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, 2003.

___ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES ACT OF 1934

For the transition period from _______________ to _______________.

Commission File Number 001-31303

Black Hills Corporation
Incorporated in South Dakota IRS Identification Number 46-0458824

625 Ninth Street
Rapid City, South Dakota 57701

Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report

NONE

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X No___

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

Yes X No___

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

Class Outstanding at October 31, 2003

Common stock, $1.00 par value 32,162,292 shares

TABLE OF CONTENTS


PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements
Condensed Consolidated Statements of Income -
Three and Nine Months Ended September 30, 2003 and 2002	3
Condensed Consolidated Balance Sheets -
September 30, 2003, December 31, 2002 and September 30, 2002	4
Condensed Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2003 and 2002	5
Notes to Condensed Consolidated Financial Statements	6-	34
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	35-	58
Item 3. Quantitative and Qualitative Disclosures about Market Risk	58-	59
Item 4. Controls and Procedures	59
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	60
Item 6. Exhibits and Reports on Form 8-K	60-	61
Signatures	62
Exhibit Index	63

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2003			2002			2003			2002
	(in thousands, except per share amounts)
Operating revenues	$	296,862		$	239,786		$	877,550		$	653,330
Contract termination revenue		114,000			--			114,000			--

		410,862			239,786			991,550			653,330

Operating expenses:
Fuel and purchased power		184,591			152,682			555,296			409,635
Operations and maintenance		25,891			17,201			76,664			51,159
Administrative and general		17,465			14,641			56,307			43,962
Depreciation, depletion and amortization		20,185			16,240			59,263			47,604
Taxes, other than income taxes		6,519			5,587			22,052			16,604
Impairment of long-lived assets		117,207			--			117,207			--

		371,858			206,351			886,789			568,964

Equity in earnings (losses) of unconsolidated
subsidiaries		894			(719	)		5,758			2,561

Operating income		39,898			32,716			110,519			86,927

Other income (expense):
Interest expense		(13,749	)		(8,063	)		(39,313	)		(24,363	)
Interest income		138			356			467			1,559
Other expense		(3	)		(864	)		(262	)		(206	)
Other income		322			385			1,763			2,645

		(13,292	)		(8,186	)		(37,345	)		(20,365	)

Income from continuing operations before minority
interest, income taxes and change in accounting
principles		26,606			24,530			73,174			66,562
Minority interest		--			1,326			--			(542	)
Income taxes		(8,965	)		(9,041	)		(25,905	)		(22,286	)

Income from continuing operations before change in
accounting principles		17,641			16,815			47,269			43,734
Income from discontinued operations, net of taxes		4,803			634			8,693			692
Change in accounting principles, net of taxes		--			--			(2,680	)		896

Net income		22,444			17,449			53,282			45,322
Preferred stock dividends		(57	)		(56	)		(172	)		(168	)

Net income available for common stock	$	22,387		$	17,393		$	53,110		$	45,154

Weighted average common shares outstanding:
Basic		32,087			26,835			29,922			26,778

Diluted		32,754			27,078			30,457			27,052

Earnings per share:
Basic-
Continuing operations	$	0.55		$	0.63		$	1.57		$	1.63
Discontinued operations		0.15			0.02			0.29			0.03
Change in accounting principles		--			--			(0.09	)		0.03

Total	$	0.70		$	0.65		$	1.77		$	1.69

Diluted-
Continuing operations	$	0.54		$	0.62		$	1.55		$	1.62
Discontinued operations		0.15			0.02			0.29			0.03
Change in accounting principles		--			--			(0.09	)		0.03

Total	$	0.69		$	0.64		$	1.75		$	1.68

Dividends paid per share of common stock	$	0.30		$	0.29		$	0.90		$	0.87

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 2003			December 31 2002			September 30 2002
	(in thousands, except share amounts)

ASSETS
Current assets:
Cash and cash equivalents	$	269,784		$	75,045		$	69,519
Restricted cash		1,070			1,070			--
Receivables (net of allowance for doubtful accounts of $4,156;
$3,860 and $3,361, respectively)		199,544			206,149			154,074
Notes receivable		555			34,085			272
Materials, supplies and fuel		46,692			24,139			24,328
Derivative assets		23,781			36,393			44,244
Deferred income taxes		4,913			5,995			2,355
Other assets		6,068			7,311			21,747
Assets of discontinued operations		4,668			178,468			178,661

		557,075			568,655			495,200

Investments		24,774			18,707			19,920

Property, plant and equipment		1,742,973			1,703,372			1,642,868
Less accumulated depreciation and depletion		(423,715	)		(380,580	)		(366,033	)

		1,319,258			1,322,792			1,276,835

Other assets:
Derivative assets		552			2,406			2,244
Goodwill		24,112			23,913			19,851
Intangible assets (net of accumulated amortization of $17,592,
$15,535 and $7,573, respectively)		40,901			78,089			79,369
Other		25,462			20,583			19,675

		91,027			124,991			121,139

	$	1,992,134		$	2,035,145		$	1,913,094

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	203,730		$	206,832		$	141,499
Accrued income taxes		73,604			2,096			--
Accrued liabilities		74,848			51,034			47,478
Current maturities of long-term debt		18,075			15,324			17,306
Notes payable		11			340,500			383,521
Derivative liabilities		25,307			42,316			43,585
Liabilities of discontinued operations		355			106,954			109,111

		395,930			765,056			742,500

Long-term debt, net of current maturities		747,211			540,959			473,482

Deferred credits and other liabilities:
Deferred income taxes		87,156			132,257			104,855
Derivative liabilities		3,237			2,889			4,914
Other		59,956			58,821			42,294

		150,349			193,967			152,063

Minority interest in subsidiaries		--			--			10,222

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

Common stock equity-
Common stock $1 par value; 100,000,000 shares authorized;
Issued 32,293,220; 27,102,351 and 27,056,390 shares, respectively		32,293			27,102			27,056
Additional paid-in capital		375,185			246,997			245,734
Retained earnings		306,392			280,628			272,339
Treasury stock, at cost		(3,788	)		(3,921	)		(3,891	)
Accumulated other comprehensive loss		(16,987	)		(21,192	)		(11,960	)

		693,095			529,614			529,278

Total stockholders' equity		698,644			535,163			534,827

	$	1,992,134		$	2,035,145		$	1,913,094

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
	2003			2002
	(in thousands)
Operating activities:
Net income available for common	$	53,110		$	45,154
Adjustments to reconcile net income available for common to net
cash provided by operating activities:
Income from discontinued operations		(8,693	)		(692	)
Impairment of long-lived assets		117,207			--
Depreciation, depletion and amortization		59,263			47,604
Net change in derivative assets and liabilities		(4,853	)		(7,218	)
Deferred income taxes		(40,037	)		31,882
Undistributed earnings in associated companies		(5,758	)		(4,328	)
Change in accounting principles		2,680			(896	)
Change in operating assets and liabilities-
Accounts receivable and other current assets		(14,501	)		(49,132	)
Accounts payable and other current liabilities		75,298			47,026
Other operating activities		7,354			(3,340	)

		241,070			106,060

Investing activities:
Property, plant and equipment additions		(77,912	)		(175,252	)
Payment for acquisition of net assets, net of cash acquired		--			(23,229	)
Payment for acquisition of minority interests		(9,000	)		(3,617	)
Proceeds from sale of assets		185,926			--
Increase in notes receivable - Mallon Resources		(5,164	)		--
Other investing activities		(455	)		354

		93,395			(201,744	)

Financing activities:
Dividends paid		(27,346	)		(23,326	)
Common stock issued		121,206			5,445
Increase (decrease) in short-term borrowings, net		(340,489	)		23,521
Long-term debt - issuance		252,000			156,133
Long-term debt - repayments		(129,395	)		(23,561	)
Cash payments to settle interest rate swaps		(12,556	)		--
Other financing activities		(3,146	)		612

		(139,726	)		138,824

Increase in cash and cash equivalents		194,739			43,140
Cash and cash equivalents:
Beginning of period		75,045			26,379

End of period	$	269,784		$	69,519

Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest	$	47,219		$	31,240
Income taxes paid, net	$	6,549		$	754
Non-cash net assets acquired through issuance of common stock and
decrease in notes receivable - Mallon Resources	$	51,153		$	--

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

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's Annual Report on Form 10-K)

(1)	MANAGEMENT'S STATEMENT

The financial statements included herein have been prepared by Black Hills Corporation (the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in the Company's 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the September 30, 2003, December 31, 2002 and September 30, 2002, financial information and are of a normal recurring nature. The results of operations for the three months and nine months ended September 30, 2003, are not necessarily indicative of the results to be expected for the full year. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

(2)	STOCK BASED COMPENSATION

At September 30, 2003, 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						Nine Months Ended
	September 30						September 30
	2003			2002			2003			2002
Net income available for common stock,
as reported	$	22,387		$	17,393		$	53,110		$	45,154
Deduct: Total stock-based employee
compensation expense determined under
fair value based method for all awards,
net of related tax effects		(282	)		(231	)		(725	)		(766	)

Pro forma net income	$	22,105		$	17,162		$	52,385		$	44,388

Earnings per share:
As reported--
Basic
Continuing operations	$	0.55		$	0.63		$	1.57		$	1.63
Discontinued operations		0.15			0.02			0.29			0.03
Change in accounting principles		--			--			(0.09	)		0.03

Total	$	0.70		$	0.65		$	1.77		$	1.69

Diluted
Continuing operations	$	0.54		$	0.62		$	1.55		$	1.62
Discontinued operations		0.15			0.02			0.29			0.03
Change in accounting principles		--			--			(0.09	)		0.03

Total	$	0.69		$	0.64		$	1.75		$	1.68

Pro forma--
Basic
Continuing operations	$	0.54		$	0.62		$	1.55		$	1.60
Discontinued operations		0.15			0.02			0.29			0.03
Change in accounting principles		--			--			(0.09	)		0.03

Total	$	0.69		$	0.64		$	1.75		$	1.66

Diluted
Continuing operations	$	0.53		$	0.62		$	1.53		$	1.59
Discontinued operations		0.15			0.02			0.29			0.03
Change in accounting principles		--			--			(0.09	)		0.03

Total	$	0.68		$	0.64		$	1.73		$	1.65

(3)	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

SFAS 143

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

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

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

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

	Balance at 12/31/02			SFAS 143 Transition Adjustment			Liabilities Incurred			Liabilities Settled	Accretion		Cash Flow Revisions	Balance at 9/30/03

Oil and Gas	$	--		$	6,133		$	547	(b)	$--	$	356	$--	$	7,036
Mining		18,513	(a)		(3,214	)		--		--		600	--		15,899

Total	$	18,513		$	2,919		$	547		$--	$	956	$--	$	22,935

(a)

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

(b)

The Company incurred certain asset retirement obligations with its acquisition of Mallon Resources completed on March 10, 2003, as described in Note 18.

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

EITF 02-3

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

Upon adoption on January 1, 2003, the Company recorded a charge for a cumulative effect of an accounting change totaling approximately $2.9 million, net of tax. This cumulative effect of an accounting change was the result of certain energy contracts in our Energy Marketing segment, previously marked to fair value under EITF 98-10, being restated to reflect historical cost. The amount of the cumulative effect represents the unrealized gain or loss recorded on these contracts as of January 1, 2003. Gains and losses on these contracts are now recognized on the accrual basis of accounting. See Note 16 for further discussion of our accounting for contracts at our Energy Marketing segment subsequent to adoption of EITF 02-3.

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

(4)	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). The Company’s subsidiary, Black Hills Wyoming (f/k/a Black Hills Generation), has an agreement with Wygen Funding, Limited Partnership, an unrelated, unconsolidated special purpose entity (SPE) to lease the Wygen plant, a 90 megawatt coal-fired power plant. On October 9, 2003, the FASB issued FASB Staff Position (FSP) FIN 46-6, “Effective Date of FIN 46”(FSP FIN 46-6) which deferred the implementation date of FIN 46 until the end of the first interim or annual period ending after December 15, 2003, if the variable interest entity was created before February 1, 2003 and the public entity has not issued financial statements reporting that variable interest entity in accordance with FIN 46, other than in the disclosure required by paragraph 26 of FIN 46. Under the new accounting interpretation, the Company will consolidate the SPE effective December 31, 2003. The effect of consolidating the SPE into the Company’s consolidated financial statements is to record both the Wygen asset and its related debt on the Company’s Condensed Consolidated Balance Sheets which is estimated to be approximately $133 million. In addition, the net effect of consolidating the income statement of the SPE is to recognize the depreciation and interest expense of the SPE in place of recognizing lease expense which is estimated to have approximately a $3.5 million negative annual effect to pre-tax income based on a 40-year depreciable life. The Company is currently evaluating the cumulative effect on earnings of adopting FIN 46.

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS 150). SFAS 150 provides accounting and disclosure requirements for classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Management adopted SFAS 150 effective July 1, 2003. Adoption did not have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

During the second quarter of 2003, discussion between the Securities and Exchange Commission (SEC) and FASB staffs have raised concerns over the interaction of SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” (SFAS 19) and SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). The discussion focuses on whether or not pronouncements set forth by SFAS 142 requiring more clarity in distinguishing between tangible and intangible assets, required oil and gas producing companies to reclassify amounts related to mineral rights from tangible assets to intangible assets upon adoption of SFAS 142. When the Company adopted SFAS 142 on January 1, 2002, the amounts related to mineral rights were not reclassified to intangible assets and continue to be classified in “Property, plant and equipment” on the accompanying Condensed Consolidated Balance Sheets. The SEC staff has confirmed that further discussion is needed with the FASB staff and final guidance has not yet been provided. The Company is currently monitoring the related discussion between the SEC and FASB staff and is evaluating the impact the reclassification would have on the Company’s balance sheet. Any impact would be to the balance sheet and related disclosures only and will not have an effect on the Company’s cash flows or results of operations.

On June 25, 2003, the FASB Derivatives Implementation Group cleared Issue C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” (Issue C20). Issue C20 clarifies which contracts qualify for the “normal purchase or sale”exception as provided by paragraph 10(b) of SFAS 133. The Company adopted this guidance on October 1, 2003. The adoption of this guidance had no material impact on its results of operations and financial position.

On July 31, 2003, the EITF issued EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and not “held for trading purposes” as defined in Issue No. 02-3” (EITF 03-11). EITF 03-11 provides new guidance on determining whether realized gains or losses on certain derivative instruments that are not “held for trading purposes” as defined in EITF 02-3, should be shown in the income statement on a net or gross basis. The Company adopted EITF 02-3 on January 1, 2003, as discussed in Note 3. Upon adoption the Company began reporting realized gains and losses on all contracts at our crude oil marketing operations, which are not “held for trading purposes” as defined by EITF 02-3, on a gross basis. The Company is currently evaluating whether the new guidance will require reporting certain of these contracts at our crude oil marketing operations on a net basis and expects to adopt the provisions during the fourth quarter of 2003. Any impact of adoption will affect revenue presentation only, and will not have an impact on the Company’s consolidated financial position, results of operations or cash flows.

(5)	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 Condensed Consolidated Statements of Income. Operating results from the Las Vegas II Cogeneration power plant are included in the Power Generation segment.

(6)	IMPAIRMENT OF LONG-LIVED ASSETS

As a result of the contract termination discussed in Note 5, 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 Condensed Consolidated Statements of Income. Operating results from the Las Vegas II Cogeneration power plant are included in the Power Generation segment.

(7)	RECLASSIFICATIONS

“Operating revenues” in the Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2003, have been reclassified to present realized and unrealized gains and losses under contracts in the Energy Marketing segment in accordance with the provisions of EITF 02-3. These provisions of EITF 02-3 were adopted on January 1, 2003 (See Note 3). This change in presentation did not have an impact on the Company’s total stockholders’ equity or net income available for common stock as previously reported.

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

(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:

Periods ended September 30, 2003 (in thousands)	Three Months					Nine Months
	Income			Average Shares		Income			Average Shares
Income from continuing operations	$	17,641				$	47,269
Less: preferred stock dividends		(57	)				(172	)

Basic - available for common
shareholders		17,584			32,087		47,097			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	$	17,641			32,754	$	47,269			30,457

Periods ended September 30, 2002 (in thousands)	Three Months					Nine Months
	Income			Average Shares		Income			Average Shares
Income from continuing operations	$	16,815				$	43,734
Less: preferred stock dividends		(56	)				(168	)

Basic - available for common
shareholders		16,759			26,835		43,566			26,778
Dilutive effect of:
Stock options		--			69		--			100
Convertible preferred stock		56			148		168			148
Others		--			26		--			26

Diluted - available for common
shareholders	$	16,815			27,078	$	43,734			27,052

As further described in Note 11, 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)	EQUITY IN EARNINGS OF UNCONSOLIDATED AFFILIATES

Included in “Equity in earnings of unconsolidated subsidiaries” for the nine months ended September 30, 2003, on the Condensed Consolidated Statements of Income is approximately $3.1 million related to the application of the provisions of the AICPA Audit and Accounting Guide, “Audits of Investment Companies,” by certain entities in which the Company invests. This guidance among other things requires investments held by investment companies to be stated at fair value. Consistent with prior periods, the Company will continue to record its portion of the net income of entities over which it exercises significant influence but which it does not control.

(10)	COMPREHENSIVE INCOME

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

	Three Months Ended					Nine Months Ended
	September 30					September 30
	2003		2002			2003		2002
	(in thousands)
Net income	$	22,444	$	17,449		$	53,282	$	45,322
Other comprehensive income, net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges, net of
minority interest		2,331		(4,875	)		276		(7,593	)
Unrealized loss on available-for-
sale securities		--		--			--		(219	)
Reclassification adjustment for unrealized gain
on available-for-sale securities included in
net income		--		--			--		(406	)
Reclassification adjustment for interest rate
swaps designated as cash flow hedges settled
as part of the hydroelectric asset sale and
included in net income, net of minority
interest		3,928		--			3,928		--

Comprehensive income	$	28,703	$	12,574		$	57,486	$	37,104

(11)	CHANGES IN COMMON STOCK

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

Third Quarter 2003 Transactions

•	1,964 stock options were exercised at a weighted average exercise price of $20.07 per share.

•	The Company issued 20,704 shares under its dividend reinvestment plan at a weighted average price of $32.10 per share.

•	The Company issued 6,549 shares under its employee stock purchase plan at a price of $23.45 per share.

•

The Company acquired 2,269 shares of restricted stock that were forfeited under the provisions of the Company’s 2001 Omnibus Incentive Compensation Plan.

Second Quarter 2003 Transactions

•

The Company issued 4.6 million shares in a public offering at a price of $27 per share. Net proceeds were approximately $118 million after commissions and expenses. The proceeds were used to pay off a $50 million credit facility due in May 2003 and to repay $68 million under the Company’s 364-day revolving credit facility which expired on August 26, 2003.

•

The Company issued 45,123 restricted stock units and 24,643 shares of restricted stock from treasury shares to certain officers. The shares vest one-third per year over three years, contingent on employment. Compensation cost related to the award is recognized over the vesting period. The market value of the award on the date of grant was approximately $2.0 million.

•	The Company issued 240,165 stock options at a weighted average exercise price of $28.09 per share.

•	5,917 stock options were exercised at a weighted average exercise price of $22.92 per share.

•	The Company issued 25,222 shares under its dividend reinvestment plan at a weighted average price of $29.60 per share.

•	The Company issued 5,653 shares under its employee stock purchase plan at a price of $23.45 per share.

•

The Company acquired 3,119 shares from certain officers under share withholding provisions to cover tax withholding on restricted stock that vested under the Company’s 2001 Omnibus Incentive Compensation Plan.

First Quarter 2003 Transactions

•

The Company issued 481,509 shares and 45,000 warrants to purchase common stock in the acquisition of Mallon Resources Corporation (see Note 18).

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

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

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

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

•

The Company issued 3,075 shares under the short-term incentive compensation plan. Compensation cost related to the award was approximately $0.1 million which was accrued for in 2002.

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

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

As part of the Mallon acquisition (see Note 18), the Company acquired additional debt in the amount of $4.1 million.

On April 30, 2003, the Company paid off the $50 million credit facility due May 2003 and repaid $68 million of the Company’s 364-day revolving credit facility (see Note 11).

On May 21, 2003, the Company sold $250 million of Notes, due 2013. Net proceeds from the offering were approximately $247.3 million and were used to repay a $35 million Term Credit Agreement due 2004, and $208.5 million of the three year and 364-day revolving credit facilities.

In August 2003, the Company closed on a $225 million multi-year, unsecured revolving credit facility that expires August 20, 2006. The new facility replaced the $195 million facility that expired in August 2003 and supplements the $200 million facility that expires in August 2004. The Company also amended the $200 million facility primarily to conform its compliance calculation to the same calculation as in the new $225 million multi-year facility and to amend its pricing grid and to remove its liquidity covenant. Interest rates under the facilities vary and are based on the Company’s credit rating. Based on the Company’s current credit rating, the interest rates under the facilities range from London Interbank Offered Rate (LIBOR) plus 0.75 percent to LIBOR plus 1.25 percent and the facility fee rate and utilization fee rate are 0.25 percent each. After inclusion of applicable letters of credit, the Company has $377.3 million of borrowing capacity available under these revolving credit facilities at September 30, 2003.

On September 30, 2003, Enserco Energy Inc. amended its credit agreement extending the expiration date to October 30, 2003, and subsequently amended it on October 10, 2003 extending the expiration date to September 30, 2004.

On September 30, 2003, in conjunction with the sale of the hydroelectric power plants (see Note 19), the Company repaid the project financing at Hudson Falls and South Glens Falls hydroelectric facilities which totaled approximately $82 million.

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

(13)	GUARANTEES

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

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

As of September 30, 2003 the Company had the following guarantees in place (in thousands):

Nature of Guarantee	Outstanding at September 30, 2003
Guarantee payments under the Power Purchase and Sales Agreement with	$	10,000	Upon 5 days
Sempra Energy Solutions			written notice
Guarantee payments under certain energy marketing derivative, power and
gas agreements		2,500	2004
Guarantee of obligation of Las Vegas Cogen II under an interconnection
and operation agreement		750	2005
Guarantee performance of Black Hills Wyoming under a power sales
agreement		5,000	2004
Guarantee obligations under the Wygen Plant Lease		111,100	2008
Guarantee payment and performance under credit agreements for two
combustion turbines		30,714	2010
Indemnification for subsidiary reclamation/surety bonds		30,600	Ongoing

	$	190,664

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

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

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

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

The Company has also guaranteed the obligations of Black Hills Wyoming under the agreement for lease and lease for the Wygen plant. The lease is currently accounted for as an off-balance sheet transaction, therefore there are no liabilities associated with the lease on the consolidated financial statements. If the lease was terminated and sold, the Company’s obligation is the amount of deficiency in the proceeds from the sale to repay the investors up to a maximum of 83.5 percent of the cost of the project. At September 30, 2003, the Company’s maximum obligation under the guarantee is $111.1 million (83.5 percent of $133.1 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 $26.4 million of debt of Black Hills Wyoming and $4.3 million of debt for another of its wholly-owned subsidiaries, Black Hills Generation (f/k/a Black Hills Energy Capital, Inc.). The debt is recorded on the Company’s Condensed Consolidated Balance Sheets and is due December 18, 2010.

In addition, at September 30, 2003, the Company had guarantees in place totaling approximately $30.6 million for reclamation and surety bonds for its subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in the Company’s Condensed Consolidated Balance Sheets.

(14)	DEFINED BENEFIT PENSION PLAN

During the third quarter of 2003, the Company made a $10.5 million contribution to its defined benefit pension plan (the Plan). The payment was recorded as a reduction to its accrued pension liability in the line item “Other” in “Deferred credits and other liabilities” on the accompanying Condensed Consolidated Balance Sheets.

Actuaries review the Plan annually and are currently in the process of reviewing the Plan to determine the Company’s obligation and expense for next year. In the fourth quarter of 2002, the Company recorded an $8.9 million accrued pension liability, a $1.8 million intangible asset and $12.5 million of “Accumulated other comprehensive loss” in accordance with the provisions of SFAS No. 87 “Employers’ Accounting for Pensions” (SFAS 87). The Company anticipates that substantially all of the Accumulated other comprehensive loss will be reduced in the fourth quarter of 2003 upon completion of the actuary’s review, due to the $10.5 million contribution made in the third quarter of 2003, and the return on plan assets for the year.

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

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of September 30, 2003, substantially all of the Company’s operations and assets are located within the United States. The Company’s operations are conducted through six reporting segments that include: Integrated Energy group consisting of the following segments: Mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and Gas, which produces, explores and operates oil and gas interests located in the Rocky Mountain region, Texas, California and other states; Energy Marketing, which markets natural gas, oil and related services to customers in the Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions and transports crude oil in Texas; and Power Generation, which produces and sells generating capacity and electricity to wholesale customers; Electric group and segment, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Communications group and segment, which primarily markets communications and software development services.

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

	External Operating Revenues			Inter-segment Operating Revenues			Income (loss) from Continuing Operations
Quarter to Date
September 30, 2003
Energy marketing	$	168,908	*	$	--		$	1,324
Power generation		164,577	**		--			7,056
Oil and gas		12,438			75			2,805
Mining		6,013			3,166			2,202
Electric		46,247			21			6,772
Communications		10,136			--			(1,031	)
Corporate		--			--			(1,487	)
Intersegment eliminations		--			(719	)		--

Total	$	408,319		$	2,543		$	17,641

*Operating revenues for Energy marketing are presented in accordance with EITF 02-3 as described in Note 3.
**Includes $114.0 million of contract termination revenue as described in Note 5.

	External Operating Revenues			Inter-segment Operating Revenues			Income (loss) from Continuing Operations
Quarter to Date
September 30, 2002
Energy marketing	$	142,186	*	$	--		$	3,130
Power generation		29,285			--			4,188
Oil and gas		6,323			238			1,066
Mining		5,531			2,778			2,103
Electric		45,291			--			8,304
Communications		8,392			--			(1,453	)
Corporate		--			--			(518	)
Intersegment eliminations		--			(238	)		(5	)

Total	$	237,008		$	2,778		$	16,815

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

	External Operating Revenues			Inter-segment Operating Revenues			Income (loss) from Continuing Operations
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		16,554			8,954			5,114
Electric		129,182			56			18,193
Communications		30,595			--			(3,273	)
Corporate		--			--			(3,722	)
Intersegment eliminations		--			(1,875	)		(1	)

Total	$	984,204		$	7,346		$	47,269

*Operating revenues for Energy marketing are presented in accordance with EITF 02-3 as described in Note 3.
**Includes $114.0 million of contract termination revenue as described in Note 5.

	External Operating Revenues			Inter-segment Operating Revenues			Income (loss) from Continuing Operations
Year to Date
September 30, 2002
Energy marketing	$	386,270	*	$	73		$	7,033
Power generation		79,656			--			10,446
Oil and gas		19,072			443			3,227
Mining		15,241			8,150			6,932
Electric		120,786			--			22,918
Communications		24,155			--			(5,729	)
Corporate		--			--			(1,081	)
Intersegment eliminations		--			(516	)		(12	)

Total	$	645,180		$	8,150		$	43,734

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

Other than the inclusion of the Oil and Gas segment’s acquisition of Mallon Resources, as described in Note 18, and the Power Generation segment’s sale of the New York hydroelectric facilities as described in Note 19 and the impairment of the Las Vegas Cogeneration II facility as described in Note 6, the Company had no material changes in total assets of its reporting segments, as reported in Note 16 of the Company’s 2002 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

(16)	RISK MANAGEMENT ACTIVITIES

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

Trading Activities

Natural Gas Marketing

On September 30, 2003, December 31, 2002 and September 30, 2002, contracts accounted for at fair value at the Company’s natural gas marketing operations had the following notional amounts, terms and related balances:

	September 30, 2003		December 31, 2002			September 30, 2002
(thousands of MMBtu's)	Notional Amounts	Maximum Term in Years	Notional Amounts	Maximum Term in Years		Notional Amounts	Maximum Term in Years
Basis swaps purchased	46,026	1.25	72,340		1	43,354		1
Basis swaps sold	45,589	1.25	72,329		1	54,686		1
Fixed-for float swaps purchased	17,822	1	10,675		1	15,295		1
Fixed-for-float swaps sold	22,097	1.25	17,934		1	21,054		1
Physical purchases	43,131	1.5	42,813		1.25	48,273		2
Physical sales	49,874	1.5	41,654		1.25	43,296		1
Options purchased	265	.5	--		-	--		--	-
Options sold	265	.5	--		-	--		--	-

Derivatives and certain other natural gas marketing activities were marked to fair value and the gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows:

(in thousands)	Current Derivative Assets		Non-current Derivative Assets		Current Derivative Liabilities		Non-current Derivative Liabilities		Unrealized Gain
September 30, 2003	$	22,507	$	552	$	20,327	$	371	$	2,361


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

September 30, 2002	$	37,009	$	2,232	$	30,443	$	1,441	$	7,357

For the three and nine month periods ended September 30, 2003, contracts and other activities at our natural gas marketing operations are accounted for under the provisions of EITF 02-3 and SFAS 133. As such, all of the contracts and other activities at the Company’s natural gas marketing operations that meet the definition of a derivative under SFAS 133 are accounted for at fair value. EITF 02-3, adopted on January 1, 2003, precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to SFAS 133. Accordingly, natural gas physical inventories and transportation contracts that have not been designated as part of a fair value hedge transaction, in accordance with SFAS 133, are recognized at a historical cost basis (lower of cost or market for physical inventories) and settlement costs or gains or losses recognized on the accrual method of accounting. Substantially all other contracts at the Company’s natural gas marketing operations are derivatives or hedging activities, as defined by SFAS 133, and have been recorded at fair value.

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

Non-trading Energy Activities

On September 30, 2003, December 31, 2002 and September 30, 2002, contracts accounted for at fair value at the Company’s non-trading energy operations had the following notional amounts, terms and related balances (in thousands):

Crude Oil Marketing

	September 30, 2003				December 31, 2002				September 30, 2002
	Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years		Notional Amounts		Maximum Term in Years
(thousands of barrels)
Crude oil purchased		--		--		4,081		0.5		4,173		1
Crude oil sold		--		--		4,150		0.5		4,172		1

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

September 30, 2003	$ --	$ --	$ --	$ --	$	--

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

September 30, 2002	$ 6,624	$ --	$ 5,849	$ --	$	775

For the three and nine month periods ended September 30, 2003, contracts at the Company’s crude oil marketing operations are accounted for under the provisions of EITF 02-3 and SFAS 133. Substantially all of the contracts at the Company’s crude oil marketing operations are either not derivatives, as defined by SFAS 133, or are derivatives but qualify for the “normal purchase/normal sale” exclusion provided by SFAS 133 and have been exempted out of fair value accounting treatment. As such, the Company accounts for all contracts at its crude oil marketing operations on a historical cost method with gains or losses recognized when realized in accordance with the accrual method of accounting.

For all other periods presented, contracts at the Company’s crude oil marketing operations fell under the purview of EITF 98-10, SFAS 133 and for contracts entered into after October 25, 2002, under EITF 02-3. As such, all contracts entered into on or before October 25, 2002 have been accounted for under mark-to-market accounting.

Oil and Gas Exploration and Production

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

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

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

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

September 30, 2002
Natural gas swaps	1,676,000	1	$	267	$	--	$	142	$	28	$	90		$	7
Crude oil swaps	141,000	1		18		12		1,027		73		(1,003	)		(67	)

			$	285	$	12	$	1,169	$	101	$	(913	)	$	(60	)

_________________

*crude in barrels, gas in MMBtu’s

Based on September 30, 2003 market prices, a $0.1 million gain 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, 2003 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

On September 30, 2003, December 31, 2002 and September 30, 2002, the Company’s interest rate swaps and related balances were as follows (in thousands):

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

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	%	.5		--		--		432		--		(430	)		(2	)

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

December 31, 2002

Swaps on
project
financing	$	147,000	4.98	%	3.75	$	--	$	--	$	5,104	$	2,314	$	(7,418	)	$	-	-
Swaps on
corporate debt		25,000	5.28	%	1.25		--		--		947		166		(1,113	)		-	-

Total	$	172,000	--		--	$	--	$	--	$	6,051	$	2,480	$	(8,531	)	$	-	-

September 30, 2002

Swaps on
project
financing	$	147,000	4.98	%	4	$	--	$	--	$	4,868	$	3,039	$	(7,907	)	$	-	-
Swaps on
corporate debt		75,000	4.45	%	2		--		--		1,201		333		(1,534	)		-	-

Total	$	222,000	--		--	$	--	$	--	$	6,069	$	3,372	$	(9,441	)	$	-	-

During the first and second quarters of 2003, the Company entered into treasury locks, with a notional amount of $150 million, to hedge the risk of interest rate movement between the hedge date and the expected pricing date for a portion of the Company’s second quarter $250 million debt offering of senior unsecured notes. These swaps terminated and cash- settled during the second quarter 2003, resulting in a $4.0 million loss. These swaps were designated as cash flow hedges, and accordingly, the resulting loss will remain in “Accumulated other comprehensive loss” on the Condensed Consolidated Balance Sheet and amortized into earnings as additional interest expense over the life of the related long-term financing.

Based on September 30, 2003 market interest rates and balances, approximately $3.8 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.

(17)	LEGAL PROCEEDINGS

Fires

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

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

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

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

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

Federal Energy Regulatory Commission (FERC) Investigations

Enron “Qualifying Facility” Status

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

On February 24, 2003, FERC issued an order announcing an investigation to determine whether Enron’s ownership of the Las Vegas Cogeneration I Facility violated the qualifying facility regulations under PURPA. In addition, the SEC issued an initial decision concluding that Enron is an electric utility and is thus not exempt from regulations under the Public Utility Holding Company Act of 1935 (PUHCA), that, among other things, prohibit electric utilities from owning more than 50 percent of a qualifying facility. Enron is appealing this decision.

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

If FERC determines that Enron violated the qualifying facility regulations with respect to the Las Vegas Cogeneration I Facility, the Company, as a partner in the entity that now owns that facility, could be liable for any refunds, fines or other penalties FERC imposes. The Company could also be subject to additional liabilities resulting from third party claims.

The Company is engaged in ongoing settlement discussions with FERC and interveners and expects to settle the FERC investigatory proceeding without formal hearing proceedings. In the event the FERC investigation is not settled and proceeds to hearing, the Company believes that it has meritorious defenses to any claim for a refund or other relief, and it intends to defend such claims vigorously. In any event, based on the information available, the Company believes that the FERC investigation will have no material adverse effect on its financial position or results of operations.

Order to Show Cause

On June 25, 2003, FERC issued an order to Enron Power Marketing, Inc. (EPMI), Enron Energy Services, Inc. (EES), and a number of other market participants to show cause why their behavior during January 1, 2000, to June 20, 2001, did not constitute gaming and/or anomalous behavior, as defined in the tariffs of the California Independent System Operator (CAISO) and California Power Exchange (CAPX) (the FERC Show Cause Order). Las Vegas Cogeneration, L.P. (LV Cogen) is among the named respondents in the FERC Show Cause Order. The Company acquired its partnership interest in LV Cogen on August 31, 2001, a date following the close of the period of inquiry under the FERC Show Cause Order.

The FERC Show Cause Order alleges that EPMI and/or EES formed partnerships and alliances with utilities, public power districts, municipalities, and qualifying facilities and used the partnerships and alliances to gain market share, acquire commercially sensitive data, acquire decision-making authority, and promote reciprocal dealing and equity share of profits, all in an effort to “game the market.” The FERC Show Cause Order directs the named respondents to show cause, in a trial-type evidentiary proceeding to be held before a FERC administrative law judge, why they should not be found to have engaged in “gaming practices” in violation of the CAISO’s and CAPX’s tariffs. The FERC Show Cause Order indicates that FERC will seek disgorgement of unjust profits associated with any violations or other additional appropriate remedies.

The Company intends to vigorously defend against claims for a refund or other relief. Based on the information available, the Company believes that the proceeding commenced by the FERC Show Cause Order will not have a material adverse effect on the Company’s financial position or results of operations.

Commodity Futures Trading Commission Investigation

In March 2003, the Company received a request for information from the Commodity Futures Trading Commission, or CFTC, calling for the production, among other things, of “all documents relating to natural gas and electricity trading” in connection with CFTC’s industry wide investigation of trade and trade reporting practices of power and natural gas trading companies. The Company cooperated fully with the CFTC producing documents and other materials in response to specific requests relating to the reporting of natural gas trading information to energy industry publications, conducted its own internal investigation into the accuracy of information that former employees of Enserco Energy Inc., its gas marketing subsidiary, voluntarily reported to trade publications, and provided detailed reports of its own investigation to the CFTC.

On July 31, 2003, the Company announced that a settlement was reached with the CFTC related to the Enserco investigation, whereby the Company agreed to pay a civil monetary penalty of $3.0 million. This charge was recorded in the second quarter and is included in “Administrative and general” expenses on the accompanying Condensed Consolidated Statement of Income for the nine months ended September 30, 2003. The settlement order recites findings of fact relating to conduct over a time period ending in June 2002 and states that the persons responsible for the misconduct no longer work for the Company. The CFTC found that the activity violated certain provisions of the Commodity Exchange Act relating to the delivery of false market information. Neither the Company nor Enserco admitted or denied these findings. The CFTC found no evidence that the Company had knowledge of, or participated in, the misconduct. The CFTC also cited efforts of the Company both before and after the inception of the investigation, to employ industry experts to assist the Company in enhancing risk management activities and internal controls on marketing activities, and the adoption by the Company of new procedures designed to prevent a reoccurrence of alleged misconduct. The Company does not believe inaccurate trade reporting to trade publications affected the financial accounting treatment of any transactions recorded in its books and records. The Company is considering its rights relative to the individuals it believes to be responsible for the conduct in question. Although the Company agreed to this civil monetary penalty with the CFTC, we cannot guarantee that other legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not occur which, in turn, could adversely affect the Company’s financial condition or results of operations.

Ongoing Proceedings

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

(18)	ACQUISITION

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

The acquisition was accounted for under the purchase method of accounting and, accordingly, the purchase price was allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and liabilities assumed as of the date of acquisition. The estimated purchase price allocation is subject to adjustment, generally within one year of the date of acquisition. The preliminary purchase allocation has been adjusted to reflect the completion of the quantification and analysis of the acquired asset retirement obligations in accordance with SFAS 143. This adjustment resulted in a $0.5 million increase to Long-term liabilities and Property, plant and equipment. The adjusted preliminary allocation of the purchase price is as follows (in thousands):



Current assets	$	165
Property, plant and equipment		56,169
Deferred tax asset		5,194

Total assets acquired	$	61,528

Current liabilities	$	6,343
Long-term liabilities		4,032

Total liabilities assumed	$	10,375

Net assets	$	51,153

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

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

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003		2002
Operating revenues	$	410,862	$	242,350	$	994,491	$	661,305
Income from continuing
operations	$	17,641	$	15,509	$	46,821	$	40,983
Net income	$	22,444	$	16,143	$	52,834	$	42,571
Earnings per share--
Basic:
Continuing operations	$	0.55	$	0.57	$	1.54	$	1.50
Total	$	0.70	$	0.59	$	1.73	$	1.56
Diluted:
Continuing operations	$	0.54	$	0.56	$	1.51	$	1.49
Total	$	0.69	$	0.59	$	1.71	$	1.55

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

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

(19)	DISCONTINUED OPERATIONS

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

Sale of Hydroelectric Assets

On September 30, 2003 the Company sold its seven hydroelectric power plants located in upstate New York. The aggregate cash purchase price of approximately $186 million was used in part to pay off the remaining amount of project-level debt and related interest rate swaps associated with these assets, which totaled approximately $91 million. The remaining cash proceeds from the sale are expected to be used to pay income taxes related to the sale, to repay other corporate or subsidiary-level debt, or for other corporate purposes. The purchasers are affiliates of Boralex, Inc., a Canadian corporation, and Boralex Power Income Fund, an unincorporated Canadian trust of which Boralex owns an interest (collectively the Purchaser). The agreements with the Purchaser required that the Company deliver 100 percent of the equity interests of the entities that owned the facilities and required that the Company acquire those minority interests which it did not then own, in advance of closing. In anticipation of entering into the agreements with the Purchaser, on July 8, 2003, the Company acquired the equity interests of a third party investor for $9.0 million and entered into a definitive agreement to acquire the balance of the equity interests from another third party investor (who is presently treated as a consolidated subsidiary of the Company for financial statement purposes, in accordance with accounting principles generally accepted in the United States). For business segment reporting purposes, the hydroelectric power plants results were previously included in the Power Generation segment.

Revenues and net income from the discontinued operations are as follows:

	Three Months Ended September 30						Nine Months Ended September 30
	2003			2002			2003			2002
	(in thousands)
Operating revenues	$	4,979		$	3,611		$	21,800		$	20,215

Pre-tax income from
discontinued operations	$	1,463		$	946		$	8,041		$	6,581
Pre-tax gain on disposal		13,873			--			13,873			--
Income tax expense		(9,665	)		(350	)		(11,984	)		(2,435	)

Net income from
discontinued operations	$	5,671		$	596		$	9,930		$	4,146

Assets and liabilities of the discontinued operations are as follows:

	December 31 2002			September 30 2002
	(in thousands)

Current assets	$	8,315		$	7,376
Property, plant and equipment		148,692			149,408
Goodwill		9,773			10,331
Other non-current assets		4,737			4,076
Current derivative liability		(4,241	)		(4,246	)
Other current liabilities		(8,747	)		(11,598	)
Long-term debt		(77,903	)		(79,959	)
Non-current derivative liability		(5,531	)		(5,983	)
Other non-current liabilities		(10,329	)		(6,394	)

Net assets of discontinued operations	$	64,766		$	63,011

Adoption of Plan to Sell Pepperell Plant

During the third quarter of 2003, the Company adopted a plan to sell the 40 megawatt gas-fired Pepperell plant, which is part of the non-regulated power generation segment. The Pepperell plant is the Company’s only remaining generation asset in the eastern market and management has determined that it is a non-strategic asset. Management currently believes the assets will be sold by September 30, 2004. In connection with the plan to sell, the Company determined that the carrying value of the underlying assets exceeded their fair value and a charge to operations was required.

Consequently, in the third quarter of 2003, the Company recorded an after-tax charge of approximately $0.6 million, which represents the difference between the carrying value of the assets versus their fair value, less estimated cost to sell. For business segment reporting purposes, the Pepperell plant results were previously included in the Power Generation segment.

Revenues and net income from the discontinued operations are as follows:

	Three Months Ended September 30						Nine Months Ended September 30
	2003			2002			2003			2002
	(in thousands)
Operating revenues	$	264		$	1,805		$	2,131		$	2,978

Pre-tax income (loss) from
discontinued operations	$	(437	)	$	61		$	(1,016	)	$	(812	)
Pre-tax loss on disposal		(3,464	)		--			(3,464	)		--
Income tax benefit
(expense)		3,033			(23	)		3,243			(5	)

Net (loss) income from
discontinued operations	$	(868	)	$	38		$	(1,237	)	$	(817	)

Assets and liabilities of the discontinued operations are as follows:

	September 30 2003			December 31 2002			September 30 2002
	(in thousands)

Current assets	$	336		$	1,798		$	2,604
Property, plant and equipment		1,064			4,779			4,866
Non-current deferred tax asset		3,268			374			--
Other current liabilities		(348	)		(203	)		(931	)
Non-current liabilities		(7	)		--			--

Net assets of discontinued operations	$	4,313		$	6,748		$	6,539

Sale of Coal Marketing Subsidiary

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

Consequently, in the second quarter of 2002, the Company recorded an after-tax charge of approximately $1.0 million, which represents the difference between the carrying values of the assets and liabilities of the subsidiary versus their fair values, less cost to sell. For business segment reporting purposes, the coal marketing business results were previously included in the Energy Marketing segment.

Gross margins on energy trading contracts and net income from the discontinued operation are as follows:

	Three Months Ended September 30 2002			Nine Months Ended September 30 2002
	(in thousands)
Gross margins on energy trading contracts	$	190		$	(235	)

Pre-tax income (loss) from discontinued
operation	$	65		$	(2,679	)
Pre-tax loss on disposal		(65	)		(1,588	)
Income tax benefit		--			1,630

Net loss from discontinued operations	$	--		$	(2,637	)

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF OPERATIONS

We are a diversified energy holding company operating principally in the United States. Our unregulated and regulated businesses have expanded significantly in recent years. Our integrated energy group, Black Hills Energy, Inc., produces and markets electric power and fuel. We produce and sell generating capacity and electricity primarily in the western United States. We also produce coal, natural gas and crude oil, primarily in the Rocky Mountain region, and transport crude oil in Texas. Our electric utility, Black Hills Power, Inc., serves an annual average of approximately 60,000 customers in South Dakota, Wyoming and Montana. Our communications group provides state-of-the-art 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.

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

Results of Operations

Consolidated Results

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

	Three Months Ended September 30						Nine Months Ended September 30
	2003			2002			2003			2002
Revenues
Integrated energy		86	%		78	%		84	%		78	%
Electric utility		11			19			13			18
Communications		3			3			3			4

		100	%		100	%		100	%		100	%

Income/ (Loss) from Continuing Operations
Integrated energy		76	%		62	%		77	%		63	%
Electric utility		38			49			38			52
Communications		(6	)		(9	)		(7	)		(13	)
Corporate		(8	)		(2	)		(8	)		(2	)

		100	%		100	%		100	%		100	%

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. Consolidated income from continuing operations for the three-month period ended September 30, 2003 was $17.6 million or $0.54 per share compared to $16.8 million or $0.62 per share in the same period of the prior year.

Income from continuing operations for the three-month period ended September 30, 2003 includes certain unusual items that resulted in a net charge of $0.05 per share. These items related to $114.0 million of proceeds or $2.09 per share after-tax gain from a contract termination agreement and $117.2 million or $2.15 per share after-tax impairment charge related to the Las Vegas Cogeneration II power plant (see Notes 5 and 6 of the accompanying Notes to Condensed Consolidated Financial Statements), and a $0.01 per share after-tax gain related to the settlement of accounts with Enron Corporation stemming from Enron’s bankruptcy in 2001. The asset impairment charge at the Las Vegas Cogeneration II plant reflects the cancellation of the facility’s long-term contract for its capacity and energy and other factors.

Per share results in the third quarter of 2003 were also affected by an increase of 5.7 million weighted average shares outstanding, compared to the same period in 2002, due primarily to a 4.6 million share common stock offering in April 2003 and the issuance of approximately 0.5 million common shares in conjunction with the March 2003 acquisition of Mallon Resources Corporation.

Financial performance in the third quarter of 2003 reflected an increase of 28 percent in income from continuing operations for the integrated energy business unit, compared to the same period in 2002. The improved results were attributed primarily to increased earnings from power generation, due to an increase in generation capacity in service, and higher oil and natural gas production and prices, partially offset by a decrease in earnings from energy marketing. In addition, the communications business unit reported improved performance due to increased revenues from a larger customer base. Overall improved results were partially offset by an 18 percent decrease in earnings at our electric utility due to higher operating costs and interest expense, compared to the same quarter in 2002.

During the third quarter of 2003, we sold our hydroelectric power plants in upstate New York and adopted a plan of sale for our 40 megawatt Pepperell power plant in Massachusetts. Prior year results of operations have been restated to reflect the discontinued operations. Net income from discontinued operations was $4.8 million or $0.15 per share for the three months ended September 30, 2003 compared to $0.6 million or $0.02 per share in 2002.

Consolidated revenues for the three-month period ended September 30, 2003 were $410.9 million compared to $239.8 million for the same period in 2002. Revenues increased in each of our three business groups. Revenues in the power generation segment include $114.0 million of contract termination revenue related to the Las Vegas II Cogeneration power plant. Excluding this contract termination revenue, revenues in the power generation segment increased 73 percent due to a substantial increase in its generating capacity in service. Energy marketing revenue increased 19 percent due to a 4 percent increase in crude oil volumes marketed at an average price 16 percent higher than the prior year and an increase in oil transportation and oil terminal revenues offset by a decrease in revenue from lower gas marketing margins. Oil and gas revenue increased 91 percent, due to an 87 percent increase in production resulting primarily from the March 2003 acquisition of Mallon Resources and a 10 percent increase in the average price received. Mining revenue increased 10 percent, due to a 16 percent increase in tons sold.

Revenues from the electric utility group increased 2 percent, due to a 5 percent increase in firm system electric sales, partially offset by an 8 percent decrease in off-system electric sales. The communications group revenue increased 21 percent as a result of a 13 percent increase in its customer base.

Consolidated operating expenses for the three-month period increased from $206.4 million in 2002 to $371.9 million in 2003. Operating expenses for the 2003 period include the $117.2 million asset impairment charge on the Las Vegas Cogeneration II power plant. Excluding this impairment charge, operating expenses increased $48.3 million or 23 percent. The increase was primarily due to an increase in fuel costs and depreciation expense as a result of our increased investment in independent power generation, and increased operating expenses related to the increase in production in each of our three business groups. Corporate costs increased $1.3 million primarily due to higher general and administrative expenses and increased pension expenses.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. Consolidated income from continuing operations for the nine-month period ended September 30, 2003 was $47.3 million or $1.55 per share compared to $43.7 million or $1.62 per share in the same period of the prior year.

Income from continuing operations for the nine-month period ended September 30, 2003 includes certain unusual items that resulted in a net charge of $0.09 per share. These items relate to the following: $114.0 million of proceeds or $2.25 per share after-tax gain from a contract termination agreement and $117.2 million or $2.31 per share after-tax impairment charge related to the Las Vegas Cogeneration II power plant (see Notes 5 and 6 of the accompanying Notes to Condensed Consolidated Financial Statements); a $0.01 per share after-tax gain related to the settlement of accounts with Enron Corporation stemming from Enron’s bankruptcy in 2001; a $3.0 million or $0.10 per share charge for the CFTC Settlement; and a $0.06 per share benefit from unrealized gains from investments in certain energy funds. The asset impairment charge at the Las Vegas Cogeneration II plant reflects the cancellation of the facility’s long-term contract for its capacity and energy and other factors. Consolidated income from continuing operations for the nine months ended September 30, 2002 include a $0.09 per share benefit attributed to the collection of previously reserved amounts.

Per share results for the nine months ended September 30, 2003, were also affected by an increase of 3.4 million weighted average shares outstanding, compared to the same period in 2002, due primarily to a 4.6 million share common stock offering in April 2003 and the issuance of approximately 0.5 million common shares in conjunction with the March 2003 acquisition of Mallon Resources Corporation.

The increase in income from continuing operations was a result of the following: higher oil and gas prices; increased oil and gas production primarily resulting from the March 2003 acquisition of Mallon Resources; an increase in power sales resulting from higher generation capacity in service in our Power Generation segment; increased earnings from power fund investments accounted for under the equity method of accounting; and improving performance in our communications business group. These increases were partially offset by a decrease in income at the electric utility due to higher operating costs and interest expense, a decrease in income in the mining segment due to higher operating costs, and a decrease in income at the energy marketing segment, due to the CFTC Settlement and lower margins received.

Net income for the nine months ended September 30, 2003, included a $2.7 million or $0.09 per share charge for changes in accounting principles compared to a $0.9 million benefit or $0.03 per share in 2002. The change in accounting principles in 2003 reflects a $2.9 million charge related to the adoption of EITF 02-3 and a $0.2 million benefit related to the adoption of SFAS 143. The change in accounting principle in 2002 reflects a $0.9 million benefit related to the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142).

During the third quarter of 2003, we sold our hydroelectric power plants in upstate New York and adopted a plan of sale for our 40 megawatt Pepperell power plant in Massachusetts. In addition, during the third quarter of 2002, we sold our coal marketing business due primarily to challenges encountered in marketing our Wyodak coal from the Powder River Basin of Wyoming to midwestern and eastern coal markets. Prior year results of operations have been restated to reflect the discontinued operations. Net income from discontinued operations was $8.7 million or $0.29 per share for the nine months ended September 30, 2003 compared to $0.7 million or $0.03 per share in 2002.

Consolidated revenues for the nine-month period ended September 30, 2003 were $991.6 million compared to $653.3 million for the same period in 2002. Revenues increased in each of our three business groups due primarily to higher production volumes. Revenues in the power generation segment include $114.0 million of contract termination revenue related to the Las Vegas II Cogeneration power plant. Excluding this contract termination revenue, revenues in the power generation segment increased 71 percent due to a substantial increase in its generating capacity in service. Energy marketing revenues increased 36 percent, due primarily to a 12 percent increase in crude oil average daily volumes marketed at average prices 22 percent higher than the same period in 2002. Oil and gas revenue increased 76 percent, primarily due to a 50 percent increase in production resulting from the March 2003 acquisition of Mallon Resources and a 46 percent increase in average price received. Mining revenue increased 9 percent, due to a 21 percent increase in coal production partially offset by lower average prices received. Revenues from the electric utility group increased 7 percent, due to a 2 percent increase in firm system electric megawatt-hour sales; a 28 percent increase in average prices received for off-system sales partially offset by a 1 percent decrease in off-system megawatt-hour sales; and increased transmission revenues. The communications group revenue increased 27 percent as a result of the recording of revenue associated with the 2003 – 2004 Black Hills telephone directory and a 13 percent increase in its customer base.

Consolidated operating expenses for the nine-month period increased to $886.8 million in 2003 from $569.0 million in 2002. Operating expenses for the 2003 period include the $117.2 million asset impairment charge on the Las Vegas Cogeneration II power plant. Excluding this impairment charge, operating expenses increased $200.6 million or 35 percent. The increase was due to an increase in fuel and depreciation expense as a result of our increased investment in independent power generation and increased operating expenses related to the increase in production in all business segments. Corporate costs increased $2.9 million primarily due to the write-off of deferred debt issuance costs associated with the $35 million term loan paid off during the second quarter of 2003, higher general and administrative expenses and increased pension expenses.

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

Integrated Energy Group

	Three Months Ended September 30					Nine Months Ended September 30
	2003		2002			2003		2002
	(in thousands)
Revenue:
Energy marketing	$	168,908	$	142,186		$	523,597	$	386,343
Power generation*		164,577		29,285			250,173		79,656
Oil and gas		12,513		6,561			34,314		19,515
Mining		9,179		8,309			25,508		23,391

Total revenue		355,177		186,341			833,592		508,905
Equity in earnings (losses) of
unconsolidated subsidiaries		894		(719	)		5,758		2,561
Operating expenses*		327,745		166,544			759,943		459,573

Operating income	$	28,326	$	19,078		$	79,407	$	51,893

Income from continuing operations	$	13,387	$	10,487		$	36,072	$	27,638

*Power generation revenue in 2003 includes $114.0 million of contract termination revenue (see Note 5) and 2003 operating expenses include $117.2 million of impairment of long-lived assets (see Note 6).

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

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003		2002

Fuel production:
Tons of coal sold		1,292,100		1,110,800		3,562,400		2,955,500
Barrels of oil sold		109,486		110,403		323,787		340,036
Mcf of natural gas sold		2,495,341		1,019,564		6,445,976		3,567,135
Mcf equivalent sales		3,152,257		1,681,982		8,388,698		5,607,351

	September 30
	2003			2002
Independent power capacity:
MWs of independent power capacity in service*		1,002	**		657
MWs of independent power capacity under construction		--			364	**

___________________

*Capacity in service includes 40 MW and 74 MW in 2003 and 2002, respectively, which are currently reported as "Discontinued operations."
**Includes a 90 MW plant under a lease arrangement.

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

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003		2002

Natural gas - MMBtus		1,205,900		1,140,200		1,181,800		1,039,200
Crude oil - barrels		59,500		57,200		60,000		53,700

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. Income from continuing operations for the integrated energy group for the three months ended September 30, 2003 was $13.4 million, compared to $10.5 million in the same period of the prior year. Income from continuing operations increased approximately $2.9 million primarily due to increased power generating capacity in service and increased oil and gas production and prices, partially offset by certain unusual items. Income from continuing operations for the 2003 period includes certain unusual items that resulted in a net charge of $1.5 million after-tax. These items relate to $114.0 million of proceeds or a $68.4 million after-tax gain from the Las Vegas Cogeneration II power plant contract termination, a $117.2 million or $70.3 million after-tax impairment charge at the Las Vegas II Cogeneration power plant, and a $0.4 million after-tax gain related to the settlement of accounts with Enron Corporation stemming from Enron’s bankruptcy in 2001.

Income from continuing operations in our power generation segment increased $2.9 million due to increased generating capacity in service and the $0.4 million after-tax gain related to the Enron settlement, partially offset by the $1.9 million of after-tax charges at the Las Vegas Cogeneration II power plant. Income from continuing operations at our oil and gas segment increased approximately $1.7 million due to higher prices received compared to 2002 and an 87 percent increase in production. Income from continuing operations at our energy marketing segment decreased $1.8 million due to a decrease in margins received, an increase in expenses associated with increased volumes of crude oil transportation and a decrease in unrealized mark-to-market gains on derivative contracts. Income from continuing operations for the mining segment was substantially flat as higher production volumes were offset by lower average prices, higher administrative and production costs related to increased volumes.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. Income from continuing operations for the integrated energy group for the nine months ended September 30, 2003 was $36.1 million, compared to $27.6 million in the same period of the prior year. Income from continuing operations increased approximately $8.4 million due to increased generating capacity, increased oil and gas production and prices, and increased earnings from power fund investments accounted for under the equity method of accounting, partially offset by certain unusual items. Income from continuing operations for the 2003 period includes certain unusual items that resulted in a net charge of $2.7 million after-tax. These items relate to $114.0 million of proceeds or a $68.4 million after-tax gain from the Las Vegas Cogeneration II power plant contract termination, a $117.2 million or $70.3 million after-tax impairment charge at the Las Vegas II Cogeneration power plant, the $3.0 million charge for the CFTC settlement, a $1.8 million after-tax benefit attributed to unrealized gains on investments accounted for under a fair value method of accounting at the power funds, and a $0.4 million after-tax gain related to the settlement of accounts with Enron Corporation stemming from Enron’s bankruptcy in 2001. In addition, 2002 income from continuing operations includes a $1.9 million benefit relating to the collection of previously reserved amounts for California operations in our power generation segment.

Income from continuing operations in our power generation segment increased $9.2 million due to increased generating capacity in service and increased earnings from power fund investments. Income from continuing operations at our oil and gas segment increased approximately $4.0 million due to higher prices received compared to 2002 and a 50 percent increase in production. Income from continuing operations at our energy marketing segment decreased $3.0 million primarily due to the CFTC Settlement. Income from continuing operations for the mining segment decreased $1.8 million as higher production volumes were more than offset by lower average prices, higher operating costs and certain accruals for taxes and other items.

Energy Marketing

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003			2002
	(in thousands)
Revenue	$	168,908	$	142,186	$	523,597		$	386,343
Equity in earnings of unconsolidated
subsidiaries		--		--		--			248
Operating income		2,243		4,860		8,166			10,479
Income before change in
accounting principle		1,324		3,130		4,079			7,033
Change in accounting principle		--		--		(2,870	)		--
Net income		1,324		3,130		1,209			7,033

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. The increase in revenues is a result of a 4 percent increase in crude oil volumes marketed at an average price 16 percent higher than the prior year, and an increase in oil transportation and oil terminal revenues, offset by a decrease in revenue from lower gas marketing margins. Revenue increases from crude oil marketing were offset by a similar increase in the cost of crude oil sold.

Operating expenses increased $29.3 million due to a $28.4 million increase in the cost of crude oil sold, reflecting the higher volumes and prices, an increase in general and administrative expenses, and an increase in operations and maintenance expense associated with increased volumes of crude oil transportation.

Income from continuing operations decreased $1.8 million due to a decrease in oil and gas margins received, and increased general and administrative expenses and operations and maintenance expense associated with increased volumes of crude oil transportation. As a result of changing commodity prices, net income was impacted by unrealized gains recognized through mark-to-market accounting treatment. Unrealized pre-tax mark-to-market gains for the three-month period ended September 30, 2003 were $0.2 million, compared to $1.5 million of unrealized pre-tax mark-to-market gains in 2002, resulting in a quarter-over-quarter decrease of $1.3 million pre-tax.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. Revenues increased 36 percent, due primarily to a 12 percent increase in crude oil volumes marketed at average prices 22 percent higher than the same period in the prior year. In addition, revenues from natural gas marketing margins and oil transportation and terminal operations increased over the prior year. Revenue increases from crude oil marketing were offset by similar increases in the cost of crude oil sold.

Operating expenses increased $139.3 million due to a $131.6 million increase in the cost of crude oil sold, the $3.0 million settlement reached with the CFTC, and an increase in operations and maintenance expense associated with increased volumes of crude oil transportation.

Income from continuing operations decreased $3.0 million primarily due to the $3.0 million CFTC Settlement. Net income decreased $5.8 million primarily due to the CFTC Settlement and a change in accounting principle of $(2.9) million, net of tax, related to the adoption of EITF 02-3, partially offset by higher earnings from increased volumes marketed. As a result of changing commodity prices, net income was impacted by an increase in unrealized gains recognized through mark-to-market accounting treatment. Unrealized pre-tax mark-to-market gains for the nine-month period ended September 30, 2003 were $2.1 million compared to $1.8 million in 2002, resulting in a period-over-period increase of $0.3 million pre-tax.

Power Generation

	Three Months Ended September 30					Nine Months Ended September 30
	2003		2002			2003		2002
	(in thousands)
Revenue*	$	164,577	$	29,285		$	250,173	$	79,656
Equity in earnings (losses) of
unconsolidated subsidiaries		894		(719	)		5,374		2,313
Operating income		19,485		10,307			55,438		30,286
Income before change in accounting
principle		7,056		4,188			19,634		10,446
Change in accounting principle		--		--			--		896
Net income		7,056		4,188			19,634		11,342

*2003 revenue includes $114.0 million of contract termination revenue (see Note 5).

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. 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 for the three month period ended September 30, 2003, increased 73 percent compared to the same period in 2002, primarily due to additional generating capacity in service. As of September 30, 2003, we had 962 megawatts of independent power capacity in service for continuing operations, compared to 583 megawatts at September 30, 2002.

Operating expenses for the three months ended September 30, 2003, increased $127.7 million, which includes a $117.2 million impairment charge for the Las Vegas II Cogeneration power plant. The impairment charge was a result of the termination of the power sales contract on the Las Vegas II Cogeneration power plant. Excluding the impairment charge operating expenses increased $10.5 million or 58 percent, primarily due to the additional generating capacity in service.

Net income for the power generation segment increased $2.9 million due to the additional generating capacity and the $0.4 million after-tax Enron settlement, partially offset by the $1.9 million net after-tax charge for the contract termination, and the asset impairment charge on the Las Vegas II Cogeneration power plant.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. Revenue for the nine 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 for the nine month period ended September 30, 2003, increased 71 percent compared to the same period in 2002, primarily due to the additional generating capacity in service. As of September 30, 2003, we had 962 megawatts of independent power capacity in service for continuing operations, compared to 583 megawatts at September 30, 2002.

Operating expenses for the nine months ended September 30, 2003, increased $148.4 million, which includes a $117.2 million impairment charge for the Las Vegas II Cogeneration power plant. The impairment charge was a result of the termination of the power sales contract on the Las Vegas II Cogeneration power plant. Excluding the impairment charge, operating expenses increased $31.2 million or 60 percent primarily due to the additional generating capacity in service.

Net income for the power generation segment increased $8.3 million due to the additional generating capacity in service, increased earnings from power fund investments accounted for under the equity method of accounting, and the $0.4 million after-tax Enron settlement, partially offset by the $1.9 million net after-tax charge for the contract termination and the asset impairment charge on the Las Vegas II Cogeneration power plant. Increased earnings from our power fund investments primarily relate to $1.8 million after-tax benefit attributed to unrealized gains on investments accounted for under a fair value method of accounting at the power funds. Results from 2002 reflect a $1.9 million after-tax benefit related to the collection of previously reserved amounts for California operations and a $0.9 million after-tax benefit from a change in accounting principle related to the adoption of SFAS 142.

Oil and Gas

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003			2002
	(in thousands)
Revenue	$	12,513	$	6,561	$	34,314		$	19,515
Equity in earnings of unconsolidated
subsidiaries		--		--		384			--
Operating income		4,129		1,408		10,960			4,191
Income before change in accounting
principle		2,805		1,066		7,245			3,227
Change in accounting principle		--		--		(128	)		--
Net income		2,805		1,066		7,117			3,227

The following is a summary of our internally estimated economically recoverable oil and gas reserves. These estimates are measured using constant product prices of $30.30 per barrel of oil and $4.69 per Mcf of natural gas as of September 30, 2003, and $30.45 per barrel of oil and $4.10 per Mcf of natural gas as of September 30, 2002. Significant increases in reserves are primarily the result of the March 2003 acquisition of Mallon Resources. 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
	2003			2002

Barrels of oil (in millions)		4	.9		4	.9
Bcf of natural gas		110	.4		32	.3
Total in Bcf equivalents		140	.0		61	.7

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. Revenue from our oil and gas production business segment increased 91 percent for the three-month period ended September 30, 2003, compared to the same period in 2002, due to an 87 percent increase in production primarily resulting from the March 2003 acquisition of Mallon Resources, and a 10 percent increase in the average price received.

Operating expenses increased 63 percent primarily due to the increase in production.

Income from continuing operations increased 163 percent due to the higher prices received and the increase in production compared to 2002.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. Revenue from our oil and gas production segment increased 76 percent for the nine month period ended September 30, 2003, compared to the same period in 2002, due to a 50 percent increase in production primarily resulting from the March 2003 acquisition of Mallon Resources, and a 46 percent increase in the average price received.

Operating expenses increased 55 percent primarily due to the increase in production.

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

Mining

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003		2002
	(in thousands)
Revenue	$	9,179	$	8,309	$	25,508	$	23,391
Operating income		2,469		2,503		4,843		6,937
Income before change in accounting
principle		2,202		2,103		5,114		6,932
Change in accounting principle		--		--		318		--
Net income		2,202		2,103		5,432		6,932

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. Revenue from our mining segment increased 10 percent for the three-month period ended September 30, 2003, compared to the same period in 2002. A 16 percent increase in tons of coal sold was partially offset by lower average prices received. The increase in tons of coal sold was primarily attributable to sales to the Wygen Plant, which began commercial operation in February 2003, and to sales of coal through the train load-out facility.

Operating expenses increased 16 percent or approximately $0.9 million, primarily due to higher operating costs related to the increase in production, accruals for taxes and an increase in general and administrative costs. General and administrative costs increased $0.6 million primarily due to increased pension expense and an increase in corporate costs.

Income from continuing operations was substantially flat as higher production volumes were offset by lower average prices, higher administrative and production-related costs. The increase in administrative costs more than offset the margins realized on the additional coal sales.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. Revenue from our mining segment increased 9 percent for the nine-month period ended September 30, 2003, compared to the same period in 2002. A 21 percent increase in tons of coal sold was partially offset by lower average prices received. The increase in tons of coal sold was primarily attributable to sales to the Wygen Plant, which began commercial operation in February 2003, and to sales of coal through the train load-out facility.

Operating expenses increased 26 percent or approximately $4.2 million primarily due to higher operating costs related to the increase in production, accruals for taxes and certain other items, and a $2.2 million increase in general and administrative costs. The increase in general and administrative costs was primarily due to an increase in pension, legal and other corporate costs.

Income from continuing operations decreased 26 percent due to an increase in general and administrative and direct mining costs, partially offset by the increase in tons of coal sold in the nine-month period ended September 30, 2003. Net income for 2003 also reflects a $0.3 million after-tax benefit from the change in accounting principle related to the adoption of SFAS 143.

Electric Utility Group

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003		2002
	(in thousands)
Revenue	$	46,268	$	45,291	$	129,238	$	120,786
Operating expenses		31,773		29,316		90,493		77,131

Operating income	$	14,495	$	15,975	$	38,745	$	43,655

Net income	$	6,772	$	8,304	$	18,193	$	22,918

The following table provides certain operating statistics:

	Three Months Ended September 30				Nine Months Ended September 30
	2003		2002		2003		2002

Firm (system) sales - MWh		545,300		510,500		1,498,100		1,466,000
Off-system sales - MWh		204,700		317,600		684,500		688,700

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. Electric utility revenues increased 2 percent for the three-month period ended September 30, 2003, compared to the same period in the prior year. The increase in revenue was primarily due to a 5 percent increase in firm system electric sales, partially offset by an 8 percent decrease in off-system electric sales. Firm residential, commercial, industrial and wholesale electricity revenues increased 6 percent, 3 percent, 1 percent and 6 percent, respectively. Degree days, which is a measure of weather trends, were 12 percent above last year and 45 percent above normal. Off-system electric revenue decreased 8 percent due to a 36 percent decrease in off-system megawatt-hour sales, partially offset by a 43 percent increase in average prices received.

Electric operating expenses increased 8 percent for the three month period ended September 30, 2003, compared to the same period in the prior year. The increase in operating expenses was primarily due to an increase in fuel and purchased power costs and an increase in depreciation expense. Purchased power and fuel costs increased $1.8 million due to higher purchased power costs and gas prices, partially offset by an 87,050 megawatt-hour decrease in gas generation and megawatt-hours purchased. The CIG average price was $4.29/mmBtu for the three months ended September 30, 2003, compared to $1.29/mmBtu for the same period in 2002. The price per megawatt-hour from our gas generation averaged $53.79 for the three months ended September 30, 2003, compared to $37.20 per megawatt-hour for purchased power, thereby making 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 price per megawatt-hour from our gas generation was $23.33 for the three months ended September 30, 2002 compared to $26.54 per megawatt-hour for purchased power for the same time period. Depreciation expense increased $0.4 million primarily due to the depreciation associated with the combustion turbines.

Interest expense increased $0.5 million for the three month period, primarily due to interest associated with the $75 million first mortgage bonds issued in August 2002.

Net income decreased $1.5 million primarily due to the decrease in off-system electric revenue and increases in fuel and purchased power expense, interest expense and depreciation expense, partially offset by an increase in firm system electric sales.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. Electric utility revenues increased 7 percent for the nine-month period ended September 30, 2003, compared to the same period in the prior year. The increase in revenue was primarily due to a 2 percent increase in firm system electric megawatt-hour sales; a 28 percent increase in average prices received for off-system sales offset by a 1 percent decrease in off-system megawatt-hour sales; and increased transmission revenues. Residential and commercial revenues increased 2 percent. Industrial revenues decreased 5 percent, primarily due to the closing of Homestake Gold Mine and Federal Beef Processors.

Electric operating expenses increased 17 percent for the nine-month period ended September 30, 2003 compared to the same period in the prior year. The increase in operating expense was primarily due to a $7.4 million increase in purchased power costs, a $1.8 million increase in fuel expense, and increased depreciation and general and administrative expenses. Purchased power and fuel costs increased primarily due to higher gas prices. The CIG average price was $4.02/mmBtu for the first nine months of 2003, compared to $1.79/mmBtu for the same period in 2002. The price per megawatt-hour from our gas generation averaged $44.92 for the nine months ended September 30, 2003, compared to $33.86 per megawatt-hour for purchased power, thereby making 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 price per megawatt-hour from our gas generation was $24.41 for the nine months ended September 30, 2002 compared to $26.92 per megawatt-hour for purchased power for the same time period. Depreciation expense increased due to additional expense related to combustion turbines. The Lange combustion turbine was placed in service in March 2002. A $1.6 million increase in pension expense contributed to the increase in general and administrative expense.

Interest expense increased $2.6 million for the nine-month period, primarily due to interest associated with the $75 million first mortgage bonds issued in August 2002.

Net income decreased $4.7 million, primarily due to the increase in fuel and purchased power expense, depreciation expense and pension expense, partially offset by an increase in off-system electric and transmission revenues.

Communications Group

	Three Months Ended September 30						Nine Months Ended September 30
	2003			2002			2003			2002
	(in thousands)
Revenue	$	10,136		$	8,392		$	30,595		$	24,155
Operating expenses		10,810			9,770			32,797			30,203

Operating (loss)	$	(674	)	$	(1,378	)	$	(2,202	)	$	(6,048	)

Net loss	$	(1,031	)	$	(1,453	)	$	(3,273	)	$	(5,729	)




Business customers(a)	2,841	2,778	3,061	2,960
Business access lines	11,518	11,271	9,094	8,772
Residential customers	23,900	23,400	21,700	20,760

(a)

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

Our communications business group and segment faces competition from several companies, including Qwest Corporation, Rapid City’s incumbent local exchange carrier, and Midcontinent Communications, the area’s incumbent cable television provider, as well as long distance providers, cellular service providers and Internet service providers. In mid-September 2003, Midcontinent launched an aggressive price marketing campaign targeting our communications customers. We have been successful in retaining our customers in response to this campaign by offering them six months of service at discounted rates in exchange for the execution of 18 to 24 month contracts, resulting in approximately a 3 percent decrease in annual revenues, as of October 31, 2003. As of this date, only one percent of our residential customers had switched service to a competitor. However, if this trend continues or accelerates, it could delay the profitability of our communications segment.

Three Months Ended September 30, 2003 Compared to Three Months Ended September 30, 2002. The communications business group’s net loss for the three-month period ended September 30, 2003 was $1.0 million, compared to $1.5 million in 2002. The performance improvement is due to a 21 percent increase in revenue as a result of a larger customer base and reduced property tax accruals, partially offset by increased cost of sales, administrative and depreciation expense, and a $0.6 million after-tax collection of previously reserved amounts recognized in the three month period ended September 30, 2002.

The total number of customers exceeded 26,700 at the end of September 2003 – a 13 percent increase over the customer base at September 30, 2002, and a 2 percent and 8 percent increase compared to June 30, 2003 and December 31, 2002, respectively.

Nine Months Ended September 30, 2003 Compared to Nine Months Ended September 30, 2002. The communications business group’s net loss for the nine-month period ended September 30, 2003 was $3.3 million, compared to $5.7 million in 2002. The performance improvement is due to a larger customer base, sales of additional services to existing business customers, and the recording of $2.4 million of revenue associated with the 2003 – 2004 Black Hills telephone directory, partially offset by increased cost of sales, directory publishing costs, higher administration, depreciation and tax expenses, and a $0.6 million after-tax collection of previously reserved amounts recognized in the three month period ended September 2002.

The total number of customers exceeded 26,700 at the end of September 2003 – a 13 percent increase compared to September 30, 2002, and a 2 percent and 8 percent increase compared to June 30, 2003 and December 31, 2002, respectively.

Earnings Guidance

Due to many factors affecting our future earnings performance, including the impact of changes in the contract status of the Las Vegas plant, the sale of the hydroelectric power plants in upstate New York, a reduction in anticipated capital deployment in 2003, together with the expected growth in our other businesses, we recently stated that we expect earnings from continuing operations in 2004 to be comparable to 2003 results.

Because of our commitment to a strong balance sheet and reflecting current prospects resulting from prevailing economic conditions, we recently revised our long-term average annual earnings per share growth target to approximately 8 percent. Our long-term growth objective is expected to be achieved through investments in new projects and the expansion of existing operations.

Critical Accounting Policies

IMPAIRMENT OF LONG-LIVED ASSETS

We evaluate the carrying values of our long-lived assets for impairment, including goodwill and other intangibles, whenever indicators of impairment exist, and at least annually for goodwill as required by SFAS 142.

For long-lived assets with finite lives, this evaluation is based upon our projections of anticipated future cash flows (undiscounted and without interest charges) from the assets being evaluated. If the sum of the anticipated future cash flows over a discrete time period is less than the assets’ carrying value, then a permanent non-cash write-down equal to the difference between the assets’ carrying value and the assets’ fair value, is required to be charged to earnings. In estimating future cash flows we generally use internal budgets. Although we believe our estimates of future cash flows are reasonable, different assumptions regarding such cash flows could materially affect our evaluations.

During the third quarter of 2003, due to the termination of the fifteen-year contract with Allegheny Energy Supply Company, LLC for capacity and energy at our Las Vegas Cogeneration II power plant, we evaluated the carrying value of our Las Vegas Cogeneration II power plant which is part of our non-regulated power generation segment. The carrying value of the assets tested for impairment was $237.2 million. We determined, based on our assumptions, the sum of the anticipated future cash flows (undiscounted and without interest charges) was less than the carrying value, and therefore we recognized an impairment of $117.2 million (the difference between the discounted cash flows and the carrying value).

DEFINED BENEFIT PENSION PLAN

We have a noncontributory defined benefit pension plan (the Plan) covering our employees and certain subsidiaries who meet eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. Our funding policy is in accordance with the federal government’s funding requirements. The Plan’s assets are held in trust and consist primarily of equity securities and cash equivalents. The determination of our obligation and expense for pension benefits is dependent on the use of certain assumptions by actuaries in calculating the amounts. Those assumptions include, among others, the expected long-term rate of return on Plan assets, the discount rate, and the rate of increase in compensation levels. The actuaries review the Plan annually and are currently in the process of reviewing our Plan to determine our obligation and our expense for next year.

During the third quarter of 2003 we made a $10.5 million contribution to the Plan. The payment was recorded as a reduction to our accrued pension liability in the line item “Other” in “Deferred credits and other liabilities” on the accompanying Condensed Consolidated Balance Sheets.

In the fourth quarter of 2002, we recorded an $8.9 million accrued pension liability, a $1.8 million intangible asset, and $12.5 million of accumulated other comprehensive loss in accordance with the provisions of SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS 87). We anticipate that substantially all of the accumulated other comprehensive loss will be reduced in the fourth quarter of 2003 upon completion of the actuary’s review, due to the $10.5 million contribution made in the third quarter of 2003, and the return on plan assets for the year and will not affect net income.

The $10.5 million contribution will also significantly reduce the previous actuary forecast of required future cash contributions to the pension plan, which were previously disclosed under the caption “Critical Accounting Policies” in Part II, Item 7 of our 2002 Annual Report on Form 10-K.

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

Liquidity and Capital Resources

Cash Flow Activities

During the nine-month period ended September 30, 2003, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our long-term debt maturities, and to fund a portion of our property additions. We plan to fund future property and investment additions primarily through a combination of operating cash flow, increased short-term debt, long-term debt, and long-term non-recourse project financing.

Cash flows from operations increased $135.0 million for the nine-month period ended September 30, 2003 compared to the same period in the prior year primarily due to the increase in cash provided by earnings from operations, the $114.0 million Las Vegas Cogeneration II power plant sales contract termination, and changes in working capital. During the third quarter of 2003, we announced the 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 Cogeneration II power plant.

During the nine months ended September 30, 2003, we had cash inflows from investing activities of $93.4 million, which includes approximately $186.0 million from the sale of seven hydroelectric power plants located in upstate New York, offset by $86.9 million for property, plant and equipment additions and the acquisition of assets.

During the nine months ended September 30, 2003, we had cash outflows from financing activities of $139.7 million, primarily due to the repayment of debt, offset by the proceeds from a public offering of 4.6 million shares of common stock and the sale of $250 million ten-year notes.

On April 30, 2003, we completed a public offering of 4.6 million shares of common stock at $27 per share. Net proceeds were approximately $118 million after commissions and expenses. The proceeds were used to pay off a $50 million credit facility due in May 2003 and to repay $68 million under our 364-day revolving credit facility which expired on August 26, 2003.

On May 21, 2003, we issued $250 million 6.5 percent ten-year notes. Net proceeds from the note offering were approximately $247 million after the discount, commissions and expenses. The proceeds were used to repay our $35 million term loan due September 30, 2004, all of our short-term borrowings under our $195 million, 364-day revolving credit facility and all of our outstanding notes payable under our $200 million three-year revolving credit facility which expires on August 27, 2004.

In August 2003, we closed on a $225 million multi-year, unsecured revolving credit facility that expires on August 20, 2006. The credit facility replaced the $195 million facility that expired in August 2003 and supplements the $200 million facility that expires in August 2004. We had no borrowings outstanding under these facilities as of September 30, 2003.

In September 2003, we paid off all of the project-level debt and related interest rate swaps totaling $91.1 million, associated with the seven hydroelectric power plants that were sold.

Dividends

Dividends paid on our common stock totaled $0.30 per share in each of the first three quarters of 2003. This reflects a 3.4 percent increase, as approved by our board of directors in January 2003, from the prior periods. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects.

Short-Term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are revolving bank facilities and cash provided by operations. As of September 30, 2003, we had approximately $269.8 million of cash unrestricted for operations and $425 million of credit through revolving bank facilities. Approximately $21.9 million of the cash balance at September 30, 2003 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company. The bank facilities consisted of a $225 million facility due August 20, 2006 and a $200 million facility due August 27, 2004. These bank facilities can be used to fund our working capital needs, for general corporate purposes, and to provide liquidity for a commercial paper program if implemented. At September 30, 2003, 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 $377.3 million at September 30, 2003.

The above bank facilities include covenants that are common in such arrangements. Several of the facilities require that we maintain a consolidated net worth in an amount of not less than the sum of $475 million and 50 percent of the aggregate consolidated net income beginning April 1, 2003; a recourse leverage ratio not to exceed 0.65 to 1.00; and a fixed charge coverage ratio of not less than 1.5 to 1.0. If these covenants are violated, it would be considered an event of default entitling the lender to terminate the remaining commitment and accelerate all principal and interest outstanding. In addition, certain of our interest rate swap agreements include cross-default provisions. These provisions would provide the counterparty the right to terminate the swap agreement and liquidate at a prevailing market rate, in the event of default. As of September 30, 2003, we were in compliance with the above covenants.

The $200 million three-year credit facility that expires in August 2004 previously contained a liquidity covenant that required us to have $30 million of liquid assets as of the last day of each fiscal quarter. This covenant was removed from the credit facility through an amendment in August 2003.

Our liquidity position has been greatly enhanced this year due to the public offering of 4.6 million shares of common stock and $250 million of ten-year notes, the sale of the seven hydroelectric power plants, and the receipt of $114.0 million for the Las Vegas II Cogeneration power plant contract termination (see discussion above under cash flow activities). The common stock and ten-year note offerings were completed in the second quarter of 2003 and provided net proceeds of approximately $365 million which were used to pay off the $50 million credit facility due in May 2003, the $35 million term loan due September 30, 2004, all of our borrowings under our 364-day revolving credit facility which expired on August 26, 2003, and all of our notes payable under our three-year revolving credit facility, which expires on August 27, 2004. The sale of the seven hydroelectric power plants provided approximately $186 million of cash and was used in part to pay off the remaining project-level debt and related interest rate swaps associated with the hydroelectric power plants, which totaled approximately $91 million. The excess proceeds from the sale of the hydroelectric power plants and the $114.0 million termination payment will be used to pay income taxes related to the transactions, to reduce debt and for other corporate purposes.

Our consolidated net worth was $698.6 million at September 30, 2003, which was approximately $204 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, 2003 was 51.7 percent, our total debt leverage (long-term debt and short-term debt) was 52.3 percent, and our recourse leverage ratio was approximately 41.7 percent.

In addition, Enserco Energy Inc., our gas marketing unit, has a $135 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. We provided no guarantee to the lender under this facility. This facility was recently extended to September 30, 2004. At September 30, 2003, there were outstanding letters of credit issued under the facility of $57.0 million, with no borrowing balances outstanding on the facility.

Similarly, Black Hills Energy Resources, Inc., our oil marketing unit, has a $40 million uncommitted, discretionary credit facility. This line of credit provides credit support for the purchases of crude oil by Black Hills Energy Resources. We provided no guarantee to the lender under this facility. At September 30, 2003, Black Hills Energy Resources had letters of credit outstanding of $9.2 million.

On May 13, 2003, our corporate credit rating was downgraded to “BBB-” by Standard and Poor’s Ratings Group. This credit rating downgrade had minimal effect on our interest rates under our credit agreements. Our issuer credit rating is “Baa3” by Moody’s Investors Service. These security ratings are subject to revision and/or withdrawal at any time by the respective rating organizations. None of our current credit agreements contain acceleration triggers. If our credit rating drops below investment grade, however, pricing under these agreements would be affected. Based upon borrowings outstanding at September 30, 2003, a further credit downgrade to BB+ would increase interest expense by an additional $1.5 million a year.

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 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission.

Guarantees

During the first quarter of 2003, a $135 million completion guarantee for the expanded facilities under a construction loan for Black Hills Colorado expired. During the second quarter of 2003, a $50 million guarantee of the secured financing for the Las Vegas II project expired when the associated debt was paid off and $7.5 million of guarantees under certain energy marketing derivative, power and gas agreements expired or were terminated. In addition a new $2.5 million guarantee was issued during the second quarter related to payments under energy marketing derivative, power and gas agreements. During the third quarter of 2003, a $10 million guarantee was issued related to the payment of obligations of Las Vegas Cogeneration Limited Partnership to Sempra Energy Solutions under a Master Power Purchase and Sale Agreement. At September 30, 2003, we had guarantees totaling $190.7 million in place.

Capital Requirements

During the nine months ended September 30, 2003, capital expenditures were approximately $77.9 million. We currently expect capital expenditures for the entire year 2003 to approximate $110 million, which is significantly less than forecasted earlier this year. Management continues active pursuit of appropriate investment opportunities, but presently, no significant asset acquisitions or other capital deployments for new or expanded projects are anticipated to close during the remainder of the year.

RISK FACTORS

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

In March 2003, we received a request for information from the Commodity Futures Trading Commission, or CFTC, calling for the production, among other things, of “all documents relating to natural gas and electricity trading” in connection with the CFTC’s industry wide investigation of trade and trade reporting practices of power and natural gas trading companies. We have cooperated fully with the CFTC producing documents and other materials in response to more specific requests relating to the reporting of natural gas trading information to energy industry publications, conducted our own internal investigation into the accuracy of information that former employees of Enserco Energy Inc., our gas marketing subsidiary, voluntarily reported to trade publications, and provided detailed reports of our investigation to the CFTC.

On July 31, 2003 we announced that a settlement was reached with the CFTC on this investigation, whereby we agreed to pay a civil monetary penalty of $3.0 million (see Note 17 of the accompanying Notes to Condensed Consolidated Financial Statements). Although we agreed to this civil monetary penalty with the CFTC, we cannot guarantee that other legal proceedings, civil or criminal fines or penalties, or other regulatory action related to this issue will not occur which, in turn, could adversely affect our financial condition or results of operations.

Ongoing regulatory industry-wide investigations into energy marketing trading activity and anomalous bidding behavior could adversely affect our business.

FERC and other regulatory agencies continue their industry-wide investigations into inappropriate energy marketing trading activity. FERC recently issued an order commencing an investigation into “anomalous bidding behavior and practices” in the Western markets. FERC Staff will investigate entities that submitted bids for short-term power sales in excess of $250 per megawatt hour in the markets operated by the CAISO and CAPX during the period May 1, 2000, to October 2, 2000. The Company cannot predict the outcome of these investigations and the effect they could have on our business.

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

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

•	consumer demands;

•	technological advances;

•	deregulation;

•	greater availability of natural gas-fired power generation; and

•	other factors.

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

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

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

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

NEW ACCOUNTING PRONOUNCEMENTS

Other than the new pronouncements reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission and those discussed in Note 4 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment.

Forward Looking Statements

Some of the statements in this Form 10-Q include “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions, which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including:

•

the effects on our business resulting from the financial difficulties of other energy companies, including the effects on liquidity in the energy marketing and power generation businesses and markets and perceptions of the energy and energy marketing business;

•

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

•

capital market conditions;

•

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

•

pricing and transportation of commodities;

•

population changes and demographic patterns;

•

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

•

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

•

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

•

weather conditions;

•

competition for retail and wholesale customers;

•

market demand, including structural market changes;

•

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

•

changes in project costs;

•

unanticipated changes in operating expenses or capital expenditures;

•

technological advances by competitors;

•

competition for new energy development opportunities;

•

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

•

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

•

risk factors discussed in this Form 10-Q; and

•

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

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

ITEM

3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following table provides a reconciliation of the activity in energy trading contracts marked to market during the nine month period ended September 30, 2003 (in thousands):




Total fair value of natural gas marketing contract net assets at December 31, 2002	$	3,021
Net cash settled during the nine month period on contracts that existed at
December 31, 2002		(691	)
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, 2003		4,250
Realized gain/(loss) on contracts that existed at December 31, 2002 and were settled
during the nine month period		(6,486	)
Unrealized gain/(loss) on contracts that existed at December 31, 2002 and still exist
at September 30, 2003		2,267

Total fair value of natural gas marketing contract net assets at September 30, 2003	$	2,361

On January 1, 2003, the Company adopted EITF Issue No. 02-3. As described in Notes 3 and 16 of the Notes to Condensed Consolidated Financial Statements in this Form 10-Q, the adoption of EITF 02-3 resulted in certain energy trading activities no longer being accounted for at fair value, therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities and our expected cash flows from those operations. The cumulative effect of the adoption of EITF 02-3 is included in the above reconciliation of fair value of energy trading contracts from December 31, 2002 to September 30, 2003.

At September 30, 2003, we had a mark to fair value unrealized gain of $2.4 million for our natural gas marketing activities with $2.2 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 - 3 years			Total Fair Value

Actively quoted (i.e., exchange-traded) prices	$	3,681		$	380		$	4,061
Prices provided by other external sources		(1,502	)		(198	)		(1,700	)
Modeled		--			--			--

Total	$	2,179		$	182		$	2,361

There have been no material changes in market risk faced by us from those reported in our 2002 Annual Report on Form 10-K filed with the Securities Exchange Commission. For more information on market risk, see Part II, Item 7 in our 2002 Annual Report on Form 10-K, and Note 16 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, 2003. 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 12 in Item 8 of the Company’s 2002 Annual Report on Form 10-K and Note 17 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 17 is incorporated by reference into this item.

Item 6.

Exhibits and Reports on Form 8-K

(a)

Exhibits –

Exhibit

10.1

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

Exhibit

10.2

Compilation of the Amended and Restated 3-year Credit Agreement dated as of August 28, 2001, incorporating the First, Second and Third Amendments.

Exhibit

31.1

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

Exhibit

31.2

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

Exhibit

32.1

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

Exhibit

32.2

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

(b)

Reports on Form 8-K

We have filed or furnished the following Reports on Form 8-K during the quarter ended September 30, 2003:

Form 8-K dated July 18, 2003.

Reported under Item 5, that the Company issued a press release announcing it had entered into a definitive agreement to sell its ownership interests in seven hydroelectric power plants in upstate New York and under Item 7, Exhibits.

Form 8-K dated August 7, 2003.

Reported under Item 7, Exhibits and Item 12, that the Company issued a press release announcing quarterly results for the quarter ended June 30, 2003.

Form 8-K dated August 20, 2003.

Reported under Item 5, that the Company issued a press release announcing that it entered into a definitive agreement to terminate an existing contract between its subsidiary, Las Vegas Cogeneration II, LLC and Allegheny Energy Supply Company, LLC, a subsidiary of Allegheny Energy, Inc. and under Item 7, Exhibits.

Form 8-K dated August 22, 2003.

Reported under Item 5, that the Company issued a press release announcing the completion of a $215 million three-year revolving credit facility, expiring August 20, 2006. This new credit facility replaces an existing $195 million credit facility and supplements a separate $200 million credit facility, which expires August 20, 2004, and under Item 7, Exhibits.

Form 8-K dated September 23, 2003.

Reported under Item 5, that the Company issued a press release announcing the completion of a transaction terminating a fifteen-year contract with Allegheny Energy Supply Company, LLC.

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

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

Dated: November 13, 2003

EXHIBIT INDEX

Exhibit Number Description

Exhibit

10.1

Exhibit

10.2

Compilation of the Amended and Restated 3-year Credit Agreement dated as of August 28, 2001, incorporating the First, Second and Third Amendments.

Exhibit

31.1

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

Exhibit

31.2

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

Exhibit

32.1

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

Exhibit

32.2

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

Black Hills - 10-Q quarterly report FY

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)

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

Results of Operations

Liquidity and Capital Resources

NEW ACCOUNTING PRONOUNCEMENTS

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Black Hills - 10-Q quarterly report FY

BLACK HILLS CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (unaudited)

BLACK HILLS CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS(unaudited)

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

Results of Operations

Liquidity and Capital Resources

NEW ACCOUNTING PRONOUNCEMENTS

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BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)

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