United States
Securities and Exchange Commission
Washington, D.C. 20549

Form 10-Q

X	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003.

___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 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___

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes X No___

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, 2003

Common stock, $1.00 par value 32,063,278 shares

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements
Condensed Consolidated Statements of Income -
Three Months Ended March 31, 2003 and 2002	3
Condensed Consolidated Balance Sheets -
March 31, 2003, December 31, 2002 and March 31, 2002	4
Condensed Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2003 and 2002	5
Notes to Condensed Consolidated Financial Statements	6-	26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27-	40
Item 3. Quantitative and Qualitative Disclosures about Market Risk	41
Item 4. Controls and Procedures	42
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	43
Item 2. Changes in Securities and Use Of Proceeds	43
Item 6. Exhibits and Reports on Form 8-K	44
Signatures	45-	46
Certifications	47-	50
Exhibit Index	51

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

	Three Months Ended
	March 31
	2003			2002
	(in thousands, except per share amounts)
Operating revenues	$	299,332		$	170,635

Operating expenses:
Fuel and purchased power		189,862			87,034
Operations and maintenance		24,056			17,277
Administrative and general		18,327			12,799
Depreciation, depletion and amortization		20,511			15,862
Taxes, other than income taxes		7,808			6,285

		260,564			139,257
Equity in earnings of unconsolidated affiliates		456			1,162

Operating income		39,224			32,540

Other income (expense):
Interest expense		(14,082	)		(9,621	)
Interest income		173			598
Other expense		(132	)		--
Other income		316			1,568

		(13,725	)		(7,455	)

Income before minority interest, income taxes,
discontinued operations and change in accounting principles		25,499			25,085
Minority interest		72			(2,266	)
Income taxes		(8,713	)		(7,927	)

Income from continuing operations		16,858			14,892
Loss from discontinued operations, net of taxes		--			(1,724	)
Change in accounting principles, net of taxes		(2,680	)		896

Net income		14,178			14,064
Preferred stock dividends		(57	)		(56	)

Net income available for common stock	$	14,121		$	14,008

Weighted average common shares outstanding:
Basic		27,041			26,694

Diluted		27,411			26,968

Earnings per share:
Basic-
Continuing operations	$	0.62		$	0.55
Discontinued operations		--			(0.06	)
Change in accounting principles		(0.10	)		0.03

Total	$	0.52		$	0.52

Diluted-
Continuing operations	$	0.62		$	0.55
Discontinued operations		--			(0.06	)
Change in accounting principles		(0.10	)		0.03

Total	$	0.52		$	0.52

Dividends paid per share of common stock	$	0.30		$	0.29

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

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)

	March 31			December 31			March 31
	2003			2002			2002
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	68,341		$	79,811		$	66,096
Restricted cash		1,070			1,070			--
Securities available-for-sale		--			--			3,331
Receivables (net of allowance for doubtful accounts of $3,929,
$3,860 and $4,242, respectively) -		293,045			209,144			136,504
Notes receivable		554			35,135			1,952
Materials, supplies and fuel		23,482			24,720			18,558
Derivative assets		33,868			36,393			22,536
Deferred income taxes		142			6,017			--
Other assets		7,630			8,020			14,493
Assets of discontinued operations		--			--			5,912

		428,132			400,310			269,382

Investments		20,284			18,707			17,398

Property, plant and equipment		1,969,110			1,890,266			1,713,476
Less accumulated depreciation and depletion		(428,179	)		(414,003	)		(374,779	)

		1,540,931			1,476,263			1,338,697

Other assets:
Derivatives assets		495			2,406			7,178
Goodwill		33,694			33,685			30,176
Intangible assets		77,023			78,089			95,027
Other		25,228			25,709			19,014

		136,440			139,889			151,395

	$	2,125,787		$	2,035,169		$	1,776,872

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	262,884		$	207,047		$	123,237
Accrued liabilities		82,630			53,753			49,849
Current maturities of long-term debt		24,916			23,448			42,115
Notes payable		336,517			340,500			389,228
Derivative liabilities		42,079			46,557			29,389
Liabilities of discontinued operations		--			--			6,367

		749,026			671,305			640,185

Long-term debt, net of current maturities		616,895			618,862			465,097

Deferred credits and other liabilities:
Federal income taxes		123,081			132,270			75,643
Derivative liabilities		10,851			8,419			6,289
Other		64,066			62,696			42,798

		197,998			203,385			124,730

Minority interest in subsidiaries		6,216			6,454			21,168

Stockholders' equity:
Preferred stock - no par Series 2000-A; 21,500 shares authorized;
Issued and Outstanding: 5,177 shares		5,549			5,549			5,549

Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized;
Issued: 27,627,211, 27,102,351 and 26,997,090 shares,
respectively		27,627			27,102			26,997
Additional paid-in capital		259,878			246,997			244,289
Retained earnings		286,655			280,628			256,775
Treasury stock, at cost		(3,850	)		(3,921	)		(4,466	)
Accumulated other comprehensive loss		(20,207	)		(21,192	)		(3,452	)

		550,103			529,614			520,143

Total stockholders' equity		555,652			535,163			525,692

	$	2,125,787		$	2,035,169		$	1,776,872

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

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

	Three Months Ended
	March 31
	2003			2002
	(in thousands)
Operating activities:
Net income available for common	$	14,121		$	14,008
Adjustments to reconcile net income available for common to net cash
provided by operating activities:
Loss from discontinued operations		--			1,724
Provision for valuation allowances		11			(1,795	)
Depreciation, depletion and amortization		20,511			15,862
Net change in derivative assets and liabilities		(333	)		1,736
Deferred income taxes		2,965			(170	)
Undistributed earnings of unconsolidated affiliates		(336	)		(1,846	)
Minority interest		(72	)		2,266
Accounting change		2,680			(896	)
Change in operating assets and liabilities-
Accounts receivable and other current assets		(82,119	)		(24,472	)
Accounts payable and other current liabilities		78,954			36,721
Other operating activities		(1,078	)		(4,906	)

		35,304			38,232

Investing activities:
Property, plant and equipment additions		(25,238	)		(57,585	)
Payment for acquisition of net assets, net of cash acquired		--			(23,229	)
Increase in notes receivable - Mallon Resources		(5,164	)		--
Other investing activities		(637	)		(1,795	)

		(31,039	)		(82,609	)

Financing activities:
Dividends paid on common stock		(8,094	)		(7,749	)
Treasury stock sold, net		71			1,037
Common stock issued		1,233			2,941
(Decrease) increase in short-term borrowings, net		(3,983	)		28,778
Long-term debt - issuance		--			60,435
Long-term debt - repayments		(4,568	)		(4,925	)
Subsidiary distributions to minority interests		(394	)		--

		(15,735	)		80,517

(Decrease) increase in cash and cash equivalents		(11,470	)		36,140
Cash and cash equivalents:
Beginning of period		79,811			29,956

End of period	$	68,341		$	66,096

Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest (net of capitalized interestof $2,936 and $578 respectively)	$	15,664		$	9,466
Income taxes, net	$	137		$	500
Non-cash net assets acquired through issuance of common stock and
decrease in notes receivable - Mallon Resources	$	51,153		$	--

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

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's 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 Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States 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 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

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, 2003, December 31, 2002 and March 31, 2002, financial information and are of a normal recurring nature. The results of operations for the three months ended March 31, 2003, 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)	STOCK BASED COMPENSATION

At March 31, 2003, the Company has three stock-based employee compensation plans under which it can issue stock options to its employees. The Company accounts for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock Issued to Employees (APB 25)," and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation (SFAS 123)," to stock-based employee compensation as of March 31 (in thousands, except per share amounts):

	Three Months Ended
	March 31
	2003			2002
Net income available for common stock, as reported	$	14,121		$	14,008
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards, net of
related tax effects		(242	)		(263	)

Pro forma net income	$	13,879		$	13,745

Earnings per share:
As reported--
Basic
Continuing operations	$	0.62		$	0.55
Discontinued operations		--			(0.06	)
Change in accounting principle		(0.10	)		0.03

Total	$	0.52		$	0.52

Diluted
Continuing operations	$	0.62		$	0.55
Discontinued operations		--			(0.06	)
Change in accounting principle		(0.10	)		0.03

Total	$	0.52		$	0.52

Pro forma--
Basic
Continuing operations	$	0.61		$	0.54
Discontinued operations		--			(0.06	)
Change in accounting principle		(0.10	)		0.03

Total	$	0.51		$	0.51

Diluted
Continuing operations	$	0.61		$	0.54
Discontinued operations		--			(0.06	)
Change in accounting principle		(0.10	)		0.03

Total	$	0.51		$	0.51

(3) RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

SFAS 143

The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”(SFAS 143) effective January 1, 2003. SFAS 143 provides accounting and disclosure requirements for retirement obligations associated with long-lived assets. SFAS 143 requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation have been recognized for the time period from the date the liability would have been recognized had the provisions of SFAS 143 been in effect, to the date of its adoption. The cumulative effect of initially applying SFAS 143 is recognized as a change in accounting principle.

The Company completed a detailed review of the specific applicability and implications of SFAS 143. The review identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in our Oil and Gas segment and reclamation of our coal mining sites in our Mining segment.

Upon adoption, the Company recorded a $2.9 million transition adjustment to properly reflect its asset retirement obligations in accordance with the provisions of SFAS 143. The transition adjustment represents the current estimated fair value of the Company’s obligation to plug its oil and gas wells at the time of abandonment and an adjustment to its liability for reclaiming its coal mining sites following completion of mining activity. These activities were previously accounted for under the provisions of SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and other industry practices and reported on the Company’s consolidated balance sheet. The cumulative effect on earnings of adopting SFAS 143 was a benefit of approximately $0.2 million representing the cumulative amounts of depreciation and changes in the asset retirement obligation due to the passage of time for historical accounting periods.

The following table presents the details of the Company’s asset retirement obligations which are included on the accompanying condensed consolidated balance sheet in “Other” under “Deferred Credits and Other Liabilities” (in thousands):

	Balance at 12/31/02			SFAS 143 Transition Adjustment			Liabilities Incurred	Liabilities Settled	Accretion		Cash Flow Revisions	Balance at 3/31/03

Oil and Gas	$	--		$	6,133		$ --(b)	$ --	$	102	$ --	$	6,235
Mining		18,513	(a)		(3,214	)	--	--		246	--		15,545

Total	$	18,513		$	2,919		$ --	$ --	$	348	$ --	$	21,780

(a)

December 31, 2002 balance for coal mine reclamation liability as previously accounted for under a cost-accumulation approach.

(b)

The Company incurred certain asset retirement obligations with its acquisition of Mallon Resources completed on March 10, 2003. As described in Note 14, the preliminary purchase price allocation for this acquisition did not include estimates to quantify the asset retirement obligations and will be adjusted in future periods when an analysis in accordance with SFAS 143 can be completed.

Pro forma net income, earnings per share and liabilities have not been presented for prior periods because the pro forma application of SFAS 143 to prior periods would result in pro forma net income, earnings per share and liabilities not materially different from the actual amounts reported for those periods in the accompanying Condensed Consolidated Statements of Income and Balance Sheets.

EITF 02-3

During 2002, the Emerging Issues Task Force (EITF) issued EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). EITF 98-10, “Accounting for Contracts Involving Energy Trading and Risk Management Activities” (EITF 98-10), required that energy trading contracts be accounted for at fair value. EITF 02-3 rescinded Issue No. 98-10 effective for any new contracts entered into after October 25, 2002. For energy trading contracts entered into on or before October 25, 2002, such contracts continued to be accounted for at fair value through December 31, 2002. Effective January 1, 2003, contracts that did not meet the accounting definition of a derivative, as defined by SFAS 133 “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), are required to be accounted for at historical cost. The Company’s energy contracts that qualify as derivatives continue to be accounted for at fair value under SFAS 133, unless those contracts meet the “normal purchase/normal sale” exclusion provided by SFAS 133 and are therefore exempted out of fair value accounting.

Upon adoption on January 1, 2003, the Company recorded a charge for a cumulative effect of an accounting change totaling approximately $2.9 million, net of tax. This cumulative effect of an accounting change was the result of certain energy contracts in our Energy Marketing segment, previously marked to fair value under EITF 98-10, being restated to reflect historical cost. The amount of the cumulative effect represents the unrealized gain or loss recorded on these contracts as of January 1, 2003. Gains and losses on these contracts are now recognized on the accrual basis of accounting. See Note 12 for further discussion of our accounting for contracts at our Energy Marketing segment subsequent to adoption of EITF 02-3.

EITF 02-3 also requires that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 be presented on a net basis in the statement of income, whether or not settled physically, if the derivative instruments are held for “trading purposes.” EITF 02-3 references a definition of “trading purposes” as “active and frequent buying and selling…with the objective of generating profits on short-term differences in price.” Contracts at our crude oil marketing operations are not held for “trading purposes” as defined by EITF 02-3 and meet the requirements of EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19) for a gross basis presentation on the statement of income. Upon adoption, the Company began reporting settlement amounts on contracts at our crude oil marketing operations, on a gross basis in the statement of income. Contracts at our natural gas marketing operations are held for “trading purposes”, as defined by EITF 02-3, and are presented on a net basis in the statement of income. The accompanying Condensed Consolidated Statements of Income have been reclassified to conform to this presentation for all periods presented.

(4) RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities”. The Company’s subsidiary, Black Hills Wyoming (f/k/a Black Hills Generation), has an agreement with Wygen Funding, Limited Partnership, an unrelated, unconsolidated special purpose entity (SPE) to lease the Wygen plant, a 90 megawatt coal-fired power plant. Under the new accounting interpretation, the Company will be required to consolidate the SPE by July 1, 2003, unless the transaction is restructured. The Company does not currently plan on restructuring the lease. The effect of consolidating the SPE into the Company’s consolidated financial statements would be to record both the Wygen asset and its related debt on the Company’s Condensed Consolidated Balance Sheets which is estimated to be approximately $135 million. In addition, the net effect of consolidating the income statement of the SPE would be to recognize the depreciation and interest expense of the SPE in place of recognizing lease expense which is estimated to have approximately a $3.5 million pre-tax negative annual effect to pre-tax income based on a 40-year depreciable life.

(5) RECLASSIFICATIONS

Operating Revenues on the Condensed Consolidated Statement of Income for the three months ended March 31, 2002, have been reclassified to present realized and unrealized gains and losses under contracts in the energy marketing segment in accordance with the provisions of EITF 02-3. These provisions of EITF 02-3 were adopted on January 1, 2003 (See Note 3). This change in presentation did not have an impact on the Company’s total stockholders’ equity or net income available for common stock as previously reported.

In addition, certain other 2002 amounts in the financial statements have been reclassified to conform to the 2003 presentation. These reclassifications did not have an effect on the Company’s total stockholders’ equity or net income available for common stock as previously reported.

(6) EARNINGS PER SHARE

Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per share 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:

	Income
Period ended March 31, 2003 (in thousands)	Three Months
Income from continuing operations	$	16,858		27,041
Less: preferred stock dividends		(57	)

Basic - available for common shareholders		16,801
Dilutive effect of:
Stock options		--		46
Convertible preferred stock		57		148
Others		--		176

Diluted - available for common shareholders	$	16,858		27,411

	Income
Period ended March 31, 2002 (in thousands)	Three Months
Income from continuing operations	$	14,892		26,694
Less: preferred stock dividends		(56	)

Basic - available for common shareholders		14,836
Dilutive effect of:
Stock options		--		101
Convertible preferred stock		56		148
Others		--		25

Diluted - available for common shareholders	$	14,892		26,968

As further described in Note 16, on April 30, 2003, the Company completed a public offering of 4.6 million shares of common stock. Accordingly, this transaction will significantly affect the weighted average number of common shares outstanding used in earnings per share calculations of future periods.

(7) COMPREHENSIVE INCOME

The following table presents the components of the Company's comprehensive income:

	Three Months Ended
	March 31
	2003		2002
	(in thousands)
Net income	$	14,178	$	14,064
Other comprehensive income, net of tax:
Unrealized gain (loss) on available-for-sale securities		--		(219	)
Fair value adjustment on derivatives designated as cash flow
hedges, net of minority interest		985		509

Comprehensive income	$	15,163	$	14,354

(8) CHANGES IN COMMON STOCK

Other than the following transactions, the Company had no other changes in its common stock, as reported in Note 6 of the Company’s 2002 Annual Report on Form 10-K.

•

The Company issued 481,509 shares of common stock and 45,000 warrants to purchase common stock in the acquisition of Mallon Resources Corporation (see Note 14).

•

The Company granted 43,500 stock options at a weighted average exercise price of $27.38 per share.

•

9,333 stock options were exercised at a weighted average exercise price of $16.87 per share.

•

The Company issued 29,376 shares of common stock under its dividend reinvestment plan at a weighted average price of $23.96 per share.

•

The Company issued 4,642 shares of common stock under its employee stock purchase plan at a price of $23.45 per share.

•

The Company issued 3,075 shares of common stock under the short-term incentive compensation plan. Compensation cost related to the award was approximately $70,000 which was accrued for in 2002.

Subsequent to the end of the first quarter, on April 30, 2003, the Company issued 4.6 million shares of common stock in a public offering at a price of $27 per share (see Note 16).

(9) CHANGES IN LONG-TERM DEBT AND NOTES PAYABLE

On January 31, 2003, Black Hills Energy Resources amended its credit agreement increasing its uncommitted, discretionary credit facility to $40 million. The facility expires January 30, 2004.

As part of the Mallon acquisition (see Note 14), the Company acquired debt in the amount of $4.1 million, of which $0.6 million is classified as current.

Subsequent to the end of the first quarter, on April 30, 2003, the Company paid off the $50 million credit facility due May 2003 and repaid $68 million of the Company’s 364-day revolving credit facility (see Note 16).

The Company had no other material changes in its consolidated indebtedness, as reported in Notes 8 and 9 of the Company’s 2002 Annual Report on Form 10-K.

(10) GUARANTEES

The Company has entered into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees of debt obligations, performance obligations under contracts and indemnification for reclamation and surety bonds.

As prescribed in FASB Interpretation No. 45, the Company records a liability for the fair value of the obligation it has undertaken for guarantees issued after December 31, 2002. The liability recognition requirements of FASB Interpretation No. 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002, while the disclosure requirements are applied to all guarantees.

As of March 31, 2003 we had the following guarantees in place (in thousands):

Nature of Guarantee	Outstanding at March 31, 2003		Year Expiring

Guarantee of secured financing for the Las Vegas II project	$	50,000	2003
Guarantee payments under certain energy marketing derivative, power and
gas agreements		7,500	2003
Guarantee of obligation of Las Vegas Cogen II under an interconnection
and operation agreement		750	2005
Guarantee performance of Black Hills Wyoming under a power sales
agreement		5,000	2004
Guarantee obligations under the Wygen Plant Lease		103,614	2008
Guarantee payment and performance under credit agreements for two
combustion turbines		32,000	2010
Indemnification for subsidiary reclamation/surety bonds		30,600	2003

	$	229,464

The Company has provided a completion guarantee and has guaranteed the payment of $50 million of project debt for the Las Vegas II project, for its wholly-owned subsidiaries, Las Vegas Cogeneration II, LLC and Las Vegas Cogeneration Energy Financing Company, LLC. The Las Vegas II unit was placed in service in January 2003. This debt is recorded on the Company’s Condensed Consolidated Balance Sheets and is due May 26, 2003. The Company paid off this debt on April 30, 2003.

The Company has guaranteed $7.5 million of commodity related payments for its energy marketing subsidiary, Enserco Energy Inc. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in energy commodities and related services. To the extent liabilities exist under the commodity- related contracts subject to these guarantees, such liabilities are included in the Condensed Consolidated Balance Sheets. Of the $7.5 million of guarantees, $4.5 million expire on June 1, 2003 and $3.0 million expire on December 31, 2003.

The Company has guaranteed up to $0.8 million of the obligations of Las Vegas Cogeneration II, LLC under an interconnection and operations agreement for the LV II unit. To the extent liabilities exist under the interconnection and operations agreement, such liabilities are included in the Condensed Consolidated Balance Sheets. The obligation is due May 20, 2005.

The Company has guaranteed up to $5 million for the performance of its wholly-owned subsidiary, Black Hills Wyoming (f/k/a Black Hills Generation), under a power sales agreement on the Wygen plant. The guarantee will expire in February 2004, the first anniversary of commercial operation of the facility. There are no liabilities on the Company’s Condensed Consolidated Balance Sheets associated with this guarantee.

The Company has also guaranteed the obligations of Black Hills Wyoming under the agreement for lease and lease for the Wygen plant. The lease is currently accounted for as an off-balance sheet transaction, therefore there are no liabilities associated with the lease on the consolidated financial statements. If the lease was terminated and sold, the Company’s obligation is the amount of deficiency in the proceeds from the sale to repay the investors up to a maximum of 83.5 percent of the cost of the project. At March 31, 2003, the Company’s maximum obligation under the guarantee is $103.6 million (83.5 percent of $124.1 million, the cost incurred for the Wygen plant as of March 31, 2003). The initial term of the lease is five years with two five-year renewal options.

The Company has guaranteed the payment of $27.5 million of debt of Black Hills Wyoming and $4.5 million of debt for another of its wholly-owned subsidiaries, Black Hills Generation (f/k/a Black Hills Energy Capital, Inc.). The debt is recorded on the Company’s Condensed Consolidated Balance Sheets and is due December 18, 2010.

In addition, at March 31, 2003, the Company had guarantees in place totaling approximately $30.6 million for reclamation and surety bonds for its subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in the Company’s Condensed Consolidated Balance Sheets.

(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, 2003, substantially all of the Company’s operations and assets are located within the United States. The Company’s operations are conducted through six reporting segments that include: Integrated Energy group consisting of the following segments: Mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and Gas, which produces, explores and operates oil and gas interests located in the Rocky Mountain region, Texas, California and other states; Energy Marketing, which markets natural gas, oil and related services to customers in the Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions and transports crude oil in Texas; Power Generation, which produces and sells power to wholesale customers; Electric group and segment, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Communications group and segment, which primarily markets communications and software development services.

Segment information follows the same accounting policies as described in Note 1 of the Company’s 2002 Annual Report on Form 10-K. In accordance with the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71), intercompany fuel sales to the electric utility are not eliminated. Segment information included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income is as follows (in thousands):

	External Operating Revenues			Inter-segment Operating Revenues			Income (loss) from Continuing Operations

Quarter to Date
March 31, 2003
Energy marketing	$	182,427	*	$	--		$	4,245
Power generation		47,609			--			4,570
Oil and gas		8,990			72			1,862
Mining		5,394			2,836			1,581
Electric		43,749			13			6,699
Communications		8,687			--			(1,809	)
Corporate		--			--			(290	)
Intersegment eliminations		--			(445	)		--

Total	$	296,856		$	2,476		$	16,858

*Operating revenues for Energy marketing are presented in accordance with EITF 02-3 as described in Note 3.

	External Operating Revenues			Inter-segment Operating Revenues			Income (loss) from Continuing Operations

Quarter to Date
March 31, 2002
Energy marketing	$	80,580	*	$	--		$	1,506
Power generation		31,168			--			4,776
Oil and gas		5,947			140			878
Mining		5,450			2,752			2,335
Electric		37,192			--			7,823
Communications		7,546			--			(2,227	)
Corporate		--			--			(199	)
Intersegment eliminations		--			(140	)		--

Total	$	167,883		$	2,752		$	14,892

*Operating revenues for Energy marketing are presented in accordance with EITF 02-3 as described in Note 3.

Other than the Oil and Gas segment’s acquisition of Mallon Resources, as described in Note 14, the Company had no material changes in total assets of its reporting segments, as reported in Note 16 of the Company’s 2002 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

(12) RISK MANAGEMENT ACTIVITIES

The Company actively manages its exposure to certain market risks as described in Note 2 of the Company’s 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 Marketing

On March 31, 2003, December 31, 2002 and March 31, 2002, contracts accounted for at fair value at the Company’s natural gas marketing operations had the following notional amounts, terms and related balances:

	March 31, 2003				December 31, 2002				March 31, 2002
(thousands of MMBtu's)	Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years
Basis swaps purchased		63,167		2		72,340		1		24,826		2
Basis swaps sold		65,303		2		72,329		1		29,067		2
Fixed-for float swaps purchased		12,589		2		10,675		1		12,752		2
Fixed-for-float swaps sold		19,194		1		17,934		1		13,966		2
Swing swaps purchased		--		--		--		--		1,370		1
Swing swaps sold		--		--		--		--		3,630		1
Physical purchases		57,512		1		42,813		1.25		35,993		1
Physical sales		37,979		2		41,654		1		16,502		1
Options purchased		3,210		1		--		--		--		--
Options sold		3,210		1		--		--		--		--

Derivatives and certain other natural gas marketing activities were marked to fair value and the 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 Derivative Assets		Non-current Derivative Assets		Current Derivative Liabilities		Non-current Derivative Liabilities		Unrealized Gain (Loss)
March 31, 2003	$	30,405	$	479	$	29,477	$	2,138	$	(731	)

December 31, 2002	$	29,559	$	2,406	$	28,535	$	409	$	3,021

March 31, 2002	$	14,004	$	1,253	$	12,179	$	999	$	2,079

For the period ended March 31, 2003, contracts and other activities at our natural gas marketing operations are accounted for under the provisions of EITF 02-3 and SFAS 133. As such, all of the contracts and other activities at our natural gas marketing operations that meet the definition of a derivative under SFAS 133 are accounted for at fair value. EITF 02-3, adopted on January 1, 2003, precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to SFAS 133. Accordingly, natural gas physical inventories and transportation contracts that have not been designated as part of a fair value hedge transaction, in accordance with SFAS 133, are recognized at a historical cost basis (lower of cost or market for physical inventories) and settlement costs or gains or losses recognized on the accrual method of accounting. Substantially all other contracts at our natural gas marketing operations are derivatives or hedging activities, as defined by SFAS 133, and have been recorded at fair value.

For all other periods presented, contracts and other activities at our natural gas marketing operations fell under the purview of EITF 98-10, SFAS 133 and for contracts entered into after October 25, 2002, under EITF 02-3. As such, all contracts and other natural gas marketing activities entered into on or before October 25, 2002 and transactions entered after that date that meet the definition of a derivative as defined by SFAS 133, are accounted for under mark-to-market accounting.

Non-trading Energy Activities

On March 31, 2003, December 31, 2002 and March 31, 2002, contracts accounted for at fair value at the Company’s non-trading energy operations had the following notional amounts, terms and related balances (in thousands):

Crude Oil Marketing

	March 31, 2003				December 31, 2002				March 31, 2002
	Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years
(thousands of barrels)
Crude oil purchased		379		0.25		4,081		0.5		4,015		1
Crude oil sold		120		0.25		4,150		0.5		4,008		1

	Current Derivative Assets		Non-current Derivative Assets	Current Derivative Liabilities		Non-current Derivative Liabilities	Unrealized Gain

March 31, 2003	$	648	$--	$	383	$--	$	265

December 31, 2002	$	6,776	$--	$	6,010	$--	$	766

March 31, 2002	$	8,518	$--	$	7,732	$--	$	786

For the period ended March 31, 2003, contracts at our crude oil marketing operations are accounted for under the provisions of EITF 02-3 and SFAS 133. Substantially all of the contracts at our crude oil marketing operations are either not derivatives, as defined by SFAS 133, or are derivatives but qualify for the “normal purchase/normal sale”exclusion provided by SFAS 133 and have been exempted out of fair value accounting treatment. As such, the Company accounts for all contracts at our crude oil marketing operations on a historical cost method with gains or losses recognized on the accrual method of accounting. Certain contracts at March 31, 2003, as noted in the tables above, were entered into before the adoption of EITF 02-3 and were not formally designated as “normal purchase/normal sale” contracts and could not be retroactively designated as such under the provisions of SFAS 133. These contracts will continue to be marked to fair value under SFAS 133 until the contracts expire. The last of these contracts expire in July 2003.

For all other periods presented, contracts at our crude oil marketing operations fell under the purview of EITF 98-10, SFAS 133 and for contracts entered into after October 25, 2002, under EITF 02-3. As such, all contracts entered into on or before October 25, 2002 have been accounted for under mark-to-market accounting. Substantially all contracts entered after that date either do not meet the definition of a derivative as defined by SFAS 133, or are derivatives and have been exempted out of fair value treatment as “normal purchase/normal sale” contracts.

Oil and Gas Exploration and Production


(in thousands)	Notional*		Maximum Terms in Years		Current Derivative Assets		Non-current Derivative Assets	Current Derivative Liabilities		Non-current Derivative Liabilities		Accumulated Other Comprehensive Income (Loss)			Pre-tax Income (Loss)
March 31, 2003
Natural gas swaps		5,580,000		1	$	1,921	$ --	$	1,497	$	--	$	424		$	--
Crude oil swaps		480,000		2		49	17		897		--		(783	)		(48	)

					$	1,970	$ 17	$	2,394	$	--	$	(359	)	$	(48	)

December 31, 2002
Natural gas swaps		1,650,000		1	$	58	$ --	$	744	$	--	$	(686	)	$	--
Crude oil swaps		360,000		1		--	--		976		--		(914	)		(62	)

					$	58	$ --	$	1,720	$	--	$	(1,600	)	$	(62	)

March 31, 2002
Natural gas swaps		1,284,000		1	$	--	$ --	$	29	$	--	$	(116	)	$	87
Crude oil swaps		360,000		2		14	--		617		78		(516	)		(165	)

					$	14	$ --	$	646	$	78	$	(632	)	$	(78	)

_________________

*crude in barrels, gas in MMBtu’s

Based on March 31, 2003 market prices, a $0.4 million loss will be realized and reported in earnings during the next twelve months related to hedges of production. These estimated realized losses for the next twelve months were calculated using March 31, 2003 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

On March 31, 2003, December 31, 2002 and March 31, 2002, the Company’s interest rate swaps and related balances were as follows (in thousands):

	Current Notional Amount					Current Derivative Assets		Non-current Derivative Assets		Current Derivative Liabilities		Non-current Derivative Liabilities		Pre-tax Accumulated Other Comprehensive Loss

March 31, 2003
Swaps on project
financing	$	251,876	5.25	%	4	$	205	$	--	$	8,886	$	8,713	$	(17,394	)
Swaps on corporate debt		125,000	4.12	%	1		640		--		939		--		(299	)

Total	$	376,876				$	845	$	--	$	9,825	$	8,713	$	(17,693	)

December 31, 2002
Swaps on project
financing	$	212,256	5.98	%	4	$	--	$	--	$	9,345	$	7,844	$	(17,189	)
Swaps on corporate debt		25,000	5.28	%	1		--		--		947		166		(1,113	)

Total	$	237,256				$	--	$	--	$	10,292	$	8,010	$	(18,302	)

March 31, 2002
Swaps on project
financing	$	316,397	5.85	%	4	$	--	$	5,925	$	7,799	$	5,077	$	(6,951	)
Swaps on corporate debt		75,000	4.45	%	2		--		--		1,033		135		(1,168	)

Total	$	391,397				$	--	$	5,925	$	8,832	$	5,212	$	(8,119	)

During the first quarter of 2003, the Company entered into treasury locks, with a notional amount of $100 million, to hedge the risk of interest rate movement between the hedge date and the expected pricing date for a portion of the Company’s anticipated debt offering of senior unsecured notes. These treasury locks were identified and documented as cash flow hedges. At March 31, 2003, the treasury locks had a fair value of $0.6 million and the resulting gain was deferred into Accumulated Other Comprehensive Loss on the Condensed Consolidated Balance Sheet.

Based on March 31, 2003 market interest rates, approximately $9.0 million will be realized as additional interest expense during the next twelve months. Estimated and realized amounts will likely change during the next twelve months as market interest rates change.

(13) LEGAL PROCEEDINGS

Fires

In September 2001, a fire, which is known as the Hell Canyon fire, occurred in the southwestern portion of the Black Hills region of South Dakota. The State of South Dakota has alleged that the fire occurred when a high voltage electrical span maintained by the Company’s electric utility subsidiary broke and electrical arcing from the severed line ignited dry grass. The fire burned approximately 10,000 acres of land owned by the Black Hills National Forest, the Oglala Sioux Tribe and other private landowners. The State of South Dakota initiated litigation against the Company in the Seventh Judicial Circuit Court, Fall River County, South Dakota, on January 31, 2003. The complaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages is asserted with respect to the claim for injury to timber. It is expected that the United States Forest Service will assert substantially similar claims against the Company. The Company’s investigation into the cause and origin of the fire is still pending. The total amount of damages claimed by the State of South Dakota is not specified in the complaint. The Company has denied all claims and will vigorously defend this matter, the timing or outcome of which is uncertain.

In June 2002, a forest fire, sometimes referred to as the Grizzly Gulch fire, damaged approximately 11,000 acres of private and governmental land located near Deadwood and Lead, South Dakota. The fire destroyed approximately 20 structures and caused the evacuation of the cities of Lead and Deadwood for approximately 48 hours.

The cause of the Grizzly Gulch fire was investigated by the State of South Dakota. Contact between power lines owned by the Company’s electric utility subsidiary and undergrowth was alleged to be the cause. The Company has initiated its own investigation into the cause of the fire, including the hiring of expert fire investigators and that investigation is continuing.

The State of South Dakota initiated a civil action in the Seventh Judicial Circuit Court, Pennington County, South Dakota seeking recovery of damages for fire suppression, reclamation and remediation costs, and treble damages for injury to trees. The United States government initiated a civil action in U.S. District Court, District of South Dakota, asserting similar claims. Neither the State of South Dakota nor the United States specified the amount of their alleged damages. In addition, the Company has been notified of potential private civil claims for property damage and business loss. The Company has denied all claims and will vigorously defend this matter. The State of South Dakota has subsequently joined its claim in the federal action.

If it is determined that power line contact was the cause of either fire and that the Company was negligent in the maintenance of those power lines, the Company could be liable for some or all of the damages related to these claims. Although the Company cannot predict the outcome or the viability of potential claims with respect to either fire, based on information currently available, management believes that any such claims, if determined adversely to the Company, will not have a material adverse effect on the Company’s financial condition or results of operations.

Federal Energy Regulatory Commission (FERC) Investigation

In August 2001, the Company purchased a partnership interest in Las Vegas Cogeneration, L.P., which owns the 53 megawatt Las Vegas Cogeneration I Facility, from an affiliate of Enron. The prior owner certified to the Company and to relevant governmental authorities that the facility complied with all regulations necessary to obtain and maintain “qualifying facility” status under Public Utility Regulatory Policies Act of 1978 (PURPA). Qualifying facilities are allowed to sell their output to electric utilities at “avoided cost” rates, which are usually higher than prevailing market-based rates. The prior owner contracted with Nevada Power Company to sell 45 megawatts of the facility’s output during the periods of peak electricity consumption at avoided cost rates. In connection with acquiring the facility, the Company assumed this contract.

Recently FERC issued an order announcing an investigation to determine whether Enron’s ownership of the Las Vegas Cogeneration I Facility violated the qualifying facility regulations under PURPA. In addition, the SEC recently issued an initial decision concluding that Enron is an electric utility and is thus not exempt from regulations under the Public Utility Holding Company Act of 1935 (PUHCA), that, among other things, prohibit electric utilities from owning more than 50 percent of a qualifying facility. Enron is appealing this decision.

The FERC investigation does not relate to the 224 megawatt gas-fired facility owned and operated by Las Vegas Cogeneration II, LLC and located on the same site in North Las Vegas, Nevada. This facility is not now and never was certified as a qualifying facility under PURPA.

If FERC determines that Enron violated the qualifying facility regulations with respect to the Las Vegas Cogeneration I Facility, the Company, as a partner in the entity that now owns that facility, could be liable for any refunds, fines or other penalties FERC imposes. The Company could also be subject to additional liabilities resulting from third party claims. Because FERC has only recently begun its investigation, the Company cannot predict the outcome of FERC’s investigation. If FERC determines that Enron violated the qualifying facility regulations, any fines, penalties, and private damage claims could adversely affect the Company’s financial condition and results of operations.

The Company is pursuing enforcement of its indemnification rights against the former owner. While the former owner is not among the Enron subsidiaries and affiliates currently in bankruptcy, the Enron bankruptcy could impair the Company’s ability to enforce its claim for indemnification.

Commodity Futures Trading Commission Investigation

In March 2003, the Company received a request for information from the Commodity Futures Trading Commission, or CFTC, calling for the production, among other things, of “all documents relating to natural gas and electricity trading” in connection with CFTC’s industry wide investigation of trade and trade reporting practices of power and natural gas trading companies. Since that time, the Company has produced documents and other materials in response to more specific requests relating to the reporting of natural gas trading information to energy industry publications. The Company is also conducting an internal investigation into the accuracy of information that former employees of Enserco Energy Inc., its gas marketing subsidiary, voluntarily reported to trade publications. As a part of its internal investigation and in response to CFTC’s document request, the Company provided documents and materials to the CFTC, including information identifying instances in which it appears that former employees at Enserco provided inaccurate reports of natural gas transactions to one or more industry trade publications. The Company intends to continue its policy of cooperation with the CFTC. However, both the internal and CFTC’s investigations are continuing, and the Company cannot predict their outcome or whether they will lead to legal proceedings, civil or criminal fines or penalties, or other regulatory action which, in turn, could adversely affect the Company’s financial condition or results of operations.

Ongoing Proceedings

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

(14) ACQUISITIONS

On October 1, 2002, the Company entered into a definitive merger agreement to acquire the Denver-based Mallon Resources Corporation. On March 10, 2003, the Company completed this acquisition. The total cost of the transaction was approximately $51.2 million. The total cost of the transaction includes $30.5 million for the October 2002 acquisition of Mallon’s debt to Aquila Energy Capital Corporation and the settlement of outstanding hedges and approximately $8.4 million, which the Company loaned to Mallon prior to completion of the acquisition. Mallon shareholders received 0.044 of a share of the Company’s common stock for each share of Mallon, which was equivalent to 481,509 shares of Black Hills Corporation common stock.

The purchase has been accounted for under the purchase method of accounting and, accordingly, the purchase price is allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and liabilities assumed as of the date of acquisition. Due to acquisition timing and the complex analysis necessary to quantify any asset retirement obligations required to be recorded in accordance with SFAS 143, the preliminary purchase price allocation does not include an estimate for these amounts. When the necessary analysis is completed, the preliminary allocation will be adjusted and will result in an increase to long-term liabilities and property, plant and equipment. The estimated purchase price allocation is subject to adjustment, generally within one year of the date of acquisition. Preliminary allocation of the purchase price is as follows (in thousands):


Current assets	$	165
Property, plant and equipment		55,622
Deferred tax asset		5,194

Total assets acquired	$	60,981


Current liabilities	$	6,343
Long-term liabilities		3,485

Total liabilities assumed	$	9,828

Net assets	$	51,153

The results of operations of the above acquired company have been included in the accompanying consolidated financial statements since the acquisition date.

The following pro forma consolidated results of operations have been prepared as if the Mallon acquisition had occurred on January 1, 2003 and 2002, respectively (in thousands):

	Three Month Period Ended
	March 31, 2003		March 31, 2002
Operating revenues	$	302,273	$	173,318
Income from continuing operations	$	16,410	$	14,347
Net income	$	13,730	$	13,519
Earnings per share--
Basic:
Continuing operations	$	0.59	$	0.53

Total	$	0.50	$	0.50

Diluted:
Continuing operations	$	0.59	$	0.52

Total	$	0.49	$	0.49

The above pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results.

Mallon Resources’ proved developed and undeveloped reserves, estimated using constant year-end product prices, as of December 31, 2002, were approximately 86 billion cubic feet of gas equivalent. These estimates are based on reserve reports by Ralph E. Davis Associates, Inc., an independent engineering firm selected by the Company. The reserves are located primarily on the Jicarilla Apache Nation in the San Juan Basin of New Mexico and are comprised almost entirely of natural gas in shallow sand formations. The oil and gas leases of the acquisition total more than 66,500 gross acres (56,000 net), most of which is contained in a contiguous block that is in the early stages of development.

(15) DISCONTINUED OPERATION

During the second quarter of 2002, the Company adopted a plan to dispose of its coal marketing subsidiary, Black Hills Coal Network. The sale and disposal was finalized in July 2002. In connection with the plan of disposal, the Company determined that the carrying values of some of the underlying assets exceeded their fair values and a charge to operations was required.

Consequently, in the second quarter of 2002, the Company recorded an after-tax charge of approximately $1.0 million, which represents the difference between the carrying values of the assets and liabilities of the subsidiary versus their fair values, less cost to sell. The disposition has been accounted for under the provisions of Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, results of operations and the related charge have been classified as “Discontinued operations” in the accompanying Condensed Consolidated Statements of Income, and prior periods have been restated. For business segment reporting purposes, the coal marketing business results were previously included in the segment “Energy marketing.”

Results of operations from the discontinued operation are as follows (in thousands):

	Three Months
	March 31
	2003	2002
Gross margins on energy trading contracts	$ --	$	(862	)
Pre-tax loss from discontinued operation	--		--
Pre-tax loss on disposal	--		(2,873	)
Income tax benefit	--		1,149

Net loss from discontinued operations	$ --	$	(1,724	)

Assets and liabilities of the discontinued operation are as follows (in thousands):

	March 31	December 31	March 31
	2003	2002	2002
Current assets	$ --	$ --	$	5,340
Non-current assets	--	--		572
Current liabilities	--	--		(5,962	)
Non-current liabilities	--	--		(405	)

Net assets of discontinued operations	$ --	$ --	$	(455	)

(16) SUBSEQUENT EVENTS

Common Stock Offering

On April 30, 2003, the Company completed a public offering of 4.6 million shares of common stock. The shares were issued at $27 per share. Net proceeds were approximately $118 million after commissions and expenses. The proceeds were used to pay off a $50 million credit facility due in May 2003 and to repay $68 million under the Company’s 364-day revolving credit facility.

Treasury Lock Acquired

On May 7, 2003, the Company entered into a treasury lock, with a notional amount of $50 million, to hedge the risk of interest rate movement between the hedge date and the expected pricing date for a portion of the Company’s anticipated debt offering of senior unsecured notes. The interest rate on the treasury lock is 3.78 percent.

Senior Unsecured Notes Offering

On May 13, 2003, the Company announced its intention to commence a public offering of senior unsecured notes under its existing shelf registration. Net proceeds from the offering will be used to repay indebtedness, including some or all of the Company’s outstanding indebtedness under its short-term revolving credit facilities.

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

We are a diversified energy holding company operating principally in the United States. Our unregulated and regulated businesses have expanded significantly in recent years. Our integrated energy group, Black Hills Energy, Inc., produces and markets electric power and fuel. We produce and sell electricity in a number of markets, with a strong emphasis in the western United States. We also produce coal, natural gas and crude oil, primarily in the Rocky Mountain region, and transport crude oil in Texas. Our electric utility, Black Hills Power, Inc., serves an average of 60,000 customers in South Dakota, Wyoming and Montana. Our communications group offers state-of-the-art broadband communications services to over 25,000 residential and business customers in Rapid City and the northern Black Hills region of South Dakota through Black Hills FiberCom, LLC.

The following discussion should be read in conjunction with Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – included in our 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Results of Operations

Consolidated Results

Revenue and Income (loss) from continuing operations provided by each business group as a percentage of our total revenue and total income (loss) from continuing operations were as follows:

	Three Months Ended
	March 31
	2003			2002
	(in thousands)
Revenues
Integrated energy		82	%		74	%
Electric utility		15			22
Communications		3			4

		100	%		100	%

Income/(Loss) from Continuing Operations
Integrated energy		73	%		64	%
Electric utility		40			53
Communications		(11	)		(15	)
Corporate		(2	)		(2	)

		100	%		100	%

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Consolidated income from continuing operations for the three-month period ended March 31, 2003 was $16.9 million or $0.62 per share compared to $14.9 million or $0.55 per share in the same period of the prior year.

The increase in income from continuing operations was a result of higher oil and gas prices and gas marketing volumes and margins, an increase in power sales resulting from higher generation capacity in our power generation segment and improving performance in our communications business group, partially offset by a decrease in net income at the electric utility due to higher operating costs and interest expense.

Net income for the three months ended March 31, 2003, included a charge of $2.7 million or ($0.10) per share for changes in accounting principles compared to a $0.9 million benefit or $0.03 per share in 2002. The change in accounting principles in 2003 reflect a $2.9 million charge related to the adoption of EITF 02-3 and a $0.2 million benefit related to the adoption of SFAS 143. The change in accounting principle in 2002 reflects a $0.9 million benefit related to the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142).

In addition, during the second quarter of 2002, we decided to discontinue operations in our coal marketing business due primarily to challenges encountered in marketing our Wyodak coal from the Powder River Basin of Wyoming to midwestern and eastern coal markets. We sold the non-strategic assets effective August 1, 2002. Net loss from discontinued operations was $(1.7) million or $(0.06) per share for the three months ended March 31, 2002. Prior year results of operations have been restated to reflect the discontinued operations.

Consolidated revenues for the three-month period ended March 31, 2003 were $299.3 million compared to $170.6 million for the same period in 2002. Revenues increased in each of our three business groups due primarily to higher production volumes. In the power generation segment, revenues increased 53 percent due to a substantial increase in its contracted capacity. Energy marketing revenues increased 126 percent, due primarily to a 41 percent increase in natural gas average daily volumes marketed and a 32 percent increase in crude oil average daily volumes marketed. Oil and gas revenue increased 49 percent, primarily due to a 14 percent increase in production. Mining revenue increased slightly, due to a 14 percent increase in coal production partially offset by lower average prices received. Revenues from the electric utility group increased 18 percent, due to a 53 percent increase in off-system sales and a 43 percent increase in average prices received. The communications group revenue increased 15 percent as a result of a 26 percent increase in its customer base.

Consolidated operating expenses for the three-month period increased from $139.3 million in 2002 to $260.6 million in 2003. Approximately 78 percent of the increase resulted from our crude oil marketing activities where the cost of crude oil sales were substantially higher due to increased volumes sold at higher prices. The remaining increase was due to an increase in fuel and depreciation expense as a result of our increased investment in independent power generation and increased operating expenses related to the increase in production in all business segments.

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

Integrated Energy Group

	Three Months Ended
	March 31
	2003		2002
	(in thousands)
Revenue:
Energy marketing	$	182,427	$	80,580
Power generation		47,609		31,168
Oil and gas		9,062		6,087
Mining		8,230		8,202

Total revenue		247,328		126,037
Equity in investments of unconsolidated subsidiaries		456		1,162
Operating expenses		219,820		106,409

Operating income	$	27,964	$	20,790

Income from continuing operations	$	12,258	$	9,495

The following is a summary of sales volumes of our coal, oil and natural gas production and various measures of power generation:

	Three Months Ended
	March 31
	2003		2002
Fuel production:
Tons of coal sold		1,143,000		1,001,000
Barrels of oil sold		106,700		114,300
Mcf of natural gas sold		1,614,200		1,287,800
Mcf equivalent sales		2,254,500		1,973,500

	March 31
	2003			2002
Independent power capacity:
MWs of independent power capacity in service		1,046	*	646
MWs of independent power capacity under construction		--		364	*

_________________

*includes a 90 MW plant under a lease arrangement

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

	Three Months Ended
	March 31
	2003		2002
Natural gas - MMBtus		1,188,000		842,000
Crude oil - barrels		58,000		44,000

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Income from continuing operations for the integrated energy group for the three months ended March 31, 2003 was $12.3 million, compared to $9.5 million in the same period of the prior year. In addition, 2002 income from continuing operations includes a $1.9 million benefit relating to the collection of previously reserved amounts for California operations in our power generation segment. Income from continuing operations from our energy marketing segment increased approximately $2.7 million due to a 41 percent increase in average daily gas volumes marketed and increased margins received at our gas marketing operations. Income from continuing operations in our power generation segment declined $0.2 million. Excluding the $1.9 million benefit mentioned above, income from continuing operations from our power generation segment increased approximately $1.7 million due to increased generating capacity in service. Income from continuing operations at our oil and gas segment increased approximately $1.0 million due to higher prices received compared to 2002 and a 14 percent increase in production. Income from continuing operations for the mining segment decreased $0.8 million as higher production volumes were more than offset by lower average prices and higher operating costs.

Energy Marketing

	Three Months Ended
	March 31
	2003			2002
	(in thousands)
Revenue	$	182,427		$	80,580
Operating income		6,678			2,111
Income from continuing operations		4,245			1,506
Change in accounting principle		(2,870	)		--
Net income		1,375			1,506

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. The increase in revenues is attributed to substantially higher crude oil sales as a result of a 32 percent increase in barrels marketed at average prices 81 percent higher than those received during 2002. Revenue increases from our crude oil marketing were offset by a similar increase in the cost of crude oil sold. Income from continuing operations increased $2.7 million due to a 41 percent increase in average daily natural gas volumes marketed with increased margins received. Net income decreased 9 percent due to a change in accounting principle of $(2.9) million, net of tax related to the adoption of EITF 02-3. As a result of changing commodity prices, net income was impacted by unrealized gains recognized through mark-to-market accounting treatment. Unrealized pre-tax mark-to-market gains for the three-month period ended March 31, 2003 were $1.7 million compared to a $1.0 million loss for the three month period ended March 31, 2002, resulting in a quarter over quarter increase of $2.7 million pre-tax.

Power Generation

	Three Months Ended
	March 31
	2003		2002
	(in thousands)
Revenue	$	47,609	$	31,168
Operating income		16,916		15,281
Income before change in accounting principle		4,570		4,776
Change in accounting principle		--		896
Net income		4,570		5,671

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Revenue and operating income increased 53 percent and 11 percent, respectively for the three-month period ended March 31, 2003 compared to the same period in 2002 and is attributed to additional generating capacity and increased earnings from additional ownership of an energy partnership. As of March 31, 2003, we had 1,046 megawatts of independent power capacity in service compared to 646 megawatts at March 31, 2002.

Net income for the power generation segment decreased $1.1 million due to a $1.9 million after-tax benefit in 2002 related to the collection of previously reserved amounts for California operations and a $0.9 million after-tax benefit in 2002 from a change in accounting principle related to the adoption of SFAS 142. The net income decrease was partially offset by the earnings generated from the additional generating capacity.

Oil and Gas

	Three Months Ended
	March 31
	2003			2002
	(in thousands)
Revenue	$	9,062		$	6,087
Operating income		2,634			1,018
Income before change in accounting principle		1,862			878
Change in accounting principle		(127	)		--
Net income		1,735			878

The following is a summary of our internally estimated economically recoverable oil and gas reserves measured using constant product prices of $31.04 per barrel of oil and $5.05 per Mcf of natural gas as of March 31, 2003 and $26.31 per barrel of oil and $3.28 per Mcf of natural gas as of March 31, 2002. Estimates of economically recoverable reserves for interim periods are based on independent year-end reserve studies updated for acquisitions, drilling activity, property sales and actual production during the interim period. These internally estimated reserves may differ from actual results.

	March 31
	2003			2002
Barrels of oil (in millions)		4	.9		4	.6
Bcf of natural gas		116	.7		24	.7
Total in Bcf equivalents		146	.1		52	.3

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Revenue from our oil and gas production business segment increased 49 percent for the three-month period ended March 31, 2003, compared to the same period in 2002, due to a 14 percent increase in production and a 30 percent increase in the average price received.

Operating expenses increased 33 percent primarily due to the increase in production.

Income from continuing operations more than doubled due to the higher prices received and the increase in production compared to 2002. Net income for 2003 also reflects a $0.1 million after-tax charge from the change in accounting principle related to the adoption of SFAS 143.

Mining

	Three Months Ended
	March 31
	2003		2002
	(in thousands)
Revenue	$	8,230	$	8,202
Operating income		1,735		2,380
Income before changes in accounting principle		1,581		2,335
Change in accounting principle		318		--
Net income		1,899		2,335

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Revenue from our mining segment was flat with 2002 and income before the change in accounting principle decreased 32 percent for the three-month period ended March 31, 2003, compared to the same period in 2002. A 14 percent increase in tons of coal sold was partially offset by lower average prices received.

Operating expenses increased 12 percent or approximately $0.7 million primarily due to higher operating costs related to the increase in production and an increase in general and administrative costs.

Income from continuing operations decreased due to an increase in direct mining costs and corporate allocations partially offset by the increase in tons of coal sold in the first quarter of 2003. Net income for 2003 also reflects a $0.3 million after-tax benefit from the change in accounting principle related to the adoption of SFAS 143.

Electric Utility Group

	Three Months Ended
	March 31
	2003		2002
	(in thousands)
Revenue	$	43,762	$	37,192
Operating expenses		30,110		22,865

Operating income	$	13,652	$	14,327

Net income	$	6,699	$	7,823

The following table provides certain operating statistics:

	Three Months Ended
	March 31
	2003		2002

Firm (system) sales - MWh		505,482		505,543
Off-system sales - MWh		245,727		161,112

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. Electric utility revenues increased 18 percent for the three-month period ended March 31, 2003, compared to the same period in the prior year. The increase in revenue was primarily due to a 53 percent increase in off-system electric megawatt-hour sales, and a 43 percent increase in average prices received. Firm residential and commercial electricity revenues increased 2 percent and 4 percent, respectively, but were offset by a 9 percent decline in industrial revenues primarily due to the closing of Homestake Gold Mine and Federal Beef Processors.

Electric operating expenses increased 32 percent for the three month period ended March 31, 2003, compared to the same period in the prior year. The increase in operating expenses was primarily due to an increase in fuel and purchased power costs and an increase in administrative and general costs. Fuel and purchased power costs increased $5.3 million due to the increase in off-system electric sales. Administrative and general expenses increased primarily due to a $0.5 million increase in pension expense and a $0.7 million increase in salaries.

Interest expense increased $1.3 million for the three month period, primarily due to interest associated with the $75 million first mortgage bonds issued in August 2002.

Net income decreased $1.1 million primarily due to the increase in interest expense, pension expense and administrative and general salaries, partially offset by an increase in electricity sales margins and transmission revenues.

Communications Group

	Three Months Ended
	March 31
	2003			2002
	(in thousands)
Revenue	$	8,687		$	7,546
Operating expenses		10,572			10,021

Operating loss	$	(1,885	)	$	(2,475	)

Net loss	$	(1,809	)	$	(2,227	)



Business customers	2,657	(a)	3,061	2,600
Business access lines	10,342		9,094	7,667
Residential customers	22,700		21,700	17,550

(a)

In 2003, reported business customers were adjusted for the consolidation of multiple-location business customers, business orders and temporary business access lines.

Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002. The communications business group’s net loss for the three-month period ended March 31, 2003 was $1.8 million, compared to $2.2 million in 2002. The performance improvement is due largely to a 15 percent increase in revenue as a result of a larger customer base, partially offset by increased depreciation and administrative and general expenses.

The total number of customers exceeded 25,000 at the end of March 2003 – a 2 percent increase over the customer base at December 31, 2002 and a 26 percent increase compared to March 31, 2002.

Earnings Guidance

We recently reaffirmed our long-term earnings per share growth rate target of 8 percent to 10 percent per year. Due to the initial dilutive effect of our common stock offering completed April 30, 2003, we expect 2003 earnings per share from continuing operations to approximate 2002 results.

Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on our critical accounting policies, see Part II, Item 7 in our 2002 Annual Report on Form 10-K.

Liquidity and Capital Resources

Cash Flow Activities

During the three-month period ended March 31, 2003, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our long-term debt maturities and to fund a portion of our property additions. We continue to fund property and investment additions primarily related to construction of additional electric generation facilities for our integrated energy business group through a combination of operating cash flow, increased short-term debt, long-term debt and long-term non-recourse project financing.

Cash flows from operations decreased $2.9 million for the three-month period ended March 31, 2003 compared to the same period in the prior year primarily due to the decrease in cash provided by changes in working capital.

During the three months ended March 31, 2003, we had cash outflows for investing activities of $31.0 million, which includes $30.3 million for property, plant and equipment additions and the acquisition of assets. Net cash outflows from financing activities totaled $15.7 million, primarily due to dividend payments and debt repayments.

Dividends

Dividends paid on our common stock totaled $0.30 per share in the first quarter of 2003. This reflects a 3.5 percent increase from the first quarter of 2002, as approved by our board of directors in January 2003, from the prior periods. 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 facilities and our future business prospects.

Short-Term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are our revolving bank facilities and cash provided by operations. As of March 31, 2003, we had approximately $68 million of cash unrestricted for operations and $395 million of credit through revolving bank facilities. Approximately $37 million of the cash balance at March 31, 2003 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company. The bank facilities consisted of a $195 million facility due August 26, 2003 and a $200 million facility due August 27, 2004. These bank facilities can be used to fund our working capital needs, for general corporate purposes and to provide liquidity for a commercial paper program if implemented. At March 31, 2003, we had $286.5 million of bank borrowings outstanding under these facilities. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $51.2 million at March 31, 2003.

A significant cash event occurred subsequent to the first quarter. On April 30, 2003, we completed a stock offering providing approximately $118 million in net proceeds. The proceeds were used to pay off a $50 million credit facility due in May 2003 and the remaining $68 million reduced the amount drawn on our 364-day revolving credit facility due August 26, 2003. After giving effect to this transaction on April 30, 2003, we had $213.5 million of bank borrowings outstanding under our corporate credit facilities with $124.2 million of remaining borrowing capacity available after the inclusion of applicable letters of credit.

The above bank facilities include covenants that are common in such arrangements. Several of the facilities require that we maintain a consolidated net worth in an amount of not less than the sum of $425 million and 50 percent of the aggregate consolidated net income beginning April 1, 2002; a recourse leverage ratio not to exceed 0.65 to 1.00; and a fixed charge coverage ratio of not less than 1.5 to 1.0. In addition, the $195 million 364-day credit facility and the $200 million three-year credit facility contain a liquidity covenant that requires us to have $30 million of liquid assets as of the last day of each fiscal quarter. Liquid assets are defined as unrestricted cash and available unused capacity under our credit facilities. If these covenants are violated, it would be considered an event of default entitling the lender to terminate the remaining commitment and accelerate all principal and interest outstanding. In addition, certain of our interest rate swap agreements include cross-default provisions. These provisions would allow the counterparty the right to terminate the swap agreement and liquidate at a prevailing market rate, in the event of default. As of March 31, 2003, we were in compliance with the above covenants.

Our consolidated net worth was $555.7 million at March 31, 2003, which was approximately $100 million in excess of the net worth we are required to maintain under the debt covenant described above. The long-term debt component of our capital structure at March 31, 2003 was 52.6 percent and our total debt leverage (long-term debt and short-term debt) was 63.8 percent. After giving effect to the common stock offering completed in April 2003 and the application of the net proceeds of the offering, our pro forma total debt leverage ratio as of March 31, 2003 was 56.1 percent.

In addition, Enserco Energy Inc., our gas marketing unit, has a $135 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. We provided no guarantee to the lender under this facility. At March 31, 2003, there were outstanding letters of credit issued under the facility of $69.9 million with no borrowing balances outstanding on the facility.

Similarly, Black Hills Energy Resources, Inc., our oil marketing unit, has a $40 million uncommitted, discretionary credit facility. This line of credit provided credit support for the purchases of crude oil by Black Hills Energy Resources. We provided no guarantee to the lender under this facility. At March 31, 2003, Black Hills Energy Resources had letters of credit outstanding of $8.7 million.

Subsequent to the end of the quarter, on May 13, 2003, our corporate credit rating was downgraded to “BBB-” by Standard and Poor’s Ratings Group.

Our ability to obtain additional financing 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 forecasted changes in liquidity and capital requirements from those reported in Item 7 of our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission.

Guarantees

During the first quarter of 2003, a $135 million completion guarantee for the expanded facilities under a construction loan for Black Hills Colorado expired. No new guarantees were issued during the three months ended March 31, 2003. At March 31, 2003, we had guarantees totaling $229.5 million in place.

RISK FACTORS

Results of an investigation into reporting of trading information could adversely affect our business.

In March 2003, we received a request for information from the Commodity Futures Trading Commission, or CFTC, calling for the production, among other things, of “all documents relating to natural gas and electricity trading” in connection with CFTC’s industry wide investigation of trade and trade reporting practices of power and natural gas trading companies. Since that time, we have produced documents and other materials in response to more specific requests relating to the reporting of natural gas trading information to energy industry publications. We are also conducting an internal investigation into the accuracy of information that former employees of Enserco Energy Inc., our gas marketing subsidiary, voluntarily reported to trade publications. As a part of our internal investigation and in response to CFTC’s document request, we provided documents and materials to the CFTC, including information identifying instances in which it appears that former employees at Enserco provided inaccurate reports of natural gas transactions to one or more industry trade publications. We intend to continue our policy of cooperation with the CFTC. However, both our internal and CFTC’s investigations are continuing, and we cannot predict their outcome or whether they will lead to legal proceedings against us, civil or criminal fines or penalties, or other regulatory action which, in turn, could adversely affect our financial condition or results of operations.

Ongoing changes in the United States utility industry, such as state and federal regulatory changes, a potential increase in the number of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.

The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:

•

consumer demands;

•

technological advances;

•

deregulation;

•

greater availability of natural gas-fired power generation; and

•

other factors.

FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses, and deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional and better capitalized competitors could become active in the generation, transmission and distribution segments of our industry, which could negatively affect our ability to expand our asset base.

In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of those generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

Several bills, including the Energy Policy Act of 2003, have been introduced in Congress that would amend or repeal portions of PURPA, including the mandatory purchase requirements under which utilities are currently required to enter into contracts to purchase power from qualifying facilities. The proposed legislation would not affect our existing contracts. If the Energy Policy Act of 2003 or similar legislation is enacted, however, utilities would no longer be required to enter into new contracts with qualifying facilities if the FERC determines that the qualifying facility has access to a competitive wholesale market for the sale of electric energy. Any such legislation, if enacted, could adversely affect the value or profitability of our qualifying facilities.

There have been no other material changes in our risk factors from those reported in Items 1 and 2 of our 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

NEW ACCOUNTING PRONOUNCEMENTS

Other than the new pronouncements reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission and those discussed in Note 4 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.

Forward Looking Statements

Some of the statements in this Form 10-Q include “forward-looking statements” as defined by the Securities and Exchange Commission, or 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 effects on our business resulting from the financial difficulties of other energy companies, including the effects on liquidity in the energy marketing and power generation businesses and markets and perceptions of the energy and energy marketing business;

•

the effects on our business resulting from a lowering of our credit rating (or actions we may take in response to changing credit ratings criteria), including demands for increased collateral by our current or new counterparties, refusal by our current or potential counterparties or customers to enter into transactions with us and our inability to obtain credit or capital in amounts or on terms favorable to us;

•

capital market conditions;

•

unanticipated developments in the western power markets, including unanticipated governmental intervention, deterioration in the financial condition of counterparties, default on amounts due from counterparties, adverse changes in current or future litigation, market disruption and adverse changes in energy and commodity supply, volume and pricing and interest rates;

•

pricing and transportation of commodities;

•

population changes and demographic patterns;

•

prevailing governmental policies and regulatory actions with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition;

•

the continuing efforts by or on behalf of the State of California to restructure its long-term power purchase contracts and efforts by regulators and private parties in several western states to recover refunds for alleged price manipulation;

•

changes in and compliance with environmental and safety laws and policies;

•

weather conditions;

•

competition for retail and wholesale customers;

•

market demand, including structural market changes;

•

changes in tax rates or policies or in rates of inflation;

•

changes in project costs;

•

unanticipated changes in operating expenses or capital expenditures;

•

technological advances by competitors;

•

competition for new energy development opportunities;

•

the cost and other effects of legal and administrative proceedings that influence our business;

•

the effects on our business, including the availability of insurance, resulting from terrorist actions or responses to such actions;

•

risk factors discussed in this Form 10-Q; and

•

other factors discussed from time to time in our 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following table provides a reconciliation of the activity in energy trading contracts marked to market during the three month period ended March 31, 2003 (in thousands):



Total fair value of natural gas marketing contract net assets at December 31, 2002	$	3,021
Net cash settled during the quarter on contracts that existed at December 31, 2002		(745	)
Change in fair value due to change in techniques and assumptions		--
Unrealized gain/(loss) on new contracts entered during the quarter and still existing
at March 31, 2003		2,725
Realized gain/(loss) on contracts that existed at December 31, 2002 and were settled
during quarter		(1,168	)
Unrealized gain/(loss) on contracts that existed at December 31, 2002 and still exist
at March 31, 2003		(4,564	)

Total fair value of natural gas marketing contract net assets at March 31, 2003	$	(731	)

On January 1, 2003, the Company adopted EITF Issue No. 02-3. As described in Notes 3 and 12 of the Notes to Condensed Consolidated Financial Statements in this Form 10-Q, the adoption of EITF 02-3 resulted in certain energy trading activities no longer being accounted for at fair value, therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities and our expected cash flows from those operations. The cumulative effect of the adoption of EITF 02-3 is included in the above reconciliation of fair value of energy trading contracts from December 31, 2002 to March 31, 2003.

At March 31, 2003, we had a mark to fair value unrealized loss of $0.7 million for our natural gas marketing activities. Of this amount, $0.9 million was current and $(1.6) million was non-current. The source of fair value measurements were as follows (in thousands):

	Maturities
Source of Fair Value	2003			2004			Total Fair Value

Actively quoted (i.e., exchange-traded) prices	$	(1,933	)	$	--		$	(1,933	)
Prices provided by other external sources		2,861			(1,659	)		1,202
Modeled		--			--			--

Total	$	928		$	(1,659	)	$	(731	)

There have been no material changes in market risk faced by us from those reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on market risk, see Part II, Item 7 in our 2002 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

Within 90 days prior to the filing date of the Form 10-Q, our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures as defined in Rules 13a-14(c) and 15d-14(c) of the Securities Exchange Act of 1934 (Exchange Act). 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 included in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.

Changes in internal controls

Our Chief Executive Officer and Chief Financial Officer have concluded that there were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their most recent evaluation of such controls, and that there were no significant deficiencies or material weaknesses in our internal controls.

BLACK HILLS CORPORATION

Part II — Other Information

Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 12 to the Company’s 2002 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 2. Changes in Securities and Use of Proceeds

(c)

On March 10, 2003, we issued the following unregistered securities pursuant to Warrant Agreements entered into in connection with the acquisition of Mallon Resources Corporation as an inducement for George O. Mallon, Jr. and Peter H. Blum to enter into consulting agreements with the Company. The warrants are exercisable on or after March 10, 2004. Each warrant provides the warrant holder the right to purchase one share of Black Hills Corporation common stock at an exercise price of $26.14 per share. The warrants shall terminate and become null and void if the warrant holder voluntarily terminates his services under the consulting agreement prior to March 10, 2004. The warrants expire on March 10, 2013.

Warrant Holder			Warrants Issued

George O. Mallon, Jr				30,000
Peter H. Blum				15,000

The unregistered securities were issued in reliance on Section 4(2) under the Securities Act of 1933, as amended. Each of the warrant holders have such knowledge and experience in financial and business matters to enable them to evaluate the risks and merits of the investment and to bear the economic risks of the investment. Warrants were not offered to any other Mallon shareholders.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits —

Exhibit 2

Agreement and Plan of Merger among Black Hills Corporation, Black Hills Acquisition Corp., and Mallon Resources Corporation, dated as of October 1, 2002 (filed as Annex A to the Proxy Statement/Prospectus included in the Registration Statement of Form S-4 No. 333-101576).

Exhibit 23.1

Consent of Petroleum Engineer and Geologist.

Exhibit 99.1

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 99.2

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

We have filed the following Reports on Form 8-K during the quarter ended March 31, 2003:

Form 8-K dated February 7, 2003.

Reported under Item 5, the Company issued press releases announcing the declaration of quarterly dividends and fourth quarter and annual results for the fiscal year ended December 31, 2002.

Form 8-K dated March 21, 2003.

Reported under Item 2, the acquisition of Mallon Resources Corporation and reported under Item 7, the financial statements of the business acquired and the pro forma financial information.

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

By: /S/ Daniel P. Landguth
Daniel P. Landguth, Chairman and
Chief Executive Officer

By: /S/ Mark T. Thies
Mark T. Thies, Executive Vice President and
Chief Financial Officer

Dated: May 15, 2003

CERTIFICATION

I, Daniel P. Landguth, certify that:

I have reviewed this quarterly report on Form 10-Q of Black Hills Corporation;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 15, 2003

/s/ Daniel P. Landguth
Chairman and
Chief Executive Officer

CERTIFICATION

I, Mark T. Thies, certify that:

I have reviewed this quarterly report on Form 10-Q of Black Hills Corporation;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 15, 2003

/s/ Mark T. Thies
Executive Vice President and
Chief Financial Officer

EXHIBIT INDEX

Exhibit Number

Description

Exhibit 2

Exhibit 23.1

Consent of Petroleum Engineer and Geologist.

Exhibit 99.1

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 99.2

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BLACK HILLS CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (unaudited)

BLACK HILLS CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS(unaudited)

BLACK HILLS CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS(unaudited)

Results of Operations

Critical Accounting Policies

Liquidity and Capital Resources

RISK FACTORS

NEW ACCOUNTING PRONOUNCEMENTS

Forward Looking Statements

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

CERTIFICATION

CERTIFICATION

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)