Black Hills (BKH) 10-Q 2007 Q1 Quarterly report

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, 2007.
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 is a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer x Accelerated filer o Non-accelerated filer 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, 2007
Common stock, $1.00 par value	37,668,388 shares

TABLE OF CONTENTS

		Page
	Glossary of Terms	3-4
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income –
	Three Months Ended March 31, 2007 and 2006	5
	Condensed Consolidated Balance Sheets –
	March 31, 2007, December 31, 2006 and March 31, 2006	6
	Condensed Consolidated Statements of Cash Flows –
	Three Months Ended March 31, 2007 and 2006	7
	Notes to Condensed Consolidated Financial Statements	8-25
Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	26-44
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45-47
Item 4.	Controls and Procedures	48
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 5.	Other Information	50
Item 6.	Exhibits	51
	Signatures	52
	Exhibit Index	53

2

GLOSSARY OF TERMS

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
Aquila	Aquila, Inc.
Bbl	Barrel
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned
	subsidiary of Black Hills Energy, Inc.
BHER	Black Hills Energy Resources, Inc., a direct, wholly-owned subsidiary of
	Black Hills Energy, Inc.
Black Hills Energy	Black Hills Energy, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Generation	Black Hills Generation, Inc., a direct, wholly-owned subsidiary of
	Black Hills Energy, Inc.
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Wyoming	Black Hills Wyoming, Inc., an indirect, wholly-owned subsidiary of
	Black Hills Energy, Inc.
Btu	British thermal unit
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned
	subsidiary of the Company
Cheyenne Light Pension Plan	The Cheyenne Light, Fuel and Power Company Pension Plan
Dth	Dekatherms
EITF	Emerging Issues Task Force
Enserco	Enserco Energy Inc., a direct, wholly-owned subsidiary of Black Hills
	Energy, Inc.
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes –
	an Interpretation of FASB Statement 109”
GAAP	Generally Accepted Accounting Principles
GECC	General Electric Capital Corporation
Great Plains	Great Plains Energy Incorporated
Indeck	Indeck Capital, Inc.
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Las Vegas I	Las Vegas I gas-fired power plant
Las Vegas II	Las Vegas II gas-fired power plant
LVC	Las Vegas Cogeneration Limited Partnership, an indirect, wholly-owned
	subsidiary of Black Hills Energy, Inc.
Mbbl	One thousand barrels
Mcf	One thousand cubic feet
Mcfe	One thousand cubic feet equivalent
MMBtu	One million British thermal units
MMcf	One million cubic feet
MMcfe	One million cubic feet equivalent
Moody’s	Moody’s Investor Services, Inc.
MW	Megawatt
MWh	Megawatt-hour
Nevada Power	Nevada Power Company
PNM	PNM Resources
SAB	SEC Staff Accounting Bulletin

3

SAB 108	SAB 108, “Effects of Prior Year Misstatement on Current Year Financial
	Statements”
SEC	U. S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 109	SFAS 109, “Accounting for Income Taxes”
SFAS 133	SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 144	SFAS 144, “Accounting for the Impairment of Long-lived Assets”
SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS 158	SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other
	Postretirement Plans, an Amendment of FASB Statements No. 87, 88, 106
	and 132(R)”
SFAS 159	SFAS 159, “The Fair Value Option for Financial Assets and Financial
	Liabilities”
S&P	Standard & Poor’s Rating Services
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned
	subsidiary of Black Hills Energy, Inc.

4

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended
	March 31,
	2007		2006
	(in thousands, except per share amounts)
Operating revenues	$	186,533	$	171,890
Operating expenses:
Fuel and purchased power		51,289		54,129
Operations and maintenance		20,559		22,003
Administrative and general		25,663		24,949
Depreciation, depletion and amortization		23,168		20,889
Taxes, other than income taxes		9,899		10,551
		130,578		132,521
Operating income		55,955		39,369
Other income (expense):
Interest expense		(11,109)		(12,000)
Interest income		733		668
Allowance for funds used during
construction – equity		1,834		—
Other income, net		349		288
		(8,193)		(11,044)
Income from continuing operations
before equity in earnings of
unconsolidated subsidiaries, minority
interest and income taxes		47,762		28,325
Equity in earnings of unconsolidated
subsidiaries		845		513
Minority interest		(94)		(86)
Income tax expense		(16,013)		(10,191)
Income from continuing operations		32,500		18,561
(Loss) income from discontinued operations,
net of taxes		(47)		7,590
Net income	$	32,453	$	26,151
Weighted average common shares
outstanding:
Basic		35,173		33,120
Diluted		35,577		33,460
Earnings per share:
Basic–
Continuing operations	$	0.92	$	0.56
Discontinued operations		—		0.23
Total	$	0.92	$	0.79
Diluted–
Continuing operations	$	0.91	$	0.55
Discontinued operations		—		0.23
Total	$	0.91	$	0.78
Dividends paid per share of common stock	$	0.34	$	0.33

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,		December 31,		March 31,
	2007		2006		2006
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	77,836	$	36,939	$	42,150
Restricted cash		2,032		2,004		—
Receivables (net of allowance for doubtful accounts of $3,647;
$4,202 and $5,016, respectively)		237,335		263,109		148,620
Materials, supplies and fuel		110,129		92,560		102,995
Derivative assets		25,906		69,244		23,268
Other assets		8,876		9,221		7,791
Assets of discontinued operations		1,444		1,424		9,986
		463,558		474,501		334,810
Investments		23,613		23,808		24,708
Property, plant and equipment		2,297,519		2,242,396		2,036,198
Less accumulated depreciation and depletion		(615,597)		(596,029)		(536,188)
		1,681,922		1,646,367		1,500,010
Other assets:
Derivative assets		1,321		2,871		1,238
Goodwill		30,563		30,563		30,562
Intangible assets (net of accumulated amortization of
$26,632; $25,852 and $23,513, respectively)		23,650		24,429		26,768
Other		63,299		42,137		44,208
		118,833		100,000		102,776
	$	2,287,926	$	2,244,676	$	1,962,304
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	237,789	$	224,009	$	120,859
Accrued liabilities		91,217		95,020		70,644
Derivative liabilities		18,159		24,041		9,845
Deferred income taxes		1,352		1,215		1,591
Notes payable		—		145,500		58,000
Current maturities of long-term debt		38,822		17,106		11,852
Accrued income taxes		12,489		19,561		12,827
Liabilities of discontinued operations		1,858		2,526		11,424
		401,686		528,978		297,042
Long-term debt, net of current maturities		602,870		628,340		665,373
Deferred credits and other liabilities:
Deferred income taxes		197,937		174,332		140,904
Derivative liabilities		3,973		1,530		976
Other		126,411		116,297		95,352
		328,321		292,159		237,232
Minority interest in subsidiaries		5,252		5,158		5,011
Stockholders’ equity:
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized;
Issued 37,701,238; 33,404,902 and 33,281,278 shares,
respectively		37,701		33,405		33,281
Additional paid-in capital		554,040		409,826		405,214
Retained earnings		369,997		348,245		326,369
Treasury stock at cost – 37,128; 35,700 and 38,058
shares, respectively		(984)		(920)		(962)
Accumulated other comprehensive loss		(10,957)		(515)		(6,256)
		949,797		790,041		757,646
	$	2,287,926	$	2,244,676	$	1,962,304

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

6

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Operating activities:
Net income	$	32,453	$	26,151
Loss (income) from discontinued operations, net of taxes		47		(7,590)
Income from continuing operations		32,500		18,561
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization		23,168		20,889
Net change in derivative assets and liabilities		(3,948)		(2,040)
Deferred income taxes		13,842		5,028
Distributed earnings in associated companies		472		3,749
Allowance for funds used during construction – equity		(1,834)		—
Change in operating assets and liabilities:
Materials, supplies and fuel		11,838		7,383
Accounts receivable and other current assets		26,965		115,773
Accounts payable and other current liabilities		1,804		(103,131)
Other operating activities		(10,705)		4,635
Net cash provided by operating activities of continuing operations		94,102		70,847
Net cash (used in) provided by operating activities of discontinued operations		(1,387)		2,550
Net cash provided by operating activities		92,715		73,397
Investing activities:
Property, plant and equipment additions		(38,558)		(89,684)
Proceeds from sale of assets		—		40,735
Other investing activities		(305)		(899)
Net cash used in investing activities of continuing operations		(38,863)		(49,848)
Net cash provided by investing activities of discontinued operations		1,200		2,873
Net cash used in investing activities		(37,663)		(46,975)
Financing activities:
Dividends paid		(11,377)		(10,968)
Common stock issued		146,638		1,237
(Decrease) increase in short-term borrowings, net		(145,500)		3,000
Long-term debt – repayments		(3,753)		(4,739)
Other financing activities		(350)		804
Net cash used in financing activities of continuing operations		(14,342)		(10,666)
Net cash used in financing activities of discontinued operations		—		—
Net cash used in financing activities		(14,342)		(10,666)
Increase in cash and cash equivalents		40,710		15,756
Cash and cash equivalents:
Beginning of period		37,530 (b)		34,198 (d)
End of period	$	78,240 (a)	$	49,954 (c)
Supplemental disclosure of cash flow information:
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities	$	25,892	$	20,378
Cash paid during the period for-
Interest (net of amounts capitalized)	$	9,282	$	11,549
Income taxes paid (net of amounts refunded)	$	6,538	$	3,609

_________________________

(a)  Includes approximately $0.4 million at March 31, 2007 of cash included in the assets of discontinued operations.

(b)  Includes approximately $0.6 million at December 31, 2006 of cash included in the assets of discontinued operations.

(c)  Includes approximately $7.8 million at March 31, 2006 of cash included in the assets of discontinued operations.

(d)  Includes approximately $2.4 million at December 31, 2005 of cash included in the assets of discontinued operations.

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

7

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2006 Annual Report on Form 10-K)

(1) MANAGEMENT’S STATEMENT

The financial statements included herein have been prepared by Black Hills Corporation (the Company) without audit, 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, the Company believes that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in the Company’s 2006 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 financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the March 31, 2007, December 31, 2006 and March 31, 2006 financial information and are of a normal recurring nature. Some of the Company’s operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as changes in market price. The results of operations for the three months ended March 31, 2007, are not necessarily indicative of the results to be expected for the full year. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

(2) RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

FIN 48

The Company adopted FIN 48 on January 1, 2007 (see Note 8). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

8

SAB 108

During September 2006, the staff of the SEC released SAB 108. SAB 108 provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement. Prior practice allowed the evaluation of materiality on the basis of (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method). Reliance on either method in prior years could have resulted in misstatement of the financial statements. The guidance provided in SAB 108 requires both methods to be used in evaluating materiality. Immaterial prior year errors may be corrected with the first filing of prior year financial statements after adoption. The cumulative effect of the correction can either be reported in the carrying amounts of assets and liabilities as of the beginning of that fiscal year, and the offsetting adjustment made to the opening balance of retained earnings for that year, or by restating prior periods. Disclosure requirements include the nature and amount of each individual error being corrected in the cumulative adjustment, as well as a disclosure of when and how each error being corrected arose and the fact that the errors had previously been considered immaterial. SAB 108 was effective January 1, 2007. SAB 108 did not have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

(3) RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS 157

During September 2006, the FASB issued SFAS 157 and applies under other accounting pronouncements that require or permit fair value measurements. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Management is currently evaluating the impact SFAS 157 will have on the Company’s consolidated financial statements.

SFAS 159

During February 2007, the FASB issued SFAS 159, which establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. Management is currently evaluating the impact SFAS 159 will have on the Company’s consolidated financial statements.

9

(4) MATERIALS, SUPPLIES AND FUEL

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

Major Classification	March 31, 2007		December 31, 2006		March 31, 2006
Materials and supplies	$	33,303	$	31,946	$	28,042
Fuel		6,096		9,663		5,753
Gas and oil held by energy
marketing*		70,730		50,951		69,200
Total materials, supplies and fuel	$	110,129	$	92,560	$	102,995

___________________________

* As of March 31, 2007, December 31, 2006 and March 31, 2006, market adjustments related to natural gas held by Energy marketing and recorded in inventory were $2.4 million, $(31.5) million and $(5.4) million, respectively (see Note 12 for further discussion of Energy marketing trading activities).

The gas inventory held by the Company’s Energy marketing subsidiary primarily consists of gas held in storage and gas imbalances held on account with pipelines. Such gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future. A substantial majority of the gas was economically hedged at the time of purchase either through a fixed price physical or financial forward sale.

(5) LONG-TERM DEBT AND NOTES PAYABLE

Note Payable

During the first quarter of 2007, the Company repaid the $145.5 million borrowing balance outstanding on its revolving credit facility with proceeds from the Company’s February 22, 2007 equity issuance (see Note 9).

Long-term Debt

On April 30, 2007, the Company prepaid the outstanding balance of the GECC Financing. Accordingly, the December 31, 2006 long-term balance of $22.2 million has been classified as a current liability on the accompanying March 31, 2007 Condensed Consolidated Balance Sheet.

Amendments to Revolver

On March 13, 2007, the Company entered into a second amendment to its revolving bank facility. The second amendment (i) increased the limit for borrowings or other credit accommodations for the separate credit facility for the Company’s energy marketing subsidiary from $260 million to $300 million, (ii) increased the allowed total commitments under the facility without requiring amendment of the facility from $500 million to $600 million, (iii) effective with the acquisition of certain electric and gas utility assets from Aquila, will increase the recourse leverage ratio limit from 0.65 to 1.00 to 0.70 to 1.00 for the first year after completion of the Aquila asset acquisition, reverting to 0.65 to 1.00 thereafter, and (iv) allowed for other modifications to enable the Company to complete the Aquila asset acquisition.

10

(6) EARNINGS PER SHARE

Basic earnings per share from continuing operations is computed by dividing income from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted earnings per share from continuing operations gives effect to all dilutive common shares potentially outstanding during a period. A reconciliation of “Income from continuing operations” and basic and diluted share amounts is as follows (in thousands):

Period ended March 31, 2007	Three Months
			Average
	Income		Shares
Income from continuing operations	$	32,500
Basic earnings		32,500	35,173
Dilutive effect of:
Stock options		—	102
Estimated contingent shares issuable
for prior acquisition		—	158
Others		—	144
Diluted earnings	$	32,500	35,577

Period ended March 31, 2006	Three Months
			Average
	Income		Shares
Income from continuing operations	$	18,561
Basic earnings		18,561	33,120
Dilutive effect of:
Stock options		—	83
Estimated contingent shares issuable
for prior acquisition		—	158
Others		—	99
Diluted earnings	$	18,561	33,460

11

(7) COMPREHENSIVE INCOME

The following table presents the components of the Company’s comprehensive income

(in thousands):

	Three Months Ended
	March 31,
	2007		2006
Net income	$	32,453	$	26,151
Other comprehensive income (loss),
net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges (net of
tax of $2,499 and $(2,255), respectively)		(4,691)		3,865
Reclassification adjustments on cash flow
hedges settled and included in net
income (net of tax of $3,065 and
$170, respectively)		(5,751)		(291)
Comprehensive income	$	22,011	$	29,725

(8) INCOME TAXES

The Company adopted the provisions of FIN 48on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized an approximate $0.7 million benefit from a decrease in the liability for unrecognized tax benefits. This benefit was accounted for as an adjustment to the January 1, 2007 balance of retained earnings.

The total gross amount of unrecognized tax benefits at January 1, 2007 was approximately $72.6 million. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $2.0 million (net of the federal benefit on state issues and interest) at the date of adoption.

It is the Company’s continuing practice to recognize penalties and/or interest related to income tax matters in income tax expense. The Company had no penalties accrued and approximately $0.4 million for the accrual of interest income at the date of adoption of FIN 48.

The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and a foreign jurisdiction. The Company is no longer subject to U.S. federal examination for tax years before 2004. However, the Company is under examination by a state taxing authority for tax years 2001 through 2003 and remains subject to examination by foreign income tax authorities for tax years as early as 1999.

The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2008.

12

(9) COMMON STOCK

Other than the following transactions, the Company had no other material changes in its common stock, as reported in Note 9 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

Private Placement of Common Stock

On February 22, 2007, the Company completed the issuance and sale of approximately 4.17 million shares of common stock at a price of $36.00 per share in a private placement offering. The Company used the approximate $145.6 million of net proceeds from this offering for debt reduction.

These shares were not initially registered under the Securities Act of 1933, therefore restricting the purchasers’ ability to offer or sell the shares. The offering agreements required the Company to register the related securities with the SEC within a specified period of time, and the Company has performed this obligation. In addition, the Company must maintain an effective shelf registration statement with the SEC, allowing resale of the restricted shares, until all related shares have been resold or cease to be restricted. If the Company fails to maintain an effective shelf registration statement in accordance with the terms of the offering agreements, it may be required to pay damages to the purchasers at a per thirty-day rate of 1.0 percent of the related share purchase price until the default is cured. The total damage payments under the agreements are limited to 10.0 percent of the related share purchase price. The Company believes the likelihood of making any payments under the damage provisions is remote and accordingly has not recognized any liability within its consolidated financial statements.

Equity Compensation Plans

•    Effective January 1, 2007, the Company granted 35,026 target performance shares to certain officers and business unit leaders of the Company for the January 1, 2007 through December 31, 2009 performance period. Performance shares are awarded based on the Company’s total shareholder return over the designated performance period as measured against a selected peer group. In addition, the Company’s stock price must also increase during the performance period.

Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50^th percentile of the selected peer group. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50 percent in the form of cash and 50 percent in the form of common stock. The grant date fair value was $34.17 per share.

•    50,514 stock options were exercised during the first quarter of 2007, at a weighted-average exercise price of $26.97 per share providing $1.4 million of proceeds to the Company.

•    The Company granted 43,556 restricted common shares during the first quarter of 2007. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $1.6 million will be recognized over the three-year vesting period.

•    The Company issued 33,143 shares of common stock under the short-term incentive compensation plan during the first quarter of 2007. Pre-tax compensation cost related to the award was approximately $1.2 million, which was accrued for in 2006.

13

(10) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The Company has two non-contributory defined benefit pension plans (Plans). One Plan covers employees of the Company and the following subsidiaries who meet certain eligibility requirements: Black Hills Service Company, Black Hills Power, WRDC and BHEP. The other Plan covers employees of the Company’s subsidiary, Cheyenne Light, who meet certain eligibility requirements.

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

	Three Months Ended
	March 31,
	2007		2006
Service cost	$	687	$	649
Interest cost		1,129		1,041
Expected return on plan assets		(1,374)		(1,247)
Prior service cost		38		38
Net loss		127		227
Net periodic benefit cost	$	607	$	708

The Company made a $0.5 million contribution to the Cheyenne Light Pension Plan in the first quarter of 2007; no additional contributions are anticipated to be made to the Plans during the 2007 fiscal year.

Supplemental Non-qualified Defined Benefit Plans

The Company has various supplemental retirement plans for key executives of the Company (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

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

	Three Months Ended
	March 31,
	2007		2006
Service cost	$	103	$	87
Interest cost		289		270
Prior service cost		3		3
Net loss		178		199
Net periodic benefit cost	$	573	$	559

The Company anticipates that it will need to make contributions to the Supplemental Plans for the 2007 fiscal year of approximately $0.7 million. The contributions are expected to be made in the form of benefit payments.

14

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in the Company’s Postretirement Healthcare Plans (Healthcare Plans) and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.

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

	Three Months Ended
	March 31,
	2007		2006
Service cost	$	135	$	164
Interest cost		207		203
Net transition obligation		15		38
Prior service cost		—		(6)
Net gain		(4)		—
Net periodic benefit cost	$	353	$	399

The Company anticipates that it will make contributions to the Healthcare Plans for the 2007 fiscal year of approximately $0.3 million. The contributions are expected to be made in the form of benefits payments.

It has been determined that the Company’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was approximately $0.1 million for each of the three month periods ended March 31, 2007 and 2006.

(11) SUMMARY OF INFORMATION RELATING TO SEGMENTS OF THE COMPANY’S BUSINESS

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of March 31, 2007, substantially all of the Company’s operations and assets are located within the United States.

The Company conducts its operations through the following six reporting segments: Retail Services group consisting of the following segments: Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Electric and gas utility, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity; and Wholesale Energy group, consisting of the following segments: Oil and gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region, Texas, California and other states; Power generation, which produces and sells power and capacity to wholesale customers with plants concentrated in Colorado, Nevada, Wyoming and California; Coal mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; and Energy marketing, which markets natural gas, crude oil and related services primarily in the western and central regions of the United States and Canada.

15

Segment information follows the same accounting policies as described in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K. In accordance with the provisions of SFAS 71, intercompany fuel sales to the electric utility are not eliminated.

Segment information included in the accompanying Condensed Consolidated Statements of Income is as follows (in thousands):

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
March 31, 2007
Retail services:
Electric utility	$	47,356	$	411	$	6,699
Electric and gas utility		36,363		—		3,072
Wholesale energy:
Oil and gas		25,843		—		3,591
Power generation		39,566		—		4,979
Coal mining		6,217		3,528		1,615
Energy marketing		28,437		—		12,659
Corporate		1		—		(115)
Inter-segment eliminations		—		(1,189)		—
Total	$	183,783	$	2,750	$	32,500

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
March 31, 2006
Retail services:
Electric utility	$	43,804	$	164	$	4,899
Electric and gas utility		43,699		—		1,397
Wholesale energy:
Oil and gas		25,185		—		5,390
Power generation		33,593		—		2,092
Coal mining		5,996		3,274		1,415
Energy marketing		16,957		—		6,247
Corporate		16		—		(2,879)
Inter-segment eliminations		—		(798)		—
Total	$	169,250	$	2,640	$	18,561

The Company had no material changes in the assets of its reporting segments, as reported in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

16

(12) RISK MANAGEMENT ACTIVITIES

The Company actively manages its exposure to certain market risks as described in Note 2 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form

10-K. Details of derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are as follows:

Trading Activities

Natural Gas and Crude Oil Marketing

The contract or notional amounts and terms of the Company’s natural gas and crude oil marketing activities and derivative commodity instruments are as follows:

	Outstanding at			Outstanding at			Outstanding at
	March 31, 2007			December 31, 2006			March 31, 2006
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)
(in thousands of MMBtus)
Natural gas basis
swaps purchased		169,341	21		138,111	22		92,737	19
Natural gas basis
swaps sold		178,563	21		148,720	22		103,437	19
Natural gas fixed - for - float
swaps purchased		40,323	24		38,239	16		17,889	20
Natural gas fixed - for - float
swaps sold		61,880	24		59,061	15		28,432	20
Natural gas physical
purchases		104,393	19		87,782	22		91,422	31
Natural gas physical sales		109,593	31		106,500	34		110,332	43
Natural gas options
purchased		33,839	9		22,373	15		6,373	18
Natural gas options sold		33,839	9		22,373	15		6,373	18

17

	Outstanding at			Outstanding at			Outstanding at
	March 31, 2007			December 31, 2006			March 31, 2006
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)
(in thousands of Bbls)
Crude oil physical
purchases		1,806	6		1,600	4		-(a)	-
Crude oil physical sales		1,557	6		1,367	7		-(a)	-
(Dollars, in thousands)
Canadian dollars
purchased	$	13,817	1	$	44,000	1	$	17,000	1
Canadian dollars sold	$	—	—	$	—	—	$	32,500	8

_________________________

(a) The Company began marketing crude oil in the Rocky Mountain region beginning May 2006.

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on March 31, 2007, December 31, 2006 and March 31, 2006, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows (in thousands):

	Current		Non-current		Current		Non-current
	Derivative		Derivative		Derivative		Derivative		Unrealized
	Assets		Assets		Liabilities		Liabilities		Gain
March 31, 2007	$	20,090	$	149	$	14,696	$	514	$	5,029
December 31, 2006	$	53,728	$	4	$	23,296	$	377	$	30,059
March 31, 2006	$	20,590	$	215	$	7,034	$	32	$	13,739

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Condensed Consolidated Balance Sheets and the related unrealized gain/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of March 31, 2007, December 31, 2006 and March 31, 2006, the market adjustments recorded in inventory were $2.4 million, $(31.5) million and $(5.4) million, respectively.

18

Activities Other Than Trading

Oil and Gas Exploration and Production

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company had the following derivatives and related balances (in thousands):

											Pre-tax
		Maximum			Non-				Non-		Accumulated
		Terms	Current		current		Current		current		Other		Pre-tax
		in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
March 31,
2007
Crude oil
swaps/options	450,000	1.00	$	649	$	—	$	934	$	546	$	(1,415)	$	584
Natural gas
swaps	11,613,000	1.17		5,049		276		2,260		2,151		1,638		(724)
			$	5,698	$	276	$	3,194	$	2,697	$	223	$	(140)
December 31,
2006
Crude oil
swaps/options	240,000	1.00	$	524	$	—	$	362	$	—	$	36	$	126
Natural gas
swaps	10,588,000	1.25		13,485		2,000		309		175		15,339		(338)
			$	14,009	$	2,000	$	671	$	175	$	15,375	$	(212)
March 31,
2006
Crude oil
swaps	360,000	1.00	$	155	$	—	$	2,811	$	944	$	(3,755)	$	155
Natural gas
swaps	1,825,000	0.60		2,086		—		—		—		2,086		—
			$	2,241	$	—	$	2,811	$	944	$	(1,669)	$	155

________________________

*crude in Bbls, gas in MMBtus

Based on March 31, 2007 market prices, a $2.0 million gain would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production. Estimated and actual realized gains will likely change during the next twelve months as market prices change.

19

Fuel in Storage

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company had the following swaps and related balances (in thousands):

											Pre-tax
					Non-				Non-		Accumulated
		Maximum	Current		current		Current		current		Other
		Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Unrealized
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		Gain
March 31,
2007
Natural gas
swaps	455,000	1.00	$	—	$	—	$	161	$	—	$	(161)	$	—
December 31,
2006
Natural gas
swaps	380,000	0.25	$	1,220	$	—	$	—	$	—	$	878	$	342
March 31,
2006
Natural gas
swaps	155,000	1.00	$	31	$	—	$	—	$	—	$	31	$	—

________________________

*gas in MMBtus

Based on March 31, 2007 market prices, a loss of $(0.2) million would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

20

Financing Activities

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company’s interest rate swaps and related balances were as follows (in thousands):

			Weighted										Pre-tax
			Average				Non-				Non-		Accumulated
	Current		Fixed	Maximum	Current		current		Current		current		Other
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Pre-tax
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		Income		Income
March 31,
2007
Interest rate
swaps	$	150,000	5.04%	9.50	$	118	$	896	$	108	$	762	$	144	$	—
December 31,
2006
Interest rate
swaps	$	150,000	5.04%	9.75	$	287	$	867	$	74	$	978	$	102	$	—
March 31,
2006
Interest rate
swaps	$	75,000	4.93%	10.00	$	406	$	1,023	$	—	$	—	$	1,412	$	17

Based on March 31, 2007 market interest rates and balances, a gain of less than $0.1 million would be realized and reported in pre-tax earnings during the next twelve months. Estimated and realized gains will likely change during the next twelve months as market interest rates change.

(13) LEGAL PROCEEDINGS

The Company is subject to various legal proceedings, claims and litigation as described in Note 18 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

Earn-Out Litigation

As disclosed in previous filings with the SEC, the Company has ongoing litigation with the former Indeck stockholders. On March 12, 2007, the Court granted, in part, the Company’s Motion to Dismiss the Amended Complaint. The Court dismissed Counts 1 and 5 of the Amended Complaint. Count 1 included all claims of fraud against individual defendants. Those individuals were not named in other counts of the Amended Complaint, so they were dismissed as parties to the lawsuit. Count 5 asserted a claim for breach of the covenant of good faith and fair dealing relating to the alleged destruction of evidence. The Court approved the amendment of the complaint on other theories. The Company expects to file Motions for Summary Judgment on these remaining claims. A status hearing is set for late June 2007, at which time we expect the Court to set a trial date if Motions for Summary Judgment are denied in whole or in part.

The outcome of this matter is uncertain, as is the amount of contingent merger consideration that could be awarded following arbitration and/or litigation. If any additional merger consideration is awarded, it would be recorded as additional goodwill. If an adverse outcome was to occur and punitive damages were awarded, the punitive damages would be recorded as an expense.

21

Las Vegas Cogeneration/Nevada Power Company Arbitration

On March 16, 2007, Nevada Power filed a Demand for Arbitration pursuant to a Power Purchase Agreement dated May 27, 1992, between Nevada Power and LVC for Las Vegas I. Nevada Power asserts that LVC is in breach of its obligation under the Agreement to maintain a reliable fuel supply throughout the term of the Agreement. Nevada Power also asserts that LVC failed to deliver the amounts of energy and capacity required by the Agreement. The relief Nevada Power requests include: (1) Determination and Order requiring LVC to provide reasonable assurance of its ability to supply fuel to the facility for the full remaining term of the Agreement; (2) Determination that LVC has breached the Agreement relating to fuel supply requirements, and therefore finding that Nevada Power is relieved of its obligation to purchase power under the Agreement; (3) Determination concerning the energy and capacity delivery requirements of the Agreement; and (4) Determination that LVC breached the performance requirements of the Agreement during the winter season of 2005-2006, and providing an award of damages incurred by Nevada Power by reason of the alleged breach.

LVC denies all these claims and filed its response to the Demand for Arbitration, asserting the following defenses: (1) That Nevada Power failed to honor its contractual obligation to properly negotiate in good faith before filing the demand for arbitration; (2) That LVC has complied with its obligations relating to fuel supply and transportation; (3) That LVC has fulfilled its obligations to deliver energy and capacity to Nevada Power, and did not breach the Agreement during the winter season of 2005-2006, when substantial mechanical problems required an extended outage to perform redesign and repair of generation equipment; and (4) That numerous other affirmative defenses preclude Nevada Power from receiving the relief requested.

The arbitration demand was filed with the American Arbitration Association, pursuant to its Commercial Arbitration Rules. The parties are in the process of selecting an arbitrator, who will establish the process and schedule for determination of this dispute. While the Company cannot predict the final timing or outcome of this action, it is not expected to have a material adverse impact on the Company’s consolidated financial position or results of operations.

Except as described above, there have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first three months of 2007.

22

(14) ACQUISITION OF UTILITY ASSETS

On February 7, 2007, the Company entered into a definitive agreement with Aquila for the asset acquisition of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The purchase price of the assets is $940.0 million, subject to closing adjustments. In conjunction with this agreement, the Company has entered into a binding agreement with a group of lenders for a committed acquisition credit facility (see Note 16).

The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the regulated utilities to the Company. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Service Commission, the Nebraska Public Service Commission, the Iowa Utilities Board and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions.

This transaction would add approximately 93,000 electric utility customers and 523,000 gas utility customers to the Company’s utility operations.

The Company is capitalizing certain incremental acquisition costs incurred in the current period related to this pending acquisition. Amounts capitalized in the three months ended March 31, 2007 were approximately $2.0 million.

(15) DISCONTINUED OPERATIONS

The Company accounts for its discontinued operations under the provisions of SFAS 144. Accordingly, results of operations and the related charges for discontinued operations have been classified as “(Loss) income from discontinued operations, net of taxes” in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis.

Sale of Crude Oil Marketing and Transportation Assets

On March 1, 2006, the Company sold the operating assets of BHER and related subsidiaries, its crude oil marketing and transportation business for approximately $41 million. Assets sold include the 200-mile Millennium and the 190-mile Kilgore Pipelines, oil marketing contracts and certain other ancillary assets. Following the sale, the Company closed the operations of the Houston, Texas based business. For business segment reporting purposes, BHER was included in the Energy marketing and transportation segment.

23

Revenues and net (loss) income from the discontinued operations were as follows (in thousands):

	Three Months Ended
	March 31,
	2007		2006
Operating revenues	$	—	$	171,869
Pre-tax loss from discontinued
operations (including
severance payments)	$	(73)	$	(1,762)
Pre-tax gain on sale of
assets		—		13,582
Income tax benefit (expense)		26		(4,230)
Net (loss) income from
discontinued operations	$	(47)	$	7,590

Losses incurred subsequent to the asset sale resulted from the settlement of certain contract disputes with the purchaser and other costs incurred in closing down the business operations.

Assets and liabilities of the crude oil marketing and transportation business were as follows (in thousands):

	March 31, 2007		December 31, 2006		March 31, 2006
Current assets	$	1,294	$	1,424	$	9,879
Property, plant and equipment, net		—		—		34
Other non-current assets		150		—		73
Current liabilities		(1,514)		(2,352)		(10,585)
Other non-current liabilities		(344)		(174)		(839)
Net deficit	$	(414)	$	(1,102)	$	(1,438)

24

(16) SUBSEQUENT EVENTS

Power Plant Project and Power Purchase Agreement

In April 2007, the Company entered into a power purchase agreement to provide electric power to Public Service Company of New Mexico, a regulated electric and natural gas utility subsidiary of PNM.

Under the terms of the agreement, the Company will provide the capacity and energy of a 149 MW, simple-cycle gas turbine generation facility to be located near Albuquerque, New Mexico. The project is expected to cost approximately $101 million, and has a commercial operation in-service date of June 1, 2008. The agreement is a customary tolling agreement, where the Company receives variable and fixed fees for the plant’s availability and operation, and Public Service Company of New Mexico will be responsible for providing fuel for the operation. In addition, the PPA affords us favorable “change of law” and “government impositions” pass throughs to Public Service Company of New Mexico. The duration of the power purchase agreement is 20 years. The agreement also allows Public Service Company of New Mexico the option to acquire an equity interest of up to 50 percent in this project.

>

Acquisition Credit Facility

On May 7, 2007, the Company entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and various other banks to provide for funding for the Company’s pending acquisition of Aquila assets. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount of up to $1.0 billion. The commitment to fund the acquisition term loan terminates on August 5, 2008. Upon funding of the loan, the loan termination date is the earlier of the date which is 364 days from the loan funding date or February 5, 2009. The facility also includes certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.

GECC

On April 30, 2007, the Company called its outstanding debt with GE Capital in the amount of $23.5 million. In conjunction with this, the Company expensed less than $0.1 million in unamortized deferred finance costs. The associated payment guarantees provided by the Company were also terminated.

25

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

We are a diversified energy company operating principally in the United States with two major business groups – retail services and wholesale energy. We report our business groups in the following segments:

Business Group	Financial Segment
Retail services group	Electric utility
	Electric and gas utility
Wholesale energy group	Oil and gas
	Power generation
	Coal mining
	Energy marketing

Our retail services group consists of our electric and gas utilities segments. Our electric utility, Black Hills Power, generates, transmits and distributes electricity to an average of approximately 64,200 customers in South Dakota, Wyoming and Montana. Our electric and gas utility, Cheyenne Light, serves approximately 38,900 electric and 32,600 natural gas customers in Cheyenne, Wyoming and vicinity. Our wholesale energy group engages in the production of coal, natural gas and crude oil primarily in the Rocky Mountain region; the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts; and the marketing of fuel products.

Pending Acquisition of Assets from Aquila

On February 7, 2007 the Company entered into a definitive agreement with Aquila for the asset acquisition of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The purchase price of the assets is $940 million, subject to closing adjustments. In conjunction with this agreement, the Company has entered into a binding agreement with a group of lenders for a committed acquisition credit facility as a bridge financing for the transaction. The Acquisition Credit Facility was completed on May 7, 2007.

The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the regulated utilities to us. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Service Commission, the Nebraska Public Service Commission, the Iowa Utilities Board and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions.

This transaction would add approximately 93,000 electric utility customers and 523,000 gas utility customers to our utility operations.

Disposition of Crude Oil Marketing and Transportation Business

In March 2006, we sold the operating assets of BHER and related subsidiaries, our crude oil marketing and pipeline transportation business headquartered in Houston, Texas. These activities were previously reported in our Energy marketing and transportation segment.

26

Results of Operations

Executive Summary

Results for the three months ended March 31, 2007 reflect solid utility performance, strong energy marketing results and improved power generation performance. Results also reflect the impacts of lower gas production and higher operating costs for the Oil and gas segment.

Increased retail services earnings resulted from overall steady operations at both of our utilities. Black Hills Power earnings benefited from a South Dakota rate increase. Cheyenne Light earnings were impacted by the effects of earnings from the AFUDC related to the construction of Wygen II. We also received additional permits on the Wygen III power plant project and expect to complete the permitting process and begin construction in late 2007 or early 2008.

Earnings from the oil and gas operations decreased due to lower production on an equivalent basis, driven by drilling permit delays in core operating areas, lower well performance in the Denver-Julesburg Basin and the effects of winter weather. Higher overall industry costs also affected results. Earnings were positively impacted by increased hedged natural gas and oil prices received compared to the prior year.

Increased earnings from power generation reflect plant availability of 96.1 percent compared to 85.7 percent in the three months ended March 31, 2006, primarily due to the return to service of the Las Vegas facilities after scheduled and unscheduled maintenance in the first quarter of 2006.

Strong earnings from energy marketing benefited from higher margins received and increased volumes. Lower overall market prices helped serve increased demand, and our storage, transportation and other marketing strategies were able to take advantage of natural gas price volatility and basis differentials in the Rocky Mountain and other regions.

On February 22, 2007 the Company completed the issuance and sale of approximately 4.17 million shares of common stock at a price of $36.00 per share in a private placement to institutional investors pursuant to a Securities Purchase Agreement dated as of February 14, 2007. We used the net proceeds from this offering for debt reduction. As a result of the use of a weighted average methodology to calculate the number of shares outstanding, the dilutive effect of the stock issuance will increase as the year progresses.

27

Consolidated Results

Revenues and Income (Loss) from Continuing Operations provided by each business group were as follows (in thousands):

	Three Months Ended March 31,
	2007		2006
Revenues
Retail services	$	83,719	$	87,503
Wholesale energy		102,813		84,371
Corporate		1		16
	$	186,533	$	171,890
Income (Loss) from Continuing Operations
Retail services	$	9,771	$	6,296
Wholesale energy		22,844		15,144
Corporate		(115)		(2,879)
	$	32,500	$	18,561

Discontinued operations in 2007 and 2006 represent the operations of our crude oil marketing and transportation business. The assets of this business were sold in March 2006.

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Revenues for the three months ended March 31, 2007 increased 9 percent, or $14.6 million, compared to the same period in 2006. Increased revenues were primarily driven by higher margins from our energy marketing activities, higher retail rates at Black Hills Power, and improved revenues from Power generation.

Operating expenses decreased 1 percent, or $1.9 million, primarily due to lower fuel and purchased power costs at the electric and gas utility, and lower operating and maintenance cost at Power generation due to the 2006 outages at the Las Vegas facility, partially offset by increased depreciation and depletion expense.

Income from continuing operations increased $13.9 million due primarily to the following:

•            a $1.8 million increase in Electric utility earnings;

•            a $1.7 million increase in Electric and gas utility earnings;

•            a $6.4 million increase in Energy marketing earnings;

•            a $2.9 million increase in Power generation earnings; and

•            a $2.8 million decrease in unallocated corporate costs,

partially offset by:

•            a $1.8 million decrease in Oil and gas earnings.

28

See the following discussion of our business segments under the captions “Retail Services Group” and “Wholesale Energy Group” for more detail on our results of operations.

The following business group and segment information does not include intercompany eliminations or discontinued operations.

Retail Services Group

Electric Utility

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Revenue	$	47,767	$	43,968
Operating expenses		35,222		33,871
Operating income	$	12,545	$	10,097
Income from continuing operations
and net income	$	6,699	$	4,899

The following tables provide certain operating statistics for the Electric utility segment:

	Electric Revenue
	(in thousands)
	Three Months Ended
	March 31,
			Percentage
Customer Base	2007		Change	2006
Commercial	$	13,105	15%	$	11,422
Residential		12,407	16		10,663
Industrial		5,096	2		5,011
Municipal sales		579	11		520
Total retail sales		31,187	13		27,616
Contract wholesale		6,457	6		6,108
Wholesale off-system		6,582	(20)		8,234
Total electric sales		44,226	5		41,958
Other revenue		3,541	76		2,010
Total revenue	$	47,767	9%	$	43,968

29

	Megawatt Hours Sold
	Three Months Ended
	March 31,
		Percentage
Customer Base	2007	Change	2006
Commercial	166,094	5%	158,593
Residential	152,736	8	141,794
Industrial	99,254	(4)	103,027
Municipal sales	7,420	5	7,059
Total retail sales	425,504	4	410,473
Contract wholesale	165,110	2	162,251
Wholesale off-system	133,849	(26)	180,163
Total electric sales	724,463	(4)%	752,887

	Three Months Ended
	March 31,
	2007	2006
Regulated power
plant fleet availability:
Coal-fired plants	95.3%	97.2%
Other plants	99.9%	99.2%
Total availability	97.3%	98.1%

	Three Months Ended
	March 31,
		Percentage
Resources	2007	Change	2006
MWhs generated:
Coal	440,518	(3)%	454,133
Gas	5,698	158	2,211
	446,216	(2)%	456,344
MWhs purchased	294,463	(6)%	312,287
Total resources	740,679	(4)%	768,631

	Three Months Ended
	March 31,
	2007	2006
Heating and cooling degree days:
Actual
Heating degree days	3,055	2,946
Percent of normal
Heating degree days	93%	90%

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Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $1.8 million primarily due to increased revenues, partially offset by increased fuel and purchased power costs and operating expenses. In addition, wholesale off-system gross margins were flat with the 2006 period.

Electric utility revenues increased 9 percent for the three month period ended March 31, 2007, compared to the same period in the prior year. Higher retail revenues were primarily due to increased rates in South Dakota that became effective January 1, 2007. Total retail MWh sales increased 4 percent compared to the three months ended March 31, 2006 due to colder weather conditions and customer growth. Heating degree days, which is a measure of weather trends, were 4 percent higher than the same period in the prior year. Wholesale off-system sales decreased 20 percent due to a 26 percent decrease in MWhs sold partially offset by an 8 percent increase in average price received. MWhs available for wholesale off-system sales decreased from the prior period due to scheduled plant outages and power transmission constraints to the east of our AC-DC transmission tie, and increased native load.

Electric operating expenses increased 4 percent for the three month period ended March 31, 2007, compared to the same period in the prior year. Fuel and purchased power costs increased 6 percent due to a 5 percent increase in purchased power at average prices that were 11 percent higher than the same period in the prior year and increased fuel production costs, primarily due to higher average coal prices. MWhs generated and purchased decreased 2 percent and 6 percent, respectively, for the three months ended March 31, 2007 compared to the same period in 2006. Operating expense for the three months ended March 31, 2007 was also affected by increased maintenance costs for scheduled outages and increased depreciation expense.

Electric and Gas Utility

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Revenue	$	36,363	$	43,699
Purchased gas and electricity		28,588		36,175
Gross margin		7,775		7,524
Operating expenses		5,328		5,624
Operating income	$	2,447	$	1,900
Income from continuing
operations and net income	$	3,072	$	1,397

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The following tables provide certain operating statistics for the Electric and gas utility segment:

Electric Margins
(in thousands)
	Three Months			Three Months
	Ended			Ended
	March 31,		Percentage	March 31,
Customer Base	2007		Change	2006
Commercial	$	1,816	17%	$	1,555
Residential		2,215	(2)		2,261
Industrial		84	(3)		87
Municipal		144	9		132
Total electric		4,259	6		4,035
Other		28	(70)		94
Total electric margins	$	4,287	4%	$	4,129

Gas Margins
(in thousands)
	Three Months			Three Months
	Ended			Ended
	March 31,		Percentage	March 31,
Customer Base	2007		Change	2006
Commercial	$	926	8%	$	858
Residential		2,185	3		2,131
Industrial		165	(10)		184
Total gas		3,276	3		3,173
Other		212	(5)		222
Total gas margins	$	3,488	3%	$	3,395

	Three Months		Three Months
	Ended		Ended
	March 31,	Percentage	March 31,
	2007	Change	2006
Electric sales - MWh	241,830	4%	232,827
Gas sales-Dth	1,969,585	5%	1,870,454

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	Three Months Ended
	March 31
	2007	2006
Heating and cooling degree days:
Actual
Heating degree days	3,023	2,991
Percent of normal
Heating degree days	96%	95%

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $1.7 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. The increase in income from continuing operations was impacted by income related to AFUDC attributable to the construction of Wygen II, a 90 MW, coal-fired power plant sited at our Wyodak energy complex near Gillette, Wyoming.

Gross margin increased 3 percent primarily due to an increase in sales volumes. We consider gross margin to be a more useful performance measure when looking at our fluctuating financial and statistical figures related to revenue. These fluctuations are a direct result of cost recovery adjustments for electricity and natural gas due to volatile market prices and timing of revenue and expense recognition. Historically, Cheyenne Light has filed an annual adjustment for electricity and more frequent filings for natural gas to manage volatile market price impacts.

Operating expenses decreased 5 percent primarily due to decreased depreciation expense and benefit costs.

Rate Increase Requested. During March 2007, Cheyenne Light filed a rate request with the WPSC. The filing requests general rate increases of $8.4 million for electric rates and $4.6 million for gas rates, based upon rates in place at December 31, 2006. The requested increases also include placing into rate base Wygen II and other capital investments necessary for the expansion and maintenance of both electric and gas distribution systems to accommodate population and energy growth.

Wholesale Energy Group

A discussion of results from our Wholesale Energy group’s operating segments follows:

Oil and Gas

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Revenue	$	25,843	$	25,185
Operating expenses		18,499		15,901
Operating income	$	7,344	$	9,284
Income from continuing operations	$	3,591	$	5,390

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The following tables provide certain operating statistics for our oil and gas segment:

	Three Months Ended
	March 31,
	2007	2006
Fuel production:
Bbls of oil sold	103,415	90,460
Mcf of natural gas sold	2,678,290	2,959,100
Mcf equivalent sales	3,298,780	3,501,860

Production for the three months ended March 31, 2007 was affected by winter weather impacts and lower well performance in the Denver Julesburg Basin. We expect to increase production coming out of the winter season and through additional drilling activity. Drilling activity will be contingent on the issuance of drilling permits and our evaluation of rising costs. We still expect to increase annual production 4-6 percent over the previous year, which is a decrease from our December 31, 2006 estimated growth of 10 percent.

	Three Months Ended
	March 31,
	2007		2006
Average price received*:
Gas/Mcf**	$	7.20	$	6.98
Oil/Bbl	$	52.63	$	45.33
Depletion expense/Mcfe	$	2.04	$	1.62

________________________

   * Net of hedges

** Exclusive of gas liquids

The following is a summary of LOE/Mcfe at March 31:

			2007						2006
			Gathering,						Gathering,
			Compression						Compression
			and						and
Location	LOE		Processing		Total		LOE		Processing		Total
New Mexico	$	1.26	$	0.43	$	1.69	$	1.12	$	0.49	$	1.61
Colorado		1.50		1.27(a)		2.77		1.24		—		1.24
Wyoming		1.11		—		1.11		1.09		—		1.09
All other properties		0.84		0.21		1.05		0.64		0.17		0.81
All locations	$	1.13	$	0.32	$	1.45	$	0.93	$	0.26	$	1.19

(a) Reflects the expenses associated with Colorado acquisitions completed in 2006 which included underutilized gathering, processing and compression assets. It is anticipated that future development of these properties will increase the capacity utilization rate of these gathering and processing assets and the per unit cost will decrease.

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Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations decreased 33 percent in the three months ended March 31, 2007 compared to the same period in 2006 due to increased production expenses, depletion expense and increased interest expense due to higher borrowings to fund acquisitions and development costs, partially offset by increased revenues.

Revenue increased 3 percent for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. Gas production decreased 9 percent and the average hedged gas price received increased 3 percent. Oil production increased 14 percent and average hedged oil price received increased 16 percent.

Total operating expenses increased 16 percent for the three month period ended March 31, 2007 primarily due to increased field service costs and depletion expense. The LOE per Mcfe sold (LOE/Mcfe) increased 22 percent primarily due to changing property mix with the 2006 acquisitions and increased repair and weather-related costs incurred in 2007. Depletion expense per Mcfe increased 26 percent. The average depletion rate per Mcfe is a function of capitalized costs, projected future development costs and the related underlying reserves in the periods presented. The increased depletion rate is due to increases in current year finding costs and higher estimated future development costs as well as the higher average cost of reserves acquired in March 2006 and their future development costs.

Power Generation

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Revenue	$	39,566	$	33,593
Operating expenses		25,130		24,039
Operating income	$	14,436	$	9,554
Income from continuing operations	$	4,979	$	2,092

The following table provides certain operating statistics for our power generation segment:

	Three Months Ended
	March 31,
	2007	2006
Contracted power plant fleet availability:
Coal-fired plant	98.8%	91.8%
Other plants	95.5%	85.5%
Total availability	96.1%	85.7%

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Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $2.9 million. Revenues in the first quarter of 2007 increased

18 percent compared to revenues in the first quarter of 2006 primarily due to the return of the Las Vegas facilities to full operations. In the first three months of 2006 the Las Vegas plants experienced scheduled and unscheduled repair outages.

Operating expenses for the three months ended March 31, 2007, increased $1.1 million from the same period in the prior year. The increase in operating expenses primarily resulted from increased variable operating costs and increased fuel costs at the Las Vegas I plant partially offset by lower maintenance costs compared to costs incurred for repairs of the Las Vegas facilities in 2006.

Coal Mining

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Revenue	$	9,745	$	9,270
Operating expenses		8,128		7,655
Operating income	$	1,617	$	1,615
Income from continuing operations	$	1,615	$	1,415

The following table provides certain operating statistics for our coal mining segment:

	Three Months Ended
	March 31,
	2007	2006
	(in thousands)
Fuel production:
Tons of coal sold	1,212	1,223

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006.

Income from continuing operations from our Coal mining segment increased 14 percent. Revenue increased 5 percent for the three month period ended March 31, 2007 compared to the same period in 2006 due to an increase in average price received partially offset by lower tons of coal sold. Operating expenses increased 6 percent during the three months ended March 31, 2007 primarily due to increased overburden removal expense, increased depreciation expense and increased general and administrative expense partially offset by lower mineral taxes.

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Energy Marketing

	Three Months Ended
	March 31,
	2007		2006
	(in thousands)
Revenue	$	28,437		$	16,957
Operating expenses		8,987			7,206
Operating income	$	19,450		$	9,751
Income from continuing operations	$	12,659		$	6,247

The following is a summary of average daily energy marketing volumes:

	Three Months Ended
	March 31,
	2007	2006
Natural gas physical sales – MMBtus	1,898,630	1,275,900
Crude oil physical sales – Bbls(a)	6,050	—

____________________

^(a) Daily oil volumes are calculated beginning May 1, 2006 to reflect the start of crude oil marketing by Enserco out of our Golden, Colorado offices.

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $6.4 million due to increased realized marketing margins and increased unrealized marketing gains.

Realized gas marketing margins increased approximately $6.3 million over the prior year due to a 49 percent increase in natural gas volumes marketed, partially offset by a lower margin per MMBtu sold. Unrealized mark-to-market gains increased $5.1 million over unrealized mark-to-market gains for the same period in 2006. Opportunities generated by existing market conditions allowed for the marketing of additional natural gas volumes, compared to the three months ended in March 2006. Colder winter weather increased demand from utility customers and we were able to purchase additional volumes within our credit limits, due to lower overall market prices. In addition, due to the volatility of natural gas markets, we were able to take advantage of seasonal price spreads and price differentials between the Rocky Mountain and other regions. (For discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas and oil marketing operations, see “Trading Activities” in Part 1, Item 3 of this Form 10-Q.) Results also reflect earnings from the addition of crude oil marketing to our Rocky Mountain region producer services. Operating expenses increased primarily due to increased compensation cost related to higher realized margins partially offset by a decrease in the bad debt provision.

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Corporate

Decreased costs in the three months ended March 31, 2007, compared to the same period in 2006, are primarily the result of increased allocation of interest costs and the capitalization of approximately $2.0 million of certain acquisition costs in the current period related to the pending purchase of certain Aquila assets, and the expensing of development costs in the same period ended March 31, 2006 associated with our activities related to Northwestern Corporation.

Critical Accounting Policies

There have been no other material changes in our critical accounting policies from those reported in our 2006 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 2006 Annual Report on Form 10-K.

Liquidity and Capital Resources

Cash Flow Activities

During the three month period ended March 31, 2007, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on our common stock, to pay our scheduled long-term debt maturities and to fund our property, plant and equipment additions. We plan to fund future property and investment additions including our pending acquisition of certain electric and gas utility assets of Aquila and the construction costs of the 149 MW, simple-cycle gas turbine generation facility to be located near Albuquerque, New Mexico through a combination of new equity, mandatory convertible securities, unsecured debt at the holding company level and internally generated cash resources.

Cash flows from operations increased $19.3 million for the three month period ended March 31, 2007 compared to the same period in the prior year as a $13.9 million increase in income from continuing operations was affected by the following:

•            A $20.6 million increase in cash flows from working capital changes. This increase primarily resulted from changes in net accounts receivable and accounts payable and a $4.5 million increase in cash flows from sales or purchases of materials, supplies and fuel. This is primarily related to natural gas held in storage by our natural gas and crude oil marketing business which fluctuates based on economic decisions reflecting current market conditions.

•            An $8.8 million increase in cash flows related to deferred income taxes. This increase was primarily the result of accelerated deductions associated with property, plant and equipment, the timing of deductions related to deferred energy costs and derivative transactions with respect to marketing operations.

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During the three months ended March 31, 2007, we had cash outflows from investing activities of $37.7 million, which was primarily due to the following:

•            Cash outflows of $38.6 million for property, plant and equipment additions. In addition to expenditures for property, plant and equipment in the normal course of business, these outflows include approximately $18.9 million related to the construction of our Wygen II power plant.

During the three months ended March 31, 2007, we had net outflows of cash used for financing activities of $14.3 million, primarily due to a $145.5 million payment on our credit facility, the payment of cash dividends on common stock, as well as payment of long-term debt maturities, partially offset by cash proceeds of $146.6 million from the issuance of common stock.

Dividends

Dividends paid on our common stock totaled $11.4 million during the three months ended March 31, 2007, or $0.34 per share. This reflects a 3 percent increase, as approved by our board of directors in January 2007, from the 2006 dividend level. 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

On February 22, 2007, we completed the issuance and sale of approximately 4.17 million shares of our common stock, par value $1.00 per share, at a sale price of $36.00 per share, in a private placement to institutional investors. Net proceeds of approximately $145.6 million were used for the pay down of our revolving bank facility.

Our principal sources of short-term liquidity are our revolving bank facility and cash provided by operations. Our liquidity position remained strong during the first three months of 2007. As of March 31, 2007, we had approximately $77.8 million of cash unrestricted for operations. Approximately $3.0 million of the cash balance at March 31, 2007 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company.

Our $400 million revolving bank facility has a five year term, expiring May 4, 2010. The cost of borrowings or letters of credit issued under the new facility is determined based on our credit ratings. At our current ratings levels, the facility has an annual facility fee of 17.5 basis points, and has a borrowing spread of 0.70 basis points over LIBOR (which equates to a 6.02 percent one-month borrowing rate as of March 31, 2007).

On March 13, 2007, we entered into a second amendment of our revolving bank facility. The second amendment (i) increased the limit for borrowings or other credit accommodations for the separate credit facility for our energy marketing subsidiary from $260 million to $300 million, (ii) increased the allowed total commitments under the facility without requiring amendment of the facility from $500 million to $600 million, (iii) effective with the acquisition of certain electric and gas utility assets from Aquila, will increase the recourse leverage ratio limit from 0.65 to 1.00 to 0.70 to 1.00 for the first year after completion of the Aquila asset acquisition, reverting to 0.65 to 1.00 thereafter, and (iv) allowed for other modifications to enable us to complete the Aquila asset acquisition.

39

Our revolving credit facility can be used to fund our working capital needs and for general corporate purposes. At March 31, 2007, we had no borrowings and $50.2 million of letters of credit issued on our revolving credit facility with a remaining available capacity of $349.8 million.

The bank facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and maintenance of the following financial covenants:

•            a consolidated net worth in an amount of not less than the sum of $625 million and 50 percent of our aggregate consolidated net income beginning January 1, 2005;

•            a recourse leverage ratio not to exceed 0.65 to 1.00, (or 0.70 to 1.00 for the first year after the Aquila acquisition); and

•            an interest expense coverage ratio of not less than 2.5 to 1.0.

If these covenants are violated, it would be considered an event of default entitling the lenders to terminate the remaining commitment and accelerate all principal and interest outstanding.

A default under the bank facility may be triggered by events such as a failure to comply with financial covenants or certain other covenants under the bank facility, 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 $20 million or more. A default under the bank facility would permit the participating banks to restrict our ability to further access the credit facility for loans or new letters of credit, require the immediate repayment of any outstanding loans with interest and require the cash collateralization of outstanding letter of credit obligations.

The bank facility prohibits us from paying cash dividends unless no default or no event of default exists prior to, or would result, after giving effect to such action.

Our consolidated net worth was $949.8 million at March 31, 2007, which was approximately $251.4million in excess of the net worth we were required to maintain under the bank facility. Our long-term debt ratio at March 31, 2007 was 38.8 percent, our total debt leverage (long-term debt and short-term debt) was 40.3 percent, our recourse leverage ratio was approximately 41.1 percent and our interest expense coverage ratio was 5.61 to 1.0.

In addition, Enserco, our energy marketing segment, has a $260 million uncommitted, discretionary line of credit to provide support for the purchase and sale of natural gas and crude oil. The line of credit is secured by all of Enserco’s assets and expires on May 11, 2007. At March 31, 2007, there were outstanding letters of credit issued under the facility of $161.7 million, with no borrowing balances outstanding on the facility. We expect to renew the facility prior to expiration with an increased total commitment level of $300.0 million.

Our corporate credit rating by Moody’s was “Baa3”during the first three months of 2007; the outlook is negative. Our corporate credit rating by S&P was “BBB-;” the outlook is stable.

On April 30, 2007, we called our outstanding debt with GE Capital in the amount of $23.5 million. In conjunction with this, we expensed less than $0.1 million in unamortized deferred finance costs. The associated payment guarantees provided by us were also terminated.

40

On May 7, 2007, the Company entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and various other banks to provide for funding for the Company’s pending acquisition of Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount of up to $1.0 billion. The commitment to fund the acquisition term loan terminates on August 5, 2008. Upon funding of the loan, the loan termination date is the earlier of the date which is 364 days from the loan funding date or February 5, 2009.

The Acquisition Facility includes conditions precedent to funding which include consummation of the Aquila acquisition substantially in accordance with the existing asset purchase agreement. Borrowings under the term loan can be made under a base rate option, which is based on the then-current prime rate, or under a LIBOR option, which is based on the then-current LIBOR plus an applicable margin. The applicable margin for LIBOR borrowings is 55 basis points during the period from the initial funding under the term loan to six months thereafter, 67.5 basis points during the period from six months and one day after the initial funding to nine months thereafter, and 92.5 basis points during the period from nine months and one day after the initial funding until the loan maturity. The facility also includes certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.

Permanent financing to replace the Acquisition Facility for funding the $940.0 million purchase price and for related other costs of the acquisition of the Aquila assets is expected to be provided through a combination of new equity, mandatory convertible securities, unsecured debt at the holding company level and internally generated cash resources.

Our ability to obtain additional financing, if necessary, will depend upon a number of factors, including our future performance and financial results, and capital market conditions. We can provide no assurance that we will be able to raise additional capital on reasonable terms or at all.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2006 Annual Report on Form 10-K filed with the SEC.

Capital Requirements

During the three months ended March 31, 2007, capital expenditures were approximately $64.5 million for property, plant and equipment additions, which includes approximately $25.9 million of accrued liabilities. We currently expect capital expenditures for the entire year 2007 to approximate $168.0 million, excluding the (a) $940.0 million purchase price and related other costs for the pending acquisition of Aquila utility assets; and (b) the $101.0 million total cost of the 149 MW, simple-cycle gas turbine generating facility to be located near Albuquerque, New Mexico, to be completed by June 2008.

We continue to actively evaluate potential future acquisitions and other growth opportunities in accordance with our disclosed business strategy. We are not obligated to a project until a definitive agreement is entered into and cannot guarantee we will be successful on any potential projects. Future projects are dependent upon the availability of economic opportunities and, as a result, actual expenditures may vary significantly from forecasted estimates.

41

New Accounting Pronouncements

Other than the new pronouncements reported in our 2006 Annual Report on Form 10-K filed with the SEC and those discussed in Notes 2 and 3 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment.

42

SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q 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. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Item 1A. of Part I of our 2006 Annual Report on Form 10-K and in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:

•     Our ability to obtain adequate cost recovery for our retail utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel and purchased power in our regulated utilities;

•     Our ability to complete acquisitions for which definitive agreements have been executed;

•     Our ability to obtain regulatory approval of acquisitions which, even if approved, could impose financial and operating conditions or restrictions that could impact our expected results;

•     Our ability to successfully integrate and profitably operate any future acquisitions;

•     The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock;

•     Our ability to successfully maintain or improve our corporate credit rating;

•     Our ability to complete the permitting, construction, start up and operation of power generating facilities in a cost-effective and timely manner;

•     Our ability to meet production targets for our oil and gas properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;

•     Our ability to provide accurate estimates of proved oil and gas reserves, coal reserves and actual future production rates and associated costs;

•     The extent of our success in connecting natural gas supplies to gathering, processing and pipeline systems;

•     The timing and extent of scheduled and unscheduled outages of power generation facilities;

•     The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

43

•     Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005;

•     Our ability to remedy any deficiencies that may be identified in the review of our internal controls;

•     The timing, volatility and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost and availability of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets;

•     Our ability to effectively use derivative financial instruments to hedge commodity, currency exchange rate and interest rate risks;

•     Our ability to minimize defaults on amounts due from counterparties with respect to trading and other transactions;

•     The amount of collateral required to be posted from time to time in our transactions;

•     Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;

•     Changes in state laws or regulations that could cause us to curtail our independent power production;

•     Weather and other natural phenomena;

•     Industry and market changes, including the impact of consolidations and changes in competition;

•     The effect of accounting policies issued periodically by accounting standard-setting bodies;

•     The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events;

•     The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements;

•     Capital market conditions, which may affect our ability to raise capital on favorable terms;

•     Price risk due to marketable securities held as investments in benefit plans;

•     General economic and political conditions, including tax rates or policies and inflation rates; and

•     Other factors discussed from time to time in our other filings with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Trading Activities

The following table provides a reconciliation of our activity in energy trading contracts that meet the definition of a derivative under SFAS 133 and that were marked-to-market during the three months ended March 31, 2007 (in thousands):

Total fair value of energy marketing positions marked-to-market at December 31, 2006	$	(1,454)
Net cash settled during the period on positions that existed at December 31, 2006		5,730
Unrealized gain on new positions entered during the period and still existing at
March 31, 2007		5,720
Realized loss on positions that existed at December 31, 2006 and were settled during
the period		(3,833)
Unrealized gain on positions that existed at December 31, 2006 and still exist at
March 31, 2007		1,314
Total fair value of energy marketing positions at March 31, 2007	$	7,477

_____________________________

(a) The fair value of positions marked-to-market consists of derivative assets/liabilities and natural gas inventory that has been designated as a hedged item and marked-to-market as part of a fair value hedge, as follows (in thousands):

	March 31,		December 31,
	2007		2006
Net derivative assets	$	5,029	$	30,059
Fair value adjustment recorded
in material, supplies and fuel		2,448		(31,513)
	$	7,477	$	(1,454)

GAAP restricts mark-to-market accounting treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. Therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities and our expected cash flows from energy trading activities. At our natural gas and crude oil marketing operations, we often employ strategies that include utilizing derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow us to mark our inventory, transportation or storage positions to market. The result is that while a significant majority of our energy marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.

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The sources of fair value measurements were as follows (in thousands):

	Maturities
Source of Fair Value	Less than 1 year		1 – 2 years		Total Fair Value
Actively quoted (i.e., exchange-traded) prices	$	614	$	1	$	615
Prices provided by other external sources		7,229		(367)		6,862
Modeled		—		—		—
Total	$	7,843	$	(366)	$	7,477

The following table presents a reconciliation of our March 31, 2007 energy marketing positions recorded at fair value under GAAP to a non-GAAP measure of the fair value of our energy marketing forward book wherein all forward trading positions are marked-to-market (in thousands). In accordance with GAAP and industry practice, the Company includes a “Liquidity Reserve” in its GAAP marked-to-market fair value. This “Liquidity Reserve” accounts for the estimated impact of the bid/ask spread in a liquidation scenario under which the Company is forced to liquidate its forward book on the balance sheet date.

Fair value of our energy marketing positions marked-to-market in accordance with GAAP
(see footnote (a) above)	$	7,477
Increase in fair value of inventory, storage and transportation positions that are
part of our forward trading book, but that are not marked-to-market under GAAP		25,218
Fair value of all forward positions (Non-GAAP)		32,695
“Liquidity Reserve” included in GAAP marked-to-market fair value		1,942
Fair value of all forward positions excluding the “Liquidity Reserve” (Non-GAAP)	$	34,637

There have been no material changes in market risk faced by us from those reported in our 2006 Annual Report on Form 10-K filed with the SEC. For more information on market risk, see Part II, Items 7 and 7A. in our 2006 Annual Report on Form 10-K, and Note 12 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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Activities Other Than Trading

The Company has entered into agreements to hedge a portion of its estimated 2007, 2008 and 2009 natural gas and crude oil production. The hedge agreements in place are as follows:

Natural Gas

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(MMBtu/day)
San Juan El Paso	04/03/2006	Swap	04/07 – 10/07	5,000	$	7.46
San Juan El Paso	06/02/2006	Swap	04/07 – 10/07	2,500	$	7.20
San Juan El Paso	11/03/2006	Swap	04/07 – 10/07	5,000	$	6.91
San Juan El Paso	11/03/2006	Swap	11/07 – 03/08	5,000	$	7.86
CIG	07/28/2006	Swap	09/06 – 03/08	2,500	$	7.60
CIG	07/31/2006	Swap	09/06 – 03/08	2,500	$	7.85
San Juan El Paso	11/29/2006	Swap	04/07 – 10/07	500	$	7.10
San Juan El Paso	11/29/2006	Swap	11/07 – 12/07	5,000	$	7.82
San Juan El Paso	11/29/2006	Swap	01/08 – 12/08	5,000	$	7.44
San Juan El Paso	11/29/2006	Swap	11/07 – 12/08	3,000	$	7.49
San Juan El Paso	01/04/2007	Swap	04/08 – 03/09	2,500	$	6.93
San Juan El Paso	01/04/2007	Swap	04/08 – 03/09	1,000	$	6.96
San Juan El Paso	01/05/2007	Swap	01/09 – 03/09	1,500	$	7.51
San Juan El Paso	01/10/2007	Swap	04/08 – 12/08	1,500	$	6.88
San Juan El Paso	01/11/2007	Swap	04/08 –12/08	2,000	$	6.81
San Juan El Paso	02/12/2007	Swap	01/09 – 03/09	5,000	$	7.87

Crude Oil

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(Bbls/month)
NYMEX	07/29/2005	Swap	Calendar 2007	5,000	$	61.00
NYMEX	08/04/2005	Swap	Calendar 2007	5,000	$	62.00
NYMEX	01/04/2006	Swap	Calendar 2007	5,000	$	65.00
NYMEX	04/03/2006	Put	Calendar 2007	5,000	$	70.00
NYMEX	01/30/2007	Swap	Calendar 2008	5,000	$	61.38
NYMEX	02/20/2007	Put	Calendar 2008	5,000	$	60.00
NYMEX	03/07/2007	Swap	Calendar 2008	5,000	$	67.34
NYMEX	03/23/2007	Swap	01/09 – 03/09	5,000	$	67.60
NYMEX	03/26/2007	Put	Calendar 2008	5,000	$	63.00
NYMEX	03/28/2007	Swap	01/09 – 03/09	5,000	$	69.00
NYMEX	04/12/2007	Put	01/09 – 03/09	5,000	$	65.00

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ITEM 4.CONTROLS AND PROCEDURES

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, 2007. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the required time periods.

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2007 that 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 18 in Item 8 of the Company’s 2006 Annual Report on Form 10-K and Note 13 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 13 is incorporated by reference into this item.

Item 1A. Risk Factors

There have been no material changes in our Risk Factors from those reported in Item 1A. of Part I of our 2006 Annual Report on Form 10-K filed with the SEC.

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

Unregistered Sales of Equity Securities

Sales as previously reported on Form 8-K filed February 22, 2007.

Issuer Purchases of Equity Securities

					Maximum
				Total	Number (or
				Number	Approximate
				of Shares	Dollar
	Total			Purchased as	Value) of Shares
	Number			Part of Publicly	That May Yet Be
	of	Average		Announced	Purchased Under
	Shares	Price Paid		Plans	the Plans
Period	Purchased	per Share		or Programs	or Programs
January 1, 2007 – January 31, 2007	7,153 (1)	$	37.11	—		—
February 1, 2007 – February 28, 2007	—	$	—	—		—
March 1, 2007 –   March 31, 2007	1,537 (2)	$	36.71	—		—
Total	8,690	$	37.04	—		—

___________________________

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

(2) 1,248 shares acquired under the share withholding provisions of the Restricted Stock Plan as described in (1) above and 289 shares acquired by a Rabbi Trust for the Outside Directors Stock Based Compensation Plan.

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Item 5. Other Information

On May 7, 2007, the Company entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and various other banks to provide for funding for the Company’s pending acquisition of Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount of up to $1.0 billion. The commitment to fund the acquisition term loan terminates on August 5, 2008. Upon funding of the loan, the loan termination date is the earlier of the date which is 364 days from the loan funding date or February 5, 2009.

The Acquisition Facility includes conditions precedent to funding which include consummation of the Aquila acquisition substantially in accordance with the existing asset purchase agreement. Borrowings under the term loan can be made under a base rate option, which is based on the then-current prime rate, or under a LIBOR option, which is based on the then-current LIBOR plus an applicable margin. The applicable margin for LIBOR borrowings is 55 basis points during the period from the initial funding under the term loan to six months thereafter, 67.5 basis points during the period from six months and one day after the initial funding to nine months thereafter, and 92.5 basis points during the period from nine months and one day after the initial funding until the loan maturity. The facility also includes certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.

Permanent financing to replace the Acquisition Facility for funding the $940.0 million purchase price and for related other costs of the acquisition of the Aquila assets is expected to be provided through a combination of new equity, mandatory convertible securities, unsecured debt at the holding company level and internally generated cash resources.

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Item 6.	Exhibits
		Exhibit 2.2*	Agreement and Plan of Merger among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp. and Black Hills Corporation dated as of February 6, 2007 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on February 8, 2007).
		Exhibit 10.1*†	2007 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on February 5, 2007).
		Exhibit 10.2*	Commitment Letter between Black Hills Corporation and ABN AMRO BANK, N.V. and certain other financial institutions dated as of February 6, 2007 (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on February 8, 2007).
		Exhibit 10.3*	Partnership Interests Purchase Agreement among Aquila, Aquila Colorado, LLC, Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated as of February 6, 2007 (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on February 8, 2007).
		Exhibit 10.4*	Asset Purchase Agreement among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated as of February 6, 2007 (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on February 8, 2007).
		Exhibit 10.5*	Securities Purchase Agreement by and among Black Hills Corporation and the Purchasers set forth therein, dated as of February 14, 2007 (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on February 22, 2007).
		Exhibit 10.6*	Registration Rights Agreement by and among Black Hills Corporation and the Purchasers set forth therein, dated as of February 22, 2007 (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on February 22, 2007).
		Exhibit 31.1	Certification 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 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 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

__________________________

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

† Indicates a board of director or management compensatory plan.

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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/ Mark T. Thies
	Mark T. Thies, Executive Vice President and
	Chief Financial Officer
Dated: May 10, 2007

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EXHIBIT INDEX

Exhibit Number	Description
Exhibit 2.2*	Agreement and Plan of Merger among Aquila, Inc., Great Plains Energy Incorporated, Gregory Acquisition Corp. and Black Hills Corporation dated as of February 6, 2007 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on February 8, 2007).
Exhibit 10.1*†	2007 Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on February 5, 2007).
Exhibit 10.2*	Commitment Letter between Black Hills Corporation and ABN AMRO BANK, N.V. and certain other financial institutions dated as of February 6, 2007 (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on February 8, 2007).
Exhibit 10.3*	Partnership Interests Purchase Agreement among Aquila, Aquila Colorado, LLC, Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated as of February 6, 2007 (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on February 8, 2007).
Exhibit 10.4*	Asset Purchase Agreement among Aquila, Inc., Black Hills Corporation, Great Plains Energy Incorporated and Gregory Acquisition Corp., dated as of February 6, 2007 (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on February 8, 2007).
Exhibit 10.5*	Securities Purchase Agreement by and among Black Hills Corporation and the Purchasers set forth therein, dated as of February 14, 2007 (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on February 22, 2007).
Exhibit 10.6*	Registration Rights Agreement by and among Black Hills Corporation and the Purchasers set forth therein, dated as of February 22, 2007 (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on February 22, 2007).
Exhibit 31.1	Certification 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 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 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

__________________________

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

† Indicates a board of director or management compensatory plan.

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