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 June 30, 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 July 31, 2004

Common stock, $1.00 par value 32,458,979 shares

TABLE OF CONTENTS

		Page
PART 1. Item 1. Item 2. Item 3. Item 4. PART II. Item 1. Item 2. Item 4. Item 6.	FINANCIAL INFORMATION Financial Statements Condensed Consolidated Statements of Income - Three and Six Months Ended June 30, 2004 and 2003 Condensed Consolidated Balance Sheets - June 30, 2004, December 31, 2003 and June 30, 2003 Condensed Consolidated Statements of Cash Flows - Six Months Ended June 30, 2004 and 2003 Notes to Condensed Consolidated Financial Statements Management's Discussion and Analysis of Financial Condition and Results of Operations Quantitative and Qualitative Disclosures about Market Risk Controls and Procedures OTHER INFORMATION Legal Proceedings Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities Submission of Matters to a Vote of Security Holders Exhibits and Reports on Form 8-K Signatures Exhibit Index	3 4 5 6-29 29-47 47-48 48 49 49 50 51 52 53

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

	Three Months Ended June 30						Six Months Ended June 30
	2004			2003			2004			2003
	(in thousands, except per share amounts)

Operating revenues	$	280,355		$	289,243		$	554,683		$	580,688

Operating expenses:
Fuel and purchased power		182,100			182,019			355,006			370,704
Operations and maintenance		25,810			27,690			50,264			50,770
Administrative and general		15,900			21,026			33,863			38,773
Depreciation, depletion and
amortization		21,478			20,032			43,750			39,079
Taxes, other than income taxes		7,793			8,146			16,220			15,528

		253,081			258,913			499,103			514,854

Equity in earnings of unconsolidated subsidiaries		(759	)		4,408			(1,008	)		4,864

Operating income		26,515			34,738			54,572			70,698

Other income (expense):
Interest expense		(12,719	)		(13,263	)		(27,070	)		(25,565	)
Interest income		341			187			733			329
Other expense		(90	)		(157	)		(193	)		(289	)
Other income		223			404			596			717

		(12,245	)		(12,829	)		(25,934	)		(24,808	)

Income from continuing operations before minority
interest, income taxes and change in accounting
principle		14,270			21,909			28,638			45,890
Minority interest		(44	)		--			(86	)		--
Income taxes		(4,674	)		(8,402	)		(9,006	)		(16,687	)

Income from continuing operations before change in
accounting principles		9,552			13,507			19,546			29,203
Income from discontinued operations,
net of taxes		1,963			3,153			1,755			4,314
Change in accounting principles, net of taxes		--			--			--			(2,680	)

Net income		11,515			16,660			21,301			30,837
Preferred stock dividends		(78	)		(57	)		(166	)		(114	)

Net income available for common stock	$	11,437		$	16,603		$	21,135		$	30,723

Weighted average common shares outstanding:
Basic		32,404			30,582			32,348			28,822

Diluted		32,951			31,128			32,884			29,295

Earnings per share:
Basic-
Continuing operations	$	0.29		$	0.44		$	0.60		$	1.01
Discontinued operations		0.06			0.10			0.05			0.15
Change in accounting principle		--			--			--			(0.09	)

Total	$	0.35		$	0.54		$	0.65		$	1.07

Diluted-
Continuing operations	$	0.29		$	0.44		$	0.60		$	1.00
Discontinued operations		0.06			0.10			0.05			0.14
Change in accounting principle		--			--			--			(0.09	)

Total	$	0.35		$	0.54		$	0.65		$	1.05

Dividends paid per share of common stock	$	0.31		$	0.30		$	0.62		$	0.60

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)

	June 30			December 31			June 30
	2004			2003			2003
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	104,235		$	172,759		$	69,494
Restricted cash		--			1,350			1,070
Receivables (net of allowance for doubtful accounts
of $7,672; $7,345 and $4,660, respectively)		214,958			201,976			177,917
Materials, supplies and fuel		83,442			44,895			35,879
Derivative assets		26,827			26,804			25,553
Prepaid income taxes		1,380			18,940			--
Deferred income taxes		4,879			4,256			579
Other current assets		4,804			8,875			5,606
Assets of discontinued operations		3,746			4,575			179,743

		444,271			484,430			495,841

Investments		27,129			26,847			24,112

Property, plant and equipment		1,921,404			1,882,545			1,802,407
Less accumulated depreciation and depletion		(482,681	)		(440,274	)		(407,858	)

		1,438,723			1,442,271			1,394,549

Other assets:
Derivative assets		445			1,002			3,146
Goodwill		30,144			30,144			24,113
Intangible assets (net of accumulated amortization
of $20,081; $18,423 and $17,645, respectively)		38,412			40,070			75,979
Other		35,543			38,488			23,902

		104,544			109,704			127,140

	$	2,014,667		$	2,063,252		$	2,041,642

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	189,287		$	162,706		$	166,320
Accrued income taxes		5,816			5,752			7,743
Accrued liabilities		57,293			66,618			73,394
Current maturities of long-term debt		15,868			17,659			17,296
Derivative liabilities		33,154			32,967			31,247
Liabilities of discontinued operations		1,085			3,444			107,380

		302,503			289,146			403,380

Long-term debt, net of current maturities		791,184			868,459			752,155

Deferred credits and other liabilities:
Deferred income taxes		136,208			125,040			129,257
Derivative liabilities		1,827			3,247			7,784
Other		63,202			62,924			70,669

		201,237			191,211			207,710

Minority interest in subsidiaries		4,775			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 32,571,365; 32,447,765 and
32,264,003 shares, respectively		32,571			32,448			32,264
Additional paid-in capital		383,170			379,271			373,905
Retained earnings		305,626			304,567			293,624
Treasury stock at cost - 112,885; 150,048 and 157,430 shares, respectively		(2,707	)		(3,560	)		(3,698	)
Accumulated other comprehensive loss		(10,859	)		(11,122	)		(23,247	)

		707,801			701,604			672,848

Total stockholders' equity		714,968			709,747			678,397

	$	2,014,667		$	2,063,252		$	2,041,642

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)

	Six Months Ended June 30
	2004			2003
	(in thousands)
Operating activities:
Net income available for common	$	21,135		$	30,723
Adjustments to reconcile net income available for common to net
cash provided by operating activities:
Income from discontinued operations		(1,755	)		(4,314	)
Provision for valuation allowances		244			750
Depreciation, depletion and amortization		43,750			39,079
Net change in derivative assets and liabilities		(35	)		(241	)
Deferred income taxes		10,282			9,857
Undistributed earnings in associated companies		81			(3,851	)
Minority interest		86			--
Accounting change		--			2,680
Change in operating assets and liabilities-
Accounts receivable and other current assets		(30,458	)		(20,477	)
Accounts payable and other current liabilities		16,191			23,602
Other operating activities		3,296			7,699

		62,817			85,507

Investing activities:
Property, plant and equipment additions		(38,559	)		(46,991	)
Increase in notes receivable - Mallon Resources		--			(5,164	)
Other investing activities		3,165			(2,584	)

		(35,394	)		(54,739	)

Financing activities:
Dividends paid		(20,076	)		(17,727	)
Common stock issued		3,046			119,897
Decrease in short-term borrowings, net		--			(340,487	)
Long-term debt - issuance		--			252,164
Long-term debt - repayments		(79,066	)		(43,064	)
Other financing activities		149			(6,978	)

		(95,947	)		(36,195	)

Decrease in cash and cash equivalents		(68,524	)		(5,427	)
Cash and cash equivalents:
Beginning of period		172,759			74,921

End of period	$	104,235		$	69,494

Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest	$	26,903		$	26,674
Income taxes paid, net	$	(18,652	)	$	3,453
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 June 30, 2004, December 31, 2003 and June 30, 2003, financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 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 June 30, 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 June 30						Six Months Ended June 30
	2004			2003			2004			2003

Net income available for common
stock, as reported	$	11,437		$	16,603		$	21,135		$	30,723
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for all
awards, net of related tax effects		(132	)		(201	)		(320	)		(443	)

Pro forma net income	$	11,305		$	16,402		$	20,815		$	30,280

Earnings per share:
As reported--
Basic
Continuing operations	$	0.29		$	0.44		$	0.60		$	1.01
Discontinued operations		0.06			0.10			0.05			0.15
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.35		$	0.54		$	0.65		$	1.07

Diluted
Continuing operations	$	0.29		$	0.44		$	0.60		$	1.00
Discontinued operations		0.06			0.10			0.05			0.14
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.35		$	0.54		$	0.65		$	1.05

Pro forma--
Basic
Continuing operations	$	0.29		$	0.44		$	0.59		$	0.99
Discontinued operations		0.06			0.10			0.05			0.15
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.35		$	0.54		$	0.64		$	1.05

Diluted
Continuing operations	$	0.29		$	0.43		$	0.59		$	0.99
Discontinued operations		0.06			0.10			0.05			0.14
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.35		$	0.53		$	0.64		$	1.04

(4)

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In May 2004, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-2), which provides guidance on the accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (2003 Medicare Act) for employers that sponsor postretirement healthcare plans that provide prescription drug benefits. FSP 106-2 supersedes FSP 106-1 that was issued in January 2004 under the same title. The Company provides prescription drug benefits to certain eligible employees and is currently analyzing what effects the 2003 Medicare Act has on its accumulated postretirement benefit obligation or net periodic postretirement benefit cost. FSP 106-2 is effective for the first interim period beginning after June 15, 2004.

(5)

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

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 IntangibleAssets, and EITF Issue No. 04-2,Whether Mineral Rights Are Tangible or IntangibleAssets.” The FSP amends SFAS 141 and SFAS 142 to conform with the EITF consensus in EITF 04-2 that mineral rights, as defined by EITF 04-2, are tangible assets. When the Company adopted SFAS 142 on January 1, 2002, the amounts related to mineral rights were already classified as tangible assets and continue to be classified in “Property, plant and equipment” on the accompanying Condensed Consolidated Balance Sheets. The adoption of FSP FAS 141-1 and FAS 142-1 had no effect on the Company’s consolidated financial position, results of operations or cash flows.

(6)

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	June 30, 2004		December 31, 2003		June 30, 2003


Gas and oil held by energy marketing	$	60,607	$	24,394	$	17,151
Materials and supplies		21,533		18,920		17,746
Fuel for generation		1,302		1,581		982

Total materials, supplies and fuel	$	83,442	$	44,895	$	35,879

(7)

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 6/30/04


Oil and Gas	$	7,233	$	--	$	--		$	286	$	--	$	7,519
Mining		15,752		372		(206	)		458		--		16,376

Total	$	22,985	$	372	$	(206	)	$	744	$	--	$	23,895

(8)

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 and six months ended June 30, 2003, lease payments were $1.3 million and $2.1 million, respectively, 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 and six months ended June 30, 2004, depreciation expense was $0.8 million and $1.7 million, respectively and interest expense was $0.8 million and $1.6 million, respectively.

(9)

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:


Period ended June 30, 2004 (in thousands)	Three Months					Six Months
	Income			Average Shares		Income			Average Shares
Income from continuing
operations	$	9,552				$	19,546
Less: preferred stock dividends		(78	)				(166	)

Basic - available for common
shareholders		9,474			32,404		19,380			32,348
Dilutive effect of:
Stock options		--			103		--			109
Convertible preferred stock		78			195		166			195
Estimated contingent shares
issuable for prior acquisition		--			158		--			158
Others		--			91		--			74

Diluted - available for common
shareholders	$	9,552			32,951	$	19,546			32,884

	Income				Income
Period ended June 30, 2003 (in thousands)	Three Months				Six Months

Income from continuing
operations	$	13,507			$	29,203
Less: preferred stock dividends		(57	)			(114	)

Basic - available for common
shareholders		13,450		30,582		29,089		28,822
Dilutive effect of:
Stock options		--		101		--		74
Convertible preferred stock		57		148		114		148
Estimated contingent shares
issuable for prior acquisition		--		261		--		217
Others		--		36		--		34

Diluted - available for common
shareholders	$	13,507		31,128	$	29,203		29,295

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.

(10)

COMPREHENSIVE INCOME

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

	Three Months Ended June 30						Six Months Ended June 30
	2004			2003			2004			2003

Net income	$	11,515		$	16,660		$	21,301		$	30,837
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 $103
and $331 for the three and six
month periods ended June 30,
2003, respectively)
		1,821			(3,040	)		317			(2,055	)
Unrealized loss on
available-for-sale securities		(33	)		--			(54	)		--

Comprehensive income	$	13,303		$	13,620		$	21,564		$	28,782

(11)

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.

•

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


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 three and six months ended June 30, 2004, was $0.3 million and $0.4 million, respectively. 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 34,176 shares of restricted stock and 16,019 restricted stock units. The pre-tax compensation cost related to the award of approximately $1.4 million will be recognized over the vesting period as follows: $0.6 million in 2004, $0.4 million in 2005, $0.3 million in 2006 and $0.1 million in 2007.

•

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

•

67,933 stock options were exercised at a weighted average price of $22.00 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 issued 22,934 shares of common stock under its dividend reinvestment plan at a weighted average price of $30.41 per share.

•

The Company issued 6,105 shares of common stock under its employee stock purchase plan at a price of $28.59 per share.

•

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

•

The Company acquired 2,770 shares of treasury stock related to the share withholding provisions of the restricted stock plan for the payment of taxes associated with the vesting of shares of restricted stock for certain officers and key employees.

(12)

CHANGES IN LONG-TERM DEBT AND NOTES PAYABLE

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.

On May 10, 2004, the Company repurchased $25 million of its 6.5 percent senior unsecured notes due 2013.

On May 13, 2004, the Company closed on a $125 million 364-day credit facility which replaced the $200 million facility which was to expire in August 2004. The Company also amended its $225 million multi-year facility that expires in August 2006 to conform its compliance calculation to the same calculation as in the new $125 million facility. Based on the Company’s current credit ratings, the interest rate under the new $125 million facility is LIBOR plus 1.30 percent and the utilization fee rate is 0.25 percent.

On May 14, 2004, Enserco Energy Inc. amended its credit agreement increasing the facility amount by $15 million to $150 million.

(13)

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 June 30, 2004, the Company had the following guarantees in place (in thousands):

Nature of Guarantee	Outstanding at June 30, 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 of Las Vegas Cogen II to Nevada Power Company
under a power purchase agreement		5,000	2013
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 payments of Black Hills Power under various transactions
with Southern California Edison Company		750	2005
Guarantee obligations under the Wygen Plant Lease		111,018	2008
Guarantee payment and performance under credit agreements for two
combustion turbines		29,214	2010
Indemnification for subsidiary reclamation/surety bonds		26,482	Ongoing

	$	186,714

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 $5.0 million of payments of its power generation subsidiary, Las Vegas Cogeneration II, LLC under the Western Systems Power Pool Confirmation Agreement with Nevada Power Company. To the extent liabilities exist under the agreements subject to this guarantee, such liabilities are included in the Condensed Consolidated Balance Sheets. The guarantee expires upon payment in full of all the obligations under the contract, which expires in 2013.

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 up to $0.8 million of the obligations of its electric utility subsidiary, Black Hills Power, Inc., under various transactions with Southern California Edison 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 April 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 June 30, 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 $25.1 million of debt of Black Hills Wyoming and $4.1 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 June 30, 2004, the Company had guarantees in place totaling approximately $26.5 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.

(14)

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 periods ended June 30 are as follows (in thousands):

	Three Months Ended						Six Months Ended
	2004			2003			2004			2003

Service cost	$	443		$	323		$	886		$	646
Interest cost		909			838			1,818			1,676
Expected return on plan
assets		(1,129	)		(780	)		(2,258	)		(1,560	)
Amortization of prior
service cost		58			58			116			116
Amortization of net loss		375			352			750			704

Net periodic benefit cost	$	656		$	791		$	1,312		$	1,582

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 supplemental retirement plans are nonqualified defined benefit plans.

The components of net periodic benefit cost for the supplemental nonqualified plans for the periods ended June 30 are as follows (in thousands):

	Three Months Ended					Six Months Ended
	2004		2003			2004		2003

Service cost	$	134	$	106		$	268	$	212
Interest cost		241		190			482		380
Amortization of prior
service cost (credit)		2		(1	)		4		(2	)
Amortization of net loss		187		128			374		256

Net periodic benefit cost	$	564	$	423		$	1,128	$	846

The Company anticipates that contributions to the supplemental retirement plans 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 periods ended June 30 are as follows (in thousands):

	Three Months Ended						Six Months Ended
	2004			2003			2004			2003

Service cost	$	140		$	96		$	280		$	192
Interest cost		166			144			332			288
Amortization of net
transition obligation		37			37			74			74
Amortization of prior
service credit		(6	)		(6	)		(12	)		(12	)
Amortization of net loss		47			22			94			44

Net periodic benefit cost	$	384		$	293		$	768		$	586

The Company anticipates that contributions to the postretirement healthcare 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.

(15)

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 June 30, 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
June 30, 2004
Energy marketing*	$	170,896	$	--		$	1,606
Power generation		40,355		--			5,233
Oil and gas**		10,877		89			764
Mining		4,771		2,772			1,358
Electric		39,788		21			1,816
Communications		11,418		--			(169	)
Corporate		157		596			(1,050	)
Intersegment eliminations		--		(1,385	)		(6	)

Total	$	278,262	$	2,093		$	9,552

_________________

All periods presented reflect a net presentation of revenues at the Company’s gas marketing subsidiary and a gross presentation of revenues at the Company’s crude oil marketing subsidiary in accordance with Emerging Issues Task Force (EITF) Issue 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) and EITF Issue 99-19 "Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19).

**	Includes a $(2.5) million revenue accrual correction.

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


Quarter to Date
June 30, 2003
Energy marketing*	$	172,262	$	--		$	(1,490	)
Power generation		45,874		--			9,201
Oil and gas		12,674		64			2,577
Mining		5,146		2,953			875
Electric		39,186		21			4,722
Communications		11,773		--			(433	)
Corporate		--		--			(1,944	)
Intersegment eliminations		--		(710	)		(1	)

Total	$	286,915	$	2,328		$	13,507

_________________

*	All periods presented reflect a net presentation of revenues at the Company’s gas marketing subsidiary and a gross presentation of revenues at the Company’s 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


Year to Date
June 30, 2004
Energy marketing*	$	335,331	$	--		$	5,575
Power generation		75,492		--			3,155
Oil and gas**		27,198		172			4,450
Mining		10,317		5,954			3,110
Electric		81,414		42			6,852
Communications		19,874		--			(1,953	)
Corporate		466		1,157			(1,639	)
Intersegment eliminations		--		(2,734	)		(4	)

Total	$	550,092	$	4,591		$	19,546

_________________

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

**	Includes a $(0.5) million revenue accrual correction.

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


Year to Date
June 30, 2003
Energy marketing*	$	354,689	$	--		$	2,755
Power generation		85,596		--			12,577
Oil and gas		21,665		136			4,440
Mining		10,541		5,788			2,488
Electric		82,935		35			11,421
Communications		20,459		--			(2,242	)
Corporate		--		--			(2,235	)
Intersegment eliminations		--		(1,156	)		(1	)

Total	$	575,885	$	4,803		$	29,203

_________________

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

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.

(16)

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 the Company’s natural gas marketing activities and derivative commodity instruments that were marked-to-market on June 30, 2004, December 31, 2003 and June 30, 2003 are as follows:

	June 30, 2004				December 31, 2003				June 30, 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		37,861		1.75		13,028		1		64,107		1
Natural gas basis swaps sold		41,489		1.75		12,691		1		65,497		1.25
Natural gas fixed-for-float
swaps purchased		17,253		1.25		19,645		1.5		17,840		1.25
Natural gas fixed-for-float
swaps sold		28,402		1.50		21,752		1.5		22,372		1.50
Natural gas physical purchases		61,301		1.75		50,757		2.25		44,869		1
Natural gas physical sales		108,993		5.25		44,066		2.25		36,137		1.25

_________________

Derivative contracts related to the Company’s 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)

June 30, 2004	$	26,314	$	445	$	26,184	$	404	$	171

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

June 30, 2003	$	23,795	$	3,146	$	24,364	$	3,139	$	(562	)

For the six month periods ended June 30, 2004 and 2003, contracts and other activities at the Company’s natural gas marketing operations are accounted for under the provisions of EITF 02-3 and SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" (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 Issue 98-10 "Accounting for Contracts Involving Energy Trading and Risk Management Activities (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 the Company’s natural gas marketing operations, management often employs strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of the Company’s producer services, end-use origination and wholesale marketing groups. Except in very limited circumstances when the Company is able to designate transportation, storage or inventory positions as part of a fair value hedge, SFAS 133 generally does not allow the Company to mark inventory, transportation or storage positions to market. The result is that while a significant majority of the Company’s natural gas marketing positions are fully economically hedged, the Company is required to mark some parts of its overall strategies (the derivatives), but are generally precluded from marking the rest of its 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 the Company’s crude oil contracts, are set forth below:

	June 30, 2004				December 31, 2003				June 30, 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		2,622		0.5		2,688		0.5		4,248		0.6
Crude oil sold		2,679		0.5		2,253		0.5		4,281		0.6

As of June 30, 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 June 30, 2003, were marked to fair value and the gains and/or losses recognized in earnings on June 30, 2003. The amounts related to these contracts did not have a significant impact on the related 2003 Condensed Consolidated Financial Statements.

Oil and Gas Exploration and Production

On June 30, 2004, December 31, 2003 and June 30, 2003, the Company had the following swaps and related balances (dollars in thousands):

			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)


June 30, 2004
Crude oil swaps	540,000	1.50	$	--	$	--	$	2,635	$	626	$	(3,198	)	$	(63	)
Natural gas swaps	3,937,009	0.75		57		--		2,004		--		(1,947	)		--

			$	57	$	--	$	4,639	$	626	$	(5,145	)	$	(63	)

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	)

June 30, 2003
Crude oil swaps	360,000	1.5	$	--	$	--	$	979	$	101	$	(1,026	)	$	(54	)
Natural gas swaps	3,600,000	0.5		1,567		--		1,010		--		558			(1	)

			$	1,567	$	--	$	1,989	$	101	$	(468	)	$	(55	)

_________________

*	crude in barrels, gas in MMBtu’s

Based on June 30, 2004 market prices, a $4.6 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 June 30, 2004 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

On June 30, 2004, December 31, 2003 and June 30, 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			Pre-tax Income (Loss)


June 30, 2004
Swaps on
project
financing	$	113,000		4.22	%	2.25	$	456	$	--	$	2,331	$	797	$	(2,672	)	$	--

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	)	$	--

June 30, 2003
Swaps on
project
financing	$	188,000	(a)	4.24	%	3.25	$	180	$	--	$	4,192	$	4,544	$	(8,556	)	$	--
Swaps on
corporate debt		25,000		5.28	%	0.75		--		--		702		--		(688	)		(14	)

Total	$	213,000					$	180	$	--	$	4,894	$	4,544	$	(9,244	)	$	(14	)

_________________

^(a)	Amounts exclude interest rate swaps related to our discontinued hydroelectric operations, sold in September 2003. At June 30, 2003, these swaps had a notional amount of $62.4 million and a fair value of $(8.8) million. The related balances are currently classified in “discontinued operations.”

Based on June 30, 2004 market interest rates and balances, approximately $1.9 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.

(17)

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 six months of 2004.

(18)

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 (see Note 15) results of operations for Daksoft were included in the Communications segment. As Daksoft now primarily provides information technology support to the Company, its results are included in “Corporate” for segment reporting.

(19)

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. On July 15, 2004, Mallon Resources Corporation changed its name to Black Hills Gas Holdings Corp. The results of operations of Black Hills Gas Holdings 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):

	Six Months Ended June 30 2003


Operating revenues	$	583,629
Income from continuing operations	$	28,755
Net income available for common	$	30,275
Earnings per share--
Basic:
Continuing operations	$	0.98
Total	$	1.03
Diluted:
Continuing operations	$	0.97
Total	$	1.02

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.

(20)

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.

(21)

DISCONTINUED OPERATIONS

The Company accounts for its discontinued operations under the provisions of SFAS 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.

Sale of Landrica Development Corp.

On May 21, 2004, the Company sold its subsidiary, Landrica Development Corp. Landrica’s primary assets consisted of a coal enhancement plant and land. The purchaser made a $0.5 million cash payment to the Company and assumed a $2.9 million reclamation liability. The sale resulted in a $2.1 million after-tax gain. For segment reporting purposes, Landrica was previously included in the Coal Mining segment.

Net income from the discontinued operations is as follows (in thousands):

	Three Months Ended June 30						Six Months Ended June 30
	2004			2003			2004			2003

Pre-tax income from
discontinued operations	$	(4	)	$	717		$	(40	)	$	678
Pre-tax gain on disposal		3,229			--			3,229			--
Income tax expense		(1,133	)		(261	)		(1,127	)		(254	)

Net income from
discontinued operations	$	2,092		$	456		$	2,062		$	424

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

	December 31 2003			June 30 2003


Current assets	$	31		$	652
Property, plant and equipment		151			152
Investments		500			500
Non-current assets		--			44
Other current liabilities		(118	)		(506	)
Deferred reclamation		(2,858	)		(3,061	)
Other non-current liabilities		(1	)		(1	)

Net liabilities of discontinued operations	$	(2,295	)	$	(2,220	)

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 June 30						Six Months Ended June 30
	2004			2003			2004			2003

Operating revenues	$	--		$	471		$	--		$	1,867

Pre-tax loss from
discontinued
operations	$	(197	)	$	(246	)	$	(469	)	$	(579	)
Income tax benefit		68			91			162			210

Net loss from
discontinued
operations	$	(129	)	$	(155	)	$	(307	)	$	(369	)

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

	June 30 2004			December 31 2003			June 30 2003


Current assets	$	102		$	249		$	847
Property, plant and equipment		1,064			1,064			4,602
Non-current deferred tax asset		2,580			2,580			388
Other current liabilities		(655	)		(86	)		(511	)
Non-current liabilities		(430	)		(381	)		(19	)

Net assets of discontinued operations	$	2,661		$	3,426		$	5,307

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 June 30			Six Months Ended June 30
	2003			2003

Operating revenues	$	10,330		$	16,821

Pre-tax income from discontinued operations	$	4,616		$	6,577
Income tax expense		(1,764	)		(2,318	)

Net income from discontinued operations	$	2,852		$	4,259

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

	June 30 2003


Current assets	$	12,895
Property, plant and equipment		146,209
Goodwill		9,772
Other non-current assets		3,682
Current derivative liability		(4,224	)
Other current liabilities		(9,109	)
Long-term debt		(73,344	)
Non-current derivative liability		(4,607	)
Other non-current liabilities		(11,998	)

Net assets of discontinued operations	$	69,276

(22)

LONG-TERM TOLLING CONTRACT AND TRANSMISSION SERVICES AGREEMENT

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 is fully dispatchable by NPC to serve its retail load.

The Company also has a Firm Point-to-Point Transmission Service Agreement (TSA) with NPC that expires April 30, 2008. The TSA provided transmission service in support of a Capacity and Ancillary Services Sale Agreement with Allegheny Energy Supply Company, which was terminated in September 2003. In its consideration and approval of the Nevada Power tolling contract, the Nevada Public Utilities Commission established a linkage between the TSA and the tolling contract that will result in the Company recognizing the costs of the TSA over the term of the tolling contract (10 years, $1.6 million per year) rather than the remaining term of the TSA (4 years, $3.9 million per year).

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 our business groups in the following financial segments:

Business Group			Financial Segment


Wholesale energy group			Power generation
			Oil and gas
			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. In May 2004, we sold our subsidiary, Landrica Development Corp., which held some land and coal enhancement facilities that were previously reported in our Coal Mining segment.

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 June 30						Six Months Ended June 30
	2004			2003			2004			2003

Revenues
Wholesale energy		82	%		82	%		82	%		82	%
Electric utility		14			14			15			14
Communications		4			4			3			4

		100	%		100	%		100	%		100	%

Income/ (Loss) from
Continuing Operations
Wholesale energy		94	%		83	%		83	%		76	%
Electric utility		19			34			35			39
Communications		(2	)		(3	)		(10	)		(8	)
Corporate		(11	)		(14	)		(8	)		(7	)

		100	%		100	%		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, and Landrica Development Corp., which was sold on May 21, 2004. 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, and Landrica Development Corp., which was sold on May 21, 2004.

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003. Consolidated income from continuing operations for the three-month period ended June 30, 2004 was $9.6 million or $0.29 per share compared to $13.5 million or $0.44 per share in the same period of the prior year.

The decrease in income from continuing operations for the three-month period ended June 30, 2004 was primarily due to the following:

•

a $2.9 million or $0.09 per share decrease in electric utility earnings, primarily due to increased purchased power and maintenance expense related to scheduled and unscheduled plant outages, partially offset by an increase in firm system and off-system electric sales,

•

a $4.0 million or $0.12 per share decrease in power generation earnings, primarily related to -

•

a $3.1 million or $0.09 per share decrease in earnings of unconsolidated subsidiaries, primarily related to unrealized mark-to-market adjustments at certain power fund investments,

•

a $2.6 million or $0.08 per share decrease in earnings from the Las Vegas II Cogeneration facility, primarily related to the termination of the Allegheny contract and replacement with a new long-term tolling agreement in place with Nevada Power Company that was effective April 1, 2004,

•

offset by growth in earnings from our other power generation projects, and

•

a $1.8 million or $0.06 per share decrease in oil and gas earnings, primarily due to a $1.6 million after-tax revenue accrual correction,

offset by:

•

a $3.1 million or $0.09 per share increase in energy marketing earnings, primarily due to the $3.0 million Commodity Futures Trading Commission (CFTC) settlement recorded in June 2003, and

•

growth in our mining and communication segments' earnings.

Per share results in the second quarter of 2004 were also affected by an increase of 1.8 million weighted average shares outstanding, compared to the same period in 2003, due primarily to a 4.6 million share common stock offering on April 30, 2003.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003. Consolidated income from continuing operations for the six-month period ended June 30, 2004 was $19.5 million or $0.60 per share compared to $29.2 million or $1.00 per share in the same period of the prior year.

The decrease in income from continuing operations for the six-month period ended June 30, 2004 was primarily due to the following:

•

a $4.6 million or $0.14 per share decrease in electric utility earnings, primarily due to a decrease in off-system electric revenue, increased purchased power and maintenance expense related to scheduled and unscheduled plant outages, and increased administrative and general expenses,

•

a $9.4 million or $0.29 per share decrease in power generation earnings, primarily related to -

•

a $3.3 million or $0.10 per share decrease in earnings of unconsolidated subsidiaries, primarily related to unrealized mark-to-market adjustments at certain power fund investments,

•

a $7.6 million or $0.23 per share decrease in earnings from the Las Vegas II Cogeneration facility, primarily related to the termination of the Allegheny contract and replacement with a new long-term tolling agreement with Nevada Power Company that was effective April 1, 2004 and limited spot market sales in the first quarter of 2004,

•

offset by a full six months of earnings from the Wygen Plant that went into service in February 2003, and growth in earnings from our other power generation projects,

offset by:

•

a $2.8 million or $0.09 per share increase in energy marketing earnings, primarily due to the $3.0 million CFTC settlement recorded in June 2003 and higher pipeline revenues and marketing margins earned at our oil marketing operations offset by a decrease in unrealized mark-to-market adjustments at our gas marketing operations, and

•

growth in our mining and communication segments' earnings.

Net income for the six months ended June 30, 2003, included a charge of $2.7 million or ($0.09) 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 at our energy marketing segment and a $0.2 million benefit related to the adoption of SFAS 143 at our oil and gas and coal mining segments.

Per share results in the first six months of 2004 were also affected by an increase of 3.6 million weighted average shares outstanding, compared to the same period in 2003, due primarily to a 4.6 million share common stock offering on April 30, 2003.

A detailed discussion of results from our operating groups and segments are included in the following pages.

Wholesale Energy Group

	Three Months Ended June 30					Six Months Ended June 30
	2004			2003		2004			2003
	(in thousands)
Revenue:
Energy marketing*	$	170,896		$	172,262	$	335,331		$	354,689
Power generation		40,355			45,874		75,492			85,596
Oil and gas**		10,966			12,738		27,370			21,801
Mining		7,543			8,099		16,271			16,329

Total revenue		229,760			238,973		454,464			478,415
Equity in earnings (losses) of
unconsolidated subsidiaries		(759	)		4,408		(1,008	)		4,864
Operating expenses		209,525			216,923		416,408			432,123

Operating income	$	19,476		$	26,458	$	37,048		$	51,156

Income from continuing operations	$	8,961		$	11,163	$	16,290		$	22,260

_________________

*	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.

**	Includes a $(2.5) million and $(0.5) million revenue accrual correction for the three and six month periods ended June 30, 2004, respectively.

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

	Three Months Ended June 30				Six Months Ended June 30
	2004		2003		2004		2003

Fuel production:
Tons of coal sold		1,071,100		1,126,800		2,274,700		2,270,300
Barrels of oil sold		119,800		104,184		234,100		207,748
Mcf of natural gas sold		2,220,500		2,006,161		4,614,900		3,306,249
Mcf equivalent sales		2,939,300		2,631,265		6,019,500		4,552,737

	June 30
	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 June 30				Six Months Ended June 30
	2004		2003		2004		2003

Natural gas - MMBtus		1,552,800		1,151,200		1,577,100		1,169,600
Crude oil - barrels		51,000		62,400		50,600		60,200

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

Energy Marketing

	Three Months Ended June 30					Six Months Ended June 30
	2004		2003			2004		2003
	(in thousands)
Revenue*	$	170,896	$	172,262		$	335,331	$	354,689
Operating income (loss)		2,592		(754	)		8,892		5,924
Income (loss) from continuing
operations		1,606		(1,490	)		5,575		2,755

_________________

*	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 June 30, 2004 Compared to Three Months Ended June 30, 2003. The decrease in revenues is a result of an 18 percent decrease in crude oil volumes marketed, partially offset by a 21 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 increased $3.1 million primarily due to the recording of the $3.0 million CFTC settlement in June 2003. A 35 percent increase in gas volumes marketed was offset by a 10 percent decrease in the average margins received.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003. The decrease in revenues is a result of a 16 percent decrease in crude oil volumes marketed, partially offset by a 12 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 increased $2.8 million primarily due to higher pipeline revenues and marketing margins earned at our oil marketing operations. A $0.2 million unrealized mark-to-market loss for 2004 compared to a $2.9 million unrealized gain in 2003, resulted in a year-over-year pre-tax decrease of $3.1 million in unrealized mark-to-market adjustments at our gas marketing operations (see Note 16 for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our gas marketing operations). The $2.9 million unrealized pre-tax gain in 2003 was offset by the $3.0 million CFTC settlement in the same period. A 35 percent increase in gas volumes marketed was offset by a 37 percent decrease in the average margins received.

Power Generation

	Three Months Ended June 30					Six Months Ended June 30
	2004			2003		2004			2003
	(in thousands)
Revenue	$	40,355		$	45,874	$	75,492		$	85,596
Equity in (losses) earnings of
unconsolidated subsidiaries		(739	)		4,363		(938	)		4,480
Operating income		14,041			22,341		17,435			35,952
Income from continuing
operations		5,233			9,201		3,155			12,577

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003. Revenue decreased 12 percent in 2004 compared to 2003 primarily as a result of lower revenues from our Las Vegas facility and lower megawatt-hours being dispatched from our Gillette gas turbine. Revenues from our Las Vegas II Cogeneration power plant were $4.8 million lower than the prior year due to the termination of the Allegheny contract and replacement with a new long-term tolling arrangement for the capacity and energy of the Las Vegas II plant. The new contract was entered into with Nevada Power Company and became effective April 1, 2004. Revenues were lower from our Gillette gas turbine due to limited opportunities for economic dispatch because of prevailing regional power market conditions. Operating expenses decreased 8 percent primarily due to a reduction in transmission expense.

Equity in earnings of unconsolidated subsidiaries decreased $5.1 million, primarily due to the impact of mark-to-market adjustments at certain of our power fund investments that use a fair value method of accounting.

Income from continuing operations decreased $4.0 million. Decreased earnings were the result of lower revenues, lower earnings from power fund investments due to the impact of their mark-to-market adjustments, and higher depreciation costs primarily related to the consolidation of the Wygen plant pursuant to FIN 46, partially offset by lower interest expense from debt reduction from the proceeds of an asset sale and contract termination.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003. Revenue decreased 12 percent in 2004 compared to 2003 primarily due to lower revenues from our Las Vegas facility and lower megawatt-hours being dispatched from our Gillette gas turbine. Revenues from our Las Vegas II plant were $10.3 million lower than the prior year due to the termination of the Allegheny contract and replacement with a new long-term tolling arrangement for the capacity and energy of the Las Vegas II plant. The new contract was entered into with Nevada Power Company and became effective April 1, 2004. Prior to this arrangement, the facility sold 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. Revenues were lower from our Gillette gas turbine due to limited opportunities for economic dispatch because of prevailing regional power market conditions.

Equity in earnings of unconsolidated subsidiaries decreased $5.4 million, primarily due to the impact of mark-to-market adjustments at certain of our power fund investments that use a fair value method of accounting.

Income from continuing operations decreased $9.4 million. Decreased earnings were the result of lower revenues, lower earnings from unconsolidated subsidiaries due to the mark-to-market of their power projects, higher fuel costs and higher depreciation expense 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.

Oil and Gas

	Three Months Ended June 30					Six Months Ended June 30
	2004			2003		2004			2003
	(in thousands)
Revenue**	$	10,966		$	12,738	$	27,370		$	21,801
Equity in (losses) earnings of
unconsolidated subsidiaries		(20	)		45		(70	)		384
Operating income		1,346			4,197		7,189			6,831
Income from continuing operations		764			2,577		4,450			4,440

**	Includes a $(2.5) million and $(0.5) million revenue accrual correction for the three and six month periods ended June 30, 2004, respectively.

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003. Revenue from our oil and gas segment decreased $1.8 million for the three-month period ended June 30, 2004, compared to the same period in 2003. The decrease is due to a $2.5 million revenue accrual correction, partially offset by higher gas prices received on higher volumes. $2.0 million of the revenue accrual correction related to first quarter of 2004 and $0.5 million related to 2003. Volumes sold increased 12 percent. Average gas and oil prices received in 2004 were $4.73/Mcf and $25.99/bbl, respectively, compared to $4.54/Mcf and $28.65/bbl in 2003. Total operating expenses increased 12 percent primarily related to the additional operations acquired in the Mallon transaction. In addition, 2004 lease operating expenses per Mcfe sold (LOE/MCFE) were 3 percent lower than 2003.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003. Revenues from our oil and gas segment increased 26 percent or approximately $5.6 million for the six month period ended June 30, 2004, compared to the same period in 2003. The increase in revenues is due to a 32 percent increase in volumes sold and higher gas prices received. The increase in volumes sold reflects a full six months of production at the Mallon properties acquired in March 2003. Average gas and oil prices received in 2004 were $4.12/Mcf and $24.20/bbl, respectively, compared to $3.95/Mcf and $26.03/bbl in 2003. Total operating expenses increased 31 percent, or approximately $4.8 million, primarily related to the additional operations acquired in the Mallon transaction. In addition, 2004 LOE/MCFE were 2 percent lower than 2003.

Income from continuing operations was relatively flat with the prior period. The net increase in revenues and operating expenses was offset by a $0.5 million decrease in equity in earnings of unconsolidated subsidiaries.

The following is a summary of our internally estimated economically recoverable oil and gas reserves. These estimates are measured using constant product prices of $37.05 per barrel of oil and $6.16 per Mcf of natural gas as of June 30, 2004, and $30.18 per barrel of oil and $5.33 per Mcf of natural gas as of June 30, 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.

	June 30
	2004		2003

Barrels of oil (in thousands)		5,498		4,733
Mmcf of natural gas		122,503		113,780
Total in Mmcf equivalents		155,492		142,180

Coal Mining

	Three Months Ended June 30				Six Months Ended June 30
	2004		2003		2004		2003
	(in thousands)
Revenue	$	7,543	$	8,099	$	16,271	$	16,329
Operating income		1,497		674		3,532		2,449
Income from continuing operations		1,358		875		3,110		2,488

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003. Revenue from our mining segment decreased 7 percent for the three-month period ended June 30, 2004, compared to the same period in 2003. The decrease is attributable to a 5 percent decrease in tons of coal sold. The decrease in tons of coal sold was primarily attributable to the scheduled electric plant maintenance outages and an unscheduled Wyodak Plant outage partially offset by additional sales through the train load-out facility and to the Wygen Plant.

Operating expenses decreased 19 percent or approximately $1.4 million, primarily due to lower mining costs, including lower production taxes, related to the decrease in production and decreased general and administrative costs, primarily due to lower compensation expense and corporate allocations.

Income from continuing operations increased $0.5 million due to lower production and general and administrative costs, partially offset by a decrease in revenues.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003. Revenue for the six-month period ended June 30, 2004 was relatively flat with the same period in 2003. Increased revenues from the Wygen Plant and train load-out facility were offset by decreased revenues due to the scheduled electric plant maintenance outages and an unscheduled outage at the Wyodak plant.

Operating expenses decreased 8 percent or approximately $1.1 million, primarily due to lower mining costs, including lower production taxes, related to the decrease in production, lower corporate allocations and lower compensation and property insurance expense, offset by increased depreciation expense.

Income from continuing operations increased $0.6 million due primarily to lower production and general and administrative costs.

Retail Services Group

Electric Utility

	Three Months Ended June 30				Six Months Ended June 30
	2004		2003		2004		2003
	(in thousands)
Revenue	$	39,809	$	39,207	$	81,456	$	82,970
Operating expenses		33,249		28,610		63,488		58,721

Operating income	$	6,560	$	10,597	$	17,968	$	24,249

Income from continuing operations
and net income	$	1,816	$	4,722	$	6,852	$	11,421

The following table provides certain operating statistics:

	Three Months Ended June 30				Six Months Ended June 30
	2004		2003		2004		2003
Firm (system) sales - MWh		451,000		447,400		964,300		952,900
Off-system sales - MWh		259,600		234,100		461,900		479,800

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003. Electric utility revenues increased 2 percent for the three-month period ended June 30, 2004, compared to the same period in the prior year. The increase in revenue was primarily due to an 11 percent increase in off-system electric MWh sales offset by a 1 percent decrease in average prices received. Revenues were impacted in part by plant availability resulting from unscheduled and scheduled maintenance outages during the three month period ended June 30, 2004. Firm commercial and industrial electricity revenues increased 1 percent and 2 percent, respectively, offset by a slight decrease in residential revenues. Degree days, which is a measure of weather trends, were 3 percent below last year.

Electric operating expenses increased 16 percent for the three-month period ended June 30, 2004, compared to the same period in the prior year. Purchased power increased $3.7 million due to a 40 percent increase in megawatt-hours purchased, at a 7 percent increase in the average cost per megawatt-hour. Megawatt-hours purchased increased due to replacement power needed because of scheduled and unscheduled plant outages and uneconomic dispatch of our gas turbines. Gas costs decreased 19 percent due to a 78 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 $81.89 for the three months ended June 30, 2004 compared to $31.34 per megawatt-hour for purchased power for the same time period. The decrease in fuel expense was offset by increased maintenance costs for scheduled and unscheduled plant outages, increased health insurance costs and an increase in allocated corporate costs.

Income from continuing operations decreased $2.9 million primarily due to increases in purchased power expense, maintenance expense, health insurance expense and allocated corporate costs, partially offset by an increase in firm system and off-system electric sales and a decrease in fuel expense.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003. Electric utility revenues decreased 2 percent for the six-month period ended June 30, 2004, compared to the same period in the prior year. The decrease in revenue was primarily due to a 4 percent decrease in off-system electric MWh sales and a 4 percent decrease in average prices received. Revenues were impacted in part by plant availability resulting from unscheduled and scheduled maintenance outages during the six month period ended June 30, 2004. The decrease in revenue from off-system sales was partially offset by strong retail sales. Residential, commercial and industrial revenues increased 2 percent, 1 percent and 4 percent, respectively, while degree days, which is a measure of weather trends, were 6 percent below last year.

Electric operating expenses increased 8 percent for the six-month period ended June 30, 2004, compared to the same period in the prior year. Purchased power increased $4.9 million due to a 31 percent increase in megawatt-hours purchased. Megawatt-hours purchased increased primarily due to replacement power needed because of scheduled and unscheduled plant outages and uneconomic dispatch of our gas turbines. Gas costs decreased 35 percent due to a 90 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 $95.22 for the six months ended June 30, 2004 compared to $32.20 per megawatt-hour for purchased power for the same time period. The decrease in fuel expense was offset by increased maintenance costs for scheduled and unscheduled plant outages, increased health insurance costs and an increase in allocated corporate costs.

Income from continuing operations decreased $4.6 million primarily due to a 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 June 30						Six Months Ended June 30
	2004			2003			2004			2003
	(in thousands)
Revenue	$	11,418		$	11,773		$	19,874		$	20,459
Operating expenses		10,714			11,415			21,010			21,987

Operating income (loss)	$	704		$	358		$	(1,136	)	$	(1,528	)

Loss from continuing operations
and net loss	$	(169	)	$	(433	)	$	(1,953	)	$	(2,242	)




Business customers	3,247	3,012	2,778
Business access lines	12,667	12,023	11,271
Residential customers	23,562	23,878	23,400

Three Months Ended June 30, 2004 Compared to Three Months Ended June 30, 2003. The communications business group’s net loss was $0.2 million compared to $0.4 million for the three-month periods ended June 30, 2004 and 2003, respectively. Earnings for the three months ended June 30, 2004 were approximately $0.3 million lower due to 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. Many of these temporary price discounts reverted to full price during the second quarter of 2004. Revenue reductions from sales incentives were partially offset by increased business 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.

Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003. The communications business group’s net loss was $2.0 million compared to $2.2 million for the six-month periods ended June 30, 2004 and 2003, respectively. Earnings for the six month period ended June 30, 2004 were approximately $0.8 million lower due to 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. Many of these temporary price discounts reverted to full price 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 the results for the first half of 2004 and current expectations for the remainder of the year, we estimate income from continuing operations to be between $1.70 and $1.85 per share, due to the following factors:

•

lower-than-expected production from oil and gas operations, due primarily to delays in obtaining drilling permits and delays in the construction of compression stations and gas gathering pipelines;

•

electric utility earnings declined, due primarily to higher fuel and purchased power costs, resulting from a combination of unexpected outages at certain power plants, market prices of gas and power, and unexpected capacity restrictions on the new AC-DC-AC transmission inter-tie relating to storm-caused transmission outages in Nebraska; and

•

results at our energy marketing operations declined, due primarily to lower-than-expected margins.

Principal assumptions in our revised guidance for the remainder of 2004 include:

•

expected improvement in oil and gas performance in the second half of 2004, based on current forward price curves and production increases approximating 50 percent in the second half of 2004, compared to the first half of 2004; this increase is expected to come from the completion of gas gathering and compression facilities and additional drilling primarily at the Mallon properties;

•

normal weather patterns, normal plant availability and resumed access to power markets at our electric utility;

•

continued high availability for contracted, non-regulated power plants;

•

consistent margins with no significant net unrealized gains or losses from energy marketing operations; and

•

modest improvements in communications results.

We anticipate 2005 income from continuing operations to approximate $1.85 to $2.00 per share, due to continued increases in oil and gas operations, the expected addition of Cheyenne Light, Fuel & Power operations, modest improvement in communications results, and effective cost management, offset in part by small decreases in energy marketing results, and lower utility and coal mining results relating to planned major maintenance outages at certain electric utility coal-fired power plants.

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 six-month period ended June 30, 2004, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our scheduled long-term debt maturities, and to fund most of our property additions. We plan to fund future property and investment additions primarily through a combination of existing cash balances, operating cash flow, increased short-term debt, long-term debt, and long-term non-recourse project financing.

Cash flows from operations decreased $22.7 million for the six-month period ended June 30, 2004 compared to the same period in the prior year primarily due to decreased earnings, purchases of gas and oil inventory held by our energy marketing operations and changes in other working capital.

During the six months ended June 30, 2004, we had cash outflows from investing activities of $35.4 million, which was primarily related to property, plant and equipment additions in the normal course of business.

During the six months ended June 30, 2004, we had cash outflows from financing activities of $95.9 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 and on May 10, 2004, we repurchased $25 million of our 6.5 percent senior unsecured notes due 2013.

Dividends

Dividends paid on our common stock totaled $0.31 per share in each of the first and second quarters 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 six months of 2004. As of June 30, 2004, we had approximately $104.2 million of cash unrestricted for operations and $350 million of credit through revolving bank facilities. Approximately $22.2 million of the cash balance at June 30, 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 $125 million facility due May 12, 2005. The $125 million facility replaced a $200 million facility, which was due to expire on 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 June 30, 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 $303.3 million at June 30, 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 $550 million and 50 percent of the aggregate consolidated net income beginning April 1, 2004;

•

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 June 30, 2004, we were in compliance with the above covenants.

Our consolidated net worth was $715.0 million at June 30, 2004, which was approximately $159.2 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 June 30, 2004 was 52.5 percent, our total debt leverage (long-term debt and short-term debt) was 53.0 percent, and our recourse leverage ratio was approximately 48.3 percent.

In addition, Enserco Energy Inc., our gas marketing unit, has a $150 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. As of June 30, 2004, we had a $3.0 million guarantee to the lender under this facility. This facility was recently increased from $135 million. At June 30, 2004, there were outstanding letters of credit issued under the facility of $98.5 million, with no borrowing balances outstanding on the facility.

Similarly, Black Hills Energy Resources, Inc. (BHER), our oil marketing unit, currently has a $25 million uncommitted, discretionary credit facility. The facility may be increased 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 June 30, 2004, BHER had letters of credit outstanding of $8.9 million.

There were no changes in our corporate credit ratings during the first six months 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 and Exchange Commission.

Contractual Obligations

The long-term debt component of our contractual obligations table disclosed in our 2003 Annual Report on Form 10-K has been reduced by the following:

•

$45 million of the project level debt on the Fountain Valley facility due in 2006. We repaid this portion in January 2004.

•

$25 million of the 6.5 percent senior unsecured notes due in 2013. We repurchased this portion in May 2004.

There were no other material changes to our contractual obligations table from those reported in Items 7 of our 2003 Annual Report on Form 10-K filed with the Securities and 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.

During the second quarter of 2004, a $5.0 million guarantee related to a power pool agreement became effective and a $0.8 million guarantee was issued related to payments under various transactions with Southern California Edison Company.

At June 30, 2004, we had guarantees totaling $186.7 million in place.

Capital Requirements

During the six months ended June 30, 2004, capital expenditures were approximately $38.6 million. Due to the lack of capital deployment opportunities, we have revised our forecasted capital requirements for maintenance capital and developmental capital as follows (in thousands):

	2004		2005		2006


Wholesale energy	$	70,850	$	46,080	$	56,920
Electric utility		21,180		34,370		35,630
Communications		9,410		7,840		7,050
Corporate		4,440		2,570		1,690
Development		74,000		93,910		105,000

	$	179,880	$	184,770	$	206,290

REGULATION

On July 19, 2004, we filed a Form U-1 with the Securities and Exchange Commission to formally request certain approvals in connection with becoming a registered holding company under the Public Utilities Holding Company Act of 1935, as amended (1935 Act).

As a registered holding company, the 1935 Act and related regulations issued by the SEC would regulate our activities and activities of our subsidiaries with respect to the acquisition and sale of securities, acquisition and sale of utility assets, transactions among affiliates, engaging in business activities not directly related to the utility or energy business and other matters.

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 and 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 Items 1 and 2 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;

•

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;

•

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 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 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 six months ended June 30, 2004 (in thousands):




Total fair value of natural gas marketing contract net liability at December 31, 2003	$	(408	)
Net cash settled during the six-month period on contracts that existed at
December 31, 2003		(1,835	)
Change in fair value due to change in techniques and assumptions		--
Unrealized gain (loss) on new contracts entered during the six-month period and
still existing at June 30, 2004		235
Realized gain on contracts that existed at December 31, 2003 and were settled
during the year		1,276
Unrealized gain on contracts that existed at December 31, 2003 and still exist
at June 30, 2004		903

Total fair value of natural gas marketing contract net assets at June 30, 2004	$	171

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 June 30, 2004, we had a mark to fair value unrealized gain of $0.2 million for our derivative contracts related to our natural gas marketing activities, with $0.1 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	$	99	$	205		$	304
Prices provided by other external sources		32		(165	)		(133	)
Modeled		--		--			--

Total	$	131	$	40		$	171

The following table presents a reconciliation of our net derivative assets/(liabilities) under GAAP for our gas marketing subsidiary to a non-GAAP measure of the fair value of our forward book wherein all forward trading positions are marked-to-market. The approach used in determining the non-GAAP measure is consistent with our previous accounting methods under EITF 98-10.




Net derivative assets/(liabilities) (GAAP)	$	171
Increase/(decrease) in fair value of inventory, storage and transportation positions
that are related to trading, but that are not marked-to-market under GAAP		3,691

Fair value of all forward positions (Non-GAAP)	$	3,862

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 June 30, 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 17 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 17 is incorporated by reference into this item.

Item 2.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Period		(b) Average Price Paid per Share


April 1, 2004 -
April 30, 2004	1,044⁽¹⁾	$	30.78	--	--
May 1, 2004 -
May 31, 2004	1,403⁽¹⁾	$	29.22	--	--
June 1, 2004 -	322⁽¹⁾	$	29.30	--	--
June 30, 2004	290⁽²⁾	$	29.78	--	--

Total	3,059	$	29.81	--	--

_________________

(1)

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

(2)

Shares acquired by a Rabbi Trust for the Outside Directors Stock Based Compensation Plan.

Item 4.

Submission of Matters to a Vote of Security Holders

(a)

The Annual Meeting of Shareholders was held on May 26, 2004.

(b)

The following Directors were elected to serve until the Annual Meeting of Shareholders in 2007:

Jack W. Eugster
Richard Korpan
Thomas J. Zeller

Other Directors whose term of office continues are:

Daniel P. Landguth
David R. Emery
David C. Ebertz
John R. Howard
Bruce B. Brundage
Kay S. Jorgensen
Stephen D. Newlin

(c)

Matters Voted Upon at the Meeting

Elected three Class I Directors to serve until the Annual Meeting of Shareholders in 2007.

Jack W. Eugster
Votes For 27,664,173
Votes Withheld 366,283

Richard Korpan
Votes For 27,662,991
Votes Withheld 367,465

Thomas J. Zeller
Votes For 27,560,221
Votes Withheld 470,235

Ratified the appointment of Deloitte & Touche LLP to serve as Black Hills Corporation's independent auditors in 2004.

     Votes For                27,532,265
     Votes Withheld            378,141
     Abstain                         120,050
     Broker Non-Votes                --

Item 6.

Exhibits and Reports on Form 8-K

(a)

Exhibits

Exhibit 10.1

Compilation of the Amended and Restated Multi-year Credit Agreement dated as of August 21, 2003 among Black Hills Corporation, as Borrower, The Financial Institutions party thereto, as Banks, ABN AMRO BANK N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, BMO Nesbitt Burns Financing, Inc., as Co-Syndication Agent, US Bank, National Association, as Documentation Agent, and The Bank of Nova Scotia, as Co-Documentation Agent.

Exhibit 10.2

364-day Credit Agreement dated as of May 13, 2004 among Black Hills Corporation, as Borrower, the Financial Institutions party thereto, as Banks, ABN AMRO Bank N.V., as Administrative Agent, Union Bank of California, N.A., as Syndication Agent, Bank of Montreal dba "Harris Nesbitt," as Co-Syndication Agent, US Bank, National Association, as Documentation Agent and The Bank of Nova Scotia, as Co-Documentation Agent.

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 June 30, 2004:

Form 8-K dated May 6, 2004.

Reported under Item 12, that the Company issued a press release announcing earnings for the first quarter of 2004.

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: August 9, 2004

EXHIBIT INDEX

Exhibit
Number Description

Exhibit 10.1

Exhibit 10.2

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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Avg

Black Hills (BKH) 10-Q2004 Q2 Quarterly report

Content analysis

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

Contractual Obligations

Guarantees

Capital Requirements

REGULATION

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 (BKH) 10-Q2004 Q2 Quarterly report

Content analysis

BLACK HILLS CORPORATIONCONDENSED CONSOLIDATED STATEMENTS OF INCOME(unaudited)

BLACK HILLS CORPORATIONCONDENSED CONSOLIDATED BALANCE SHEETS(unaudited)

BLACK HILLS CORPORATIONCONDENSED 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

Contractual Obligations

Guarantees

Capital Requirements

REGULATION

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK