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, 2004.

___ 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, 2004

Common stock, $1.00 par value 32,416,379 shares

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements
Condensed Consolidated Statements of Income -
Three Months Ended March 31, 2004 and 2003	3
Condensed Consolidated Balance Sheets -
March 31, 2004, December 31, 2003 and March 31, 2003	4
Condensed Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2004 and 2003	5
Notes to Condensed Consolidated Financial Statements	6-	26
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26-	37
Item 3. Quantitative and Qualitative Disclosures about Market Risk	38-	39
Item 4. Controls and Procedures	39
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	40
Item 6. Exhibits and Reports on Form 8-K	40-	41
Signatures	42
Exhibit Index	43

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

	Three Months Ended March 31
	2004			2003
	(in thousands, except per share amounts)
Operating revenues	$	274,328		$	291,445

Operating expenses:
Fuel and purchased power		172,906			188,685
Operations and maintenance		24,455			23,082
Administrative and general		18,010			17,783
Depreciation, depletion and amortization		22,272			19,047
Taxes, other than income taxes		8,431			7,385

		246,074			255,982

Equity in earnings (losses) of unconsolidated subsidiaries		(249	)		456

Operating income		28,005			35,919

Other income (expense):
Interest expense		(14,351	)		(12,302	)
Interest income		392			142
Other expense		(103	)		(132	)
Other income		389			316

		(13,673	)		(11,976	)

Income from continuing operations before minority interest, income taxes and
change in accounting principles		14,332			23,943
Minority interest		(42	)		--
Income taxes		(4,326	)		(8,278	)

Income from continuing operations before change in accounting principles		9,964			15,665
Income (loss) from discontinued operations, net of taxes		(178	)		1,193
Change in accounting principles, net of taxes		--			(2,680	)

Net income		9,786			14,178
Preferred stock dividends		(88	)		(57	)

Net income available for common stock	$	9,698		$	14,121

Weighted average common shares outstanding:
Basic		32,291			27,041

Diluted		32,811			27,411

Earnings per share:
Basic-
Continuing operations	$	0.31		$	0.58
Discontinued operations		(0.01	)		0.04
Change in accounting principles		--			(0.10	)

Total	$	0.30		$	0.52

Diluted-
Continuing operations	$	0.30		$	0.58
Discontinued operations		--			0.04
Change in accounting principles		--			(0.10	)

Total	$	0.30		$	0.52

Dividends paid per share of common stock	$	0.31		$	0.30

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 2004			December 31 2003			March 31 2003
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	191,484		$	172,771		$	63,095
Restricted cash		1,070			1,350			1,070
Receivables (net of allowance for doubtful accounts
of $7,582; $7,345 and $3,929, respectively)		205,052			201,992			210,825
Notes receivable		239			554			554
Materials, supplies and fuel		50,980			44,895			23,482
Derivative assets		23,214			26,804			31,881
Prepaid income taxes		--			18,940			--
Deferred income taxes		5,350			4,229			131
Other assets		5,678			8,324			6,460
Assets of discontinued operations		3,876			3,893			175,599

		486,943			483,752			513,097

Investments		27,560			27,347			20,282

Property, plant and equipment		1,898,072			1,882,697			1,782,250
Less accumulated depreciation and depletion		(463,564	)		(440,275	)		(390,510	)

		1,434,508			1,442,422			1,391,740

Other assets:
Derivative assets		257			1,002			496
Goodwill		30,144			30,144			23,922
Intangible assets (net of accumulated amortization
of $19,252, $18,423 and $16,601, respectively)		39,241			40,070			77,023
Other		36,717			38,488			21,414

		106,359			109,704			122,855

	$	2,055,370		$	2,063,225		$	2,047,974

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	200,000		$	162,722		$	183,726
Accrued income taxes		5,973			5,816			133
Accrued liabilities		68,160			66,629			78,126
Current maturities of long-term debt		15,723			17,659			16,543
Notes payable		--			--			336,517
Derivative liabilities		30,326			32,967			35,839
Liabilities of discontinued operations		493			467			103,818

		320,675			286,260			754,702

Long-term debt, net of current maturities		822,289			868,459			541,271

Deferred credits and other liabilities:
Deferred income taxes		129,194			125,041			123,456
Derivative liabilities		2,894			3,247			5,912
Other		64,918			65,782			66,981

		197,006			194,070			196,349

Minority interest in subsidiaries		4,731			4,689			--

Stockholders' equity:
Preferred stock - no par Series 2000-A; 21,500
shares authorized; Issued and outstanding: 6,839;
7,771 and 5,177 shares, respectively		7,167			8,143			5,549

Common stock equity-
Common stock $1 par value; 100,000,000
shares authorized;
Issued 32,552,878; 32,447,765 and 27,627,211
shares, respectively		32,553			32,448			27,627
Additional paid-in capital		382,782			379,271			259,878
Retained earnings		304,249			304,567			286,655
Treasury stock at cost - 144,001; 150,048 and
166,649 shares, respectively		(3,435	)		(3,560	)		(3,850	)
Accumulated other comprehensive loss		(12,647	)		(11,122	)		(20,207	)

		703,502			701,604			550,103

Total stockholders' equity		710,669			709,747			555,652

	$	2,055,370		$	2,063,225		$	2,047,974

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
	2004			2003
	(in thousands)
Operating activities:
Net income available for common	$	9,698		$	14,121
Adjustments to reconcile net income available for common to net cash
provided by operating activities:
Income (loss) from discontinued operations		178			(1,193	)
Depreciation, depletion and amortization		22,272			19,047
Net change in derivative assets and liabilities		(1,139	)		(333	)
Deferred income taxes		3,886			2,965
Undistributed earnings in associated companies		(234	)		(336	)
Change in accounting principles		--			2,680
Change in operating assets and liabilities-
Accounts receivable and other current assets		12,329			(42,043	)
Accounts payable and other current liabilities		38,966			35,280
Other operating activities		179			3,063

		86,135			33,251

Investing activities:
Property, plant and equipment additions		(13,544	)		(25,042	)
Increase in notes receivable - Mallon Resources		--			(5,164	)
Other investing activities		1,529			(1,685	)

		(12,015	)		(31,891	)

Financing activities:
Dividends paid		(10,016	)		(8,094	)
Common stock issued		2,640			1,233
Decrease in short-term borrowings, net		--			(3,983	)
Long-term debt - repayments		(48,106	)		(2,537	)
Other financing activities		75			71

		(55,407	)		(13,310	)

Increase (decrease) in cash and cash equivalents		18,713			(11,950	)
Cash and cash equivalents:
Beginning of period		172,771			75,045

End of period	$	191,484		$	63,095

Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest	$	10,744		$	15,664
Net income taxes (received) paid	$	(18,819	)	$	137
Non-cash net assets acquired through issuance of common stock and
decrease in notes receivable - Mallon Resources	$	--		$	51,153
Common stock issued in conversion of preferred shares	$	976		$	--

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 2003 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 2003 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, 2004, December 31, 2003 and March 31, 2003, financial information and are of a normal recurring nature. The results of operations for the three months ended March 31, 2004, 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)

RECLASSIFICATIONS

Certain 2003 amounts in the financial statements have been reclassified to conform to the 2004 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.

(3)

STOCK-BASED COMPENSATION

At March 31, 2004, the Company had 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 employee compensation cost related to stock options 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 (in thousands, except per share amounts):

	Three Months Ended March 31
	2004			2003

Net income available for common stock, as reported	$	9,698		$	14,121
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects		(188	)		(242	)

Pro forma net income	$	9,510		$	13,879

Earnings per share:
As reported--
Basic
Continuing operations	$	0.31		$	0.58
Discontinued operations		(0.01	)		0.04
Change in accounting principles		--			(0.10	)

Total	$	0.30		$	0.52

Diluted
Continuing operations	$	0.30		$	0.58
Discontinued operations		--			0.04
Change in accounting principles		--			(0.10	)

Total	$	0.30		$	0.52

Pro forma--
Basic
Continuing operations	$	0.30		$	0.57
Discontinued operations		(0.01	)		0.04
Change in accounting principles		--			(0.10	)

Total	$	0.29		$	0.51

Diluted
Continuing operations	$	0.29		$	0.57
Discontinued operations		--			0.04
Change in accounting principles		--			(0.10	)

Total	$	0.29		$	0.51

(4)

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In January 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-1), which permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 until remaining questions – notably the issue of how to account for the federal subsidy – are resolved. The Company provides prescription drug benefits to certain eligible employees and has elected the one-time deferral of accounting for the effects of the 2003 Medicare Act. The Company intends to analyze the 2003 Medicare Act, along with the authoritative guidance, when issued, to determine if its benefit plans need to be amended and how to record the effects of the 2003 Medicare Act. Specific guidance on the accounting for the federal subsidy provided by the 2003 Medicare Act is pending and that guidance, when issued, could require the Company to change previously reported postretirement benefit information.

During the second quarter of 2003, discussion between the Securities and Exchange Commission (SEC) and FASB staffs raised concerns over the interaction of SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (SFAS 19) and SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). The discussion focused on whether or not pronouncements set forth by SFAS 142 requiring more clarity in distinguishing between tangible and intangible assets, required oil and gas producing companies to reclassify amounts related to mineral rights from tangible assets to intangible assets upon adoption of SFAS 142. In April 2004, the FASB issued FSP FAS 141-1 and FAS 142-1, “Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, Whether Mineral Rights Are Tangible or Intangible Assets.” The FSP amends SFAS 141 and SFAS 142 to conform with the EITF consensus in EITF 04-2 that mineral rights, as defined by the Issue, are tangible assets. When the Company adopted SFAS 142 on January 1, 2002, the amounts related to mineral rights were classified as tangible assets and continue to be classified in “Property, plant and equipment” on the accompanying Condensed Consolidated Balance Sheets.

(5)

MATERIALS, SUPPLIES AND FUEL

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

Major Classification	March 31, 2004		December 31, 2003		March 31, 2003


Materials and supplies	$	20,884	$	18,920	$	17,530
Fuel for generation		1,248		1,581		1,002
Gas and oil held by energy marketing		28,848		24,394		4,950

Total materials, supplies and fuel	$	50,980	$	44,895	$	23,482

(6)

ASSET RETIREMENT OBLIGATIONS

SFAS No. 143, “Accounting for Asset Retirement Obligations” (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 Company has 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.

The following table presents the details of the Company’s asset retirement obligations which are included on the accompanying Condensed Consolidated Balance Sheets in “Other” under “Deferred credits and other liabilities” (in thousands):

	Balance at 12/31/03		Liabilities Incurred		Liabilities Settled			Accretion		Cash Flow Revisions		Balance at 3/31/04


Oil and Gas	$	7,233	$	--	$	--		$	161	$	--	$	7,394
Mining		15,752		219		(22	)		270		--		16,219

Total	$	22,985	$	219	$	(22	)	$	431	$	--	$	23,613

(7)

VARIABLE INTEREST ENTITY

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). In December 2003, the FASB issued FIN No. 46 (Revised) (FIN 46-R) to address certain FIN 46 implementation issues. The Company’s subsidiary, Black Hills Wyoming has an agreement with Wygen Funding, Limited Partnership, an unrelated variable interest entity (VIE) to lease the Wygen plant. Under the accounting interpretation, as amended, the Company consolidated the VIE effective December 31, 2003. The effect of consolidating the VIE into the Company’s Consolidated Balance Sheet at December 31, 2003, was an increase in total assets of $129.0 million, of which $121.5 million, net of accumulated depreciation of $3.0 million, is included in Property, plant and equipment and an increase in long-term debt in the amount of $128.3 million.

Prior to the December 31, 2003 consolidation, the Company recorded lease expense on the Wygen plant. Lease payments began upon completion of the plant in February 2003. During the three months ended March 31, 2003, lease payments were $0.9 million and are included in Operations and maintenance on the accompanying 2003 Condensed Consolidated Statement of Income. The net effect on current results is to recognize depreciation and interest expense in place of recognizing lease expense. During the three months ended March 31, 2004, depreciation expense was $0.8 million and interest expense was $0.8 million, respectively.

(8)

EARNINGS PER SHARE

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

	Income
Period ended March 31, 2004 (in thousands)	Three Months

Income from continuing operations	$	9,964
Less: preferred stock dividends		(88	)

Basic - available for common shareholders		9,876		32,291
Dilutive effect of:
Stock options		--		115
Convertible preferred stock		88		195
Estimated contingent shares issuable for prior acquisition		--		158
Others		--		52

Diluted - available for common shareholders	$	9,964		32,811

	Income
Period ended March 31, 2003 (in thousands)	Three Months

Income from continuing operations	$	15,665
Less: preferred stock dividends		(57	)

Basic - available for common shareholders		15,608		27,041
Dilutive effect of:
Stock options		--		46
Convertible preferred stock		57		148
Others		--		176

Diluted - available for common shareholders	$	15,665		27,411

On April 30, 2003, the Company completed a public offering of 4.6 million shares of common stock. Accordingly, this transaction significantly affects the weighted average number of common shares outstanding used in earnings per share calculations for the current and for future periods.

(9)

COMPREHENSIVE INCOME

The following table presents the components of the Company’s comprehensive (loss) income (in thousands):

	Three Months Ended March 31
	2004			2003

Net income	$	9,786		$	14,178
Other comprehensive (loss) income, net of tax:
Fair value adjustment on derivatives designated as cash
flow hedges, (2003 is net of minority interest share of $228)		(1,504	)		985
Unrealized loss on available-for-sale securities		(21	)		--

Comprehensive income	$	8,261		$	15,163

(10)

CHANGES IN COMMON STOCK

Other than the following transactions, the Company had no other material changes in its common stock, as reported in Note 8 of the Company’s 2003 Annual Report on Form 10-K.

First Quarter 2004 Transactions

•

On March 1, 2004, certain officers of the Company were named participants in a performance share award plan. Entitlement to performance shares is based on the Company’s total shareholder return over designated performance periods as measured against a selected peer group. In addition, the Company’s stock price must also increase during the performance periods. Target grants of performance shares were made for the following performance periods:


Grant Date	Performance Period	Target Grant of Shares

March 1, 2004	March 1, 2004 - December 31, 2005		15,458
March 1, 2004	March 1, 2004 - December 31, 2006		31,384

Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50^th percentile of the selected peer group. The final value of the performance shares may vary according to the number of shares of common stock that are ultimately granted based upon the performance criteria. Compensation expense recognized for the performance share awards for the quarter ended March 31, 2004, was $0.1 million. The performance awards are paid in 50 percent cash and 50 percent common stock.

•

932 shares of the Preferred Stock, Series 2000-A were converted into 26,628 shares of common stock at the conversion price of $35.00 per share.

•

The Company granted 98,000 stock options at a weighted average exercise price of $30.14 per share.

•

55,934 stock options were exercised at a weighted average price of $20.34 per share.

•

The Company issued 10,310 shares of common stock from treasury shares under the short-term incentive compensation plan. Compensation cost related to the award was approximately $0.3 million, which was accrued for in 2003.

•

The Company granted 1,886 restricted stock units. The pre-tax compensation cost related to the award of approximately $0.1 million will be recognized over the three year vesting period.

•

The Company acquired 4,005 shares of treasury stock related to a forfeiture of unvested restricted stock.

•

The Company issued 2,437 shares of common stock under its employee stock purchase plan at a price of $28.59 per share.

•

The Company issued 20,948 shares of common stock under its dividend reinvestment plan at a weighted average price of $30.33 per share.

(11)

CHANGES IN LONG-TERM DEBT

On January 30, 2004, the Company repaid $45 million of the long-term debt outstanding on the project-level debt at our Fountain Valley facility.

(12)

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, 2004 the Company had the following guarantees in place (in thousands):

Nature of Guarantee	Outstanding at March 31, 2004		Year Expiring


Guarantee payments under the Las Vegas Cogen I Power Purchase and			Upon 5 days
Sales Agreement with Sempra Energy Solutions	$	10,000	written notice
Guarantee payments under certain energy marketing derivative, power
and gas agreements		2,500	2004
Guarantee of certain obligations under Enserco's credit facility		3,000	2004
Guarantee of obligation of Las Vegas Cogen II under an
interconnection and operation agreement		750	2005
Guarantee payments of Black Hills Power under various transactions
with Idaho Power Company		500	2005
Guarantee obligations under the Wygen Plant Lease		111,018	2008
Guarantee payment and performance under credit agreements for two
combustion turbines		29,714	2010
Indemnification for subsidiary reclamation/surety bonds		29,759	Ongoing

	$	187,241

The Company has guaranteed up to $10.0 million of payments of its power generation subsidiary, Las Vegas Cogeneration Limited Partnership, to Sempra Energy Solutions which may arise from transactions entered into by the two parties under a Master Power Purchase and Sale Agreement. To the extent liabilities exist under this power and purchase sale agreement subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. The guarantee may be terminated for future transactions upon five days written notice.

The Company has guaranteed up to $2.5 million of commodity related payments for its energy marketing subsidiary, Enserco Energy Inc. This guarantee was provided to the counterparty in order to facilitate physical and financial transactions in energy commodities and related services. To the extent liabilities exist under the commodity- related contract subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. The guarantee expires on June 30, 2004.

The Company has guaranteed up to $3.0 million of Enserco Energy Inc.‘s obligations to Fortis Capital Corp. under its credit facility. There are no liabilities on the Company’s Condensed Consolidated Balance Sheets associated with this guarantee.

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 $0.5 million of the obligations of its electric utility subsidiary, Black Hills Power, Inc., under various transactions with Idaho Power Company. To the extent liabilities exist under these transactions and subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. This guarantee expires on the earlier of March 1, 2005 or 30 days after the date creditor receives written notification from guarantor.

The Company has guaranteed the obligations of Black Hills Wyoming under the Agreement for Lease and Lease for the Wygen plant. The Company consolidates the Variable Interest Entity that owns the plant into its financial statements, therefore the obligations associated with this guarantee are included in the Condensed Consolidated Balance Sheets. 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, 2004, the Company’s maximum obligation under the guarantee is $111.0 million (83.5 percent of $133.0 million, the cost incurred for the Wygen plant). The initial term of the lease is five years with two five-year renewal options.

The Company has guaranteed the payment of $25.5 million of debt of Black Hills Wyoming and $4.2 million of debt for another of its wholly-owned subsidiaries, Black Hills Generation. The debt is recorded on the Company’s Condensed Consolidated Balance Sheets and is due December 18, 2010.

In addition, at March 31, 2004, the Company had guarantees in place totaling approximately $29.8 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.

(13)

EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of the Company and the following subsidiaries, Black Hills Power, Inc., Wyodak Resources Development Corp., Black Hills Exploration and Production and Daksoft who meet certain eligibility requirements.

The components of net periodic benefit cost for the Plan for the three months ended March 31 are as follows (in thousands):

	2004			2003


Service cost	$	443		$	323
Interest cost		909			838
Expected return on plan assets		(1,129	)		(780	)
Amortization of prior service cost		58			58
Amortization of net loss		375			352

Net periodic benefit cost	$	656		$	791

The Company does not anticipate that a contribution will be made to the Plan in the 2004 fiscal year.

Supplemental Nonqualified Defined Benefit Plan

The Company has various supplemental retirement plans for outside directors and key executives of the Company. The Plans are nonqualified defined benefit plans.

The components of net periodic benefit cost for the supplemental nonqualified plans for the three months ended March 31 are as follows (in thousands):

	2004		2003


Service cost	$	134	$	106
Interest cost		241		190
Amortization of prior service cost		2		(1	)
Amortization of net loss		187		128

Net periodic benefit cost	$	564	$	423

The Company anticipates that contributions to the Plan for the 2004 fiscal year will be approximately $0.8 million; the contributions are expected to be in the form of benefit payments.

Non-pension Defined Benefit Postretirement Plan

Employees who are participants in the Company’s Postretirement Healthcare Plan and who retire from the Company on or after attaining age 55 after completing at least five years of service to the Company are entitled to postretirement healthcare benefits. These financial statements and this Note do not reflect the effects of the 2003 Medicare Act on the postretirement benefit plan (see Note 4).

The components of net periodic benefit cost for the Postretirement Healthcare Plan for the three months ended March 31 are as follows (in thousands):

	2004			2003


Service cost	$	140		$	96
Interest cost		166			144
Amortization of net transition obligation		37			37
Amortization of prior service cost		(6	)		(6	)
Amortization of net loss		47			22

Net periodic benefit cost	$	384		$	293

The Company anticipates that contributions to the Plan for the 2004 fiscal year will be approximately $0.6 million; the contributions are expected to be in the form of benefits and administrative costs paid.

(14)

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, 2004, 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: Wholesale 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; and Power Generation, which produces and sells generating capacity and electricity to wholesale customers; Retail Services group consisting of the following segments: Electric, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Communications, which primarily markets broadband communications services.

Prior to 2004, the Company’s communications segment marketed campground reservation services and software development services to external parties through Daksoft, Inc. With the sale of certain assets and a change in its business strategy, Daksoft now primarily provides information technology support to the Company. With its focus now on corporate support, beginning with the first quarter 2004, Daksoft’s results of operations are included with corporate results.

Other than noted above, segment information follows the same accounting policies as described in Note 18 of the Company’s 2003 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 Statements of Income is as follows (in thousands):

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


Quarter to Date and Year to Date
March 31, 2004
Energy marketing*	$	164,435	$	--		$	3,969
Power generation		35,137		--			(2,077	)
Oil and gas		16,321		83			3,687
Mining		5,546		3,182			1,722
Electric		41,626		21			5,037
Communications		8,455		--			(1,784	)
Corporate		310		561			(590	)
Intersegment eliminations		--		(1,349	)		--

Total	$	271,830	$	2,498		$	9,964

*All periods presented reflect a net presentation of revenues at our gas marketing subsidiary and a gross presentation of revenues
at our crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19.

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


Quarter to Date and Year to Date
March 31, 2003
Energy marketing*	$	182,427	$	--		$	4,245
Power generation		39,722		--			3,377
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	$	288,969	$	2,476		$	15,665

The Company had no material changes in total assets of its reporting segments, as reported in Note 18 of the Company’s 2003 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

(15)

RISK MANAGEMENT ACTIVITIES

The Company actively manages its exposure to certain market risks as described in Note 2 of the Company’s 2003 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

The contract or notional amounts and terms of our natural gas marketing activities and derivative commodity instruments that were marked-to-market on March 31, 2004, December 31, 2003 and March 31, 2003 are as follows:

	March 31, 2004				December 31, 2003				March 31, 2003
(thousands of MMBtu's)	Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years
Natural gas basis swaps
purchased		36,180		2		13,028		1		63,167		2
Natural gas basis swaps sold		38,340		2		12,691		1		65,303		2
Natural gas fixed-for-float
swaps purchased		16,578		1.5		19,645		1.5		12,589		2
Natural gas fixed-for-float
swaps sold		26,779		1.75		21,752		1.5		19,194		1
Natural gas physical purchases		72,888		1.75		50,757		2.25		57,512		1
Natural gas physical sales		59,969		2		44,066		2.25		37,979		2

Derivative contracts related to our 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, 2004	$	22,918	$	257	$	22,372	$	165	$	638

December 31, 2003	$	26,376	$	1,002	$	26,495	$	1,291	$	(408	)

March 31, 2003	$	28,418	$	479	$	27,490	$	2,138	$	(731	)

For the three month periods ended March 31, 2004 and 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 the Company’s 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. The prior authoritative accounting guidance applied was EITF 98-10, which allowed a broad interpretation of what constituted “trading activity” and hence what would be marked-to-market. EITF 02-3 took a much narrower view of what “trading activity” should be marked-to-market, limiting mark-to-market treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. At our natural gas marketing operations, we often employ strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in very limited circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow us to mark our inventory, transportation or storage positions to market. The result is that while a significant majority of our natural gas marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives), but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.

Non-trading Energy Activities

Crude Oil Marketing

The contract or notional amounts and terms of our crude oil contracts, are set forth below:

	March 31, 2004				December 31, 2003				March 31, 2003
	Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years

(thousands of barrels)
Crude oil purchased		1,574		.75		2,688		0.5		3,530		.75
Crude oil sold		2,215		.75		2,253		0.5		3,426		.75

As of March 31, 2004 and December 31, 2003, all of the Company’s crude oil marketing contracts are accounted for under the accrual method of accounting. Oil contracts entered into on or before October 25, 2002 and still in effect at March 31, 2003, were marked to fair value and the gains and/or losses recognized in earnings on March 31, 2003. The amounts related to the accompanying 2003 Condensed Consolidated Balance Sheet and Statement of Income are as follows (in thousands):

	Current Derivative Assets		Non-current Derivative Assets		Current Derivative Liabilities		Non-current Derivative		Liabilities


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

Oil and Gas Exploration and Production

On March 31, 2004, December 31, 2003 and March 31, 2003 the Company had the following swaps and related balances (in thousands):

(in thousands)		Maximum Terms in Years	Current Derivative Assets		Non-current Derivative Assets	Current Derivative Liabilities		Non-current Derivative Liabilities		Pre-tax Accumulated Other Comprehensive Income (Loss)			Pre-tax Income (Loss)


March 31, 2004
Crude oil swaps	390,000	1.75	$	--	$ --	$	2,228	$	258	$	(2,448	)	$	(38	)
Natural gas swaps	2,870,000	1		25	--		2,548		--		(2,523	)		--

			$	25	$ --	$	4,776	$	258	$	(4,971	)	$	(38	)

December 31, 2003
Crude oil swaps	360,000	1	$	--	$ --	$	1,445	$	--	$	(1,384	)	$	(61	)
Natural gas swaps	4,830,000	1.25		172	--		1,611		25		(1,462	)		(2	)

			$	172	$ --	$	3,056	$	25	$	(2,846	)	$	(63	)

March 31, 2003
Crude oil swaps	480,000	2	$	49	$ 17	$	897	$	--	$	(783	)	$	(48	)
Natural gas swaps	5,580,000	1		1,921	--		1,497		--		424			--

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

_________________

*crude in barrels, gas in MMBtu’s

Based on March 31, 2004 market prices, a $4.8 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, 2004 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

On March 31, 2004, December 31, 2003 and March 31, 2003, 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, 2004
Swaps on
project
financing	$	113,000		4.48	%	2.5	$	271	$	--	$	3,178	$	2,471	$	(5,378	)

December 31, 2003

Swaps on
project
financing	$	113,000		4.48	%	2.75	$	256	$	--	$	3,247	$	1,931	$	(4,922	)
Swaps on
corporate debt		25,000		5.28	%	0.25		--		--		169		--		(169	)

Total	$	138,000					$	256	$	--	$	3,416	$	1,931	$	(5,091	)

March 31, 2003
Swaps on
project
financing	$	188,000	^(a)	4.24	%	4	$	205	$	--	$	4,633	$	3,774	$	(8,202	)
Swaps on
corporate debt		125,000		4.12	%	1		640		--		939		--		(299	)

Total	$	313,000					$	845	$	--	$	5,572	$	3,774	$	(8,501	)

^(a)Amounts exclude interest rate swaps related to our discontinued hydroelectric operations, sold in September 2003. At March 31, 2003, these swaps had a notional amount of $63.9 million and a fair value of $(9.2) million. The related balances are currently classified in “discontinued operations”.

Based on March 31, 2004 market interest rates and balances, approximately $2.9 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.

(16)

LEGAL PROCEEDINGS

The Company is subject to various legal proceedings, claims and litigation as described in Note 14 of the Company’s 2003 Annual Report on Form 10-K. There have been no material developments in these proceedings or any new material proceedings that have developed during the first quarter of 2004.

(17)

GAIN ON SALE OF ASSETS

On March 1, 2004, the Company’s subsidiary, Daksoft, Inc., sold assets used in its campground reservation system. The Company recorded a pre-tax gain on the sale of the assets of $1.0 million, which is included as an offset to Operating expenses, Administrative and general on the 2004 Condensed Consolidated Statement of Income. Prior to this sale, for segment reporting (Note 14) results of operations for Daksoft were included in the Communications Group and Segment. As Daksoft now primarily provides information technology support to the Company, its results are included in “Corporate” for segment reporting.

(18)

ACQUISITION

On March 10, 2003, the Company completed its acquisition of the Denver-based Mallon Resources Corporation as further described in Note 19 of the Company’s 2003 Annual Report on Form 10-K. The results of operations of Mallon Resources Corporation have been included in the accompanying Condensed 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 (in thousands):

	Three Months Ended March 31
	2003

Operating revenues		$294,386
Income from continuing operations		$15,217
Net income		$13,730
Earnings per share--
Basic:
Continuing operations		$0.55
Total		$0.50
Diluted:
Continuing operations		$0.55
Total		$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.

(19)

PENDING ACQUISITON

On January 13, 2004, the Company entered into a Stock Purchase Agreement to acquire from Xcel Energy Inc. all of the outstanding capital stock of its subsidiary, Cheyenne Light, Fuel & Power Company (Cheyenne), a Wyoming corporation. Cheyenne owns and operates transmission and distribution facilities to provide electricity and natural gas to consumers in Laramie County, Wyoming. The consideration for the acquisition includes a cash payment plus assumption of outstanding debt of Cheyenne. The acquisition, which is subject to federal and state regulatory approvals, is expected to close prior to December 31, 2004.

(20)

DISCONTINUED OPERATIONS

The Company accounts for its discontinued operations under the provisions of Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (SFAS 144). Accordingly, results of operations and the related charges for discontinued operations have been classified as “Income from discontinued operations, net of tax” in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis.

Adoption of Plan to Sell Pepperell Plant

During the third quarter of 2003, the Company adopted a plan to sell the 40 megawatt gas-fired Pepperell plant, which is part of the non-regulated Power Generation segment. The Pepperell plant is the Company’s only remaining generation asset in the eastern market and management has determined that it is a non-strategic asset. Management currently believes the assets will be sold by September 30, 2004. For business segment reporting purposes, the Pepperell plant results were previously included in the Power Generation segment.

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

	Three Months Ended March 31
	2004			2003

Operating revenues	$	--		$	1,396

Pre-tax loss from discontinued operations	$	(272	)	$	(333	)
Income tax benefit		94			119

Net loss from discontinued operations	$	(178	)	$	(214	)

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

	March 31 2004			December 31 2003			March 31 2003


Current assets	$	232		$	249		$	810
Property, plant and equipment		1,064			1,064			4,692
Non-current deferred tax asset		2,580			2,580			388
Other current liabilities		(88	)		(86	)		(14	)
Non-current liabilities		(405	)		(381	)		(18	)

Net assets of discontinued operations	$	3,383		$	3,426		$	5,858

Sale of Hydroelectric Assets

On September 30, 2003 the Company sold its seven hydroelectric power plants located in upstate New York.

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

	Three Months Ended March 31
	2003

Operating revenues	$	6,491

Pre-tax income from discontinued operations	$	1,961
Income tax expense		(554	)

Net income from discontinued operations	$	1,407

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

	March 31 2003


Current assets	$	8,693
Property, plant and equipment		147,431
Goodwill		9,772
Other non-current assets		3,813
Current derivative liability		(4,253	)
Other current liabilities		(12,744	)
Long-term debt		(75,624	)
Non-current derivative liability		(4,939	)
Other non-current liabilities		(6,226	)

Net assets of discontinued operations	$	65,923

(21)

SUBSEQUENT EVENT

On April 1, 2004, the Company’s long-term tolling contract to provide capacity and energy from the Las Vegas II power plant to Nevada Power Company (NPC), a subsidiary of Sierra Pacific Resources, became effective. The contract is a tolling arrangement whereby NPC is responsible for supplying natural gas. The Las Vegas II power plant, comprised of combined-cycle gas turbines, is rated at 224 megawatts. The power plant’s capacity and energy will be fully dispatchable by NPC to serve its retail load.

The Company has guaranteed up to $5.0 million of payments of its power generation subsidiary, Las Vegas Cogeneration II, LLC to Nevada Power Company, which may arise from transactions under the Western Systems Power Pool Agreement dated October 1, 2003, and the related Confirmation Agreement dated December 19, 2003. To the extent liabilities exist under this agreement subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. The guarantee will expire upon the payment in full of all the obligations under the contract, which expires in 2013.

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

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


Business Group			Financial Segment

Wholesale energy group			Power generation
			Oil and gas exploration and production
			Coal mining
			Energy marketing
Retail services group			Electric utility
			Communications

Our wholesale energy group, Black Hills Energy, Inc., engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing and transportation of fuel products. Our retail services group consists of our electric utility and communications segments. Our electric utility, Black Hills Power, Inc., generates, transmits and distributes electricity to an average of approximately 61,000 customers in South Dakota, Wyoming and Montana. Our communications segment provides broadband communications services to over 26,000 residential and business customers in Rapid City and the Northern Black Hills region of South Dakota through Black Hills FiberCom, LLC.

In 2003, we made the decision to divest of our non-strategic power generation assets located in the Northeastern United States. On September 30, 2003, we sold our seven hydroelectric power plants located in Upstate New York.

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 2003 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
	2004			2003

Revenues
Wholesale energy		82	%		82	%
Electric utility		15			15
Communications		3			3

		100	%		100	%

Income/ (Loss) from Continuing Operations
Wholesale energy		73	%		71	%
Electric utility		51			43
Communications		(18	)		(12	)
Corporate		(6	)		(2	)

		100	%		100	%

Discontinued operations in 2004 represent the operations of our 40 MW Pepperell power plant, our last power plant in the Eastern region, which is currently held for sale. Discontinued operations in 2003 represent the Pepperell plant as well as operations of the hydroelectric power plants located in upstate New York, which were sold on September 30, 2003.

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Consolidated income from continuing operations for the three-month period ended March 31, 2004 was $10.0 million or $0.30 per share compared to $15.7 million or $0.58 per share in the same period of the prior year. Income from continuing operations for the three-month period ended March 31, 2004 includes a gain on the sale of certain assets that resulted in a net benefit of $0.02 per share after-tax. This gain on sale is included in our “Corporate” results.

Per share results in the first quarter of 2004 were also affected by an increase of 5.4 million weighted average shares outstanding, compared to the same period in 2003, due primarily to a 4.6 million share common stock offering in April 2003.

Net income for the three months ended March 31, 2003, included a charge of $2.7 million or ($0.10) per share for change in accounting principles. The change in accounting principles 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.

Discussion of results from our operating groups and segments are included in the following pages.

Wholesale Energy Group

	Three Months Ended
	March 31
	2004			2003
	(in thousands)
Revenue:
Energy marketing*	$	164,435		$	182,427
Power generation		35,137			39,722
Oil and gas		16,404			9,062
Mining		8,728			8,230

Total revenue		224,704			239,441
Equity in earnings (losses) of unconsolidated subsidiaries		(249	)		456
Operating expenses		206,935			215,239

Operating income	$	17,520		$	24,658

Income from continuing operations	$	7,301		$	11,065

*All periods presented reflect a net presentation of revenues at our gas marketing subsidiary and a gross presentation of revenues at our crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19.

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

	Three Months Ended March 31
	2004		2003

Fuel production:
Tons of coal sold		1,203,600		1,143,000
Barrels of oil sold		114,300		103,560
Mcf of natural gas sold		2,394,300		1,300,100
Mcf equivalent sales		3,079,900		1,921,500

	March 31
	2004		2003

Independent power capacity:
MWs of independent power capacity in service(a)		1,004		1,046

___________________

(a)	Capacity in service includes 40 MW and 82 MW in 2004 and 2003, respectively, which are currently reported as "Discontinued operations."

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

	Three Months Ended March 31
	2004		2003

Natural gas - MMBtus		1,584,200		1,188,000
Crude oil - barrels		49,700		58,000

Discussion of results from our Wholesale Energy group’s operating segments are as follows:

Energy Marketing

	Three Months Ended March 31
	2004		2003
	(in thousands)
Revenue*	$	164,435	$	182,427
Operating income		6,301		6,678
Income from continuing operations before change in accounting
principle		3,969		4,245
Change in accounting principle		--		(2,870	)
Net income		3,969		1,375

*All periods presented reflect a net presentation of revenues at our gas marketing subsidiary and a gross presentation of revenues at our crude oil marketing subsidiary in accordance with EITF 02-3 and EITF 99-19.

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. The decrease in revenues is a result of a 13 percent decrease in crude oil volumes marketed, partially offset by a 4 percent increase in the average price per barrel marketed. Revenue decreases from crude oil marketing were offset by a similar decrease in the cost of crude oil sold.

Income from continuing operations decreased $0.3 million due to a decrease in gas marketing margins received and a $0.3 million unrealized mark-to-market loss for 2004, compared to a $2.4 million unrealized gain in 2003, resulting in a quarter-over-quarter pre-tax decrease of $2.7 million in unrealized mark-to-market adjustment at our gas marketing operations (See Note 15 for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas marketing operations). These items were partially offset by a 33 percent increase in natural gas volumes marketed and a $1.5 million increase in income from continuing operations at our crude oil marketing and transportation business resulting from an increase in contracted crude oil transportation and storage revenues.

Power Generation

	Three Months Ended March 31
	2004			2003
	(in thousands)
Revenue	$	35,137		$	39,722
Equity in (losses) earnings of unconsolidated subsidiaries		(199	)		117
Operating income		3,394			13,611
(Loss) income from continuing operations		(2,077	)		3,377

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Revenue decreased 12 percent in 2004 compared to 2003 primarily as a result of decreased energy sales at our plants not currently under long-term contract as there had been limited opportunities for economic dispatch due to the prevailing regional power market conditions. This includes a $5.8 million decrease in revenues at our Las Vegas facility, which has been selling power into the market, when economic to do so, since the September 2003 termination and buyout of the long-term contract at the Las Vegas II plant. A new long-term tolling arrangement for the capacity and energy of the Las Vegas II plant was entered into with Nevada Power Company and became effective April 1, 2004. These decreases were partially offset by additional revenue from a full quarter of capacity and energy payments at our 90 megawatt Wygen plant that became operational in February 2003.

Income from continuing operations decreased $5.5 million. Decreased earnings were the result of lower revenues, increased fuel cost primarily related to generating costs at our Las Vegas facility, higher depreciation costs primarily related to the Wygen plant, partially offset by lower interest expense from debt reduction from the proceeds of an asset sale and contract termination outweighed higher interest rates.

Oil and Gas

	Three Months Ended March 31
	2004			2003
	(in thousands)
Revenue	$	16,404		$	9,062
Equity in (losses) earnings of unconsolidated subsidiaries		(50	)		339
Operating income		5,842			2,634
Income from continuing operations before change in accounting
principle		3,687			1,862
Change in accounting principle		--			(127	)
Net income		3,687			1,735

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Income from continuing operations increased $1.8 million. Volumes sold increased 60 percent, primarily related to a full quarter of production at the Mallon properties acquired in March 2003. Average gas and oil prices received in 2004 were $4.54/Mcf and $28.65/bbl, respectively, compared to $3.40/Mcf and $29.17/bbl in 2003. Total operating expenses increased 55 percent primarily related to the additional operations acquired in the Mallon transaction. In addition, 2004 lease operating expenses per Mcfe sold (LOE/MCFE) were flat with 2003.

The following is a summary of our internally estimated economically recoverable oil and gas reserves. These estimates are measured using constant product prices of $35.76 per barrel of oil and $5.93 per Mcf of natural gas as of March 31, 2004, and $31.04 per barrel of oil and $5.05 per Mcf of natural gas as of March 31, 2003. The increases in reserves are primarily the result of increased product prices. 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
	2004		2003

Barrels of oil (in thousands)		5,564		4,972
Mmcf of natural gas		124,852		116,630
Total in Mmcf equivalents		158,236		146,462

Coal Mining

	Three Months Ended March 31
	2004		2003
	(in thousands)
Revenue	$	8,728	$	8,230
Operating income		1,983		1,735
Income from continuing operations before change in accounting
principle		1,722		1,581
Change in accounting principle		--		318
Net income		1,722		1,899

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Revenue from our mining segment increased 6 percent for the three-month period ended March 31, 2004, compared to the same period in 2003. The increase is attributable to a 5 percent increase in tons of coal sold. The increase in tons of coal sold was primarily attributable to sales to the Wygen Plant, which began commercial operation in February 2003, and additional sales through the train load-out facility.

Operating expenses increased 4 percent or approximately $0.2 million, primarily due to higher operating costs related to the increase in production and accruals for taxes.

Income from continuing operations increased 9 percent due to higher production volumes at higher average prices offset by higher taxes and production-related costs.

Retail Services Group

Electric Utility

	Three Months Ended March 31
	2004		2003
	(in thousands)
Revenue	$	41,647	$	43,762
Operating expenses		30,239		30,110

Operating income	$	11,408	$	13,652

Income from continuing operations and net income	$	5,037	$	6,699

The following table provides certain operating statistics:

	Three Months Ended March 31
	2004		2003

Firm (system) sales - MWh		513,234		505,482
Off-system sales - MWh		202,294		245,727

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. Electric utility revenues decreased 5 percent for the three-month period ended March 31, 2004, compared to the same period in the prior year. The decrease in revenue was primarily due to an 18 percent decrease in off-system electric MWh sales at a 6 percent decrease in average prices received. Decreased off-system megawatt-hour sales were impacted in part by plant availability resulting from scheduled maintenance outages during the three month period ended March 31, 2004. Firm residential, commercial, industrial and wholesale electricity revenues increased 3 percent, 1 percent, 5 percent and 2 percent, respectively. Residential and commercial customers increased 2 percent. Degree days, which is a measure of weather trends, were 7 percent below last year.

Electric operating expenses remained flat for the three-month period ended March 31, 2004, compared to the same period in the prior year. Purchased power increased $1.2 million due to a 21 percent increase in megawatt-hours purchased, partially offset by a 5 percent decrease in the average cost per megawatt-hour. Gas costs decreased 88 percent due to a 96 percent decrease in megawatt-hours generated with our gas turbines as prevailing prices made it more economical for us to purchase power for our peaking needs when it was available rather than generate energy from our gas turbines. The average cost per megawatt-hour of our gas generation was $40.57 for the three months ended March 31, 2003 compared to $35.02 per megawatt-hour for purchased power for the same time period. The decrease in fuel expense was offset by increased maintenance costs for scheduled plant outages, increased health insurance costs and an increase in allocated corporate costs.

Income from continuing operations decreased $1.7 million primarily due to the decrease in off-system electric revenue and increases in purchased power expense, maintenance expense, health insurance expense and allocated corporate costs, partially offset by an increase in firm system electric sales and a decrease in fuel expense.

Communications

	Three Months Ended March 31
	2004			2003
	(in thousands)
Revenue	$	8,455		$	8,687
Operating expenses		10,294			10,572

Operating loss	$	(1,839	)	$	(1,885	)

Net loss	$	(1,784	)	$	(1,809	)




Business customers	3,156	3,012	2,657
Business access lines	12,508	12,023	10,342
Residential customers	23,478	23,878	22,700

Three Months Ended March 31, 2004 Compared to Three Months Ended March 31, 2003. The communications business group’s net loss was $1.8 million for the three-month periods ended March 31, 2004 and 2003, respectively. Revenues decreased as a result of $0.8 million in sales incentive costs related to a marketing campaign responding to a local competitor’s aggressive pricing pressure, primarily in the fourth quarter of 2003. These sales incentives included six months of service at discounted prices, of which many will become full price service during the second quarter of 2004. Revenue reductions from sales incentives were partially offset by increased customers, compared to 2003. In addition, reduced property tax accruals and a decrease in operations and maintenance expense were partially offset by increased corporate cost allocations.

Earnings Guidance

Based on lower-than-expected results in the first quarter of 2004 and management’s current evaluation of capital deployment prospects for the remainder of 2004, the Company expects 2004 income from continuing operations to approximate $2.00 to $2.15 per share. The narrowing of guidance takes into consideration possible additional delay in the deployment of excess cash balances for anticipated capital investments in retail and wholesale energy operations, further debt reduction, stock repurchase or other corporate purposes, which, until deployed should result in lower returns from short-term investments instead of higher returns from alternative uses, and a revised expectation that any new development capital deployment likely would not have an accretive effect in 2004 due to the timing of such deployment. The Company continues to expect strong financial performance in 2004 from the oil and gas production business segment, due to expected continued increases in production and an advantageous price environment, and from the energy marketing business segment, due to expected increases in daily volumes marketed.

Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2003 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 2003 Annual Report on Form 10-K.

Liquidity and Capital Resources

Cash Flow Activities

During the three-month period ended March 31, 2004, 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 our property additions. We plan to fund future property and investment additions primarily 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 increased $52.9 million for the three-month period ended March 31, 2004 compared to the same period in the prior year primarily due to an $18.8 million federal income tax refund and changes in working capital.

During the three months ended March 31, 2004, we had cash outflows from investing activities of $12.0 million, which was primarily related to property, plant and equipment additions in the normal course of business.

During the three months ended March 31, 2004, we had cash outflows from financing activities of $55.4 million, primarily due to the repayment of debt and payment of quarterly cash dividends on stock. On January 30, 2004, we repaid $45 million of the project-level debt outstanding on the Fountain Valley project.

Dividends

Dividends paid on our common stock totaled $0.31 per share in the first quarter of 2004. This reflects a 3.3 percent increase, as approved by our board of directors in January 2004, from the 2003 quarterly dividend level. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects.

Short-Term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are revolving bank facilities and cash provided by operations. Our liquidity position remained strong during the first quarter of 2004. As of March 31, 2004, we had approximately $191.5 million of cash unrestricted for operations and $425 million of credit through revolving bank facilities. Approximately $55.5 million of the cash balance at March 31, 2004 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company. The bank facilities consisted of a $225 million facility due August 20, 2006 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, 2004, we had no bank borrowings outstanding under these facilities. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $374.4 million at March 31, 2004.

The above bank facilities include the following covenants that are common in such arrangements:

•

a consolidated net worth in an amount of not less than the sum of $475 million and 50 percent of the aggregate consolidated net income beginning April 1, 2003;

•

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.

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. As of March 31, 2004, we were in compliance with the above covenants.

Our consolidated net worth was $710.7 million at March 31, 2004, which was approximately $207.3 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, 2004 was 53.6 percent, our total debt leverage (long-term debt and short-term debt) was 54.1 percent, and our recourse leverage ratio was approximately 49.5 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. As of March 31, 2004, we had a $3.0 million guarantee to the lender under this facility. At March 31, 2004, there were outstanding letters of credit issued under the facility of $92.2 million, with no borrowing balances outstanding on the facility.

Similarly, Black Hills Energy Resources, Inc. (BHER), our oil marketing unit, has a $25 million uncommitted, discretionary credit facility. The facility allows BHER to elect up to $40 million of available credit via notification to the bank at the beginning of each calendar quarter. This line of credit provides credit support for the purchases of crude oil by BHER. We provided no guarantee to the lender under this facility. At March 31, 2004, BHER had letters of credit outstanding of $6.1 million.

There were no changes in our corporate credit ratings during the first quarter of 2004.

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

There have been no other material changes in our forecasted changes in liquidity requirements from those reported in Item 7 of our 2003 Annual Report on Form 10-K filed with the Securities Exchange Commission.

Guarantees

During the first quarter of 2004, a $5.0 million performance guarantee for Black Hills Wyoming, under a power sales agreement on the Wygen Plant expired. In addition a new $0.5 million guarantee was issued related to payments under various transactions with Idaho Power Company. At March 31, 2004, we had guarantees totaling $187.2 million in place.

Capital Requirements

During the three months ended March 31, 2004, capital expenditures were approximately $13 million. We currently expect capital expenditures for the entire year 2004 to approximate $312 million, as detailed in Item 7 of our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

RISK FACTORS

There have been no material changes in our risk factors from those reported in Items 1 and 2 of our 2003 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

NEW ACCOUNTING PRONOUNCEMENTS

Other than the new pronouncements reported in our 2003 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.

SAFE HARBOR FOR FORWARD LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “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 risk factors described above, in Item 1 of our 2003 Annual Report on Form 10-K filed with the SEC, and the following:

•

The amount and timing of capital deployment in new investment opportunities;

•

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

•

Our use of derivative financial instruments to hedge commodity and interest rate risks;

•

The creditworthiness of counterparties to trading and other transactions, and defaults on amounts due from counterparties;

•

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

•

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

•

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

•

Weather and other natural phenomena;

•

The timing of production from oil and gas development facilities, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of building, environmental and other permits, and the availability of specialized contractors, work force, equipment, and prices of and demand for our products;

•

The extent of success in connecting natural gas supplies to gathering and processing systems;

•

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

•

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

•

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

•

Capital market conditions, including price risk due to marketable securities held as investments in benefit plans; 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 is a required disclosure and provides a reconciliation of the activity in energy trading contracts that meet the definition of a derivative under SFAS 133 and that were marked-to-market during the three months ended March 31, 2004 (in thousands):




Total fair value of natural gas marketing contract net liability at December 31, 2003	$	(408	)
Net cash settled during the quarter on contracts that existed at December 31, 2003		(1,464	)
Change in fair value due to change in techniques and assumptions		--
Unrealized loss on new contracts entered during the quarter and still existing
at March 31, 2004		(19	)
Realized gain on contracts that existed at December 31, 2003 and were settled
during the quarter		1,187
Unrealized gain on contracts that existed at December 31, 2003 and still exist
at March 31, 2004		1,342

Total fair value of natural gas marketing contract net assets at March 31, 2004	$	638

On January 1, 2003, the Company adopted EITF Issue No. 02-3. 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. EITF 98-10 was superseded by EITF 02-3 and allowed a broad interpretation of what constituted “trading activity” and hence what would be marked-to-market. EITF 02-3 took a much narrower view of what “trading activity” should be marked-to-market, limiting mark-to-market treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. At our natural gas marketing operations, we often employ strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in very limited circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow us to mark our inventory, transportation or storage positions to market. The result is that while a significant majority of our natural gas marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives), but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.

At March 31, 2004, we had a mark to fair value unrealized gain of $0.6 million for our derivative contracts related to our natural gas marketing activities, with $0.5 million of this amount current. The sources of fair value measurements were as follows (in thousands):

	Maturities
Source of Fair Value	Less than 1 year			1 - 2 years		Total Fair Value

Actively quoted (i.e., exchange-traded) prices	$	(599	)	$	--	$	(599	)
Prices provided by other external sources		1,145			92		1,237
Modeled		--			--		--

Total	$	546		$	92	$	638

There have been no material changes in market risk faced by us from those reported in our 2003 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 2003 Annual Report on Form 10-K, and Note 15 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

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of March 31, 2004. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.

Changes in internal control over financial reporting

During the period covered by this Quarterly Report on Form 10-Q, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

BLACK HILLS CORPORATION

Part II — Other Information

Item 1.

Legal Proceedings

For information regarding legal proceedings, see Note 14 in Item 8 of the Company’s 2003 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.

Item 6.

Exhibits and Reports on Form 8-K

(a)

Exhibits - -

Exhibit 2.1

Stock Purchase Agreement between Xcel Energy, Inc., as "Seller" and Black Hills Corporation, as "Buyer," dated January 13, 2004.

Exhibit 10.1

Severance Agreement and Release, dated February 26, 2004, between John W. Salyer and Black Hills Corporation.

Exhibit 31.1

Certification pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 31.2

Certification pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.

Exhibit 32.1

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

Exhibit 32.2

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

(b)

Reports on Form 8-K

We have filed or furnished the following Reports on Form 8-K during the quarter ended March 31, 2004:

Form 8-K dated January 14, 2004.

Reported under Item 5, that the Company issued a press release announcing it had entered into a definitive agreement to acquire Cheyenne Light, Fuel & Power from Xcel Energy Inc., pending regulatory approval and under Item 7, Exhibits.

Form 8-K dated January 14, 2004.

Reported under Item 5, that the Company issued a press release announcing CEO succession and changes in its board membership and under Item 7, Exhibits.

Form 8-K dated February 9, 2004.

Reported under Item 12, that the Company issued a press release announcing earnings for the fourth quarter and the year 2003.

BLACK HILLS CORPORATION

Signatures

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

BLACK HILLS CORPORATION

/s/ David R. Emery
David R. Emery, President and
Chief Executive Officer

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

Dated: May 10, 2004

EXHIBIT INDEX

Exhibit Number Description

Exhibit 2.1

Stock Purchase Agreement between Xcel Energy, Inc., as "Seller" and Black Hills Corporation, as "Buyer,"
dated January 13, 2004.

Exhibit 10.1

Severance Agreement and Release, dated February 26, 2004, between John W. Salyer and Black Hills Corporation.

Exhibit 31.1

Certification pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302
of the Sarbanes - Oxley Act of 2002.

Exhibit 31.2

Certification pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302
of the Sarbanes - Oxley Act of 2002.

Exhibit 32.1

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

Exhibit 32.2

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

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)

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

Results of Operations

Consolidated Results

Wholesale Energy Group

Retail Services Group

Earnings Guidance

Critical Accounting Policies

Liquidity and Capital Resources

Cash Flow Activities

Dividends

Short-Term Liquidity and Financing Transactions

Guarantees

Capital Requirements

RISK FACTORS

NEW ACCOUNTING PRONOUNCEMENTS

SAFE HARBOR FOR FORWARD LOOKING INFORMATION

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

Changes in internal control over financial reporting

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)

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