or any change in Applicable Law or the interpretation thereof or effect resulting therefrom; (i) any action required to be taken under any Major Contract or Applicable Law; or (j) any adverse event or condition regarding the Business that is, in all material respects, cured, taken into account in the Purchase Price or otherwise mitigated at no expense to Buyer before the

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earlier of (1) the Closing Date and (2) the date on which this Agreement is terminated pursuant to Section 6.4.

“Materiality Qualifier” means a qualification to a representation or warranty by use of the word “material,” “materially” or “materiality” or by a reference regarding the occurrence or non-occurrence or possible occurrence or non-occurrence of a Material Adverse Effect or a “materially adverse effect.”

“Membership Interest” is defined in Section 3.2(b).

“Methodologies” is defined in Section 2.2(a).

“Multiemployer Plan” has the meaning given in section 3(37) of ERISA.

“Net Book Value of Non-Current Assets and Liabilities” is defined in Section 2.2(c).

“Net Tax Savings” is defined in Section 2.8.

“Net Working Capital” is defined in Section 2.2(b).

“Net Working Capital Baseline” is defined in Section 2.2(b).

“Non-Competition Agreement” means the Non-Competition and Non-Solicitation Agreement, substantially in the form attached hereto as Exhibit A.

“Non-Defending Party” is defined in Section 8.5(c).

“Order” means any order, writ, injunction, decree, judgment, award or determination, that is exclusive to the applicable Person, of or from, or Contract with, any Governmental Authority or similar binding decision of any arbitration (or similar Proceeding).

“Ordinary Course of Business” means any action (which includes, for this definition, any failure to take action), condition, circumstance or status of or regarding a Person that is (a) consistent with the past practices of such Person and is taken or exists in the ordinary course of the normal operations of such Person or (b) similar in nature and magnitude to actions customarily taken (or not taken) without any specific authorization by the board of directors (or by any Person or group of Persons exercising similar authority) of such Person.

“Organizational Document” means, for any Person (a) the articles or certificate of incorporation, formation or organization (as applicable) and the by-laws or similar governing document of such Person, (b) any limited liability company agreement, partnership agreement, operating agreement, shareholder agreement, voting agreement, voting trust agreement or similar document of or regarding such Person, (c) any other charter or similar document adopted or filed in connection with the incorporation, formation, organization or governance of such Person or (d) any amendment to any of the foregoing.

A-7

“Other Indemnified Person” means, for any Person, such Person's Affiliates and each of such Person's and each of such Affiliate's stockholders, officers, directors, partners, members, governors, managers, employees, agents, representatives and permitted successors and assigns.

“Party” means Seller or Buyer, individually, and “Parties” means Seller and Buyer, collectively.

“Pension Plan” has the meaning given in section 3(2) of ERISA.

“Permit” means any license, permit, registration or similar authorization from a Governmental Authority.

“Permitted Encumbrance” means any (a) Encumbrance listed in the Schedules or noted in any of the Financial Statements, (b) Encumbrance for any Tax, assessment or other governmental charge that is not yet due and payable or that may thereafter be paid without penalty, (c) Encumbrance arising under any original purchase price conditional sales contract or equipment lease, (d) easement, covenant, condition or restriction of record, (e) easement, covenant, condition or restriction not of record as to which no material violation or encroachment exists or, if such violation or encroachment exists, as to which the cure of such violation or encroachment would not materially interfere with the conduct of the Business, (f) zoning or other governmentally established Encumbrance, (g) pledge or deposit to secure any obligation under any workers or unemployment compensation law or to secure any other public or statutory obligation, (h) mechanic's, materialmen's, landlord's, carrier's, supplier's or vendor's lien or similar Encumbrance arising or incurred in the Ordinary Course of Business of the applicable Person that secures any amount that is not overdue for a period of more than 90 days, (i) railroad trackage agreement, utility, slope or drainage easement, right-of-way easement or lease regarding any sign, or (j) other imperfection of title or license or other Encumbrance, if any, that does not impair the use or operation of any asset to which it relates in the conduct of the business of the applicable Person as presently conducted.

“Person” means any individual, partnership, corporation, limited liability company, association, joint stock company, trust, joint venture, unincorporated organization or any other business entity or association or any Government Authority.

“Plan” means an “employee benefit plan” (as such term is defined in section 3(3) of ERISA) and any other employee benefit plan, program, agreement or arrangement of any kind, including any: stock option or ownership plan; stock appreciation rights plan; stock purchase plan; phantom stock plan; executive compensation plan; bonus, incentive compensation, deferred compensation or profit-sharing plan; or arrangement regarding any vacation, holiday, sick leave, fringe benefit, educational assistance, pre-Tax premium or flexible spending account plan or life insurance.

“Plan Sponsor” has the meaning given in section 3(16)(B) of ERISA.

“Post-Closing Statement” is defined in Section 2.6.

“Pre-Closing Tax Period” means (a) any Tax period ending on or before the Closing Date and (b) with respect to any complete Tax period of the Company relating to any Tax that

A-8

includes but does not end on the Closing Date, any portion thereof ending on, and including, the Closing Date.

“Pre-Closing Taxes” is defined in Section 5.8(b).

“Proceeding” means any action, arbitration, audit, claim, demand, grievance, complaint, hearing, inquiry, investigation, litigation, proceeding or suit (whether civil, criminal or administrative), in each case that is commenced, brought, conducted or heard by or before, or otherwise involving, any Governmental Authority or arbitrator.

“Prohibited Transaction” has the meaning given in section 406 of ERISA and 4975 of the Code.

“Prop Trading” is defined in Section 5.2(e).

“Purchase Price” is defined in Section 2.1.

“Purchase Price Cap” is defined in Section 2.1.

“Purchase Price Component” is defined in Section 2.1.

“Purchase Price Mediator” is defined in Section 2.6(b).

“Purchase Price Threshold” is defined in Section 2.5(a).

“Qualified Mediator” is defined in Section 2.6(b).

“RCRA” is defined in Section 3.12(a).

“Real Property” means all real property, buildings, structures or fixtures owned or leased by the Company or Enserco Midstream.

“Real Property Leases” is defined in Section 3.11.

“Reporting Date” is defined in Section 2.2(a).

“Retained Employees” is defined in Section 5.9(a).

“Retention Agreements” is defined in Section 5.9(a).

“Risk Policy” means the Company's Risk Policies and Procedures and in effect as of March 31, 2009 through the date of this Agreement.

“Schedule or Schedules” means the schedule delivered and made a part of this Agreement on the date hereof, subject to Section 9.13.

“Securities Act” means the Securities Act of 1933, as amended.

“Seller” is defined in the Preamble to this Agreement.

A-9

“Seller's Statement” is defined in Section 2.6.

“Seller Termination Fee” is defined in Section 6.5(a).

“Shares” is defined in the Recitals to this Agreement.

“Software Assignment” is defined in Section 5.13.

“Special Representation” is defined in Section 8.3(c).

“Straddle Period” is defined in Section 5.8(b).

“Straddle Tax Returns” is defined in Section 5.8(b).

“Subsidiary” means, with respect to any Person, any other Person of which at least a majority of the securities or other interests, having by their terms ordinary voting power to elect a majority of the board of directors of such other Person (or others performing similar functions with respect to such other Person), is directly or indirectly owned or controlled by such first Person or by any one or more of such first Person's Subsidiaries.

“Tax” means any federal, state, local or foreign income, gross receipts, license, payroll, employment, excise, severance, stamp, occupation, premium, windfall profits, environmental (including taxes under section 59A of the Code), customs duties, capital stock, franchise, profits, withholding, social security (or similar), unemployment, disability, real property, personal property, sales, use, transfer, registration, value added, alternative or add-on minimum, estimated or other tax of any kind whatsoever, including any interest, fine, penalty or similar addition thereto, whether disputed or not.

“Tax Benefit” is defined in Section 8.7(a).

“Tax Claim” means any claim by a Governmental Authority with respect to any Tax that, if successful, might result in an indemnity obligation hereunder.

“Tax Return” means any return, declaration, report, filing, claim for refund or information return or statement relating to any Tax, including any schedule or attachment thereto and including any amendment thereof.

“Termination Date” is defined in Section 6.4(b).

“Third-Party Claim” is defined in Section 8.5(a).

“Threatened” means, with respect to any matter, that a demand, notice or statement has been made or given, in writing, that states that such matter is being or will be asserted, commenced, taken or otherwise pursued (including if conditioned upon certain events occurring or not occurring).

“Title IV Plan” means a Pension Plan that is subject to Title IV of ERISA, other than a Multiemployer Plan.

A-10

“Trade Book” means the Electronically Recorded Trade Book and the Manually Recorded Commodity Transactions.

“Trade Book Value” is defined in Section 2.2(a).

“Trade Book Claim” means Seller's failure to disclose on or prior to Closing or material misrepresentation with respect to (a) a Commodity Transaction in the Trade Book or (b) a Major Contract.

“Transfer Tax” means any sales, use, value-added, business, goods and services, transfer (including any stamp duty or other similar tax chargeable in respect of any instrument transferring property), documentary, conveyance or similar tax or expense or any recording fee, in each case that is imposed as a result of any transaction contemplated herein, together with any penalty, interest and addition to any such item with respect to such item.

“Transition Services Agreement” is defined in Section 5.16.

A-11

EX-31.1

Exhibit 31.1

CERTIFICATION

I, David R. Emery, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Black Hills Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 4, 2012
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman, President and
		Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Anthony S. Cleberg, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Black Hills Corporation;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
	a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 4, 2012
		/S/ ANTHONY S. CLEBERG
		Anthony S. Cleberg
		Executive Vice President and
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David R. Emery, Chairman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 4, 2012
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman, President and
		Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Anthony S. Cleberg, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13 (a) or 15 (d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 4, 2012
		/S/ ANTHONY S. CLEBERG
		Anthony S. Cleberg
		Executive Vice President and
		Chief Financial Officer

EX-95

Exhibit 95

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included below.

Mine Safety and Health Administration Safety Data

Safety is a core value at Black Hills Corporation and at each of its subsidiary operations. We have in place a comprehensive safety program that includes extensive health & safety training for all employees, site inspections, emergency response preparedness, crisis communications training, incident investigation, regulatory compliance training and process auditing, as well as an open dialogue between all levels of employees. The goals of our processes are to eliminate exposure to hazards in the workplace, ensure that we comply with all mine safety regulations, and support regulatory and industry efforts to improve the health and safety of our employees along with the industry as a whole.

Under the recently enacted Dodd-Frank Act, each operator of a coal or other mine is required to include certain mine safety results in its periodic reports filed with the SEC. Our mining operation, consisting of Wyodak Coal Mine, is subject to regulation by the federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). Below we present the following information regarding certain mining safety and health matters for the three month period ended March 31, 2012. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed. The information presented includes:

• Total number of violations of mandatory health and safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;

• Total number of orders issued under section 104(b) of the Mine Act;

• Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health and safety standards under section 104(d) of the Mine Act;

• Total number of imminent danger orders issued under section 107(a) of the Mine Act; and

• Total dollar value of proposed assessments from MSHA under the Mine Act.

The table below sets forth the total number of citations and/or orders issued by MSHA to WRDC under the indicated provisions of the Mine Act, together with the total dollar value of proposed MSHA assessments received during the three months ended March 31, 2012 and legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for WRDC, our only mining complex. All citations were abated within 24 hours of issue.

Mine/ MSHA Identification Number	Mine Act Section 104 S&S Citations issued during three months ended March 31, 2012	Mine Act Section 104(b) Orders (#)	Mine Act Section 104(d) Citations and Orders (#)	Mine Act Section 110(b)(2) Violations (#)	Mine Act Section 107(a) Imminent Danger Orders (#)	Total Dollar Value of Proposed MSHA Assessments (a)		Total Number of Mining Related Fatalities (#)	Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)	Legal Actions Pending as of Last Day of Period (#) (b)	Legal Actions Initiated During Period (#)	Legal Actions Resolved During Period (#)
Wyodak Coal Mine - 4800083	1	—	—	—	—	$	524	—	No	1	—	—

________________________

(a) An assessment has not yet been received for the 2012 S&S citation.

(b) The types of proceedings by class: (1) contests of citations and orders - none; (2) contests of proposed penalties - one; (3) complaints for compensation - none; (4) complaints of discharge, discrimination or interference under Section 105 of the Mine Act - none; (5) applications for temporary relief - none; and (6) appeals of judges' decisions or orders to the FMSHRC - none.

XML

Notes Payable Line of Credit Facility (Details) (USD $)	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011
Line of Credit Facility
Notes Payable	$ 225,000,000	$ 345,000,000	$ 287,000,000
Letters of Credit, Amount Outstanding	41,200,000	43,700,000	51,000,000
Consolidated Net Worth, Actual	1,224,692,000	1,209,336,000	1,113,147,000
Line of Credit, Covenant Requirement, Consolidated Net Worth, Minimum	899,024,000
Recourse Leverage Ratio	56.40%
Line of Credit, Covenant Requirement, Recourse Leverage Ratio	65.00%
Line of Credit [Member]
Line of Credit Facility
Notes Payable	75,000,000	195,000,000	187,000,000
Letters of Credit, Amount Outstanding	41,200,000	43,700,000	51,000,000
Line of Credit Facility, Current Borrowing Capacity	500,000,000
Line of Credit Facility, Expiration Date	2/1/2017
Line of Credit Facility, Maximum Borrowing Capacity	750,000,000
Line of Credit Facility, Commitment Fee Percentage	0.25%
Deferred Financing Costs Remaining on Balance Sheet	2,800,000
Write off of Deferred Debt Issuance Cost	1,500,000
Line of Credit [Member] | Base Rate Option
Line of Credit Facility
Line of Credit Facility, Interest Rate at Period End	0.50%
Line of Credit [Member] | Eurodollar Option
Line of Credit Facility
Line of Credit Facility, Interest Rate at Period End	1.50%
Line of Credit [Member] | Letter of Credit [Member]
Line of Credit Facility
Line of Credit Facility, Interest Rate at Period End	1.50%
Corporate Term Loan due June 2012 [Member] | Loans Payable [Member]
Line of Credit Facility
Notes Payable	150,000,000	150,000,000	0
Letters of Credit, Amount Outstanding	0	0	0
Corporate Term Loan due in 2013 [Member] | Loans Payable [Member]
Line of Credit Facility
Notes Payable	0	0	100,000,000	[1]
Letters of Credit, Amount Outstanding	$ 0	$ 0	$ 0

[1] The short-term loan was renegotiated to a longer term note, maturing in 2013.

XML

Fair Value Measurements Fair Value Measures (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011	Mar. 31, 2011
Derivatives Designated as Hedges
Derivatives, Fair Value
Derivative Asset, Fair Value, Net	$ 9,516		$ 10,658	$ 7,732
Derivative Liability, Fair Value, Net	29,206		30,253	27,247
Derivatives Not Designated as Hedges
Derivatives, Fair Value
Derivative Asset, Fair Value, Net	0		0	0
Derivative Liability, Fair Value, Net	98,761		112,667	50,971
Commodity Derivatives | Derivatives Designated as Hedges | Derivative Assets, Current
Derivatives, Fair Value
Derivative Asset, Fair Value	8,662		8,739	6,757
Derivative Asset, Fair Value, Gross Liability	0		0	0
Commodity Derivatives | Derivatives Designated as Hedges | Derivative Assets, Noncurrent
Derivatives, Fair Value
Derivative Asset, Fair Value	854		1,919	975
Derivative Asset, Fair Value, Gross Liability	0		0	0
Commodity Derivatives | Derivatives Designated as Hedges | Derivative Liabilities, Current
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	2,904		2,559	4,688
Commodity Derivatives | Derivatives Designated as Hedges | Derivative Liabilities, Noncurrent
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	1,084		818	2,835
Commodity Derivatives | Derivatives Not Designated as Hedges | Derivative Assets, Current
Derivatives, Fair Value
Derivative Asset, Fair Value	0		0	0
Derivative Asset, Fair Value, Gross Liability	8,436		9,572	2,665
Commodity Derivatives | Derivatives Not Designated as Hedges | Derivative Assets, Noncurrent
Derivatives, Fair Value
Derivative Asset, Fair Value	0		0	0
Derivative Asset, Fair Value, Gross Liability	(27)		(52)	(209)
Commodity Derivatives | Derivatives Not Designated as Hedges | Derivative Liabilities, Current
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	0		0	0
Commodity Derivatives | Derivatives Not Designated as Hedges | Derivative Liabilities, Noncurrent
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	6,407		7,156	0
Interest Rate Swap [Member] | Derivatives Designated as Hedges | Derivative Liabilities, Current
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	6,777		6,513	6,769
Interest Rate Swap [Member] | Derivatives Designated as Hedges | Derivative Liabilities, Noncurrent
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	18,441		20,363	12,955
Interest Rate Swap [Member] | Derivatives Not Designated as Hedges | Derivative Liabilities, Current
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	66,708		75,295	48,515
Interest Rate Swap [Member] | Derivatives Not Designated as Hedges | Derivative Liabilities, Noncurrent
Derivatives, Fair Value
Derivative Liability, Fair Value, Gross Asset	0		0	0
Derivative Liability, Fair Value	17,237		20,696	0
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Swap [Member]
Derivatives, Fair Value
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Fair Value, Inputs, Level 3 [Member] | Fair Value, Measurements, Recurring [Member] | Utilities Group [Member] | Commodity Derivatives
Derivatives, Fair Value
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 48	[1]	$ 0	$ 0

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

XML

Employee Benefit Plans Employee Benefit Plans (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 1,430	$ 1,355
Interest cost	3,687	3,732
Expected return on plan assets	(4,084)	(4,239)
Prior service cost	22	25
Net loss (gain)	2,408	1,135
Net periodic benefit cost	3,463	2,008
Contributions Made	25,000
Contributions Remaining in Current Fiscal Year	0
Contributions Anticipated in Next Fiscal Year	4,500
Non-pension Postretirement Healthcare Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	402	375
Interest cost	523	542
Expected return on plan assets	(19)	(41)
Prior service cost	(125)	(120)
Net loss (gain)	222	169
Net periodic benefit cost	1,003	925
Contributions Made	1,063
Contributions Remaining in Current Fiscal Year	3,188
Contributions Anticipated in Next Fiscal Year	4,380
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	246	257
Interest cost	331	324
Prior service cost	1	1
Net loss (gain)	202	127
Net periodic benefit cost	780	709
Contributions Made	278
Contributions Remaining in Current Fiscal Year	833
Contributions Anticipated in Next Fiscal Year	$ 1,090

XML

Fair Value Measurements Hedging Activities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash Flow Hedging [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	$ 521	$ (3,785)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	1,187	(861)
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Cash Flow Hedging [Member] | Commodity Derivatives
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	1,283	(4,083)
Cash Flow Hedging [Member] | Commodity Derivatives | Operating Revenue
Derivative Instruments, Gain (Loss)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	3,009	1,031
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Cash Flow Hedging [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)	(762)	298
Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion)	0	0
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Interest Expense
Derivative Instruments, Gain (Loss)
Amount of Reclassfied Gain/(Loss) from AOCI into Income (Effective Portion)	(1,822)	(1,892)
Derivatives Not Designated as Hedge Instruments
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) on Derivatives Recognized in Income	8,840	2,113
Derivatives Not Designated as Hedge Instruments | Interest Rate Swap [Member] | Interest Rate Swap - Unrealized (Loss) Gain
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) on Derivatives Recognized in Income	12,045	5,465
Derivatives Not Designated as Hedge Instruments | Interest Rate Swap [Member] | Interest Expense
Derivative Instruments, Gain (Loss)
Amount of Gain/(Loss) on Derivatives Recognized in Income	$ (3,205)	$ (3,352)

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Common Stock Dividend Reinvestment and Stock Purchase Plan (Details) (DRIP [Member], USD $)	3 Months Ended
	Mar. 31, 2012
DRIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock purchase, Percentage of Recent Average Market Price	100.00%
Stock Issued During Period, Shares, Dividend Reinvestment Plan	27,155
Weighted Average Price of Shares, Dividend Reinvestment Plan	$ 33.20
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	426,109

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

3 Months Ended

Mar. 31, 2012

Fair Value of Financial Instruments [Abstract]

Fair value of financial instruments

The estimated fair values of our financial instruments are as follows (in thousands) as of:

	March 31, 2012				December 31, 2011				March 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	56,132	$	56,132	$	21,628	$	21,628	$	26,418	$	26,418
Restricted cash (a)	$	8,960	$	8,960	$	9,254	$	9,254	$	3,406	$	3,406
Total derivative assets (b)	$	18,758	$	18,758	$	20,554	$	20,554	$	8,996	$	8,996
Total derivative liabilities (b)	$	119,558	$	119,558	$	133,400	$	133,400	$	75,762	$	75,762
Notes payable (a)	$	225,000	$	225,000	$	345,000	$	345,000	$	287,000	$	287,000
Long-term debt, including current maturities (c)	$	1,280,993	$	1,439,724	$	1,282,882	$	1,464,289	$	1,189,084	$	1,260,539

____________

(a) Carrying value approximates fair value due to short-term maturities and therefore is classified in Level 1 in the fair value hierarchy.

(b) See Note 14 for information on classification within the fair value hierarchy.

(c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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Fair Value of Financial Instruments Restricted Cash (Details) (Power Generation [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011
Power Generation [Member]
Restricted Cash - Guaranteed Investment Certificates	$ 4.8	$ 0	$ 0

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Accounts Receivable Accounts Receivable (Tables)

3 Months Ended

Mar. 31, 2012

Receivables [Abstract]

Summary of accounts receivables

Following is a summary of receivables (in thousands) as of:

	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric	$	44,356	$	19,381	$	(585	)	$	63,152
Gas	44,287		18,502		(936		)	61,853
Oil and Gas	15,014		—		(105		)	14,909
Coal Mining	2,578		—		—			2,578
Power Generation	265		—		—			265
Corporate	1,230		—		—			1,230
Total	$	107,730	$	37,883	$	(1,626	)	$	143,987

	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2011	Receivable, Trade		Revenue		Doubtful 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

	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric	$	46,077	$	16,196	$	(728	)	$	61,545
Gas	58,665		21,620		(1,763		)	78,522
Oil and Gas	7,503		—		(161		)	7,342
Coal Mining	982		—		—			982
Power Generation	2,050		—		—			2,050
Corporate	1,083		—		—			1,083
Total	$	116,360	$	37,816	$	(2,652	)	$	151,524

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Segment Reporting Assets (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011		Mar. 31, 2011
Segment Reporting, Asset Reconciling Item
Total Assets	$ 3,807,936		$ 4,127,083		$ 3,729,350
Electric Utilities [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	2,268,524	[1]	2,254,914	[1]	1,868,600	[1]
Gas Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	717,185		746,444		683,927
Oil and Gas [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	430,851		425,970		355,357
Power Generation [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	128,225	[1]	129,121	[1]	336,827	[1]
Coal Mining
Segment Reporting, Asset Reconciling Item
Total Assets	87,139		88,704		94,416
Unallocated Amount to Segment [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	176,012		141,079		94,499	[2]
Discontinued Operation or Asset Disposal [Member]
Segment Reporting, Asset Reconciling Item
Total Assets	$ 0		$ 340,851	[3]	$ 295,724	[3]

[1] The PPA under which the new generating facility was constructed at our Pueblo Airport Generation site by Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing December 31, 2011, assets previously at Power Generation are now accounted for at Colorado Electric under accounting for a capital lease.

[2] Assets of the Corporate segment were restated due to deferred taxes that were not classified as discontinued operations.

[3] See Note 17 for further information relating to discontinued operations.

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Earnings per Share Anti-dilutive shares (Details) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	174	90
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	127	83
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	31	7
Other Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	16	0

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Materials, Supplies and Fuel Materials, Supplies and Fuel (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011
Materials and supplies	$ 44,361	$ 40,838	$ 34,129
Natural gas in storage - gas utilities	11,063	35,025	2,199
Materials, supplies and fuel	63,236	84,064	45,635
Electric Utilities [Member]
Fuel - Electric Utilities	$ 7,812	$ 8,201	$ 9,307

XML

Fair Value Measurements Fair Value Heirarchy Assets and Liabilities (Details) (Fair Value, Measurements, Recurring [Member], USD $) In Thousands, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011	Mar. 31, 2011
Level 1
Derivative Assets [Abstract]
Money Market Funds			$ 6,005	$ 9,050
Assets, Total	55,919		6,005	9,050
Derivative Liabilities [Abstract]
Liabilities, Total	0		0	0
Level 1 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets			0	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0	0
Level 1 | Commodity Derivatives | Regulated Utilities Group
Derivative Assets [Abstract]
Derivative Assets	0		0	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Level 1 | Interest Rate Swap [Member]
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Level 2
Derivative Assets [Abstract]
Money Market Funds			0	0
Assets, Total	1,104		365	5,171
Derivative Liabilities [Abstract]
Liabilities, Total	119,510		132,230	75,762
Level 2 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets			9,885	7,626
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			2,207	7,523
Level 2 | Commodity Derivatives | Regulated Utilities Group
Derivative Assets [Abstract]
Derivative Assets	(8,412)		(9,520)	(2,455)
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	6,359		7,156	0
Level 2 | Interest Rate Swap [Member]
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	109,163		122,867	68,239
Level 3
Derivative Assets [Abstract]
Money Market Funds			0	0
Assets, Total	3		768	106
Derivative Liabilities [Abstract]
Liabilities, Total	48		1,165	0
Level 3 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets			768	106
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			1,165	0
Level 3 | Commodity Derivatives | Regulated Utilities Group
Derivative Assets [Abstract]
Derivative Assets	3	[1]	0	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	48	[1]	0	0
Level 3 | Interest Rate Swap [Member]
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Counterparty Netting
Derivative Assets [Abstract]
Money Market Funds			0	0
Assets, Total	0		5	0
Derivative Liabilities [Abstract]
Liabilities, Total	0		5	0
Counterparty Netting | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets			5	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			5	0
Counterparty Netting | Commodity Derivatives | Regulated Utilities Group
Derivative Assets [Abstract]
Derivative Assets	0		0	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Counterparty Netting | Interest Rate Swap [Member]
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Cash Collateral [Member]
Derivative Assets [Abstract]
Money Market Funds			0	0
Assets, Total	17,651		19,416	3,720
Derivative Liabilities [Abstract]
Liabilities, Total	0		0	0
Cash Collateral [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets			0	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			0	0
Cash Collateral [Member] | Commodity Derivatives | Regulated Utilities Group
Derivative Assets [Abstract]
Derivative Assets	17,651		19,416	3,720
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Cash Collateral [Member] | Interest Rate Swap [Member]
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0		0	0
Estimate of Fair Value, Fair Value Disclosure [Member]
Derivative Assets [Abstract]
Money Market Funds			6,005	9,050
Assets, Total	74,677		26,559	18,047
Derivative Liabilities [Abstract]
Liabilities, Total	119,558		133,400	75,762
Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets			10,658	7,732
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure			3,377	7,523
Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Derivatives | Regulated Utilities Group
Derivative Assets [Abstract]
Derivative Assets	9,242		9,896	1,265
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	6,407		7,156	0
Estimate of Fair Value, Fair Value Disclosure [Member] | Interest Rate Swap [Member]
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	109,163		122,867	68,239
Repurchase Agreements [Member] | Level 1
Derivative Assets [Abstract]
Money Market Funds	43,128
Repurchase Agreements [Member] | Level 2
Derivative Assets [Abstract]
Money Market Funds	0
Repurchase Agreements [Member] | Level 3
Derivative Assets [Abstract]
Money Market Funds	0
Repurchase Agreements [Member] | Counterparty Netting
Derivative Assets [Abstract]
Money Market Funds	0
Repurchase Agreements [Member] | Cash Collateral [Member]
Derivative Assets [Abstract]
Money Market Funds	0
Repurchase Agreements [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Derivative Assets [Abstract]
Money Market Funds	43,128
Interest-bearing Deposits [Member] | Level 1
Derivative Assets [Abstract]
Money Market Funds	12,791
Interest-bearing Deposits [Member] | Level 2
Derivative Assets [Abstract]
Money Market Funds	0
Interest-bearing Deposits [Member] | Level 3
Derivative Assets [Abstract]
Money Market Funds	0
Interest-bearing Deposits [Member] | Counterparty Netting
Derivative Assets [Abstract]
Money Market Funds	0
Interest-bearing Deposits [Member] | Cash Collateral [Member]
Derivative Assets [Abstract]
Money Market Funds	0
Interest-bearing Deposits [Member] | Estimate of Fair Value, Fair Value Disclosure [Member]
Derivative Assets [Abstract]
Money Market Funds	12,791
Crude Oil [Member] | Commodity Option [Member] | Level 1 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Commodity Option [Member] | Level 2 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	404
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1,347
Crude Oil [Member] | Commodity Option [Member] | Level 3 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Commodity Option [Member] | Counterparty Netting | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Commodity Option [Member] | Cash Collateral [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Commodity Option [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	404
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	1,347
Crude Oil [Member] | Basis Swap [Member] | Level 1 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Basis Swap [Member] | Level 2 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	48
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2,641
Crude Oil [Member] | Basis Swap [Member] | Level 3 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Basis Swap [Member] | Counterparty Netting | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Basis Swap [Member] | Cash Collateral [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Crude Oil [Member] | Basis Swap [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	48
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	2,641
Natural Gas [Member] | Commodity Option [Member] | Level 1 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Commodity Option [Member] | Level 2 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Commodity Option [Member] | Level 3 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Commodity Option [Member] | Counterparty Netting | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Commodity Option [Member] | Cash Collateral [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Commodity Option [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Basis Swap [Member] | Level 2 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	9,064
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Basis Swap [Member] | Level 3 | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Natural Gas [Member] | Basis Swap [Member] | Counterparty Netting | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Basis Swap [Member] | Cash Collateral [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	0
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	0
Natural Gas [Member] | Basis Swap [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Commodity Derivatives | Oil and Gas [Member]
Derivative Assets [Abstract]
Derivative Assets	9,064
Derivative Liabilities [Abstract]
Derivative Financial Instruments, Liabilities, Fair Value Disclosure	$ 0

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

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Common Stock Dividend Restrictions Subsidiaries (Details) (USD $)				3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011	Mar. 31, 2012 Cheyenne Light [Member]	Mar. 31, 2012 Utilities Group [Member]	Mar. 31, 2012 Non Regulated Energy Group [Member]	Mar. 31, 2012 Restricted Cash, Carrying Amount	Dec. 31, 2011 Restricted Cash, Carrying Amount	Mar. 31, 2011 Restricted Cash, Carrying Amount
Debt Instrument, Covenant Description				Debt capitalization requirement of 0.60 to 1.00
Amount of Restricted Net Assets for Subsidiaries					$ 81,400,000	$ 100,000,000
Restricted cash	$ 8,960,000	$ 9,254,000	$ 3,406,000				$ 8,960,000	$ 9,254,000	$ 3,406,000

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Materials, Supplies and Fuel

3 Months Ended

Mar. 31, 2012

Inventory, Net [Abstract]

Materials, Supplies and Fuel

MATERIALS, SUPPLIES AND FUEL

The amounts of Materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:

	March 31, 2012		December 31, 2011		March 31, 2011
Materials and supplies	$	44,361	$	40,838	$	34,129
Fuel - Electric Utilities	7,812		8,201		9,307
Natural gas in storage - gas utilities	11,063		35,025		2,199
Total materials, supplies and fuel	$	63,236	$	84,064	$	45,635

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Comprehensive Income (Loss) Comprehensive Income (Loss) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net income (loss)	$ 29,787	$ 26,910
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives designated as cash flow hedges	521	(3,785)
Reclassification adjustments on cash flow hedges settled and included in net income (loss)	(1,187)	861
Other Comprehensive Income (Loss), before Tax	(666)	(2,924)
Taxes on fair value adjustment on derivatives designated as cash flow hedges	55	1,637
Reclassification adjustment on cash flow hedges settled and included in net income (loss), tax	445	(292)
Other Comprehensive Income (Loss), Tax	500	1,345
Fair value adjustment on derivatives designated as cash flow hedges, net of tax	576	(2,148)
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax	(742)	569
Other comprehensive income (loss), net of tax	$ (166)	$ (1,579)

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Employee Benefit Plans Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2012

Defined Benefit Plan Disclosure [Line Items]

Contributions to Healthcare and Supplemental Plans

Contributions to the Defined Benefit Plans will be made in cash and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):

	Contributions Made
	Three Months Ended March 31, 2012		Additional Contributions Anticipated for 2012		Contributions Anticipated for 2013
Defined Benefit Pension Plans	$	25,000	$	—	$	4,500
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,063	$	3,188	$	4,380
Supplemental Non-qualified Defined Benefit Plans	$	278	$	833	$	1,090

Pension Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Components of net periodic benefit cost

The components of net periodic benefit cost for the Pension Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Service cost	$	1,430		$	1,355
Interest cost	3,687			3,732
Expected return on plan assets	(4,084		)	(4,239		)
Prior service cost	22			25
Net loss (gain)	2,408			1,135
Net periodic benefit cost	$	3,463		$	2,008

Non-pension Postretirement Healthcare Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Components of net periodic benefit cost

The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Service cost	$	402		$	375
Interest cost	523			542
Expected return on plan assets	(19		)	(41		)
Prior service cost (benefit)	(125		)	(120		)
Net loss (gain)	222			169
Net periodic benefit cost	$	1,003		$	925

Supplemental Non-qualified Plans, Defined Benefit

Defined Benefit Plan Disclosure [Line Items]

Components of net periodic benefit cost

The components of net periodic benefit cost for the Supplemental Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Service cost	$	246	$	257
Interest cost	331		324
Prior service cost	1		1
Net loss (gain)	202		127
Net periodic benefit cost	$	780	$	709

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Comprehensive Income (Loss) Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2012

Other Comprehensive (Loss) Income [Abstract]

Components of Comprehensive Income (loss)

The following table presents the components of our comprehensive income (loss) (in thousands):

Three Months Ended March 31, 2012	Pre-tax Amount			Tax (Expense) Benefit		Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges	$	521		$	55	$	576
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	(1,187		)	445		(742		)
Other comprehensive income (loss)	$	(666	)	$	500	$	(166	)

Three Months Ended March 31, 2011	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges	$	(3,785	)	$	1,637		$	(2,148	)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	861			(292		)	569
Other comprehensive income (loss)	$	(2,924	)	$	1,345		$	(1,579	)

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

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

	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
Balance as of December 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	(166		)	—			(166		)
Ending Balance March 31, 2012	$	(13,968	)	$	(19,076	)	$	(33,044	)
	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
Balance as of December 31, 2010	$	(12,439	)	$	(11,142	)	$	(23,581	)
Other comprehensive income (loss)	(1,579		)	—			(1,579		)
Ending Balance March 31, 2011	$	(14,018	)	$	(11,142	)	$	(25,160	)

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Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011		Mar. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 56,132		$ 21,628		$ 26,418
Restricted cash	8,960		9,254		3,406
Notes Payable	225,000		345,000		287,000
Restricted Cash, Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	56,132		21,628		26,418
Restricted cash	8,960		9,254		3,406
Derivative financial instruments - assets	18,758	[1]	20,554	[1]	8,996	[1]
Derivative financial instruments - liabilities	119,558	[1]	133,400	[1]	75,762	[1]
Notes Payable	225,000		345,000		287,000
Long-term debt, including current maturities	1,280,993		1,282,882		1,189,084
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, fair value	56,132	[2]	21,628	[2]	26,418	[2]
Restricted cash, fair value	8,960	[2]	9,254	[2]	3,406	[2]
Derivative financial instruments - assets	18,758	[1]	20,554	[1]	8,996	[1]
Derivative financial instruments - liabilities	119,558	[1]	133,400	[1]	75,762	[1]
Notes payable, fair value	225,000		345,000		287,000
Long-term debt, including current maturities, fair value	$ 1,439,724	[3]	$ 1,464,289	[3]	$ 1,260,539	[3]

[1] See Note 14 for information on classification within the fair value hierarchy.

[2] Carrying value approximates fair value due to short-term maturities and therefore is classified in Level 1 in the fair value hierarchy.

[3] Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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Comprehensive Income (Loss) Accumulated Other Comprehensive Loss (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive income (loss) total, period start	$ (32,878)	$ (23,581)
Other comprehensive income (loss), net of tax	(166)	(1,579)
Accumulated other comprehensive income (loss) total, period end	(33,044)	(25,160)
Cash Flow Hedging [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive income (loss) total, period start	(13,802)	(12,439)
Other comprehensive income (loss), net of tax	(166)	(1,579)
Accumulated other comprehensive income (loss) total, period end	(13,968)	(14,018)
Accumulated Defined Benefit Plans Adjustment [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive income (loss) total, period start	(19,076)	(11,142)
Other comprehensive income (loss), net of tax	0	0
Accumulated other comprehensive income (loss) total, period end	$ (19,076)	$ (11,142)

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Segment Reporting Segment Reporting (Tables)

3 Months Ended

Mar. 31, 2012

Segment Reporting Information, Additional Information [Abstract]

Segment information included in Condensed Consolidated Statements of Income

Segment information included in the accompanying Condensed Consolidated Statements of Income and Comprehensive Income and Condensed Consolidated Balance Sheets was as follows (in thousands):

Three Months Ended March 31, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	156,133	$	3,036		$	8,746
Gas	180,522		—			15,207
Non-regulated Energy:
Oil and Gas	21,645		—			13
Power Generation	1,178		18,449			6,914
Coal Mining	6,373		8,616			1,000
Corporate (a)(b)	—		—			3,391
Intercompany eliminations	—		(30,101		)	—
Total	$	365,851	$	—		$	35,271

Three Months Ended March 31, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	144,430	$	3,839		$	10,249
Gas	230,266		—			19,263
Non-regulated Energy:
Oil and Gas	17,906		—			(715		)
Power Generation	687		6,933			1,186
Coal Mining	7,614		7,881			(1,298		)
Corporate (a)(b)	—		—			451
Intercompany eliminations	—		(18,721		)	(68		)
Total	$	400,903	$	(68	)	$	29,068

____________

(a) Income (loss) from continuing operations includes $7.8 million and $3.6 million net after-tax mark-to-market gain on interest rate swaps for the three months ended March 31, 2012 and March 31, 2011, respectively.

(b) Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not classified as discontinued operations but were included in the Corporate segment. See Note 17 for further information.

Segment information included in Condensed Consolidated Balance Sheets

Total Assets (net of inter-company eliminations)	March 31, 2012		December 31, 2011		March 31, 2011
Utilities:
Electric (a)	$	2,268,524	$	2,254,914	$	1,868,600
Gas	717,185		746,444		683,927
Non-regulated Energy:
Oil and Gas	430,851		425,970		355,357
Power Generation (a)	128,225		129,121		336,827
Coal Mining	87,139		88,704		94,416
Corporate (b)	176,012		141,079		94,499
Discontinued operations (c)	—		340,851		295,724
Total assets	$	3,807,936	$	4,127,083	$	3,729,350

____________

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

(b) Assets of the Corporate segment were restated due to deferred taxes that were not classified as discontinued operations.

(c) See Note 17 for further information relating to discontinued operations.

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Risk Management Activities Risk Management (Tables)

3 Months Ended

Mar. 31, 2012

Financing Activities

Derivative [Line Items]

Interest rate swaps and related balances

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

	March 31, 2012						December 31, 2011						March 31, 2011
	Designated  Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.75			1.75			5.00			2.00			5.75			0.75
Derivative liabilities, current	$	6,777		$	66,708		$	6,513		$	75,295		$	6,769		$	48,515
Derivative liabilities, non-current	$	18,441		$	17,237		$	20,363		$	20,696		$	12,955		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(25,218	)	$	—		$	(26,876	)	$	—		$	(19,724	)	$	—
Pre-tax gain (loss)	$	—		$	12,045		$	—		$	(42,010	)	$	—		$	5,465
Cash collateral receivable (payable)	$	—		$	—		$	—		$	—		$	—		$	—

_____________

* Maximum terms in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. If extended, de-designated swaps totaling $100 million terminate in 7 years and de-designated swaps totaling $150 million terminate in 17 years.

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

Derivative [Line Items]

Cash flow heding instruments included in financial statements

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

	March 31, 2012					December 31, 2011					March 31, 2011
	Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps
Notional (a)	522,000			5,001,750		528,000			5,406,250		487,500			5,974,800
Maximum terms in years (b)	1.25			1.50		1.25			1.75		1.00			0.25
Derivative assets, current	$	406		$	8,256	$	729		$	8,010	$	108		$	6,649
Derivative assets, non-current	$	46		$	808	$	771		$	1,148	$	—		$	975
Derivative liabilities, current	$	2,904		$	—	$	2,559		$	—	$	4,688		$	—
Derivative liabilities, non-current	$	1,084		$	—	$	811		$	7	$	2,678		$	157
Pre-tax accumulated other comprehensive income (loss)	$	(3,566	)	$	9,064	$	(1,928	)	$	9,152	$	(7,613	)	$	7,467
Revenue (c)	$	30		$	—	$	58		$	—	$	355		$	—

____________

(a) Crude oil in Bbls, gas in MMBtus

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

(c) Represents the amortization of put premiums

Utilities Group [Member] | Regulated Utilities - Gas Hedges

Derivative [Line Items]

Cash flow heding instruments included in financial statements

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

	March 31, 2012		December 31, 2011		March 31, 2011
Derivative assets, current	$	9,215	$	9,844	$	1,056
Derivative assets, non-current	$	27	$	52	$	209
Derivative liabilities, non-current	$	6,407	$	7,156	$	—
Net unrealized gain (loss) included in Regulatory assets or liabilities	$	15,223	$	17,556	$	2,455
Included in Derivatives:
Cash collateral receivable (payable)	$	17,651	$	19,416	$	3,720
Option premiums and commissions	$	407	$	880	$	—

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 at our Utilities were as follows as of:

	March 31, 2012		December 31, 2011		March 31, 2011
	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)
Natural gas futures purchased	11,550,000	81	14,310,000	84	4,680,000	24
Natural gas options purchased	670,000	12	1,720,000	3	—	—
Natural gas basis swaps purchased	7,640,000	81	7,160,000	60	—	—

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Supplemental Disclosure of Cash Flow Information

3 Months Ended

Mar. 31, 2012

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

	Three Months Ended
	March 31, 2012			March 31, 2011
	(in thousands)
Non-cash investing activities from continuing operations—
Property, plant and equipment acquired with accrued liabilities	$	31,644		$	32,220
Capitalized assets associated with retirement obligations	$	2,826		$	—
Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(16,799	)	$	(11,572	)
Income taxes, net	$	(1,838	)	$	48

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Fair Value Measurements Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

Derivative Instruments, Gain (Loss)

Fair value assets and liabilities measured on recurring basis

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 March 31, 2012
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	404		$	—	$	—	$	—	$	404
Basis Swaps -- Oil	—		48			—		—		—		48
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		9,064			—		—		—		9,064
Commodity derivatives — Utilities	—		(8,412		)	3		—		17,651		9,242
Repurchase agreement (a)	43,128		—			—		—		—		43,128
Money market funds and term deposits (a)	12,791		—			—		—		—		12,791
Total	$	55,919	$	1,104		$	3	$	—	$	17,651	$	74,677
Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	1,347		$	—	$	—	$	—	$	1,347
Basis Swaps -- Oil	—		2,641			—		—		—		2,641
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		—			—		—		—		—
Commodity derivatives — Utilities	—		6,359			48		—		—		6,407
Interest rate swaps	—		109,163			—		—		—		109,163
Total	$	—	$	119,510		$	48	$	—	$	—	$	119,558

______________

(a) Level 1 assets and liabilities and described at Note 15.

	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 funds	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 March 31, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas	$	—	$	7,626		$	106	$	—	$	—	$	7,732
Commodity derivatives — Utilities	—		(2,455		)	—		—		3,720		1,265
Money market funds	9,050		—			—		—		—		9,050
Total	$	9,050	$	5,171		$	106	$	—	$	3,720	$	18,047
Liabilities:
Commodity derivatives — Oil and Gas	$	—	$	7,523		$	—	$	—	$	—	$	7,523
Commodity derivatives — Utilities	—		—			—		—		—		—
Interest rate swaps	—		68,239			—		—		—		68,239
Total	$	—	$	75,762		$	—	$	—	$	—	$	75,762

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis, Valuation Techniques [Table Text Block]

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

	Fair Value at		Valuation	Unobservable	Range (Weighted
	March 31, 2012		Technique	Input	Average)
ASSETS
Commodity derivatives - Utilities(a)	$	3	Independent price quotes	Long-term natural gas prices	Not applicable
LIABILITIES
Commodity derivatives - Utilities(a)	$	48	Independent price quotes	Long-term natural gas prices	Not applicable

______________________

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

Changes in level 3 recurring fair value

The following tables present the changes in Level 3 recurring fair value for the three months ended March 31, 2012 and 2011, respectively (in thousands):

	Three Months Ended March 31, 2012
Assets:	Commodity Derivatives -- Oil			Commodity Derivatives -- Gas		Commodity Derivatives -- Utilities		Total
Balances as of beginning of period	$	768		$	—	$	—	$	768
Total gain (loss) included in revenue	—			—		—		—
Total gain (loss) included in AOCI	(360		)	—		—		(360		)
Purchases	—			—		3		3
Issuances	—			—		—		—
Settlements	(4		)	—		—		(4		)
Transfers into level 3 (a)	—			—		—		—
Transfers out of level 3(b)(c)	(404		)	—		—		(404		)
Balances at end of period	$	—		$	—	$	3	$	3
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	3	$	3

	Three Months Ended March 31, 2012
Liabilities:	Commodity Derivatives -- Oil			Commodity Derivatives -- Gas		Commodity Derivatives -- Utilities		Total
Balances as of beginning of period	$	1,165		$	—	$	—	$	1,165
Total gain (loss) included in revenue	—			—		—		—
Total gain (loss) included in AOCI	182			—		—		182
Purchases	—			—		48		48
Issuances	—			—		—		—
Settlements	—			—		—		—
Transfers into level 3 (a)	—			—		—		—
Transfers out of level 3(b)(c)	(1,347		)	—		—		(1,347		)
Balances at end of period	$	—		$	—	$	48	$	48
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	48	$	48

	Three Months Ended March 31, 2011
	Commodity  Derivatives
Balance as of beginning of period	$	266
Unrealized losses	(160		)
Unrealized gains	—
Settlements	—
Transfers into level 3 (a)	—
Transfers out of level 3(b)	—
Balance at end of period	$	106
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	(159	)

____________

(a) Transfers into Level 3 would occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs.

(b) Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

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

Fair Value Hedging

Derivative Instruments, Gain (Loss)

Fair value and balance sheet classification of derivative instruments

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

As of March 31, 2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,662	$	—
Commodity derivatives	Derivative assets — non-current	854		—
Commodity derivatives	Derivative liabilities — current	—		2,904
Commodity derivatives	Derivative liabilities — non-current	—		1,084
Interest rate swaps	Derivative liabilities — current	—		6,777
Interest rate swaps	Derivative liabilities — non-current	—		18,441
Total derivatives designated as hedges		$	9,516	$	29,206
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	8,436
Commodity derivatives	Derivative assets — non-current	—		(27		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		6,407
Interest rate swaps	Derivative liabilities — current	—		66,708
Interest rate swaps	Derivative liabilities — non-current	—		17,237
Total derivatives not designated as hedges		$	—	$	98,761

As of December 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,739	$	—
Commodity derivatives	Derivative assets — non-current	1,919		—
Commodity derivatives	Derivative liabilities — current	—		2,559
Commodity derivatives	Derivative liabilities — non-current	—		818
Interest rate swaps	Derivative liabilities — current	—		6,513
Interest rate swaps	Derivative liabilities — non-current	—		20,363
Total derivatives designated as hedges		$	10,658	$	30,253
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	9,572
Commodity derivatives	Derivative assets — non-current	—		(52		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		7,156
Interest rate swaps	Derivative liabilities — current	—		75,295
Interest rate swaps	Derivative liabilities — non-current	—		20,696
Total derivatives not designated as hedges		$	—	$	112,667

As of March 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	6,757	$	—
Commodity derivatives	Derivative assets — non-current	975		—
Commodity derivatives	Derivative liabilities — current	—		4,688
Commodity derivatives	Derivative liabilities — non-current	—		2,835
Interest rate swaps	Derivative liabilities — current	—		6,769
Interest rate swaps	Derivative liabilities — non-current	—		12,955
Total derivatives designated as hedges		$	7,732	$	27,247
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	2,665
Commodity derivatives	Derivative assets — non-current	—		(209		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		—
Interest rate swaps	Derivative liabilities — current	—		48,515
Interest rate swaps	Derivative liabilities — non-current	—		—
Total derivatives not designated as hedges		$	—	$	50,971

Cash Flow Hedging [Member]

Derivative Instruments, Gain (Loss)

Cash flow hedges included in Accumulated Other Comprehensive Income

The impact of cash flow hedges on our Condensed Consolidated Statements of Income and Comprehensive Income was as follows (in thousands):

Three Months Ended March 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) 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	$	(762	)	Interest expense	$	(1,822	)		$	—
Commodity derivatives	1,283			Revenue	3,009				—
Total	$	521			$	1,187			$	—

Three Months Ended March 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 Reclassified Gain/(Loss) 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	$	298		Interest expense	$	(1,892	)		$	—
Commodity derivatives	(4,083		)	Revenue	1,031				—
Total	$	(3,785	)		$	(861	)		$	—

Derivatives Not Designated as Hedge Instruments

Derivative Instruments, Gain (Loss)

Gains and losses recognized in income

The impact of derivative instruments that have not been designated as hedging instruments on our Condensed Consolidated Statements of Income and Comprehensive Income was as follows (in thousands):

		Three Months Ended
		March 31, 2012
Derivatives Not Designated  as Hedging Instruments	Location of Gain/(Loss)  on Derivatives  Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swaps, net	$	12,045
Interest rate swaps - realized	Interest expense	(3,205		)
		$	8,840

		Three Months Ended
		March 31, 2011
Derivatives Not Designated  as Hedging Instruments	Location 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 swaps, net	$	5,465
Interest rate swaps - realized	Interest expense	(3,352		)
		$	2,113

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Long-Term Debt Long-term Debt (Details) (Electric Utilities [Member], Polution Control Revenue Bonds Due 2014 [Member], USD $) In Millions, unless otherwise specified	0 Months Ended	3 Months Ended
	May 15, 2012	Mar. 31, 2012
Electric Utilities [Member] | Polution Control Revenue Bonds Due 2014 [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date		Oct. 01, 2014
Early Repayment of Subordinated Debt	$ 6.5
Debt Instrument, Early Repayment Date	May 15, 2012

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Fair Value Measurements Changes in Level 3 Recurring Fair Value (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended		3 Months Ended				3 Months Ended		12 Months Ended		3 Months Ended	12 Months Ended		3 Months Ended
	Dec. 31, 2011		Mar. 31, 2012 Commodity Derivatives	Mar. 31, 2011 Commodity Derivatives		Jun. 30, 2010 Commodity Derivatives	Mar. 31, 2012 Oil and Gas [Member] Crude Oil [Member] Commodity Derivatives		Dec. 31, 2011 Oil and Gas [Member] Natural Gas [Member]		Mar. 31, 2012 Oil and Gas [Member] Natural Gas [Member] Commodity Derivatives	Dec. 31, 2011 Utilities Group [Member] Natural Gas [Member]		Mar. 31, 2012 Utilities Group [Member] Natural Gas [Member] Commodity Derivatives
Unobservable Inputs Reconciliation, Asset, Purchases, Sales, Issuances, Settlements [Abstract]
Asset, balance at beginning of period							$ 768
Total Gain (Loss) Included in Earnings, assets	0						0		0			0
Gain (Loss) Included in AOCI, assets			(360)				(360)				0			0
Purchases, assets	3						0		0			3
Issues, assets	0						0		0			0
Settlements, assets	(4)						(4)		0			0
Transfers Into Level 3, assets	0	[1]					0	[1]	0	[1]		0	[1]
Transfers out of Level 3, assets	(404)	[2],[3]					(404)	[2],[3]	0	[2],[3]		0	[2],[3]
Asset, balance at beginning of period	768		3				0		0		0	0		3
Changes in unrealized gains relating to instruments still held as of quarter-end			3				0				0			3
Unobservable Inputs Reconciliation, Liability, Purchases, Sales, Issuances, Settlements [Abstract]
Liabilities, Balance as of beginning of period							1,165
Total gain (loss) included in revenue, liabilities	0						0		0			0
Total gain (loss) included in AOCI, liabilities			182				182				0			0
Purchases, liabilities	48						0		0			48
Issuances, liabilities	0						0		0			0
Settlements, liabilities	0						0		0			0
Transfers into level 3, liabilities	0	[1]					0	[1]	0	[1]		0	[1]
Transfers out of level 3, liabilities	(1,347)	[2],[3]					(1,347)	[2],[3]	0	[2],[3]		0	[2],[3]
Liabilities, Balance as of beginning of period	1,165		48				0		0		0	0		48
Fair Value, Liabilities Measured on Recurring Basis, Change in Unrealized Gain (Loss) Included in Other Income			48				0				0			48
Unobservable Input Reconciliation, net assets and liabilities [Abstract]
Unobservable Inputs Reconciliation Net Value, balance at beginning of period						266
Net unrealized losess				(160)
Net unrealized gains				0
Net, Purchases, Sales, Issuances, Settlements				0
Net Transfers Into Level 3				0	[1]
Net, Transfers out of Level 3				0	[2]
Unobservable Inputs Reconciliation Net Value, balance at end of period				106		266
Change in Unrealized Gain (Loss) Included in Earnings				$ (159)

[1] Transfers into Level 3 would occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs.

[2] Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

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

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Condensed Consolidated Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Revenue:
Utilities	$ 336,655	$ 374,696
Non-regulated energy	29,196	26,139
Total revenue	365,851	400,835
Utilities -
Fuel, purchased power and cost of gas sold	157,183	210,511
Operations and maintenance	64,760	67,409
Non-regulated energy operations and maintenance	22,595	23,474
Depreciation, depletion and amortization	38,559	31,910
Taxes - property, production and severance	11,510	8,198
Other operating expenses	1,196	966
Total operating expenses	295,803	342,468
Operating income	70,048	58,367
Interest charges -
Interest expense incurred (including amortizationof debt issuance costs, premiums and discounts, realized settlements on interest rate swaps)	(29,914)	(29,203)
Allowance for funds used during construction - borrowed	518	3,363
Capitalized interest	161	2,434
Unrealized (loss) gain on interest rate swaps, net	12,045	5,465
Interest income	437	548
Allowance for funds used during construction - equity	277	295
Other income, net	1,472	731
Total other income (expense)	(15,004)	(16,367)
Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes	55,044	42,000
Equity in earnings (loss) of unconsolidated subsidiaries	(56)	993
Income tax benefit (expense)	(19,717)	(13,925)
Income (loss) from continuing operations	35,271	29,068
Income (Loss) from discontinued operations, net of tax	(5,484)	(2,158)
Net income (loss)	29,787	26,910
Other comprehensive income (loss), net of tax	(166)	(1,579)
Comprehensive Income (Loss)	$ 29,621	$ 25,331
Income (loss) per share, Basic-
Income (loss) from continuing operation, per share	$ 0.81	$ 0.74
Income (loss) from discontinued operations, per share	$ (0.13)	$ (0.05)
Total income (loss) per share - Basic	$ 0.68	$ 0.69
Income (loss) per share, Diluted-
Income (loss) from continuing operations, per share	$ 0.80	$ 0.73
Income (loss) from discontinued operations, per share	$ (0.12)	$ (0.05)
Total income (loss) per share - Diluted	$ 0.68	$ 0.68
Weighted average common shares outstanding:
Basic	43,731	39,059
Diluted	43,969	39,761
Dividends paid per share of common stock	$ 0.37	$ 0.365

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Common Stock Equity Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012 years	Mar. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 12.2
Allocated Share-based Compensation Expense	1.8	2.3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2.3
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	66,690
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period	2012-01-01P3Y
Performance Share Award, Percentage of Target, Minimum	0.00%
Performance Share Award, Percentage of Target, Maximum	200.00%
Performance Share Award Payout, Cash Percentage	50.00%
Performance Share Award Payout, Shares of Common Stock Percentage	50.00%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 32.26
Short-term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	3,690
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	0.1
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	139,550
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	4.9
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	41,206
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	$ 28.28
Proceeds from Stock Options Exercised	$ 1.2
Cheyenne Light [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Debt Instrument, Covenant Description	Debt capitalization requirement of 0.60 to 1.00

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Management's Statement

3 Months Ended

Mar. 31, 2012

Management's Statement [Abstract]

Management's Statement

MANAGEMENT'S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation together with our subsidiaries (the "Company," "us," "we," or "our"), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2011 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2012, December 31, 2011 and March 31, 2011 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2012 and March 31, 2011, and our financial condition as of March 31, 2012, December 31, 2011, and March 31, 2011 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On February 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. For further information see Note 17.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. Specifically, the Company has reclassified deferred financing cost amortization into a separate line on the Condensed Consolidated Statements of Cash Flow. This reclassification had no effect on total assets, net income, cash flows or earnings per share.

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Management's Statement Management's Statement (Details) (Energy Marketing [Member])	0 Months Ended
	Feb. 29, 2012
Energy Marketing [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Significant Acquisitions and Disposals, Date of Transaction for Acquisition or Disposal	Feb. 29, 2012

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Discontinued Operations

3 Months Ended

Mar. 31, 2012

Discontinued Operations [Abstract]

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

DISCONTINUED OPERATIONS

On February 29, 2012, we sold the outstanding stock of our Energy Marketing segment, Enserco Energy Inc. The transaction was completed through a stock purchase agreement and certain other ancillary agreements. Net cash proceeds were approximately $166.3 million, subject to final post-closing adjustments that are expected to be settled during the second quarter of 2012. The proceeds represent $108.8 million received from Twin Eagle and $57.5 million cash retained from Enserco prior to closing. We recorded an after-tax loss on sale of $1.6 million, including transaction related costs net of tax of $2.2 million.

The accompanying Condensed Consolidated Financial Statements have been classified to reflect Enserco as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification.

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

	For the Three Months Ended
	March 31, 2012			March 31, 2011
Revenue	$	(604	)	$	2,465
Pre-tax income (loss) from discontinued operations	(5,836		)	(3,174		)
Pre-tax gain (loss) on sale	(2,453		)	—
Income tax (expense) benefit	2,805			1,016
Income (loss) from discontinued operations, net of tax	$	(5,484	)	$	(2,158	)

Indirect corporate costs and inter-segment interest expenses totaling $1.6 million and $0.5 million for the three months ended March 31, 2012 and March 31, 2011, respectively, are reclassified from the Energy Marketing segment to the Corporate segment in continuing operations on the accompanying Condensed Consolidated Statements of Income and Comprehensive Income.

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

	December 31, 2011			March 31, 2011
Other current assets	$	280,221		$	243,473
Derivative assets, current and non-current	52,859			45,432
Property, plant and equipment, net	5,828			4,750
Goodwill	1,435			1,435
Other non-current assets	508			631
Other current liabilities	(132,951		)	(129,706		)
Derivative liabilities, current and non-current	(26,084		)	(30,932		)
Other non-current liabilities	(14,894		)	(2,652		)
Net assets	$	166,922		$	132,431

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Supplemental Disclosure of Cash Flow Information Supplemental Disclosures of Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Non-cash investing activities
Property, plant and equipment acquired with accrued liabilities	$ 31,644	$ 32,220
Non-cash Revision to Capitalized Asset Retirement Costs	2,826	0
Cash (paid) refunded during the period for
Interest (net of amounts capitalized)	(16,799)	(11,572)
Income taxes, net	$ (1,838)	$ 48

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Materials, Supplies and Fuel Materials, Supplies and Fuel (Tables)

3 Months Ended

Mar. 31, 2012

Inventory, Net [Abstract]

Schedule of Inventory, current

The amounts of Materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:

	March 31, 2012		December 31, 2011		March 31, 2011
Materials and supplies	$	44,361	$	40,838	$	34,129
Fuel - Electric Utilities	7,812		8,201		9,307
Natural gas in storage - gas utilities	11,063		35,025		2,199
Total materials, supplies and fuel	$	63,236	$	84,064	$	45,635

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Recently Adopted and Recently Issued Accounting Standards and Legislation

3 Months Ended

Mar. 31, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Adopted and Recently Issued Accounting Standards and Legislation

RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards and Legislation

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending ASC 220, Comprehensive Income, 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 2011-05 requires retrospective application, and it is effective for the fiscal years, and interim periods within those years beginning after December 15, 2011. In December 2011, FASB issued ASU 2011-12 which 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.

At December 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements and provided additional details in the notes to the financial statements, but did not have any other impact on our financial statements.

Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04

FASB issued an accounting standards update amending ASC 820, Fair Value Measurements and Disclosures, to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity's use of a non-financial asset that is different from the asset's highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. Additional disclosures are included in Notes 14 and 15.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing of 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 testing performed for fiscal years beginning after December 15, 2011. We perform our annual impairment testing in November of each year. The adoption of this standard will not have an impact on our financial statements.

Recently Issued Accounting Standards and Legislation

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company's netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning January 1, 2013. Management does not believe that the adoption of this standard will have an impact on the Company’s financial position, results of operations or cash flows.

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011
Current assets:
Cash and cash equivalents	$ 56,132	$ 21,628	$ 26,418
Restricted cash	8,960	9,254	3,406
Accounts receivable, net	143,987	156,774	151,524
Materials, supplies and fuel	63,236	84,064	45,635
Derivative assets, current	17,877	18,583	7,812
Income tax receivable, net	10,399	9,344	20,173
Deferred income tax assets, current	23,710	37,202	20,491
Regulatory assets, current	56,282	59,955	36,834
Other current assets	26,546	21,266	17,486
Assets of Discontinued Operations	0	340,851	295,724
Total current assets	407,129	758,921	625,503
Investments	16,451	17,261	17,088
Property, plant and equipment	3,800,011	3,724,016	3,454,179
Less accumulated depreciation and depletion	(980,944)	(934,441)	(886,401)
Total property, plant and equipment, net	2,819,067	2,789,575	2,567,778
Other assets:
Goodwill	353,396	353,396	353,396
Intangible assets, net	3,787	3,843	4,011
Derivative assets, non-current	881	1,971	1,184
Regulatory assets, non-current	186,093	182,175	140,735
Other assets, non-current	21,132	19,941	19,655
Total other assets	565,289	561,326	518,981
TOTAL ASSETS	3,807,936	4,127,083	3,729,350
Current liabilities:
Accounts payable	59,793	104,748	104,742
Accrued liabilities	151,130	151,319	127,235
Derivative liabilities, current	76,389	84,367	59,972
Regulatory liabilities, current	35,414	16,231	15,004
Notes Payable	225,000	345,000	287,000
Current maturities of long-term debt	8,977	2,473	4,254
Liabilities of Disposal Group, Including Discontinued Operation	0	173,929	163,293
Total current liabilities	556,703	878,067	761,500
Long-term debt, net of current maturities	1,272,016	1,280,409	1,184,830
Deferred credits and other liabilities:
Deferred income tax liabilities, non-current	317,369	300,988	301,097
Derivative liabilities, non-current	43,169	49,033	15,790
Regulatory liabilities, non-current	112,516	108,217	90,923
Benefit plan liabilities	157,623	177,480	128,170
Other deferred credits and other liabilities	123,848	123,553	133,893
Total deferred credits and other liabilities	754,525	759,271	669,873
Common stockholders' —
Common stock $1 par value; 100,000,000 shares authorized; issued 44,151,428; 43,957,502 and 39,434,304 shares, respectively	44,151	43,958	39,434
Additional paid-in capital	725,512	722,623	601,021
Retained earnings	490,114	476,603	498,614
Treasury stock at cost – 65,015; 32,766 and 26,075 share, respectively	(2,041)	(970)	(762)
Accumulated other comprehensive Income (loss)	(33,044)	(32,878)	(25,160)
Total stockholders' equity	1,224,692	1,209,336	1,113,147
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$ 3,807,936	$ 4,127,083	$ 3,729,350

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Segment Reporting

3 Months Ended

Mar. 31, 2012

Segment Reporting Information, Additional Information [Abstract]

Summary of Information Relating to Segments of our Business

BUSINESS SEGMENTS INFORMATION

Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.

On February 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations reclassified to our Corporate segment. For further information see Note 17.

We conduct our operations through the following five reportable segments:

Utilities Group —

• Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyoming and vicinity; and

• Gas Utilities, which supplies natural gas utility service to areas in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group —

• Oil and Gas, which acquires, explores for, develops and produces crude oil and natural gas interests located in the Rocky Mountain region and other states;

• Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming and Colorado; and

• Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyoming.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Segment information included in the accompanying Condensed Consolidated Statements of Income and Comprehensive Income and Condensed Consolidated Balance Sheets was as follows (in thousands):

Three Months Ended March 31, 2012	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	156,133	$	3,036		$	8,746
Gas	180,522		—			15,207
Non-regulated Energy:
Oil and Gas	21,645		—			13
Power Generation	1,178		18,449			6,914
Coal Mining	6,373		8,616			1,000
Corporate (a)(b)	—		—			3,391
Intercompany eliminations	—		(30,101		)	—
Total	$	365,851	$	—		$	35,271

Three Months Ended March 31, 2011	External Operating Revenues		Intercompany Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	144,430	$	3,839		$	10,249
Gas	230,266		—			19,263
Non-regulated Energy:
Oil and Gas	17,906		—			(715		)
Power Generation	687		6,933			1,186
Coal Mining	7,614		7,881			(1,298		)
Corporate (a)(b)	—		—			451
Intercompany eliminations	—		(18,721		)	(68		)
Total	$	400,903	$	(68	)	$	29,068

____________

(a) Income (loss) from continuing operations includes $7.8 million and $3.6 million net after-tax mark-to-market gain on interest rate swaps for the three months ended March 31, 2012 and March 31, 2011, respectively.

(b) Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not classified as discontinued operations but were included in the Corporate segment. See Note 17 for further information.

Total Assets (net of inter-company eliminations)	March 31, 2012		December 31, 2011		March 31, 2011
Utilities:
Electric (a)	$	2,268,524	$	2,254,914	$	1,868,600
Gas	717,185		746,444		683,927
Non-regulated Energy:
Oil and Gas	430,851		425,970		355,357
Power Generation (a)	128,225		129,121		336,827
Coal Mining	87,139		88,704		94,416
Corporate (b)	176,012		141,079		94,499
Discontinued operations (c)	—		340,851		295,724
Total assets	$	3,807,936	$	4,127,083	$	3,729,350

____________

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

(b) Assets of the Corporate segment were restated due to deferred taxes that were not classified as discontinued operations.

(c) See Note 17 for further information relating to discontinued operations.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 30, 2012
Entity Information [Line Items]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	0001130464
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		44,089,428,000

XML

Risk Management Activities

3 Months Ended

Mar. 31, 2012

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 operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2011 Annual Report on Form 10-K filed with the SEC.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks:

• 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 segment; and

• Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our derivative instruments.

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.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with investment grade companies and credit quality municipalities and electric cooperatives, 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 March 31, 2012, 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.

We actively manage our exposure to certain market and credit risks as described in Note 3 of the Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income and Comprehensive Income are detailed below and within Note 14.

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, result in commodity price risk and variability to our cash flows.

We hold a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those OTC 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 are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives is reported in Accumulated other comprehensive income (loss) and the ineffective portion, if any, is reported in Revenue.

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

	March 31, 2012					December 31, 2011					March 31, 2011
	Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps
Notional (a)	522,000			5,001,750		528,000			5,406,250		487,500			5,974,800
Maximum terms in years (b)	1.25			1.50		1.25			1.75		1.00			0.25
Derivative assets, current	$	406		$	8,256	$	729		$	8,010	$	108		$	6,649
Derivative assets, non-current	$	46		$	808	$	771		$	1,148	$	—		$	975
Derivative liabilities, current	$	2,904		$	—	$	2,559		$	—	$	4,688		$	—
Derivative liabilities, non-current	$	1,084		$	—	$	811		$	7	$	2,678		$	157
Pre-tax accumulated other comprehensive income (loss)	$	(3,566	)	$	9,064	$	(1,928	)	$	9,152	$	(7,613	)	$	7,467
Revenue (c)	$	30		$	—	$	58		$	—	$	355		$	—

____________

(a) Crude oil in Bbls, gas in MMBtus

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

(c) Represents the amortization of put premiums.

Based on March 31, 2012 market prices, a $4.3 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains will change during future periods as market prices fluctuate.

Utilities

Our utility customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain exchange-traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums and commissions, 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 Condensed Consolidated Statements of Income and Comprehensive Income when the related costs are recovered through our rates.

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

	March 31, 2012		December 31, 2011		March 31, 2011
	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)	Notional (MMBtus)	Latest Expiration (months)
Natural gas futures purchased	11,550,000	81	14,310,000	84	4,680,000	24
Natural gas options purchased	670,000	12	1,720,000	3	—	—
Natural gas basis swaps purchased	7,640,000	81	7,160,000	60	—	—

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

	March 31, 2012		December 31, 2011		March 31, 2011
Derivative assets, current	$	9,215	$	9,844	$	1,056
Derivative assets, non-current	$	27	$	52	$	209
Derivative liabilities, non-current	$	6,407	$	7,156	$	—
Net unrealized gain (loss) included in Regulatory assets or liabilities	$	15,223	$	17,556	$	2,455
Included in Derivatives:
Cash collateral receivable (payable)	$	17,651	$	19,416	$	3,720
Option premiums and commissions	$	407	$	880	$	—

Financing Activities

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

	March 31, 2012						December 31, 2011						March 31, 2011
	Designated  Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*			Designated Interest Rate Swaps			De-designated Interest Rate Swaps*
Notional	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	4.75			1.75			5.00			2.00			5.75			0.75
Derivative liabilities, current	$	6,777		$	66,708		$	6,513		$	75,295		$	6,769		$	48,515
Derivative liabilities, non-current	$	18,441		$	17,237		$	20,363		$	20,696		$	12,955		$	—
Pre-tax accumulated other comprehensive income (loss)	$	(25,218	)	$	—		$	(26,876	)	$	—		$	(19,724	)	$	—
Pre-tax gain (loss)	$	—		$	12,045		$	—		$	(42,010	)	$	—		$	5,465
Cash collateral receivable (payable)	$	—		$	—		$	—		$	—		$	—		$	—

_____________

* Maximum terms in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. If extended, de-designated swaps totaling $100 million terminate in 7 years and de-designated swaps totaling $150 million terminate in 17 years.

$50 million of our de-designated swaps have collateral requirements based on our corporate credit ratings. At our current credit ratings, we would be required to post collateral for any amount by which the swaps' negative mark-to-market fair value exceeds $20 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 swaps' negative mark-to-market fair value.

Based on March 31, 2012 market interest rates and balances related to our designated interest rate swaps, a lossof approximately $6.8 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

XML

Condensed Consolidated Balance Sheets (Parentheticals) (USD $)	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011
Common Stock Par Value	$ 1,000.00	$ 1,000.00	$ 1,000.00
Common Stock, Shares Authorized	100,000,000,000	100,000,000,000	100,000,000,000
Common Stock, Shares, Issued	44,151,428,000	43,957,502,000	39,434,304,000
Common Stock, Shares, Outstanding	44,086,413,000	43,924,736,000	39,408,229,000
Treasury Stock, Shares	65,015,000	32,766,000	26,075,000

XML

Long-Term Debt

3 Months Ended

Mar. 31, 2012

Long-term Debt, Unclassified [Abstract]

Long-term Debt [Text Block]

LONG TERM DEBT

Pollution Control Revenue Bonds

On March 28, 2012, Black Hills Power provided notice to the trustee of its intent to call the Pollution Control Refund Revenue Bonds which were originally due to mature on October 1, 2014. The principal amount due on the bonds has been reclassified to Current maturities of long-term debt on the accompanying Condensed Consolidated Balance Sheets. Repayment of $6.5 million principal and accrued interest will be made on May 15, 2012.

XML

Notes Payable

3 Months Ended

Mar. 31, 2012

Notes Payable [Abstract]

Notes Payable

NOTES PAYABLE

Our credit facility and debt securities contain certain restrictive financial covenants. As of March 31, 2012, we were in compliance with all of these covenants.

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

	March 31, 2012				December 31, 2011				March 31, 2011
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	75,000	$	41,200	$	195,000	$	43,700	$	187,000	$	51,000
Term Loan due 2011*	—		—		—		—		100,000		—
Term Loan due 2012	150,000		—		150,000		—		—		—
Total	$	225,000	$	41,200	$	345,000	$	43,700	$	287,000	$	51,000

______________

* The short-term loan was renegotiated to a longer term note, maturing in 2013.

Revolving Credit Facility

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

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

Debt Covenants

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

	As of			Covenant
	March 31, 2012			Requirement
Consolidated Net Worth	$	1,224,692		$	899,024
Recourse Leverage Ratio	56.4		%	65.0		%

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Supplemental Disclosure of Cash Flow Information Suplemental Disclosures of Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2012

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

	Three Months Ended
	March 31, 2012			March 31, 2011
	(in thousands)
Non-cash investing activities from continuing operations—
Property, plant and equipment acquired with accrued liabilities	$	31,644		$	32,220
Capitalized assets associated with retirement obligations	$	2,826		$	—
Cash (paid) refunded during the period for continuing operations—
Interest (net of amounts capitalized)	$	(16,799	)	$	(11,572	)
Income taxes, net	$	(1,838	)	$	48

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

Fair Value Measurements

FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

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

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Valuation Methodologies

Oil and Gas Segment:

• The commodity option contracts for the Oil and Gas segment are valued under the market approach and include calls and puts. Fair value was derived using quoted prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through multiple sources.

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

Utilities Segment:

• The commodity contracts for the Utilities, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) and OTC basis swaps (Level 3) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third party market participant.

Corporate Segment:

• The interest rate swaps are valued using the market valuation approach. The company establishes fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.

Recurring Fair Value Measurements

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 March 31, 2012
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	404		$	—	$	—	$	—	$	404
Basis Swaps -- Oil	—		48			—		—		—		48
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		9,064			—		—		—		9,064
Commodity derivatives — Utilities	—		(8,412		)	3		—		17,651		9,242
Repurchase agreement (a)	43,128		—			—		—		—		43,128
Money market funds and term deposits (a)	12,791		—			—		—		—		12,791
Total	$	55,919	$	1,104		$	3	$	—	$	17,651	$	74,677
Liabilities:
Commodity derivatives — Oil and Gas
Options -- Oil	$	—	$	1,347		$	—	$	—	$	—	$	1,347
Basis Swaps -- Oil	—		2,641			—		—		—		2,641
Options -- Gas	—		—			—		—		—		—
Basis Swaps -- Gas	—		—			—		—		—		—
Commodity derivatives — Utilities	—		6,359			48		—		—		6,407
Interest rate swaps	—		109,163			—		—		—		109,163
Total	$	—	$	119,510		$	48	$	—	$	—	$	119,558

______________

(a) Level 1 assets and liabilities and described at Note 15.

	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 funds	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 March 31, 2011
	Level 1		Level 2			Level 3		Counterparty Netting		Cash Collateral		Total
Assets:
Commodity derivatives — Oil and Gas	$	—	$	7,626		$	106	$	—	$	—	$	7,732
Commodity derivatives — Utilities	—		(2,455		)	—		—		3,720		1,265
Money market funds	9,050		—			—		—		—		9,050
Total	$	9,050	$	5,171		$	106	$	—	$	3,720	$	18,047
Liabilities:
Commodity derivatives — Oil and Gas	$	—	$	7,523		$	—	$	—	$	—	$	7,523
Commodity derivatives — Utilities	—		—			—		—		—		—
Interest rate swaps	—		68,239			—		—		—		68,239
Total	$	—	$	75,762		$	—	$	—	$	—	$	75,762

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

	Fair Value at		Valuation	Unobservable	Range (Weighted
	March 31, 2012		Technique	Input	Average)
ASSETS
Commodity derivatives - Utilities(a)	$	3	Independent price quotes	Long-term natural gas prices	Not applicable
LIABILITIES
Commodity derivatives - Utilities(a)	$	48	Independent price quotes	Long-term natural gas prices	Not applicable

______________________

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

The following tables present the changes in Level 3 recurring fair value for the three months ended March 31, 2012 and 2011, respectively (in thousands):

	Three Months Ended March 31, 2012
Assets:	Commodity Derivatives -- Oil			Commodity Derivatives -- Gas		Commodity Derivatives -- Utilities		Total
Balances as of beginning of period	$	768		$	—	$	—	$	768
Total gain (loss) included in revenue	—			—		—		—
Total gain (loss) included in AOCI	(360		)	—		—		(360		)
Purchases	—			—		3		3
Issuances	—			—		—		—
Settlements	(4		)	—		—		(4		)
Transfers into level 3 (a)	—			—		—		—
Transfers out of level 3(b)(c)	(404		)	—		—		(404		)
Balances at end of period	$	—		$	—	$	3	$	3
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	3	$	3

	Three Months Ended March 31, 2012
Liabilities:	Commodity Derivatives -- Oil			Commodity Derivatives -- Gas		Commodity Derivatives -- Utilities		Total
Balances as of beginning of period	$	1,165		$	—	$	—	$	1,165
Total gain (loss) included in revenue	—			—		—		—
Total gain (loss) included in AOCI	182			—		—		182
Purchases	—			—		48		48
Issuances	—			—		—		—
Settlements	—			—		—		—
Transfers into level 3 (a)	—			—		—		—
Transfers out of level 3(b)(c)	(1,347		)	—		—		(1,347		)
Balances at end of period	$	—		$	—	$	48	$	48
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	—		$	—	$	48	$	48

	Three Months Ended March 31, 2011
	Commodity  Derivatives
Balance as of beginning of period	$	266
Unrealized losses	(160		)
Unrealized gains	—
Settlements	—
Transfers into level 3 (a)	—
Transfers out of level 3(b)	—
Balance at end of period	$	106
Changes in unrealized gains (losses) relating to instruments still held as of period-end	$	(159	)

____________

(a) Transfers into Level 3 would occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs.

(b) Transfers out of Level 3 would occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

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

Fair Value Measures

As required by accounting standards for derivatives and hedges, 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 March 31, 2012, December 31, 2011, and March 31, 2011, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 13.

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

As of March 31, 2012
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,662	$	—
Commodity derivatives	Derivative assets — non-current	854		—
Commodity derivatives	Derivative liabilities — current	—		2,904
Commodity derivatives	Derivative liabilities — non-current	—		1,084
Interest rate swaps	Derivative liabilities — current	—		6,777
Interest rate swaps	Derivative liabilities — non-current	—		18,441
Total derivatives designated as hedges		$	9,516	$	29,206
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	8,436
Commodity derivatives	Derivative assets — non-current	—		(27		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		6,407
Interest rate swaps	Derivative liabilities — current	—		66,708
Interest rate swaps	Derivative liabilities — non-current	—		17,237
Total derivatives not designated as hedges		$	—	$	98,761

As of December 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	8,739	$	—
Commodity derivatives	Derivative assets — non-current	1,919		—
Commodity derivatives	Derivative liabilities — current	—		2,559
Commodity derivatives	Derivative liabilities — non-current	—		818
Interest rate swaps	Derivative liabilities — current	—		6,513
Interest rate swaps	Derivative liabilities — non-current	—		20,363
Total derivatives designated as hedges		$	10,658	$	30,253
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	9,572
Commodity derivatives	Derivative assets — non-current	—		(52		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		7,156
Interest rate swaps	Derivative liabilities — current	—		75,295
Interest rate swaps	Derivative liabilities — non-current	—		20,696
Total derivatives not designated as hedges		$	—	$	112,667

As of March 31, 2011
	Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
Derivatives designated as hedges:
Commodity derivatives	Derivative assets — current	$	6,757	$	—
Commodity derivatives	Derivative assets — non-current	975		—
Commodity derivatives	Derivative liabilities — current	—		4,688
Commodity derivatives	Derivative liabilities — non-current	—		2,835
Interest rate swaps	Derivative liabilities — current	—		6,769
Interest rate swaps	Derivative liabilities — non-current	—		12,955
Total derivatives designated as hedges		$	7,732	$	27,247
Derivatives not designated as hedges:
Commodity derivatives	Derivative assets — current	$	—	$	2,665
Commodity derivatives	Derivative assets — non-current	—		(209		)
Commodity derivatives	Derivative liabilities — current	—		—
Commodity derivatives	Derivative liabilities — non-current	—		—
Interest rate swaps	Derivative liabilities — current	—		48,515
Interest rate swaps	Derivative liabilities — non-current	—		—
Total derivatives not designated as hedges		$	—	$	50,971

A description of our derivative activities is included in Note 13. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income and Comprehensive Income.

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income and Comprehensive Income was as follows (in thousands):

Three Months Ended March 31, 2012
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in AOCI Derivative (Effective Portion)			Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion)	Amount of Reclassified Gain/(Loss) 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	$	(762	)	Interest expense	$	(1,822	)		$	—
Commodity derivatives	1,283			Revenue	3,009				—
Total	$	521			$	1,187			$	—

Three Months Ended March 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 Reclassified Gain/(Loss) 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	$	298		Interest expense	$	(1,892	)		$	—
Commodity derivatives	(4,083		)	Revenue	1,031				—
Total	$	(3,785	)		$	(861	)		$	—

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedging instruments on our Condensed Consolidated Statements of Income and Comprehensive Income was as follows (in thousands):

		Three Months Ended
		March 31, 2012
Derivatives Not Designated  as Hedging Instruments	Location of Gain/(Loss)  on Derivatives  Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
Interest rate swaps - unrealized	Unrealized gain (loss) on interest rate swaps, net	$	12,045
Interest rate swaps - realized	Interest expense	(3,205		)
		$	8,840

		Three Months Ended
		March 31, 2011
Derivatives Not Designated  as Hedging Instruments	Location 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 swaps, net	$	5,465
Interest rate swaps - realized	Interest expense	(3,352		)
		$	2,113

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Common Stock

3 Months Ended

Mar. 31, 2012

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

Common Stock

COMMON STOCK

Other than the following transactions, we had no material changes in our common stock during the three months ended March 31, 2012 from the amount reported in Note 11 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Equity Compensation Plans

• We granted 66,690 target performance shares to certain officers and business unit leaders for the January 1, 2012 through December 31, 2014 performance period during the three months ended March 31, 2012. Actual shares are issued after the end of the performance plan period. Performance shares are awarded based on our total stockholder return over the designated performance period as measured against a selected peer group and can range from 0% to 200% 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 the form of cash and 50% in shares of common stock. The grant date fair value was $32.26 per share.

• We granted 139,550 shares of restricted common stock and restricted stock units during the three months ended March 31, 2012. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $4.9 million will be recognized over the vesting period.

• Stock options totaling 41,206 shares were exercised during the three months ended March 31, 2012 at a weighted-average exercise price of $28.28 per share, providing $1.2 million of proceeds.

• We issued 3,690 shares of common stock under our short-term incentive compensation plan during the three months ended March 31, 2012. Pre-tax compensation cost related to the awards was approximately $0.1 million, which was expensed in 2011.

Stock-based compensation expense for the three months ended March 31, 2012 and 2011 was $1.8 million and $2.3 million, respectively.

As of March 31, 2012, total unrecognized compensation expense related to non-vested stock awards was $12.2 million and is expected to be recognized over a weighted-average period of 2.3 years.

Dividend Reinvestment and Stock Purchase Plan

We have a DRIP under which stockholders 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. We issued 27,155 new shares at a weighted-average price of $33.20 during the three months ended March 31, 2012. Unissued common stock totaling 426,109 shares was available for future offering under the DRIP at March 31, 2012.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of March 31, 2012, we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders 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 March 31, 2012:

• Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of March 31, 2012, the restricted net assets at our Utilities Group were approximately $81.4 million.

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

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Earnings per Share

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

Basic earnings (loss) per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted earnings (loss) per share is computed by including all dilutive common shares potentially outstanding during a period. A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Income (loss) from continuing operations	$	35,271	$	29,068
Weighted average shares - basic	43,731		39,059
Dilutive effect of:
Restricted stock	147		132
Stock options	18		17
Equity forward instruments	—		460
Other dilutive effects	73		93
Weighted average shares - diluted	43,969		39,761

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):

	Three Months Ended March 31,
	2012	2011
Stock options	127	83
Restricted stock	31	7
Other stock	16	—
Anti-dilutive shares	174	90

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Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2012

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Comprehensive Income (Loss)

COMPREHENSIVE INCOME (LOSS)

The following table presents the components of our comprehensive income (loss) (in thousands):

Three Months Ended March 31, 2012	Pre-tax Amount			Tax (Expense) Benefit		Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges	$	521		$	55	$	576
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	(1,187		)	445		(742		)
Other comprehensive income (loss)	$	(666	)	$	500	$	(166	)

Three Months Ended March 31, 2011	Pre-tax Amount			Tax (Expense) Benefit			Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges	$	(3,785	)	$	1,637		$	(2,148	)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)	861			(292		)	569
Other comprehensive income (loss)	$	(2,924	)	$	1,345		$	(1,579	)

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

	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
Balance as of December 31, 2011	$	(13,802	)	$	(19,076	)	$	(32,878	)
Other comprehensive income (loss)	(166		)	—			(166		)
Ending Balance March 31, 2012	$	(13,968	)	$	(19,076	)	$	(33,044	)
	Derivatives Designated as Cash Flow Hedges			Employee Benefit Plans			Total
Balance as of December 31, 2010	$	(12,439	)	$	(11,142	)	$	(23,581	)
Other comprehensive income (loss)	(1,579		)	—			(1,579		)
Ending Balance March 31, 2011	$	(14,018	)	$	(11,142	)	$	(25,160	)

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Employee Benefit Plans

3 Months Ended

Mar. 31, 2012

Employee Benefit Plans [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (the "Pension Plans"). One covers certain eligible employees of the following subsidiaries: Black Hills Service Company, Black Hills Power, WRDC and BHEP, one covers certain eligible employees of Cheyenne Light, and one covers certain eligible employees of Black Hills Energy. The Pension Plan benefits are based on years of service and compensation levels.

The components of net periodic benefit cost for the Pension Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Service cost	$	1,430		$	1,355
Interest cost	3,687			3,732
Expected return on plan assets	(4,084		)	(4,239		)
Prior service cost	22			25
Net loss (gain)	2,408			1,135
Net periodic benefit cost	$	3,463		$	2,008

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor the following retiree healthcare plans (the "Healthcare Plans"): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are entitled to postretirement healthcare benefits.

The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012			2011
Service cost	$	402		$	375
Interest cost	523			542
Expected return on plan assets	(19		)	(41		)
Prior service cost (benefit)	(125		)	(120		)
Net loss (gain)	222			169
Net periodic benefit cost	$	1,003		$	925

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (the "Supplemental Plans"). The Supplemental Plans are non-qualified defined benefit plans.

The components of net periodic benefit cost for the Supplemental Plans were as follows (in thousands):

	Three Months Ended March 31,
	2012		2011
Service cost	$	246	$	257
Interest cost	331		324
Prior service cost	1		1
Net loss (gain)	202		127
Net periodic benefit cost	$	780	$	709

Contributions

We anticipate that we will make contributions to the benefit plans during 2012 and 2013. Contributions to the Defined Benefit Plans will be made in cash and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):

	Contributions Made
	Three Months Ended March 31, 2012		Additional Contributions Anticipated for 2012		Contributions Anticipated for 2013
Defined Benefit Pension Plans	$	25,000	$	—	$	4,500
Non-pension Defined Benefit Postretirement Healthcare Plans	$	1,063	$	3,188	$	4,380
Supplemental Non-qualified Defined Benefit Plans	$	278	$	833	$	1,090

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Discontinued Operations Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2012

Condensed Statement of Income [Member]

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

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

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

	For the Three Months Ended
	March 31, 2012			March 31, 2011
Revenue	$	(604	)	$	2,465
Pre-tax income (loss) from discontinued operations	(5,836		)	(3,174		)
Pre-tax gain (loss) on sale	(2,453		)	—
Income tax (expense) benefit	2,805			1,016
Income (loss) from discontinued operations, net of tax	$	(5,484	)	$	(2,158	)

Condensed Balance Sheet [Member]

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

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

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

	December 31, 2011			March 31, 2011
Other current assets	$	280,221		$	243,473
Derivative assets, current and non-current	52,859			45,432
Property, plant and equipment, net	5,828			4,750
Goodwill	1,435			1,435
Other non-current assets	508			631
Other current liabilities	(132,951		)	(129,706		)
Derivative liabilities, current and non-current	(26,084		)	(30,932		)
Other non-current liabilities	(14,894		)	(2,652		)
Net assets	$	166,922		$	132,431

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Risk Management Activities Risk Management (Details) (USD $)	3 Months Ended				12 Months Ended
	Mar. 31, 2012		Mar. 31, 2011		Dec. 31, 2011
Derivative [Line Items]
Current derivative assets	$ 17,877,000		$ 7,812,000		$ 18,583,000
Non-current derivative assets	881,000		1,184,000		1,971,000
Current derivative liabilities	76,389,000		59,972,000		84,367,000
Non-current derivative liabilities	43,169,000		15,790,000		49,033,000
Unrealized Gain (Loss) on Derivatives	(1,594,000)		(2,010,000)
Financing Activities | Interest Rate Swaps, Designated
Derivative [Line Items]
Maximum Length of Time Hedged in Cash Flow Hedge (years)	4 years 9 months		5 years 9 months		5 years
Current derivative liabilities	6,777,000		6,769,000		6,513,000
Non-current derivative liabilities	18,441,000		12,955,000		20,363,000
Accumulated Other Comprehensive Income Loss PreTax	(25,218,000)		(19,724,000)		(26,876,000)
Collateral, included in other current assets	0		0		0
Interest Rate Derivatives [Abstract]
Notional Amount of Interest Rate Derivatives	150,000,000		150,000,000		150,000,000
Derivative, Average Interest Rate	5.04%		5.04%		5.04%
Gain (Loss) on Derivative Instruments, Net, Pretax	0		0		0
Interest Rate Cash Flow Hedge Gain (Loss) to be Reclassified During Next 12 Months, Net	(6,800,000)
Financing Activities | Interest Rate Swaps, Dedesignated
Derivative [Line Items]
Current derivative liabilities	66,708,000		48,515,000		75,295,000
Non-current derivative liabilities	17,237,000		0		20,696,000
Accumulated Other Comprehensive Income Loss PreTax	0		0		0
Latest Expiration, Maximum terms (months)	1 year 9 months		9 months		2 years
Derivative, Collateral, Right to Reclaim Cash	0		0		0
Interest Rate Derivatives [Abstract]
Notional Amount of Interest Rate Derivatives	250,000,000		250,000,000		250,000,000
Derivative, Average Interest Rate	5.67%		5.67%		5.67%
Gain (Loss) on Derivative Instruments, Net, Pretax	12,045,000		5,465,000		(42,010,000)
Financing Activities | Interest Rate Swaps, Dedesignated | Dedesignated Interest Rate Swap Expiring 2018 [Member]
Derivative [Line Items]
Derivative, Remaining Maturity (months)	7 years
Interest Rate Derivatives [Abstract]
Notional Amount of Interest Rate Derivatives	100,000,000
Financing Activities | Interest Rate Swaps, Dedesignated | Dedesignated Interest Rate Swaps Expiring 2028 [Member]
Derivative [Line Items]
Derivative, Remaining Maturity (months)	17 years
Interest Rate Derivatives [Abstract]
Notional Amount of Interest Rate Derivatives	150,000,000
Oil and Gas [Member] | Oil and Gas Exploration and Production
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	4,300,000
Oil and Gas [Member] | Oil and Gas Exploration and Production | Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	5,001,750	[1]	5,974,800		5,406,250
Maximum Length of Time Hedged in Cash Flow Hedge (years)	1 year 6 months		3 months		1 year 9 months
Current derivative assets	8,256,000		6,649,000		8,010,000
Non-current derivative assets	808,000		975,000		1,148,000
Current derivative liabilities	0		0		0
Non-current derivative liabilities	0		157,000		7,000
Accumulated Other Comprehensive Income Loss PreTax	9,064,000		7,467,000		9,152,000
Revenue	0	[2]	0	[2]	0	[2]
Oil and Gas [Member] | Oil and Gas Exploration and Production | Crude Oil [Member] | Swaps and Options [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	522,000	[1]	487,500		528,000
Maximum Length of Time Hedged in Cash Flow Hedge (years)	1 year 3 months		1 year		1 year 3 months
Current derivative assets	406,000		108,000		729,000
Non-current derivative assets	46,000		0		771,000
Current derivative liabilities	2,904,000		4,688,000		2,559,000
Non-current derivative liabilities	1,084,000		2,678,000		811,000
Accumulated Other Comprehensive Income Loss PreTax	(3,566,000)		(7,613,000)		(1,928,000)
Revenue	30,000	[2]	355,000	[2]	58,000	[2]
Utilities Group [Member] | Regulated Utilities - Gas Hedges
Derivative [Line Items]
Current derivative assets	9,215,000		1,056,000		9,844,000
Non-current derivative assets	27,000		209,000		52,000
Non-current derivative liabilities	6,407,000		0		7,156,000
Net Unrealized Gain (Loss) Included in Regulatory Assets	15,223,000		2,455,000		17,556,000
Cash collateral (receivable)/payable included in derivative assets/liabilities	17,651,000		3,720,000		19,416,000
Option Premium Included in Derivative Assets, Current	407,000		0		880,000
Utilities Group [Member] | Regulated Utilities - Gas Hedges | Natural Gas [Member] | Commodity Option [Member] | Purchase Contract [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	670,000		0		1,720,000
Derivative, Remaining Maturity (months)	12 months		0		3 months
Utilities Group [Member] | Regulated Utilities - Gas Hedges | Natural Gas [Member] | Future [Member] | Purchase Contract [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	11,550,000		4,680,000		14,310,000
Derivative, Remaining Maturity (months)	81 months		24 months		84 months
Utilities Group [Member] | Regulated Utilities - Gas Hedges | Natural Gas [Member] | Basis Swap [Member] | Purchase Contract [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	7,640,000		0		7,160,000
Derivative, Remaining Maturity (months)	81 months		0		60 months
Credit Risk [Member] | Interest Rate Swaps, Dedesignated
Interest Rate Derivatives [Abstract]
Notional Amount of Interest Rate Derivatives	50,000,000
Potential Future Exposure on Credit Related Contingent Feature	$ 20,000,000

[1] Crude oil in Bbls, gas in MMBtus

[2] Represents the amortization of put premiums.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

There have been no significant changes to commitments and contingencies from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

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Notes Payable Notes Payable (Tables)

3 Months Ended

Mar. 31, 2012

Line of Credit Facility

Schedule of Short-term Debt

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

	March 31, 2012				December 31, 2011				March 31, 2011
	Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit		Balance Outstanding		Letters of Credit
Revolving Credit Facility	$	75,000	$	41,200	$	195,000	$	43,700	$	187,000	$	51,000
Term Loan due 2011*	—		—		—		—		100,000		—
Term Loan due 2012	150,000		—		150,000		—		—		—
Total	$	225,000	$	41,200	$	345,000	$	43,700	$	287,000	$	51,000

______________

* The short-term loan was renegotiated to a longer term note, maturing in 2013.

Revolving Credit Facility, Existing [Member]

Line of Credit Facility

Credit Facility Covenants

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

	As of			Covenant
	March 31, 2012			Requirement
Consolidated Net Worth	$	1,224,692		$	899,024
Recourse Leverage Ratio	56.4		%	65.0		%

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Segment Reporting Income Statement (Details) (USD $)	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Segment Reporting Information
External Operating Revenue	$ 365,851,000		$ 400,903,000
Inter-segment Operating Revenue	0		(68,000)
Net income (loss)	29,787,000		26,910,000
Income (loss) from continuing operations	35,271,000		29,068,000
Increase Decrease in Fair Value of Derivative Instruments Not Designated as Hedging Instruments Net of Tax Included in Net Income	7,800,000		3,600,000
Electric Utilities [Member]
Segment Reporting Information
External Operating Revenue	156,133,000		144,430,000
Inter-segment Operating Revenue	3,036,000		3,839,000
Net income (loss)	8,746,000		10,249,000
Gas Utilities
Segment Reporting Information
External Operating Revenue	180,522,000		230,266,000
Inter-segment Operating Revenue	0		0
Net income (loss)	15,207,000		19,263,000
Oil and Gas [Member]
Segment Reporting Information
External Operating Revenue	21,645,000		17,906,000
Inter-segment Operating Revenue	0		0
Net income (loss)	13,000		(715,000)
Power Generation [Member]
Segment Reporting Information
External Operating Revenue	1,178,000		687,000
Inter-segment Operating Revenue	18,449,000		6,933,000
Net income (loss)	6,914,000		1,186,000
Coal Mining
Segment Reporting Information
External Operating Revenue	6,373,000		7,614,000
Inter-segment Operating Revenue	8,616,000		7,881,000
Net income (loss)	1,000,000		(1,298,000)
Corporate Elimination [Member]
Segment Reporting Information
External Operating Revenue	0		0
Inter-segment Operating Revenue	0		0
Net income (loss)	3,391,000	[1]	451,000	[1],[2]
Intersegment Elimination [Member]
Segment Reporting Information
External Operating Revenue	0		0
Inter-segment Operating Revenue	(30,101,000)		(18,721,000)
Net income (loss)	$ 0		$ (68,000)

[1] Income (loss) from continuing operations includes $7.8 million and $3.6 million net after-tax mark-to-market gain on interest rate swaps for the three months ended March 31, 2012 and March 31, 2011, respectively.

[2] Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not classified as discontinued operations but were included in the Corporate segment. See Note 17 for further information.

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Earnings per Share Reconcilation of Basic to Dilutive Shares (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Income (loss) from continuing operations	$ 35,271	$ 29,068
Weighted average shares - basic	43,731	39,059
Dilutive effect of:
Incremental Common Shares Attributable To Share Based Payment Arrangements, Restricted Stock and Restricted Stock Units	147	132
Incremental Common Shares Attributable To Share Based Payment Arrangements, Options	18	17
Equity forward issuance	0	460
Other Stock	73	93
Weighted average shares - diluted	43,969	39,761

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Condensed Consolidated Statements of Cash Flows (USD $)	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Operating activities:
Net income (loss)	$ 29,787,000		$ 26,910,000
(Income) loss from discontinued operations, net of tax	5,484,000		2,158,000
Income (loss) from continuing operations	35,271,000		29,068,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	38,559,000		31,910,000
Deferred financing cost amortization	2,719,000		1,528,000
Derivative fair value adjustments	1,594,000		2,010,000
Stock compensation	1,817,000		2,289,000
Unrealized mark-to-market (gain) loss on interest rate swaps	(12,045,000)		(5,465,000)
Deferred income taxes	18,083,000		25,844,000
Equity in (earnings) loss of unconsolidated subsidiaries	56,000		(993,000)
Allowance for funds used during construction - equity	(277,000)		(295,000)
Employee benefit plans	5,246,000		3,642,000
Other adjustments, net	2,187,000		(3,440,000)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel	20,828,000		17,280,000
Accounts receivable and other current assets	9,439,000		(5,591,000)
Accounts payable and other current liabilities	(42,368,000)		(44,617,000)
Regulatory assets	(776,000)		33,966,000
Regulatory liabilities	18,938,000		9,984,000
Contributions to defined pension plans	(25,000,000)		0
Other operating activities, net	610,000		5,301,000
Net cash provided by operating activities of continuing operations	74,881,000		102,421,000
Net cash provided by (used in) operating activities of discontinued operations	21,184,000		8,850,000
Net cash provided by operating activities	96,065,000		111,271,000
Investing activities:
Property, plant and equipment additions	(67,652,000)		(121,615,000)
Other investing activities	1,105,000		786,000
Net cash provided by (used in) investing activities of continuing operations	(66,547,000)		(120,829,000)
Proceeds from sale of business operations	108,837,000		0
Net cash provided by (used in) investing activities of discontinued operations	(824,000)		(929,000)
Net cash provided by (used in) investing activities	41,466,000		(121,758,000)
Financing activities:
Dividends paid on common stock	(16,276,000)		(14,371,000)
Common stock issued	764,000		605,000
Short-term borrowings - issuances	56,453,000		210,000,000
Short-term borrowings - repayments	(176,453,000)		(172,000,000)
Long-term debt - repayments	(1,897,000)		(2,155,000)
Other financing activities	(2,758,000)		(14,000)
Net cash provided by (used in) financing activities of continuing operations	(140,167,000)		22,065,000
Net cash provided by (used in) financing activities of discontinued operations	0		0
Net cash provided by (used in) financing activities	(140,167,000)		22,065,000
Net change in cash and cash equivalents	(2,636,000)		11,578,000
Cash and cash equivalents:
Cash and cash equivalents, beginning of period	58,768,000	[1]	32,438,000	[1]
Cash and cash equivalents, end of period	56,132,000		44,016,000	[1]
Disposal Group, Including Discontinued Operation, Cash and Cash Equivalents			$ 17,600,000

[1] Cash and cash equivalents include cash of discontinued operations of $37.1 million, $17.6 million and $16.0 million at December 31, 2011, March 31, 2011 and December 31, 2010, respectively.

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Accounts Receivable

3 Months Ended

Mar. 31, 2012

Receivables [Abstract]

Accounts Receivable

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable consists primarily of customer trade accounts. The Gas Utilities balance fluctuates primarily due to seasonality. We maintain an allowance for doubtful accounts that reflects our best estimate of probable uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.

Following is a summary of receivables (in thousands) as of:

	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2012	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric	$	44,356	$	19,381	$	(585	)	$	63,152
Gas	44,287		18,502		(936		)	61,853
Oil and Gas	15,014		—		(105		)	14,909
Coal Mining	2,578		—		—			2,578
Power Generation	265		—		—			265
Corporate	1,230		—		—			1,230
Total	$	107,730	$	37,883	$	(1,626	)	$	143,987

	Accounts		Unbilled		Less Allowance for			Accounts
December 31, 2011	Receivable, Trade		Revenue		Doubtful 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

	Accounts		Unbilled		Less Allowance for			Accounts
March 31, 2011	Receivable, Trade		Revenue		Doubtful Accounts			Receivable, net
Electric	$	46,077	$	16,196	$	(728	)	$	61,545
Gas	58,665		21,620		(1,763		)	78,522
Oil and Gas	7,503		—		(161		)	7,342
Coal Mining	982		—		—			982
Power Generation	2,050		—		—			2,050
Corporate	1,083		—		—			1,083
Total	$	116,360	$	37,816	$	(2,652	)	$	151,524

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Discontinued Operations Discontinued Operations (Details) (USD $)	0 Months Ended	3 Months Ended
	Feb. 29, 2012	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of business		$ 108,837,000	$ 0
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax		1,600,000
Discontinued Operation, Income (Loss) from Discontinued Operation Disclosures [Abstract]
Overhead Of Discontinued Operations		1,600,000	500,000
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Assets of Discontinued Operations		0	295,724,000	340,851,000
Energy Marketing [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Significant Acquisitions and Disposals, Date of Transaction for Acquisition or Disposal	Feb. 29, 2012
Proceeds from Sales of Business, Affiliate and Productive Assets		166,300,000
Funds Retained, Sale of Business		57,500,000
Business Exit Costs		2,200,000
Discontinued Operation, Income (Loss) from Discontinued Operation Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue		(604,000)	2,465,000
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax		(5,836,000)	(3,174,000)
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax		(2,453,000)	0
Discontinued Operation, Tax Effect of Discontinued Operation		2,805,000	1,016,000
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent		(5,484,000)	(2,158,000)
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Assets of Disposal Group, Including Discontinued Operation, Current			243,473,000	280,221,000
Derivative Assets of Disposal Group, Including Discontinued Operations			45,432,000	52,859,000
Disposal Group, Including Discontinued Operation, Property, Plant, and Equipment, Net			4,750,000	5,828,000
Disposal Group, Including Discontinued Operation, Goodwill			1,435,000	1,435,000
Assets of Disposal Group, Including Discontinued Operation, Noncurrent			631,000	508,000
Liabilities of Disposal Group, Including Discontinued Operation, Current			(129,706,000)	(132,951,000)
Derivative Liabilities of Disposal Group, Including Discontinued Operations			(30,932,000)	(26,084,000)
Liabilities of Disposal Group, Including Discontinued Operation, Noncurrent			(2,652,000)	(14,894,000)
Assets of Discontinued Operations			$ 132,431,000	$ 166,922,000

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Earnings per Share Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Earnings Per Share Reconciliation

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

	Three Months Ended March 31,
	2012		2011
Income (loss) from continuing operations	$	35,271	$	29,068
Weighted average shares - basic	43,731		39,059
Dilutive effect of:
Restricted stock	147		132
Stock options	18		17
Equity forward instruments	—		460
Other dilutive effects	73		93
Weighted average shares - diluted	43,969		39,761

Antidilutive Securities Excluded from Computation of Earnings Per Share

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):

	Three Months Ended March 31,
	2012	2011
Stock options	127	83
Restricted stock	31	7
Other stock	16	—
Anti-dilutive shares	174	90

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Accounts Receivable Accounts Receivable (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable, Current	$ (1,626)	$ (1,661)	$ (2,652)
Accounts receivable, net	143,987	156,774	151,524
Electric Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable, Current	(585)	(545)	(728)
Accounts receivable, net	63,152	63,379	61,545
Gas Utilities
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable, Current	(936)	(1,011)	(1,763)
Accounts receivable, net	61,853	77,334	78,522
Oil and Gas [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable, Current	(105)	(105)	(161)
Accounts receivable, net	14,909	11,177	7,342
Coal Mining
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable, Current	0	0	0
Accounts receivable, net	2,578	4,056	982
Power Generation [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable, Current	0	0	0
Accounts receivable, net	265	282	2,050
Corporate
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for Doubtful Accounts Receivable, Current	0	0	0
Accounts receivable, net	1,230	546	1,083
Billed Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	107,730	98,292	116,360
Billed Revenues [Member] | Electric Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	44,356	42,773	46,077
Billed Revenues [Member] | Gas Utilities
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	44,287	39,353	58,665
Billed Revenues [Member] | Oil and Gas [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	15,014	11,282	7,503
Billed Revenues [Member] | Coal Mining
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	2,578	4,056	982
Billed Revenues [Member] | Power Generation [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	265	282	2,050
Billed Revenues [Member] | Corporate
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	1,230	546	1,083
Unbilled Revenues [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	37,883	60,143	37,816
Unbilled Revenues [Member] | Electric Utilities [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	19,381	21,151	16,196
Unbilled Revenues [Member] | Gas Utilities
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	18,502	38,992	21,620
Unbilled Revenues [Member] | Oil and Gas [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	0	0	0
Unbilled Revenues [Member] | Coal Mining
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	0	0	0
Unbilled Revenues [Member] | Power Generation [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	0	0	0
Unbilled Revenues [Member] | Corporate
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross, Current	$ 0	$ 0	$ 0

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2012

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

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments are as follows (in thousands) as of:

	March 31, 2012				December 31, 2011				March 31, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	56,132	$	56,132	$	21,628	$	21,628	$	26,418	$	26,418
Restricted cash (a)	$	8,960	$	8,960	$	9,254	$	9,254	$	3,406	$	3,406
Total derivative assets (b)	$	18,758	$	18,758	$	20,554	$	20,554	$	8,996	$	8,996
Total derivative liabilities (b)	$	119,558	$	119,558	$	133,400	$	133,400	$	75,762	$	75,762
Notes payable (a)	$	225,000	$	225,000	$	345,000	$	345,000	$	287,000	$	287,000
Long-term debt, including current maturities (c)	$	1,280,993	$	1,439,724	$	1,282,882	$	1,464,289	$	1,189,084	$	1,260,539

____________

(a) Carrying value approximates fair value due to short-term maturities and therefore is classified in Level 1 in the fair value hierarchy.

(b) See Note 14 for information on classification within the fair value hierarchy.

(c) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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, overnight repurchase agreement accounts, money market funds and term deposits. As part of our cash management process, excess operating cash is invested in overnight repurchase agreements with our bank.  Repurchase agreements are not deposits and are not insured by the U.S. Government, the FDIC or any other government agency and involve investment risk including possible loss of principal.  We believe however, the market risk arising from holding these financial instruments is minimal.  The carrying amount for cash and cash equivalents approximates fair value due to the short-term maturity of these instruments.

Restricted Cash

Restricted cash represents amounts required by Black Hills Wyoming project financing agreements. Of this total, $4.8 million, $0.0 million and $0.0 million for March 31, 2012, December 31, 2011 and March 31, 2011, respectively, were held in uninsured term deposits held at a Canadian bank.

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 13 and 14.

Notes Payable

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

Long-term Debt

Our debt instruments are marked to fair value using the market valuation approach. The fair value for our fixed rate debt instruments is estimated based on quoted market prices and yields for debt instruments having similar maturities and debt ratings. The carrying amounts of our variable rate debt approximate fair value due to the variable interest rates with short reset periods.