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 September 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 October 29, 2004

Common stock, $1.00 par value 32,469,651 shares

		Page
PART 1. Item 1. Item 2. Item 3. Item 4. PART II. Item 1. Item 2. Item 6.	FINANCIAL INFORMATION Financial Statements Condensed Consolidated Statements of Income - Three and Nine Months Ended September 30, 2004 and 2003 Condensed Consolidated Balance Sheets - September 30, 2004, December 31, 2003 and September 30, 2003 Condensed Consolidated Statements of Cash Flows - Nine Months Ended September 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 Unregistered Sales of Equity Securities and Use of Proceeds Exhibits Signatures Exhibit Index	3 4 5 6-30 31-49 50-51 51 52 52 53 54 55

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

	Three Months Ended September 30						Nine Months Ended September 30
	2004			2003			2004			2003
	(in thousands, except per share amounts)
Operating revenues	$	279,614		$	296,860		$	834,297		$	877,548
Contract termination revenue		--			114,000			--			114,000

		279,614			410,860			834,297			991,548

Operating expenses:
Fuel and purchased power		175,833			184,591			530,839			555,296
Operations and maintenance		22,773			25,887			73,037			76,659
Administrative and general		16,088			17,431			49,951			56,206
Depreciation, depletion and amortization		22,062			20,185			65,812			59,263
Taxes, other than income taxes		5,545			6,515			21,765			22,041
Impairment of long-lived assets		--			117,207			--			117,207

		242,301			371,816			741,404			886,672

Equity in earnings (loss) of unconsolidated subsidiaries		285			894			(723	)		5,758

Operating income		37,598			39,938			92,170			110,634

Other income (expense):
Interest expense		(12,085	)		(13,749	)		(39,155	)		(39,313	)
Interest income		339			138			1,072			467
Other expense		(83	)		(3	)		(276	)		(262	)
Other income		196			321			792			1,010

		(11,633	)		(13,293	)		(37,567	)		(38,098	)

Income from continuing operations before minority
interest, income taxes and change in accounting principle		25,965			26,645			54,603			72,536
Minority interest		(48	)		--			(134	)		--
Income taxes		(8,569	)		(8,972	)		(17,575	)		(25,659	)

Income from continuing operations before change in accounting principles		17,348			17,673			36,894			46,877
(Loss) income from discontinued operations, net of taxes		(168	)		4,771			1,587			9,085
Change in accounting principles, net of taxes		--			--			--			(2,680	)

Net income		17,180			22,444			38,481			53,282
Preferred stock dividends		(78	)		(57	)		(244	)		(172	)

Net income available for common stock	$	17,102		$	22,387		$	38,237		$	53,110

Weighted average common shares outstanding:
Basic		32,420			32,087			32,372			29,922

Diluted		32,913			32,754			32,885			30,457

Earnings per share:
Basic-
Continuing operations	$	0.53		$	0.55		$	1.13		$	1.56
Discontinued operations		--			0.15			0.05			0.30
Change in accounting principle		--			--			--			(0.09	)

Total	$	0.53		$	0.70		$	1.18		$	1.77

Diluted-
Continuing operations	$	0.53		$	0.54		$	1.12		$	1.54
Discontinued operations		(0.01	)		0.15			0.05			0.30
Change in accounting principle		--			--			--			(0.09	)

Total	$	0.52		$	0.69		$	1.17		$	1.75

Dividends paid per share of common stock	$	0.31		$	0.30		$	0.93		$	0.90

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)

	September 30 2004			December 31 2003			September 30 2003
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	79,942		$	172,759		$	269,669
Restricted cash		--			1,350			1,070
Receivables (net of allowance for doubtful accounts of $7,359; $7,345 and $4,156, respectively)		201,618			201,976			166,819
Materials, supplies and fuel		123,027			44,895			46,692
Derivative assets		36,271			26,804			23,781
Prepaid income taxes		4,241			18,940			--
Deferred income taxes		4,085			4,256			4,940
Other current assets		5,582			8,875			6,058
Assets of discontinued operations		3,751			4,575			6,197

		458,517			484,430			525,226

Investments		23,900			26,847			24,274

Property, plant and equipment		1,946,396			1,882,545			1,742,821
Less accumulated depreciation and depletion		(501,893	)		(440,274	)		(420,725	)

		1,444,503			1,442,271			1,322,096

Other assets:
Derivative assets		625			1,002			552
Goodwill		30,144			30,144			24,112
Intangible assets (net of accumulated amortization of $20,910; $18,423 and $17,592, respectively)		37,583			40,070			40,901
Other		36,263			38,488			25,462

		104,615			109,704			91,027

	$	2,031,535		$	2,063,252		$	1,962,623

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	172,958		$	162,706		$	171,149
Accrued liabilities		59,172			66,618			74,723
Accrued income taxes		6,839			5,752			73,393
Current maturities of long-term debt		61,016			17,659			18,075
Derivative liabilities		57,288			32,967			25,307
Liabilities of discontinued operations		589			3,444			3,800

		357,862			289,146			366,447

Long-term debt, net of current maturities		736,959			868,459			747,211

Deferred credits and other liabilities:
Deferred income taxes		145,436			125,040			87,199
Derivative liabilities		1,860			3,247			3,237
Other		63,667			62,924			59,885

		210,963			191,211			150,321

Minority interest in subsidiaries		4,782			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 32,586,929; 32,447,765 and 32,293,220 shares, respectively		32,587			32,448			32,293
Additional paid-in capital		383,786			379,271			375,185
Retained earnings		312,661			304,567			306,392
Treasury stock at cost - 117,778; 150,048 and 159,966 shares, respectively		(2,842	)		(3,560	)		(3,788	)
Accumulated other comprehensive loss		(12,390	)		(11,122	)		(16,987	)

		713,802			701,604			693,095

Total stockholders' equity		720,969			709,747			698,644

	$	2,031,535		$	2,063,252		$	1,962,623

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)

	Nine Months Ended September 30
	2004			2003
	(in thousands)
Operating activities:
Net income available for common	$	38,237		$	53,110
Adjustments to reconcile net income available for common to net cash
provided by operating activities:
Income from discontinued operations		(1,587	)		(9,085	)
Impairment of long-lived assets		--			117,207
Provision for valuation allowances		(70	)		(39	)
Depreciation, depletion and amortization		65,812			59,263
Net change in derivative assets and liabilities		6,491			(4,854	)
Deferred income taxes		21,144			(40,433	)
Net (undistributed) distributed earnings in associated companies		3,448			(5,758	)
Minority interest		134			--
Change in accounting principles		--			2,680
Change in operating assets and liabilities-
Accounts receivable and other current assets		(54,498	)		(19,853	)
Accounts payable and other current liabilities		2,763			81,192
Other operating activities		2,636			(911	)

		84,510			232,519

Investing activities:
Property, plant and equipment additions		(65,572	)		(77,912	)
Payment for acquisition of minority interests		--			(9,000	)
Proceeds from sale of assets		--			185,926
Increase in notes receivable - Mallon Resources		--			(5,164	)
Other investing activities		3,144			(455	)

		(62,428	)		93,395

Financing activities:
Dividends paid		(30,143	)		(27,346	)
Common stock issued		3,678			121,206
Decrease in short-term borrowings, net		--			(340,500	)
Long-term debt - issuance		--			252,000
Long-term debt - repayments		(88,143	)		(129,394	)
Other financing activities		(291	)		(7,132	)

		(114,899	)		(131,166	)

(Decrease) increase in cash and cash equivalents		(92,817	)		194,748
Cash and cash equivalents:
Beginning of period		172,759			74,921

End of period	$	79,942		$	269,669

Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest	$	35,461		$	47,219
Income taxes paid (refunded), net	$	(18,637	)	$	6,549
Non-cash net assets acquired through issuance of common stock and
decrease in notes receivable - Mallon Resources	$	--		$	51,153

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

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 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 September 30, 2004, December 31, 2003 and September 30, 2003, financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 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 September 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 September 30						Nine Months Ended September 30
	2004			2003			2004			2003
Net income available for common
stock, as reported	$	17,102		$	22,387		$	38,237		$	53,110
Deduct: Total stock-based employee
compensation expense determined
under fair value based method for all
awards, net of related tax effects		(176	)		(282	)		(496	)		(725	)

Pro forma net income	$	16,926		$	22,105		$	37,741		$	52,385

Earnings per share:
As reported--
Basic
Continuing operations	$	0.53		$	0.55		$	1.13		$	1.56
Discontinued operations		--			0.15			0.05			0.30
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.53		$	0.70		$	1.18		$	1.77

Diluted
Continuing operations	$	0.53		$	0.54		$	1.12		$	1.54
Discontinued operations		(0.01	)		0.15			0.05			0.30
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.52		$	0.69		$	1.17		$	1.75

Pro forma--
Basic
Continuing operations	$	0.53		$	0.54		$	1.12		$	1.54
Discontinued operations		--			0.15			0.05			0.30
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.53		$	0.69		$	1.17		$	1.75

Diluted
Continuing operations	$	0.52		$	0.53		$	1.11		$	1.52
Discontinued operations		(0.01	)		0.15			0.05			0.30
Change in accounting principles		--			--			--			(0.09	)

Total	$	0.51		$	0.68		$	1.16		$	1.73

(4)	RECENTLY ADOPTED 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. FSP 106-2 is effective for the first interim period beginning after June 15, 2004. The Company provides prescription drug benefits to certain eligible employees and will include the effects of the 2003 Medicare Act on its next actuarial measurement of the accumulated postretirement benefit obligation or net periodic postretirement benefit cost. The Company uses a September 30 measurement date for the Plan.

In April 2004, the FASB issued FSP FAS 141-1 and FAS 142-1, “Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, Whether Mineral Rights Are Tangible orIntangible Assets.” The FSP amends SFAS 141 and SFAS 142 to conform with the EITF consensus in EITF 04-2 that mineral rights, as defined by 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.

(5)	MATERIALS, SUPPLIES AND FUEL

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

Major Classification	September 30, 2004		December 31, 2003		September 30, 2003
Natural gas and oil held by
Energy Marketing	$	99,350	$	24,394	$	28,355
Materials and supplies		22,387		18,920		17,049
Fuel for generation		1,290		1,581		1,288

Total materials, supplies and fuel	$	123,027	$	44,895	$	46,692

The inventory held by our natural gas marketing company is in the form of storage agreements. The gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future. A substantial majority of the gas was economically hedged at the time of purchase either through a fixed price physical or financial forward sale. Most of this natural gas is currently projected to flow out of inventory in the fourth quarter of 2004 and the first quarter of 2005. If changing market conditions make it economically advantageous to do so, the duration of holding significant amounts of natural gas in inventory could be extended.

(6)	ASSET RETIREMENT OBLIGATIONS

SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143) requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Cumulative accretion and accumulated depreciation have been recognized for the time period from the date the liability would have been recognized had the provisions of SFAS 143 been in effect, to the date of its adoption.

The Company has identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in our Oil and Gas segment and reclamation of our coal mining sites in our Mining segment.

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

	Balance at 12/31/03		Liabilities Incurred		Liabilities Settled			Accretion		Cash Flow Revisions		Balance at 9/30/04
Oil and Gas	$	7,233	$	--	$	--		$	412	$	--	$	7,645
Mining		15,752		485		(354	)		597		--		16,480

Total	$	22,985	$	485	$	(354	)	$	1,009	$	--	$	24,125

(7)	VARIABLE INTEREST ENTITY

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

Prior to the December 31, 2003 consolidation, the Company recorded lease expense on the Wygen plant. Lease payments began upon completion of the plant in February 2003. During the three and nine months ended September 30, 2003, lease payments were $0.9 million and $3.0 million, respectively, and are included in Operations and maintenance on the accompanying 2003 Condensed Consolidated Statements 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 nine months ended September 30, 2004, depreciation expense was $0.8 million and $2.5 million, respectively and interest expense was $0.9 million and $2.5 million, respectively.

(8)	EARNINGS PER SHARE

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

	Income				Income
Period ended September 30, 2004 (in thousands)	Three Months				Nine Months

Income from continuing operations	$	17,348			$	36,894
Less: preferred stock dividends		(78	)			(244	)

Basic - available for common
shareholders		17,270		32,420		36,650		32,372
Dilutive effect of:
Stock options		--		75		--		98
Convertible preferred stock		78		195		244		195
Estimated contingent shares
issuable for prior acquisition		--		158		--		158
Others		--		65		--		62

Diluted - available for common shareholders	$	17,348		32,913	$	36,894		32,885

	Income				Income
Period ended September 30, 2003 (in thousands)	Three Months				Nine Months

Income from continuing operations	$	17,673			$	46,877
Less: preferred stock dividends		(57	)			(172	)

Basic - available for common
shareholders		17,616		32,087		46,705		29,922
Dilutive effect of:
Stock options		--		139		--		92
Convertible preferred stock		57		148		172		148
Estimated contingent shares
issuable for prior acquisition		--		335		--		257
Others		--		45		--		38

Diluted - available for common shareholders	$	17,673		32,754	$	46,877		30,457

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

(9)	COMPREHENSIVE INCOME

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

	Three Months Ended September 30					Nine Months Ended September 30
	2004			2003		2004			2003
Net income	$	17,180		$	22,444	$	38,481		$	53,282
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 $331
for the nine month period ended
September 30, 2003)		(1,484	)		2,331		(1,166	)		276
Unrealized loss on
available-for-sale securities		(47	)		--		(101	)		--
Reclassification adjustment for
interest rate swaps designated
as cash flow hedges settled as
part of the hydroelectric sale
and included in net income, net
of minority interest of $2,379
for the three and nine months
ended September 30, 2003		--			3,928		--			3,928

Comprehensive income	$	15,649		$	28,703	$	37,214		$	57,486

(10)	CHANGES IN COMMON STOCK

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

•

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	Total Target Grant of Shares
March 1, 2004	March 1, 2004 - December 31, 2005		15,458
March 1, 2004	March 1, 2004 - December 31, 2006		31,384

Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50^th percentile of the selected peer group. The final value of the performance shares may vary according to the number of shares of common stock that are ultimately granted based upon the performance criteria. Compensation expense recognized for the performance share awards for the three and nine month periods ended September 30, 2004 was $0 and $0.3 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 34,328 shares of restricted stock and 16,019 restricted stock units and issued 11,215 shares of common stock for the conversion of restricted stock units. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units 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 103,000 stock options at a weighted average exercise price of $30.02 per share.

•

68,433 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 9,954 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 7,508 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.

(11)	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 and on September 30, 2004, the facility was renewed to September 30, 2005.

On August 31, 2004, the Company effected a call on Black Hills Power’s $5.9 million, 6.7 percent Pollution Control Revenue Bonds issued through Lawrence County, South Dakota. The bonds had a maturity date of 2010.

On September 21, 2004, the Company initiated a notice to call effective October 21, 2004, the entire $45 million Series AB 8.3 percent bonds. The bonds had a maturity date of 2024. Due to the notice to call, the bonds have been classified to current maturities of long-term debt on the September 30, 2004 Balance Sheet.

(12)	GUARANTEES

The Company has entered into various agreements providing financial or performance assurance to third parties on behalf of certain subsidiaries. Such agreements include guarantees of debt obligations, contractual performance obligations 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 September 30, 2004, the Company had the following guarantees in place (in thousands):

Nature of Guarantee	Outstanding at September 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		2005
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		28,714		2010
Indemnification for subsidiary reclamation/surety bonds		26,481		Ongoing

	$	186,213

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 September 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 $24.6 million of debt of Black Hills Wyoming and $4.1 million of debt for another of the Company’s 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 September 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.

(13)	EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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

The components of net periodic benefit cost for the Plan for the periods ended September 30 are as follows (in thousands):

	Three Months Ended						Nine Months Ended
	2004			2003			2004			2003
Service cost	$	443		$	323		$	1,329		$	969
Interest cost		909			838			2,727			2,514
Expected return on plan
assets		(1,129	)		(780	)		(3,387	)		(2,340	)
Amortization of prior
service cost		58			58			174			174
Amortization of net loss		375			352			1,125			1,056

Net periodic benefit cost	$	656		$	791		$	1,968		$	2,373

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 September 30 are as follows (in thousands):

	Three Months Ended					Nine Months Ended
	2004		2003			2004		2003
Service cost	$	134	$	106		$	402	$	318
Interest cost		241		190			723		570
Amortization of prior
service cost (credit)		2		(1	)		6		(3	)
Amortization of net loss		187		128			561		384

Net periodic benefit cost	$	564	$	423		$	1,692	$	1,269

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 September 30 are as follows (in thousands):

	Three Months Ended						Nine Months Ended
	2004			2003			2004			2003
Service cost	$	140		$	96		$	420		$	288
Interest cost		166			144			498			432
Amortization of net
transition obligation		37			37			111			111
Amortization of prior
service credit		(6	)		(6	)		(18	)		(18	)
Amortization of net loss		47			22			141			66

Net periodic benefit cost	$	384		$	293		$	1,152		$	879

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.

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

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of September 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 in Rapid City and the Northern Black Hills region of South Dakota.

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
September 30, 2004
Energy marketing*	$	159,694	$	--		$	670
Power generation		42,980		--			7,192
Oil and gas		13,578		88			2,765
Mining		3,776		3,256			2,537
Electric		47,405		516			5,860
Communications		9,455		--			(1,256	)
Corporate		163		310			(420	)
Intersegment eliminations		--		(1,607	)		--

Total	$	277,051	$	2,563		$	17,348

_________________

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).

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

Quarter to Date
September 30, 2003
Energy marketing*	$	168,908	$	--		$	1,324
Power generation**		164,577		--			7,056
Oil and gas		12,438		75			2,805
Mining		6,011		3,166			2,234
Electric		46,247		21			6,772
Communications		10,136		--			(1,031	)
Corporate		--		--			(1,487	)
Intersegment eliminations		--		(719	)		--

Total	$	408,317	$	2,543		$	17,673

_________________

Includes $114 million contract termination revenue as described in Note 18.

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

Year to Date
September 30, 2004
Energy marketing*	$	495,024	$	--		$	6,245
Power generation		118,472		--			10,347
Oil and gas**		40,776		260			7,215
Mining		14,093		9,210			5,648
Electric		128,819		558			12,712
Communications		29,329		--			(3,209	)
Corporate		630		946			(2,060	)
Intersegment eliminations		--		(3,820	)		(4	)

Total	$	827,143	$	7,154		$	36,894

_________________

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
September 30, 2003
Energy marketing*	$	523,597	$	--		$	4,079
Power generation**		250,173		--			19,634
Oil and gas		34,103		211			7,245
Mining		16,552		8,954			4,722
Electric		129,182		56			18,193
Communications		30,595		--			(3,273	)
Corporate		--		--			(3,722	)
Intersegment eliminations		--		(1,875	)		(1	)

Total	$	984,202	$	7,346		$	46,877

_________________

Includes $114 million contract termination revenue as described in Note 18.

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

(15)	RISK MANAGEMENT ACTIVITIES

The Company actively manages its exposure to certain market risks as described in Note 2 of the Company’s 2003 Annual Report on Form 10-K. Details of derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are as follows:

Trading Activities

Natural Gas Marketing

The contract or notional amounts and terms of the Company’s natural gas marketing activities and derivative commodity instruments that were marked-to-market on September 30, 2004, December 31, 2003 and September 30, 2003 are as follows:

	September 30, 2004				December 31, 2003				September 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		28,793		1.5		13,028		1		46,026		1.25
Natural gas basis swaps sold		30,548		1.5		12,691		1		45,589		1.25
Natural gas fixed-for-float
swaps purchased		22,083		1		19,645		1.5		17,822		1
Natural gas fixed-for-float
swaps sold		26,090		1.25		21,752		1.5		22,097		1.25
Natural gas physical purchases		64,395		1.5		50,757		2.25		43,131		1.5
Natural gas physical sales		114,031		5		44,066		2.25		49,874		1.5

_________________

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)
September 30, 2004	$	36,244	$	625	$	48,569	$	329	$	(12,029	)

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

September 30, 2003	$	22,507	$	552	$	20,327	$	371	$	2,361

For the nine month periods ended September 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:

	September 30, 2004				December 31, 2003				September 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		1,892		0.5		2,688		0.5		3,253		0.5
Crude oil sold		1,880		0.5		2,253		0.5		3,230		0.5

All of the Company’s crude oil marketing contracts are accounted for under the accrual method of accounting for all periods presented.

Oil and Gas Exploration and Production

On September 30, 2004, December 31, 2003 and September 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)

September 30, 2004
Crude oil swaps	330,000	1.25	$	--	$	--	$	4,991	$	806	$	(5,748	)	$	(49	)
Natural gas swaps	2,499,000	0.5		27		--		1,891		74		(1,938	)		--

			$	27	$	--	$	6,882	$	880	$	(7,686	)	$	(49	)

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	)

September 30, 2003
Crude oil swaps	270,000	1.5	$	--	$	--	$	676	$	96	$	(736	)	$	(36	)
Natural gas swaps	945,000	0.5		1,106		--		298		--		808			--

			$	1,106	$	--	$	974	$	96	$	72		$	(36	)

_________________

*crude in barrels, gas in MMBtu’s

Based on September 30, 2004 market prices, a $6.9 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 September 30, 2004 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

On September 30, 2004, December 31, 2003 and September 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)

September 30, 2004

Swaps on
project
financing	$	113,000	4.22	%	2	$	--	$	--	$	1,837	$	651	$	(2,488	)	$	--

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	)	$	--

September 30, 2003

Swaps on
project
financing	$	113,000	4.22	%	3	$	168	$	--	$	3,574	$	2,770	$	(6,176	)	$	--
Swaps on
corporate debt		25,000	5.28	%	0.5		--		--		432		--		(430	)		(2	)

Total	$	138,000				$	168	$	--	$	4,006	$	2,770	$	(6,606	)	$	(2	)

Based on September 30, 2004 market interest rates and balances, approximately $1.8 million will be realized as additional interest expense during the next twelve months. Estimated and realized amounts will likely change during the next twelve months as market interest rates change.

(16)	LEGAL PROCEEDINGS

On August 13, 2004, the former shareholders of Indeck Capital, Inc. (Indeck) commenced litigation against the Company in United States District Court, Northeastern District of Illinois, Eastern Division. The lawsuit concerns the Company’s performance of its obligation under the “Earn-out” provisions of the Agreement and Plan of Merger dated July 7, 2000, related to the Company’s acquisition of Indeck. Under the “Earn-out” provisions, the former shareholders of Indeck were entitled to receive “contingent merger consideration” for a four year period beginning in 2000. The “contingent merger consideration” was not to exceed $35.0 million and was based on the acquired company’s earnings over the four year period. As of September 30, 2004, $11.3 million has been either paid or offered for payment under the “Earn-out” provisions.

The lawsuit alleges that the Company failed to meet its obligation to produce documentation for its calculation of the contingent merger consideration, and in addition, failed to issue stock compensation in the full amount due to them. The Company denies these allegations and believes that it has fully and in good faith performed all of its obligations under the Agreement and Plan of Merger. The outcome of this matter is uncertain, as is the amount of contingent merger consideration that could be awarded following arbitration or litigation.

In addition, 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. Other than noted above, there have been no material developments in these proceedings or any new material proceedings that have developed during the first nine months of 2004.

(17)	GAIN ON SALE OF ASSETS

On March 1, 2004, the Company’s subsidiary, Daksoft, Inc., sold assets used in its campground reservation system. The Company recorded a pre-tax gain on the sale of the assets of $1.0 million, which is included as an offset to Operating expenses, Administrative and general on the Condensed Consolidated Statement of Income for the nine month period ended September 30, 2004. Prior to this sale, for segment reporting (see Note 14) 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.

(18)	CONTRACT TERMINATION REVENUE

During the third quarter of 2003, the Company completed a transaction terminating a fifteen year contract with Allegheny Energy Supply Company, LLC, a subsidiary of Allegheny Energy, Inc., for capacity and energy at the Company’s Las Vegas Cogeneration II power plant. The Company received a cash payment of $114.0 million, which is recorded as “Contract termination revenue” in the accompanying 2003 Condensed Consolidated Statements of Income. Operating results from the Las Vegas II Cogeneration power plant are included in the Power Generation segment.

(19)	IMPAIRMENT OF LONG-LIVED ASSETS

As a result of the contract termination discussed in Note 18, the Company assessed the recoverability of the carrying value of the Las Vegas Cogeneration II facility. The carrying value of the assets tested for impairment was $237.2 million. This assessment resulted in an impairment charge of $117.2 million to write down the related Property, plant and equipment by $83.1 million, net of accumulated depreciation of $5.1 million, and intangible assets by $34.1 million, net of accumulated amortization of $1.1 million. This charge reflects the amount by which the carrying value of the facility exceeded its estimated fair value determined by its estimated future discounted cash flows. This charge was recorded during the third quarter of 2003 and is included as a component of “Operating expenses” on the accompanying 2003 Condensed Consolidated Statements of Income. Operating results from the Las Vegas II Cogeneration power plant are included in the Power Generation segment.

(20)	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):

	Nine Months Ended September 30 2003

Operating revenues	$	994,489
Income from continuing operations	$	46,429
Net income available for common	$	52,662
Earnings per share--
Basic:
Continuing operations	$	1.52
Total	$	1.73
Diluted:
Continuing operations	$	1.50
Total	$	1.71

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.

(21)	PENDING ACQUISITION

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 has received certain state and federal regulatory approvals and remains subject to further federal approval, is expected to close on or prior to December 31, 2004.

(22)	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 “(Loss) 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 September 30						Nine Months Ended September 30
	2004			2003			2004			2003
Pre-tax (loss) income
from discontinued
operations	$	--		$	(39	)	$	(40	)	$	639
Pre-tax gain (loss) on disposal		(21	)		--			3,208			--
Income tax (expense) benefit		7			7			(1,120	)		(247	)

Net income (loss) from
discontinued operations	$	(14	)	$	(32	)	$	2,048		$	392

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

	December 31 2003			September 30 2003

Current assets	$	31		$	833
Property, plant and equipment		151			152
Investments		500			500
Non-current assets		--			44
Other current liabilities		(118	)		(383	)
Deferred reclamation		(2,858	)		(3,061	)
Other non-current liabilities		(1	)		(1	)

Net liabilities of discontinued operations	$	(2,295	)	$	(1,916	)

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 and management continues to actively market the plant for sale. 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. For business segment reporting purposes, the Pepperell plant results were previously included in the Power Generation segment.

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

	Three Months Ended September 30						Nine Months Ended September 30
	2004			2003			2004			2003
Operating revenues	$	10		$	264		$	10		$	2,131

Pre-tax loss from
discontinued
operations	$	(248	)	$	(437	)	$	(717	)	$	(1,016	)
Pre-tax loss on
disposal		--			(3,464	)		--			(3,464	)
Income tax benefit		94			3,033			256			3,243

Net loss from
discontinued
operations	$	(154	)	$	(868	)	$	(461	)	$	(1,237	)

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

	September 30 2004			December 31 2003			September 30 2003

Current assets	$	107		$	249		$	336
Property, plant and equipment		1,064			1,064			1,064
Non-current deferred tax asset		2,580			2,580			3,268
Other current liabilities		(130	)		(86	)		(348	)
Non-current liabilities		(459	)		(381	)		(7	)

Net assets of discontinued operations	$	3,162		$	3,426		$	4,313

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 September 30 2003			Nine Months Ended September 30 2003

Operating revenues	$	4,979		$	21,800

Pre-tax income from discontinued operations	$	1,463		$	8,041
Pre-tax gain on disposal		13,873			13,873
Income tax expense		(9,665	)		(11,984	)

Net income from discontinued operations	$	5,671		$	9,930

(23)	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).

(24)	SUBSEQUENT EVENT

On October 21, 2004, the Company effected a call on its Series AB, $45 million 8.3 percent First Mortgage Bonds issued by Black Hills Power, Inc. The bonds had a maturity date of 2024.

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 Retail services group	Power generation Oil and gas Coal mining Energy marketing 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 September 30						Nine Months Ended September 30
	2004			2003			2004			2003
Revenues
Wholesale energy		80	%		86	%		81	%		84	%
Electric utility		17			11			15			13
Communications		3			3			4			3

		100	%		100	%		100	%		100	%

Income/ (Loss) from
Continuing Operations
Wholesale energy		76	%		76	%		80	%		76	%
Electric utility		34			38			34			39
Communications		(7	)		(6	)		(9	)		(7	)
Corporate		(3	)		(8	)		(5	)		(8	)

		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 September 30, 2004 Compared to Three Months Ended September 30, 2003. Consolidated income from continuing operations for the three-month period ended September 30, 2004 was $17.3 million or $0.53 per share compared to $17.7 million or $0.54 per share in the same period of the prior year.

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

•

a $0.7 million or $0.02 per share decrease in energy marketing earnings, primarily due to a $2.1 million impact from unrealized mark-to-market adjustments, partially offset by increased realized gas marketing margins and increased earnings from crude oil pipelines; and

•

a $0.9 million or $0.03 per share decrease in electric utility earnings, primarily due to lower firm system sales resulting from a 37 percent decrease in degree days, increases in purchased power expense, increased costs associated with off-system sales, higher health insurance expense and allocated corporate costs, partially offset by an increase in off-system electric sales and a decrease in fuel expense;

offset by:

•

a $1.1 million or $0.03 per share decrease in corporate losses due to higher allocation of corporate costs to the business segments in 2004.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Consolidated income from continuing operations for the nine-month period ended September 30, 2004 was $36.9 million or $1.12 per share compared to $46.9 million or $1.54 per share in the same period of the prior year.

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

•

a $9.3 million or $0.28 per share decrease in power generation earnings, primarily related to:

•

a decrease in earnings from the Las Vegas II facility, primarily related to lower revenues from the termination of the Allegheny contract and replacement with a new long-term tolling agreement at lower rates, with Nevada Power Company, that was effective April 1, 2004 and limited spot market sales in the first quarter of 2004;

•

a $5.9 million or $0.18 per share decrease in earnings of unconsolidated subsidiaries, due to lower earnings and unrealized mark-to-market adjustments at certain power fund investments; and

•

lower earnings at the Harbor facility due to the expiration of a 2003 summer peaking agreement,

partially offset by:

•

a full nine months of earnings from the Wygen Plant that went into service in February 2003, partially offset by increased depreciation expense related to the December 31, 2003 consolidation of the Wygen plant;

•

a $1.0 million, or $0.03 per share, after-tax benefit from construction related litigation settlements;

•

a $1.9 million, or $0.06 per share, after-tax negative impact to 2003 earnings for the contract termination and asset impairment on the Las Vegas II power plant, partially offset by a $0.4 million after-tax benefit for a settlement with Enron; and

•

a $5.5 million or $0.17 per share decrease in electric utility earnings, primarily due to lower firm system sales resulting from a 12 percent decrease in degree days, increases in purchased power expense, maintenance expense, costs associated with off-system sales, higher health insurance expense and allocated corporate costs, partially offset by increased off-system electric sales and a decrease in fuel expense;

offset by:

•

a $2.2 million or $0.07 per share increase in energy marketing earnings, primarily due to higher earnings at our crude oil pipelines and higher margins received at our crude oil marketing operations. Earnings at our gas marketing operations were flat as a result of negative impacts from unrealized mark-to-market losses, increased payroll, incentive compensation and bank fees were offset by higher realized gas trading margins and the impact of a $3.0 million CFTC settlement on 2003 results;

•

a $0.9 million, or $0.03 per share increase in coal mining earnings, primarily due to a benefit from an income tax reserve adjustment, decreased production expense, administrative and interest expenses, partially offset by lower revenues and increased depreciation expense; and

•

a $1.7 million, or $0.05 per share decrease in corporate losses due to higher allocation of corporate costs to the business segments in 2004.

Net income for the nine months ended September 30, 2003, included a charge of $2.7 million or ($0.09) per share for change in accounting principles. The change in accounting principles reflects 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 nine months of 2004 were also affected by an increase of 2.4 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 September 30				Nine Months Ended September 30
	2004		2003		2004			2003
	(in thousands)
Revenue:
Energy marketing*	$	159,694	$	168,908	$	495,024		$	523,597
Power generation**		42,980		164,577		118,472			250,173
Oil and gas***		13,666		12,513		41,036			34,314
Mining		7,032		9,177		23,303			25,506

Total revenue		223,372		355,175		677,835			833,590
Equity in earnings (losses) of
unconsolidated subsidiaries		285		894		(723	)		5,758
Operating expenses**		197,614		327,703		614,022			759,826

Operating income	$	26,043	$	28,366	$	63,090		$	79,522

Income from continuing operations	$	13,164	$	13,419	$	29,455		$	35,680

_________________

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.

Power generation revenue in 2003 includes $114 million of contract termination revenue (see Note 18) and 2003 operating expenses include $117.2 million of impairment of long-lived assets (see Note 19).

***

Includes $(0.5) million revenue accrual correction for the nine month period ended September 30, 2004.

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

Energy Marketing

	Three Months Ended September 30				Nine Months Ended September 30
	2004		2003		2004		2003
	(in thousands)
Revenue*	$	159,694	$	168,908	$	495,024	$	523,597
Operating income		1,584		2,243		10,476		8,166
Income from continuing operations		670		1,324		6,245		4,079

_________________

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

	Three Months Ended September 30				Nine Months Ended September 30
	2004		2003		2004		2003
Natural gas - MMBtus		1,749,300		1,205,900		1,635,200		1,181,800
Crude oil - barrels		41,000		59,500		47,400		60,000

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. The decrease in revenues is a result of a 31 percent decrease in crude oil volumes marketed, partially offset by a 37 percent increase in the average price per barrel marketed. Revenue decreases from crude oil marketing were offset by a similar decrease in the cost of crude oil sold.

Income from continuing operations decreased $0.7 million primarily due to decreased earnings at our gas marketing company as a result of increased compensation expense and a $1.9 million unrealized mark-to-market loss for 2004, compared to a $0.2 million unrealized gain in 2003 (see Note 15 and Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-Q, for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our gas marketing operations). This was partially offset by increased realized gas trading margins resulting from a 45 percent increase in gas volumes marketed and increased earnings at our crude oil pipelines.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. The decrease in revenues is a result of a 21 percent decrease in crude oil volumes marketed, partially offset by a 19 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.

The segment’s income from continuing operations increased $2.2 million compared to 2003 primarily due to higher earnings at our crude oil pipelines and higher margins received at our crude oil marketing operations. Income from continuing operations at our gas marketing operations was flat as a $2.1 million unrealized mark-to-market loss for 2004 compared to a $3.1 million unrealized gain in 2003, resulted in a year-over-year pre-tax decrease of $5.2 million in unrealized mark-to-market adjustments at our gas marketing operations (see Note 15 and Item 3. “Quantitative and Qualitative Disclosures About Market Risk” of this Form 10-Q, for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our gas marketing operations). The impacts of unrealized mark-to-market adjustments and increased payroll, incentive compensation and increased bank fees due to higher outstanding letters of credit related to increased inventory levels were offset by higher realized gas trading margins from a 38 percent increase in gas volumes marketed in 2004 and the impact of a $3.0 million CFTC settlement impacting 2003 results.

Power Generation

	Three Months Ended September 30				Nine Months Ended September 30
	2004		2003		2004			2003
	(in thousands)
Revenue*	$	42,980	$	164,577	$	118,472		$	250,173
Equity in (losses) earnings of
unconsolidated subsidiaries		378		894		(560	)		5,374
Operating income		17,729		19,485		35,164			55,438
Income from continuing
operations		7,192		7,056		10,347			19,634

_________________

* 2003 revenue includes $114 million of contract termination revenue (see Note 18).

	September 30
	2004		2003
Independent power capacity:
MWs of independent power capacity in service^(a)		1,004		1,002

_________________

^(a) Capacity in service includes 40 MW in 2004 and 2003, which are currently reported as “Discontinued operations.”

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenue for the three months ended September 30, 2003, includes $114.0 million of contract termination revenue related to the Las Vegas II Cogeneration power plant. Excluding the contract termination revenue, revenue decreased 15 percent in 2004 compared to 2003 primarily as a result of lower revenues from our Las Vegas and Harbor facilities and lower megawatt-hours being dispatched from our Gillette gas turbine. Revenues from our Las Vegas II power plant were $4.0 million lower than the prior year primarily 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 at lower rates. The new contract was entered into with Nevada Power Company and became effective April 1, 2004. Capacity revenues decreased at our Harbor facility due to the expiration of a 2003 summer peaking agreement and lower merchant sales in 2004 compared to 2003. 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 $120.4 million, primarily the result of 2003 operating expense including a $117.2 million impairment charge for the Las Vegas II power plant, the result of the termination of the Allegheny power sales contract on the Las Vegas II power plant. Excluding the impairment charge, operating expenses decreased $3.2 million, or 11 percent, primarily due to lower fuel costs from reduced dispatch at our non-tolled power plants.

Income from continuing operations increased $0.1 million. Earnings results for 2004 were impacted by reduced plant revenues partially offset by lower interest expense from debt reduction from the proceeds of an asset sale and contract termination. In addition, earnings results for 2003 were negatively impacted by a $1.9 million after-tax charge for the contract termination and the asset impairment charge on the Las Vegas II power plant, partially offset by a $0.4 million after-tax benefit from a settlement with Enron.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenue for the nine months ended September 30, 2003, includes $114.0 million of contract termination revenue related to the Las Vegas II power plant. Excluding the contract termination revenue, revenue decreased 13 percent in 2004 compared to 2003 primarily due to lower revenues from our Las Vegas and Harbor facilities. Revenues from our Las Vegas II plant were $14.3 million lower than the prior year primarily 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 at lower rates. 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 Harbor facility due to lower merchant sales and lower capacity revenue due to the expiration of a 2003 summer peaking agreement.

Equity in earnings of unconsolidated subsidiaries decreased $5.9 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.

Operating expenses decreased $117.4 million. 2003 operating expense includes a $117.2 million impairment charge for the Las Vegas II power plant, the result of the termination of the power sales contract on the Las Vegas II power plant. Excluding the impairment charge, operating expenses decreased $0.2 million due to lower maintenance expense, offset by higher fuel costs and depreciation expense.

Income from continuing operations decreased $9.3 million. Earnings results for 2004 were impacted by reduced plant revenues, lower earnings from power fund investments, higher fuel costs and higher depreciation expense, partially offset by lower maintenance expense, lower interest expense from debt reduction from the proceeds of an asset sale and contract termination, and a $1.0 million after-tax benefit from litigation settlements. In addition, 2003 earnings results were negatively impacted by a $1.9 million after-tax charge for the contract termination and the asset impairment on the Las Vegas II plant, partially offset by a $0.4 million after-tax benefit from a settlement with Enron.

Oil and Gas

	Three Months Ended September 30					Nine Months Ended September 30
	2004			2003		2004			2003
	(in thousands)
Revenue	$	13,666		$	12,513	$	41,036	*	$	34,314
Equity in (losses) earnings of
unconsolidated subsidiaries		(93	)		--		(163	)		384
Operating income		4,325			4,129		11,513			10,960
Income from continuing operations		2,765			2,805		7,215			7,245

_________________

Includes $(0.5) million revenue accrual correction for the nine month period ended September 30, 2004.

The following is a summary of oil and natural gas production:

	Three Months Ended September 30				Nine Months Ended September 30
	2004		2003		2004		2003
Fuel production:
Barrels of oil sold		99,149		109,486		333,260		317,234
Mcf of natural gas sold		2,517,581		2,495,341		7,132,472		5,801,590
Mcf equivalent sales		3,112,475		3,152,257		9,132,032		7,704,994

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenue from our oil and gas segment increased $1.2 million for the three-month period ended September 30, 2004, compared to the same period in 2003. The increase is due to higher gas and oil prices received. Average gas and oil prices received, net of hedging activity, in 2004 were $4.43/Mcf and $27.32/bbl, respectively, compared to $3.39/Mcf and $23.48/bbl in 2003. Lease operating expenses per Mcfe sold (LOE/MCFE) were 28 percent higher than 2003.

Income from continuing operations was flat compared to 2003. Earnings results for 2004 were affected by increased revenues from higher prices received offset by a 10 percent increase in operating expenses related to higher depletion costs and lease operating expenses.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenues from our oil and gas segment increased $6.7 million for the nine month period ended September 30, 2004, compared to the same period in 2003. The increase in revenues is due to a 19 percent increase in volumes sold and higher gas prices received. The increase in volumes sold reflects a full nine months of production at the Mallon properties acquired in March 2003. Average gas and oil prices received, net of hedging activity, in 2004 were $4.23/Mcf and $25.13/bbl, respectively, compared to $3.94/Mcf and $25.15/bbl in 2003.

Income from continuing operations was flat when compared to the same period in 2003. Earnings results were affected by higher prices and volumes sold, offset by a 24 percent, or approximately $5.6 million, increase in total operating expenses related to additional operations acquired in the Mallon transaction and higher depletion and lease operating expenses. In addition, 2004 LOE/MCFE was 8 percent higher than 2003.

The following is a summary of our internally estimated economically recoverable oil and gas reserves. These estimates are measured using constant product prices of $47.66 per barrel of oil and $5.17 per Mcf of natural gas as of September 30, 2004, and $30.30 per barrel of oil and $4.69 per Mcf of natural gas as of September 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.

	September 30
	2004		2003
Barrels of oil (in thousands)		5,692		4,938
Mmcf of natural gas		125,625		110,423
Total in Mmcf equivalents		159,777		140,051

Coal Mining

	Three Months Ended September 30				Nine Months Ended September 30
	2004		2003		2004		2003
	(in thousands)
Revenue	$	7,032	$	9,177	$	23,303	$	25,506
Operating income		2,405		2,509		5,937		4,958
Income from continuing operations		2,537		2,234		5,648		4,722
The following is a summary of coal sales volumes:
Tons of coal sold		1,235,400		1,292,100		3,510,100		3,562,400

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenue from our mining segment decreased 23 percent for the three-month period ended September 30, 2004, compared to the same period in 2003. In September 2004, the Company reached a tax settlement with the Wyoming Department of Revenue which resulted in an adjustment to coal billings for the period of fourth quarter 2001 through the year 2003. The Company recorded a $1.7 million reduction in revenues and a corresponding reduction in mineral taxes. The Company also recorded an additional $0.4 million decrease to mineral taxes and $0.5 million decrease to interest expense related to the settlement. Revenues were also impacted by a 4 percent decrease in tons of coal sold, primarily due to a reduction in train load-out sales.

Operating expenses increased 2 percent, exclusive of the recording of the tax settlement, primarily due to an increase in depreciation expense, partially offset by lower overburden rates.

Income from continuing operations increased $0.3 million primarily due to a $0.4 million benefit from an income tax reserve adjustment, a $0.6 million after-tax benefit from the Wyoming tax settlement, and lower overburden expense, partially offset by increased depreciation and a decrease in tons of coal sold.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenue for the nine-month period ended September 30, 2004 decreased 9 percent compared to the same period in 2003. In September 2004, the Company reached a tax settlement with the Wyoming Department of Revenue, which resulted in an adjustment to coal billings for the period of fourth quarter 2001 through the year 2003. The Company recorded a $1.7 million reduction in revenues and a corresponding reduction in mineral taxes. The Company also recorded an additional $0.4 million decrease to mineral taxes and $0.5 million decrease to interest expense related to the settlement. Revenues were also impacted by a 1 percent decrease in tons of coal sold. The decrease in tons of coal sold is primarily attributable to scheduled electric plant maintenance outages and an unscheduled outage at the Wyodak plant.

Operating expenses decreased 5 percent, exclusive of the recording of the tax settlement, primarily due to lower mining costs related to the decrease in production, lower overburden rates, lower corporate allocations and lower compensation expense, offset by increased depreciation expense.

Income from continuing operations increased $0.9 million primarily due to a $0.4 million benefit from an income tax reserve adjustment, a $0.6 million after-tax benefit from the Wyoming tax settlement, lower production costs and general and administrative costs, partially offset by lower revenues, lower interest income and increased depreciation expense.

Retail Services Group

Electric Utility

	Three Months Ended September 30				Nine Months Ended September 30
	2004		2003		2004		2003
	(in thousands)
Revenue	$	47,921	$	46,268	$	129,377	$	129,238
Operating expenses		35,415		31,773		98,902		90,493

Operating income	$	12,506	$	14,495	$	30,475	$	38,745

Income from continuing operations	$	5,860	$	6,772	$	12,712	$	18,193

The following table provides certain operating statistics:

	Three Months Ended September 30				Nine Months Ended September 30
	2004		2003		2004		2003

Firm (system) sales - MWh		511,800		545,300		1,476,000		1,498,100
Off-system sales - MWh		335,500		204,700		797,400		684,500

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Electric utility revenues increased 4 percent for the three-month period ended September 30, 2004, compared to the same period in the prior year. The increase in revenue was primarily due to a 64 percent increase in off-system electric megawatt-hour sales offset by an 11 percent decrease in average prices received from off-system sales. Firm commercial and residential electricity revenues decreased 5 percent and 12 percent, respectively, and industrial revenues increased 1 percent. Degree days, which is a measure of weather trends, were 37 percent below last year.

Electric operating expenses increased 11 percent for the three-month period ended September 30, 2004, compared to the same period in the prior year. Purchased power increased $4.3 million due to a 51 percent increase in megawatt-hours purchased, at a 5 percent decrease in the average cost per megawatt-hour. Megawatt-hours purchased increased due to uneconomic dispatch of our gas turbines and to support the increase in off-system sales. Gas costs decreased 55 percent due to a 64 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 $67.03 for the three months ended September 30, 2004, while the average cost for purchased power was $35.25 per megawatt-hour for the same period. The decrease in fuel expense was offset by increased power marketing costs, increased health insurance costs and an increase in allocated corporate costs.

Income from continuing operations decreased $0.9 million primarily due to increases in purchased power expense, costs associated with the increase in off-system sales, health insurance expense and allocated corporate costs, partially offset by an increase in off-system electric sales and the decrease in gas costs.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Electric utility revenues were flat for the nine-month period ended September 30, 2004, compared to the same period in the prior year. Off-system electric megawatt-hour sales increased 16 percent at a 5 percent decrease in average prices received. Revenues were impacted in part by reduced Open Access Transmission Tariff rates and plant availability resulting from unscheduled and scheduled maintenance outages during the nine month period ended September 30, 2004. The increase in revenue from off-system sales was partially offset by decreased retail sales. Residential and commercial revenues decreased 3 percent and 2 percent, respectively, and industrial revenues increased 3 percent. Degree days, which is a measure of weather trends, were 12 percent below last year.

Electric operating expenses increased 9 percent for the nine-month period ended September 30, 2004, compared to the same period in the prior year. Purchased power increased $9.2 million due to a 38 percent increase in megawatt-hours purchased. Megawatt-hours purchased increased primarily due to a 16 percent increase in off-system megawatt-hour sales and the uneconomic dispatch of our gas turbines. Gas costs decreased 70 percent due to an 83 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 $76.33 for the nine months ended September 30, 2004, while the average cost for purchased power was $33.38 per megawatt-hour for the same period. The decrease in fuel expense was offset by increased plant maintenance costs, power marketing costs, health insurance costs and allocated corporate costs.

Income from continuing operations decreased $5.5 million primarily due to increases in purchased power expense, maintenance expense, costs associated with the increase in off-system sales, health insurance expense and allocated corporate costs, partially offset by an increase in off-system electric sales and the decrease in gas costs.

Communications

	Three Months Ended September 30						Nine Months Ended September 30
	2004			2003			2004			2003
	(in thousands)
Revenue	$	9,455		$	10,136		$	29,329		$	30,595
Operating expenses		10,449			10,810			31,458			32,797

Operating loss	$	(994	)	$	(674	)	$	(2,129	)	$	(2,202	)

Loss from continuing operations
and net loss	$	(1,256	)	$	(1,031	)	$	(3,209	)	$	(3,273	)




Business customers	3,311	3,012	2,841
Business access lines	12,949	12,023	11,518
Residential customers	23,557	23,878	23,900

Three Months Ended September 30, 2004 Compared to Three Months Ended September 30, 2003. Revenues from our communications group decreased $0.7 million compared to the same period in 2003. The decrease was due to the results of operations of our information technology support subsidiary, Daksoft, Inc., being included in 2003 results. Beginning in the first quarter of 2004, Daksoft’s focus became corporate information technology support and therefore its results are included as “corporate” costs. Daksoft’s results had an insignificant impact on net earnings. Excluding Daksoft’s results, revenues were flat for the communications group as increased business customer revenues were offset by a decrease in residential customer revenues and revenues from system access billings.

Loss from continuing operations increased $0.2 million compared to the same period in 2003. Earnings results for 2003 benefited from a reduction in property tax accruals.

Nine Months Ended September 30, 2004 Compared to Nine Months Ended September 30, 2003. Revenue from our communications group decreased $1.3 million compared to the same period in 2003. This was due to the results of operations of our information technology support subsidiary, Daksoft, Inc., being included in 2003 results. Beginning in the first quarter of 2004, Daksoft’s focus became corporate information technology support and therefore its results are included in “corporate” costs. Daksoft’s results had an insignificant impact on net earnings. Excluding Daksoft’s results, revenue increased $0.3 million as increased business customer revenues were partially offset by a decrease in revenues from system access billings and residential customer revenues. Revenues for the nine month period ended September 30, 2004, were approximately $1.3 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, offset by revenues from additional services sold to existing customers.

Loss from continuing operations decreased $0.1 million compared to the same period in 2003. In addition to the revenue impacts, earnings were also impacted by an increase in allocated corporate costs.

Earnings Guidance

Our current guidance extends through 2005 with an estimate of 2004 income from continuing operations to be between $1.70 and $1.85 per share and 2005 estimated to be $1.85 to $2.00 per share.

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 nine-month period ended September 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 $148.0 million for the nine-month period ended September 30, 2004 compared to the same period in the prior year. The decrease is primarily due to the third quarter 2003 receipt of $114.0 million from Allegheny Energy Supply Company, LLC for the termination of a fifteen-year contract for capacity and energy at our Las Vegas II power plant, as well as decreased earnings, purchases of gas inventory held by our energy marketing operations and changes in other working capital.

During the nine months ended September 30, 2004, we had cash outflows from investing activities of $62.4 million, which was primarily related to property, plant and equipment additions in the normal course of business.

During the nine months ended September 30, 2004, we had cash outflows from financing activities of $114.9 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. On August 31, 2004, we called $5.9 million of Pollution Control Revenue Bonds, having a maturity date of 2010.

Dividends

Dividends paid on our common stock were $0.31 per share in each of the first, second and third quarters of 2004. As approved by our board of directors in January 2004, this reflects a 3.3 percent increase 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 our revolving credit facilities and cash provided by operations. Our liquidity position remained strong during the first nine months of 2004. As of September 30, 2004, we had approximately $79.9 million of cash unrestricted for operations and $350 million of credit through revolving bank facilities. Approximately $10.0 million of the cash balance at September 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 September 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 $305.5 million at September 30, 2004.

Additional short-term liquidity is currently expected to be provided from the proceeds of forward sales of gas inventory held by our Energy Marketing segment. At September 30, 2004, the segment had $99.4 million of oil and gas inventory, substantially all of which was economically hedged at the time of purchase through either forward physical sales or forward financial sales. Sales for a substantial majority of this inventory have been made through transactions which are scheduled to settle in the fourth quarter of 2004 and the first quarter of 2005.

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

Our consolidated net worth was $721.0 million at September 30, 2004, which was approximately $156.6 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 September 30, 2004 was 48.5 percent, our total debt leverage (long-term debt and short-term debt) was 52.5 percent, and our recourse leverage ratio was approximately 47.7 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 September 30, 2004, we had a $3.0 million guarantee to the lender under this facility. This facility was recently increased from $135 million. At September 30, 2004, there were outstanding letters of credit issued under the facility of $85.3 million, with no borrowing balances outstanding on the facility. On September 30, 2004, the facility was renewed for a one year period expiring September 30, 2005.

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 September 30, 2004, BHER had letters of credit outstanding of $7.3 million.

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

In September 2004, the Company initiated a call notice, effective October 21, 2004, to call the entire $45 million Series AB 8.3 percent First Mortgage Bonds of Black Hills Power, Inc. The utility bonds have a maturity date of 2024.

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.

•

$5.9 million of the 6.7 percent Pollution Control Revenue Bonds due in 2010. We called the bonds in August 2004.

•

$45 million of the Series AB 8.3 percent First Mortgage Bonds due 2024. In September, we initiated a call notice to call the bonds effective October 21, 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 September 30, 2004, we had guarantees totaling $186.2 million in place.

Capital Requirements

During the nine months ended September 30, 2004, capital expenditures were approximately $65.6 million. Due to the lack of capital deployment opportunities, in July 2004 we 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 an Application-Declaration on Form U-1 with the Securities and Exchange Commission (SEC) 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). On November 1, 2004, we filed an amendment to the Application-Declaration, and the SEC issued a public notice of such filing establishing a public notice and comment period expiring November 24, 2004.

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 nine months ended September 30, 2004 (in thousands):




Total fair value of natural gas marketing contract net liability at December 31, 2003	$	(408	)
Net cash settled during the nine-month period on contracts that existed at
December 31, 2003		(2,355	)
Change in fair value due to change in techniques and assumptions		--
Unrealized gain (loss) on new contracts entered during the nine-month period and
still existing at September 30, 2004		(4,079	)
Realized gain (loss) on contracts that existed at December 31, 2003 and were settled
during the nine-month period ended September 30, 2004		(2,717	)
Unrealized gain (loss) on contracts that existed at December 31, 2003 and still exist
at September 30, 2004		(2,470	)

Total fair value of natural gas marketing contract net assets at September 30, 2004	$	(12,029	)

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 September 30, 2004, we had a mark to fair value unrealized loss of $12.0 million for our derivative contracts related to our natural gas marketing activities, with $12.3 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	$	1,181		$	--	$	1,181
Prices provided by other external sources		(13,507	)		297		(13,210	)
Modeled		--			--		--

Total	$	(12,326	)	$	297	$	(12,029	)

The following table (in thousands) 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)	$	(12,029	)
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		17,491

Fair value of all forward positions (Non-GAAP)	$	5,462

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 September 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 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Period			(b) Average Price Paid per Share


July 1, 2004 -
July 31, 2004	--		$	--	--	--
August 1, 2004 -
August 31, 2004	4,738	⁽¹⁾	$	27.40	--	--
September 1, 2004 -
September 30, 2004	306	⁽²⁾	$	28.42	--	--

Total	5,044		$	27.46	--	--

_________________

(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 6.

Exhibits

Exhibit 10.1*

10.1* Form of Stock Option Agreement (filed as Exhibit 10.1 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.2*

Form of Restricted Stock Award Agreement (filed as Exhibit 10.2 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.3*

Form of Restricted Stock Unit Award Agreement (filed as Exhibit 10.3 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.4*

Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.5*

Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.6*

Amended and Restated Credit Agreement dated as of May 14, 2004 among Enserco Energy Inc., as Borrower, and Fortis Capital Corp., as administrative agent, collateral agent, documentation agent and arranger, and BNP Paribas, and U.S. Bank National Association and Societe Generale, and each other financial institution which may become a party hereto (filed as Exhibit 10.1 to the Registrant's Form 8-K for September 30, 2004).

Exhibit 10.7*

First Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2004, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale (filed as Exhibit 10.2 to the Registrant's Form 8-K for September 30, 2004).

Exhibit 31.1

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

Exhibit 31.2

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

Exhibit 32.1

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

Exhibit 32.2

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

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

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: November 9, 2004

EXHIBIT INDEX

Exhibit
Number Description

Exhibit 10.1*

10.1* Form of Stock Option Agreement (filed as Exhibit 10.1 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.2*

Form of Restricted Stock Award Agreement (filed as Exhibit 10.2 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.3*

Form of Restricted Stock Unit Award Agreement (filed as Exhibit 10.3 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.4*

Form of Performance Share Award Agreement (filed as Exhibit 10.4 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.5*

Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant's Form 8-K for August 30, 2004).

Exhibit 10.6*

Exhibit 10.7*

Exhibit 31.1

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

Exhibit 31.2

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

Exhibit 32.1

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

Exhibit 32.2

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

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

Black Hills - 10-Q quarterly report FY

TABLE OF CONTENTS

Results of Operations

REGULATION

RISK FACTORS

NEW ACCOUNTING PRONOUNCEMENTS

SAFE HARBOR FOR FORWARD LOOKING INFORMATION

What is the market capitalization of a company?

DISCLAIMER

Contact

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