Black Hills (BKH) 10-Q 2005 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2005.

OR

o 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 o

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

Yes x No o

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

Class	Outstanding at July 29, 2005
Common stock, $1.00 par value	32,750,462 shares

TABLE OF CONTENTS

		Page
PART 1.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income –
	Three and Six Months Ended June 30, 2005 and 2004	3
	Condensed Consolidated Balance Sheets –
	June 30, 2005, December 31, 2004 and June 30, 2004	4
	Condensed Consolidated Statements of Cash Flows –
	Six Months Ended June 30, 2005 and 2004	5
	Notes to Condensed Consolidated Financial Statements	6-23
Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	24-40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41-43
Item 4.	Controls and Procedures	43
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44-45
Item 4.	Submission of Matters to a Vote of Security Holders	45-46
Item 6.	Exhibits	47
	Signatures	48
	Exhibit Index	49

2

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	(in thousands, except per share amounts)
Operating revenues	$	309,443	$	268,937	$	605,462	$	534,809
Operating expenses:
Fuel and purchased power		205,478		182,100		396,456		355,006
Operations and maintenance		20,545		20,554		40,119		40,192
Administrative and general		19,817		14,227		41,502		30,409
Depreciation, depletion and amortization		20,768		18,020		40,861		36,890
Taxes, other than income taxes		8,660		7,466		16,820		15,598
		275,268		242,367		535,758		478,095
Operating income		34,175		26,570		69,704		56,714
Other income (expense):
Interest expense		(13,472)		(11,772)		(25,333)		(25,200)
Interest income		638		341		1,028		733
Other income, net		392		145		680		404
		(12,442)		(11,286)		(23,625)		(24,063)
Income from continuing operations before equity in
earnings (losses) of unconsolidated subsidiaries,
minority interest and income taxes		21,733		15,284		46,079		32,651
Equity in earnings (losses) of unconsolidated subsidiaries		2,879		(759)		4,354		(1,008)
Minority interest		(65)		(44)		(125)		(86)
Income taxes		(8,507)		(4,760)		(17,516)		(10,058)
Income from continuing operations		16,040		9,721		32,792		21,499
Income (loss) from discontinued operations, net of taxes		(1,070)		1,794		(2,082)		(198)
Net income		14,970		11,515		30,710		21,301
Preferred stock dividends		(80)		(78)		(159)		(166)
Net income available for common stock	$	14,890	$	11,437	$	30,551	$	21,135
Weighted average common shares outstanding:
Basic		32,562		32,404		32,503		32,348
Diluted		33,203		32,951		33,121		32,884
Earnings per share:
Basic–
Continuing operations	$	0.49	$	0.30	$	1.00	$	0.66
Discontinued operations		(0.03)		0.05		(0.06)		(0.01)
Total	$	0.46	$	0.35	$	0.94	$	0.65
Diluted–
Continuing operations	$	0.48	$	0.30	$	0.99	$	0.66
Discontinued operations		(0.03)		0.05		(0.06)		(0.01)
Total	$	0.45	$	0.35	$	0.93	$	0.65
Dividends paid per share of common stock	$	0.32	$	0.31	$	0.64	$	0.62

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

3

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

	June 30		December 31		June 30
	2005		2004		2004
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	60,628	$	64,506	$	104,235
Restricted cash		700		3,069		—
Receivables (net  of allowance for doubtful accounts of $5,292; $4,196 and $7,080, respectively)		277,994		251,945		209,776
Materials, supplies and fuel		106,675		88,475		82,094
Derivative assets		27,838		47,977		26,827
Prepaid income taxes		—		3,978		1,380
Deferred income taxes		1,840		4,237		4,879
Other assets		7,648		7,120		4,667
Assets of discontinued operations		—		117,861		122,215
		483,323		589,168		556,073
Investments		24,253		24,436		27,129
Property, plant and equipment		1,954,660		1,805,768		1,760,041
Less accumulated depreciation and depletion		(494,645)		(468,840)		(433,058)
		1,460,015		1,336,928		1,326,983
Other assets:
Derivative assets		1,017		593		445
Goodwill		30,144		30,144		30,144
Intangible assets (net of accumulated amortization of $23,415; $21,744 and $20,081, respectively)		35,017		36,688		38,350
Other		51,825		38,206		35,543
		118,003		105,631		104,482
	$	2,085,594	$	2,056,163	$	2,014,667
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	255,192	$	196,018	$	188,720
Accrued liabilities		64,883		63,795		51,500
Derivative liabilities		36,425		43,206		33,154
Notes payable		13,000		24,000		—
Current maturities of long-term debt		11,609		16,166		15,868
Accrued income taxes		16,404		7,799		5,816
Liabilities of discontinued operations		—		7,679		8,305
		397,513		358,663		303,363
Long-term debt, net of current maturities		674,860		733,581		791,184
Deferred credits and other liabilities:
Deferred income taxes		168,079		159,623		136,208
Derivative liabilities		2,083		206		1,827
Other		87,487		63,490		62,342
		257,649		223,319		200,377
Minority interest in subsidiaries		4,960		4,835		4,775
Stockholders’ equity:
Preferred stock – no par Series 2000-A; 21,500 shares authorized; 6,839 issued and outstanding		7,167		7,167		7,167
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized; Issued 32,811,919;
32,595,285 and 32,571,365 shares, respectively		32,812		32,595		32,571
Additional paid-in capital		390,433		384,439		383,170
Retained earnings		331,697		322,009		305,626
Treasury stock at cost – 74,330; 117,567 and 112,885 shares, respectively		(1,918)		(2,838)		(2,707)
Accumulated other comprehensive loss		(9,579)		(7,607)		(10,859)
		743,445		728,598		707,801
Total stockholders’ equity		750,612		735,765		714,968
	$	2,085,594	$	2,056,163	$	2,014,667

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

4

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(unaudited)

	Six Months Ended
	June 30
	2005		2004
	(in thousands)
Operating activities:
Net income available for common	$	30,551	$	21,135
Adjustments to reconcile net income available for common to net cash provided by operating activities:
Loss from discontinued operations		2,082		198
Change in provision for valuation allowances		(365)		309
Depreciation, depletion and amortization		40,861		36,890
Net change in derivative assets and liabilities		11,617		(35)
Deferred income taxes		9,268		10,282
Distributed (undistributed) earnings in associated companies		(2,188)		81
Minority interest		125		86
Change in operating assets and liabilities, net of acquisition-
Accounts receivable and other current assets		(24,120)		(29,566)
Accounts payable and other current liabilities		58,637		15,516
Other operating activities		8,622		3,791
		135,090		58,687
Investing activities:
Property, plant and equipment additions		(63,775)		(34,427)
Proceeds from sale of assets		103,010		—
Payment for acquisition, net of cash acquired		(67,331)		—
Other investing activities		5,099		3,165
		(22,997)		(31,262)
Financing activities:
Dividends paid		(20,863)		(20,076)
Common stock issued		6,211		3,046
Decrease in short-term borrowings, net		(11,000)		—
Long-term debt – repayments		(89,666)		(79,066)
Other financing activities		(653)		149
		(115,971)		(95,947)
Decrease in cash and cash equivalents		(3,878)		(68,522)
Cash and cash equivalents:
Beginning of period		64,506		172,757
End of period	$	60,628	$	104,235
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest	$	25,665	$	26,903
Net income taxes refunded	$	(1,632)	$	(18,652)
Common stock issued in conversion of preferred shares	$	—	$	976

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

5

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2004 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 of America 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 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the June 30, 2005, December 31, 2004 and June 30, 2004 financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2005, are not necessarily indicative of the results to be expected for the full year. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

(2) RECLASSIFICATIONS

Certain 2004 amounts in the financial statements have been reclassified to conform to the 2005 presentation. These reclassifications did not have an effect on the Company’s total stockholders’ equity or net income available for common stock as previously reported.

(3) STOCK-BASED COMPENSATION

At June 30, 2005, the Company had one stock-based employee compensation plan under which it can grant stock options to its employees and two prior plans with stock options outstanding. 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.

6

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				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Net income available for common stock, as reported	$	14,890	$	11,437	$	30,551	$	21,135
Deduct: Total stock-based employee compensation
expense determined under fair value based method
for all awards, net of related tax effects		(122)		(132)		(263)		(320)
Pro forma net income available for common stock	$	14,768	$	11,305	$	30,288	$	20,815
Earnings per share:
As reported–
Basic
Continuing operations	$	0.49	$	0.30	$	1.00	$	0.66
Discontinued operations		(0.03)		0.05		(0.06)		(0.01)
Total	$	0.46	$	0.35	$	0.94	$	0.65
Diluted
Continuing operations	$	0.48	$	0.30	$	0.99	$	0.66
Discontinued operations		(0.03)		0.05		(0.06)		(0.01)
Total	$	0.45	$	0.35	$	0.93	$	0.65
Pro forma–
Basic
Continuing operations	$	0.49	$	0.30	$	0.99	$	0.65
Discontinued operations		(0.03)		0.05		(0.06)		(0.01)
Total	$	0.46	$	0.35	$	0.93	$	0.64
Diluted
Continuing operations	$	0.48	$	0.30	$	0.98	$	0.65
Discontinued operations		(0.03)		0.05		(0.06)		(0.01)
Total	$	0.45	$	0.35	$	0.92	$	0.64

7

(4) RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS No. 123 (Revised 2004)

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (Revised 2004) “Share Based Payment” (SFAS 123 (Revised 2004)). SFAS 123 (Revised 2004) requires the measurement and recognition of the cost of employee services received in exchange for an award of equity instruments, based on the grant-date fair value of the award. The cost is to be recognized over the requisite service period. In April 2005, the Securities and Exchange Commission (SEC) adopted a final rule amending the effective date of SFAS 123 (Revised 2004) to the first interim or annual reporting period of the fiscal year beginning after June 15, 2005. The Company currently accounts for its employee equity compensation stock option plans under the provisions of APB No. 25 and no stock-based employee compensation cost is reflected in net income (see Note 3, Stock-Based Compensation). The effect of adoption of SFAS 123 (Revised 2004) will be to recognize compensation expense for the fair value of the stock options granted at the grant date. Total stock-based employee compensation expense, net of related tax effects, would have been $0.1 million for the three month periods ending June 30, 2005 and 2004, and $0.3 million for the six month periods ending June 30, 2005 and 2004, had the Company applied the fair value recognition provisions of SFAS 123 during those periods.

FIN 47

In March 2005 the FASB issued FIN 47, “Accounting for Conditional Asset Retirement Obligations.” This interpretation clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” (SFAS 143) refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred – generally upon acquisition, construction, or development and (or) through the normal operation of the asset. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists.

The Company has identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in its Oil and gas segment and reclamation of its coal mining sites in its Coal mining segment. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company is currently evaluating the effect of FIN 47 on the Company’s consolidated results of operations, financial position and cash flows.

EITF Issue No. 04-6

On March 17, 2005, the Emerging Issues Task Force (EITF) issued EITF Issue No. 04-6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” (EITF 04-6). EITF 04-6 provides that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005. The Company does not believe the adoption of EITF 04-6 will have a material impact on the Company’s consolidated results of operations, financial position and cash flows.

8

Proposed Accounting Rules for Uncertain Tax Positions

On July 14, 2005, the FASB published an Exposure Draft of a proposed Interpretation, “Accounting for Uncertain Tax Positions”. The Exposure Draft would apply to all tax positions accounted for in accordance with FASB Statement No. 109, “Accounting for Income Taxes” and would establish specific criteria that must be met for benefits of an uncertain tax position to be recognized in the financial statements. Management is currently evaluating the potential impact the proposed Interpretation would have on the Company’s consolidated financial statements and will monitor the FASB’s progress towards finalizing this Exposure Draft. The Exposure draft proposes an effective date of the close of the first fiscal year ending after December 15, 2005 with the impact of adoption to be reported as a cumulative effect of an accounting change.

(5) MATERIALS, SUPPLIES AND FUEL

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

	June 30,		December 31,		June 30,
Major Classification	2005		2004		2004
Materials and supplies	$	23,779	$	21,404	$	20,185
Fuel for generation		4,081		2,211		1,302
Gas and oil held by energy marketing		78,815		64,860		60,607
Total materials, supplies and fuel	$	106,675	$	88,475	$	82,094

(6) ASSET RETIREMENT OBLIGATIONS

In accordance with SFAS 143, the Company has identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells in our Oil and gas segment and reclamation of our coal mining sites in our Coal mining segment.

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

	Balance at		Liabilities		Liabilities				Cash Flow		Balance at
	12/31/04		Incurred		Settled		Accretion		Revisions		6/30/05
Oil and gas	$	7,942	$	—	$	—	$	276	$	—	$	8,218
Coal mining		15,867		234		(55)		287		—		16,333
Total	$	23,809	$	234	$	(55)	$	563	$	—	$	24,551

9

(7) RECOVERED/RECOVERABLE PURCHASED ELECTRIC AND GAS ENERGY COSTS –

NET

The Company’s electric and gas subsidiary, Cheyenne Light, Fuel & Power (CLF&P), recovers purchased power and natural gas costs from customers through an electric cost adjustment (ECA) and gas cost adjustment (GCA) mechanism. Each year CLF&P files with the Wyoming Public Service Commission (WPSC) an ECA, effective January 1, and a GCA, effective October 1, to be included in tariff rates for that following year. The ECA and GCA are based on forecasts of the upcoming year’s energy costs and recovery of prior year unrecovered costs. To the extent that energy costs are under recovered or over recovered during the year, they are recorded as a regulatory deferred asset or liability, respectively. These deferred energy balances are interest bearing. As of June 30, 2005, the Company had a deferred energy asset balance of approximately $6.0 million, which is included in “Other” under “Other assets” on the accompanying Condensed Consolidated Balance Sheet.

(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 (in thousands):

Period ended June 30, 2005	Three Months			Six Months
			Average			Average
	Income		Shares	Income		Shares
Income from continuing operations	$	16,040		$	32,792
Less: preferred stock dividends		(80)			(159)
Basic – available for common shareholders		15,960	32,562		32,633	32,503
Dilutive effect of:
Stock options		—	170		—	147
Convertible preferred stock		80	195		159	195
Estimated contingent shares issuable for prior acquisition		—	159		—	159
Others		—	117		—	117
Diluted – available for common shareholders	$	16,040	33,203	$	32,792	33,121

Period ended June 30, 2004	Three Months			Six Months
			Average			Average
	Income		Shares	Income		Shares
Income from continuing operations	$	9,721		$	21,499
Less: preferred stock dividends		(78)			(166)
Basic – available for common shareholders		9,643	32,404		21,333	32,348
Dilutive effect of:
Stock options		—	103		—	109
Convertible preferred stock		78	195		166	195
Estimated contingent shares issuable for prior acquisition		—	158		—	158
Others		—	91		—	74
Diluted – available for common shareholders	$	9,721	32,951	$	21,499	32,884

10

(9) COMPREHENSIVE INCOME

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

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Net income	$	14,970	$	11,515	$	30,710	$	21,301
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges		480		(984)		(4,166)		(4,273)
Reclassification adjustments on cash flow
hedges settled and included in net income		2,035		2,805		2,179		4,590
Unrealized gain (loss) on available-for-sale
securities		—		(33)		15		(54)
Comprehensive income	$	17,485	$	13,303	$	28,738	$	21,564

(10) CHANGES IN COMMON STOCK

Other than the following transactions, the Company has no other material changes in its common stock, as reported in Note 10 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K.

•              Effective January 1, 2005, the Company adopted a performance share award plan in which certain officers of the Company are participants. Performance shares are awarded based on the Company’s total shareholder return over designated performance periods as measured against a selected peer group. In addition, the Company’s stock price must also increase during the performance periods. Target grants of 41,499 performance shares were made for the January 1, 2005 through December 31, 2007 performance period.

Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50^th percentile of the selected peer group. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50 percent in the form of cash and 50 percent in the form of common stock.

Grants under this performance share plan are in addition to grants under two other performance share plans awarded March 1, 2004. Compensation expense recognized for all of the performance share awards for the three and six months ended June 30, 2005 was $0.6 million and $0.9 million, respectively.

•              The Company granted 14,400 stock options at a weighted-average exercise price of $30.71 per share.

•              205,678 stock options were exercised at a weighted-average price of $23.61 per share.

•              The Company acquired 11,964 shares of treasury stock related to the share withholding provisions of the Restricted Stock Plan for the payment of taxes associated with the vesting of shares of restricted stock for certain officers and key employees.

11

•             The Company granted 42,913 restricted common shares and 2,594 restricted stock units during the first six months of 2005. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $1.4 million will be recognized over the three-year vesting period.

•             The Company issued 9,557 shares as a payout of Board of Directors Common Stock Equivalents upon a director’s retirement.

(11) CHANGES IN LONG-TERM DEBT

On January 21, 2005, the Company acquired CLF&P from Xcel Energy Inc. Included in the purchase price of CLF&P was the assumption of $24.6 million in long-term debt consisting of First Mortgage Bonds. The debt consists of $7.0 million of variable rate Industrial Development Revenue Bonds due in 2021, $10.0 million variable rate Industrial Development Revenue Bonds due 2027 and $7.6 million 7.5 percent Bonds due 2024. Substantially all properties of CLF&P are subject to the liens securing the First Mortgage Bonds. Annual maturities on the First Mortgage Bonds for the next five years are $0.2 million a year.

In June 2005, the Company repaid $81.5 million of long-term debt (including current maturities) outstanding on the project level financing at our Fountain Valley facility. Upon repayment of the debt, the Company expensed approximately $0.4 million of associated, unamortized deferred financing costs and approximately $0.3 million related to an interest rate swap previously designated as a cash flow hedge of this debt.

(12) GUARANTEES

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

As of June 30, 2005, the Company had the following guarantees in place (in thousands):

	Outstanding at	Year
Nature of Guarantee	June 30, 2005	Expiring
Guarantee payments under the Las Vegas Cogen I Power Purchase		Upon 5 days
and Sales Agreement with Sempra Energy Solutions	$  10,000	written notice
Guarantee of certain obligations under Enserco’s credit facility	3,000	2005
Guarantee of obligation of Las Vegas Cogen II (LVII) under an
interconnection and operation agreement	750	2005
Guarantee payments of Black Hills Power under various
transactions with Idaho Power Company	250	2006
Guarantee obligations under the Wygen Plant Lease	111,018	2008
Guarantee payment and performance under credit agreements for
two combustion turbines	27,214	2010
Guarantee payments of Las Vegas Cogen II to Nevada Power
Company under a power purchase agreement	5,000	2013
Indemnification for subsidiary reclamation/surety bonds	25,000	Ongoing
	$  182,232

12

(13) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The Company has two noncontributory defined benefit pension plans (Plans). One Plan covers the employees of the Company and the following subsidiaries who meet certain eligibility requirements: Black Hills Power, Inc., Wyodak Resources Development Corp., and Black Hills Exploration and Production. The other Plan covers the employees of the Company’s subsidiary, CLF&P, who meet certain eligibility requirements.

The components of net periodic benefit cost for the two Plans are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Service cost	$	576	$	443	$	1,152	$	886
Interest cost		995		909		1,990		1,818
Expected return on plan assets		(1,157)		(1,129)		(2,314)		(2,258)
Amortization of prior service cost		54		58		108		116
Amortization of net loss		296		375		592		750
Net periodic benefit cost	$	764	$	656	$	1,528	$	1,312

The Company does not anticipate that it will need to make contributions to the Plans in the 2005 fiscal year.

Supplemental Nonqualified Defined Benefit Plans

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

The components of net periodic benefit cost for the Supplemental Plans are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Service cost	$	86	$	134	$	172	$	268
Interest cost		252		241		504		482
Amortization of prior service cost		2		2		4		4
Amortization of net loss		157		187		314		374
Net periodic benefit cost	$	497	$	564	$	994	$	1,128

The Company anticipates that it will need to make contributions to the Supplemental Plans for the 2005 fiscal year of approximately $0.3 million. The contributions are expected to be made in the form of benefit payments.

13

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in the Company’s Postretirement Healthcare Plans (Healthcare Plans) and who meet certain eligibility requirements are entitled to postretirement healthcare benefits. These financial statements and this Note do not reflect the effects of the 2003 Medicare Act on the Healthcare Plans.

The components of net periodic benefit cost for the Healthcare Plans are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Service cost	$	185	$	140	$	370	$	280
Interest cost		232		166		464		332
Amortization of net transition obligation		37		37		74		74
Amortization of prior service cost		(6)		(6)		(12)		(12)
Amortization of net loss		25		47		50		94
Net periodic benefit cost	$	473	$	384	$	946	$	768

The Company anticipates that it will make contributions to the Healthcare Plans for the 2005 fiscal year of approximately $0.2 million; the contributions are expected to be made in the form of benefits paid.

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

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of June 30, 2005, substantially all of the Company’s operations and assets are located within the United States. On June 30, 2005, the Company completed the sale of its subsidiary, Black Hills FiberSystems, Inc., which operated as the Company’s Communications segment (see Note 18). The financial information of the Communications segment has been reclassified into Discontinued operations on the accompanying condensed consolidated financial statements. With the sale of the communications segment, the Company now conducts its operations through the following six reporting segments: Wholesale Energy group consisting of the following segments: Coal 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 and transportation, 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 power and capacity to wholesale customers with plants concentrated in Colorado, Nevada, Wyoming and California; and Retail Services group consisting of the following segments: Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Electric and gas utility, acquired January 21, 2005, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity.

Segment information follows the same accounting policies as described in Note 23 of the Company’s 2004 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.

14

Segment information included in the accompanying Condensed Consolidated Statements of Income is as follows (in thousands):

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Three Month Period Ended
June 30, 2005
Wholesale energy:
Coal mining	$	5,307	$	3,053	$	1,728
Oil and gas		19,662		—		4,277
Energy marketing and transportation		172,321		—		2,689
Power generation		40,128		—		6,101
Retail services:
Electric utility		41,910		351		3,409
Electric and gas utility		27,459		—		643
Corporate		289		—		(2,807)
Intersegment eliminations		—		(1,037)		—
Total	$	307,076	$	2,367	$	16,040

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Three Month Period Ended
June 30, 2004
Wholesale energy:
Coal mining	$	4,771	$	2,772	$	1,358
Oil and gas*		10,877		89		764
Energy marketing and transportation		170,896		—		1,606
Power generation		40,355		—		5,233
Retail services:
Electric utility		39,788		21		1,816
Corporate		157		596		(1,050)
Intersegment eliminations		—		(1,385)		(6)
Total	$	266,844	$	2,093	$	9,721

__________________________

*Includes a $(2.5) million revenue accrual correction

15

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Six Month Period Ended
June 30, 2005
Wholesale energy:
Coal mining	$	10,180	$	6,199	$	3,216
Oil and gas		38,703		—		9,237
Energy marketing and transportation		333,452		—		5,615
Power generation		78,290		—		9,987
Retail services:
Electric utility		84,959		449		7,732
Electric and gas utility		54,533		—		1,155
Corporate		554		—		(4,150)
Intersegment eliminations		—		(1,857)		—
Total	$	600,671	$	4,791	$	32,792

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Six Month Period Ended
June 30, 2004
Wholesale energy:
Coal mining	$	10,317	$	5,954	$	3,110
Oil and gas*		27,198		172		4,450
Energy marketing and transportation		335,331		—		5,575
Power generation		75,492		—		3,155
Retail services:
Electric utility		81,414		42		6,852
Corporate		466		1,157		(1,639)
Intersegment eliminations		—		(2,734)		(4)
Total	$	530,218	$	4,591	$	21,499

__________________________

*Includes a $(0.5) million revenue accrual correction

Other than the acquisition and consolidation of CLF&P into the Company’s Condensed Consolidated Balance Sheet (see Note 17), and the reclassification of its Communications segment to Discontinued operations and subsequent sale completed on June 30, 2005 (see Note 18), the Company had no material changes in the assets of its reporting segments, as reported in Note 23 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

16

(15) RISK MANAGEMENT ACTIVITIES

The Company actively manages its exposure to certain market risks as described in Note 2 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K. Details of derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are as follows:

Trading Activities

Natural Gas Marketing

The contract or notional amounts and terms of our natural gas marketing activities and derivative commodity instruments are as follows:

(in thousands of MMbtus)	June 30, 2005			December 31, 2004			June 30, 2004
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)
Natural gas basis swaps purchased		61,431	21		24,942	15		37,861	21
Natural gas basis swaps sold		59,426	16		27,145	15		41,489	21
Natural gas fixed-for-float
swaps purchased		24,532	21		27,274	15		17,253	16
Natural gas fixed-for-float
swaps sold		25,562	16		32,206	12		28,402	18
Natural gas physical purchases		88,729	18		64,799	15		61,301	21
Natural gas physical sales		127,996	53		95,996	58		108,993	64
Natural gas options purchased		7,568	27		9,643	33		4,520	4
Natural gas options sold		7,568	27		9,613	33		4,520	4
(thousands of U.S. dollars)
Canadian dollars purchased	$	4,300	1	$	10,800	1	$	—	—
Canadian dollars sold	$	25,700	7	$	38,000	4	$	19,000	3

Derivatives and certain natural gas marketing activities were marked to fair value on June 30, 2005, December 31, 2004 and June 30, 2004, and the related 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		Non-current		Current		Non-current
	Derivative		Derivative		Derivative		Derivative		Unrealized
	Assets		Assets		Liabilities		Liabilities		Gain (loss)
June 30, 2005	$	27,613	$	1,017	$	30,473	$	1,130	$	(2,973)
December 31, 2004	$	46,177	$	286	$	38,375	$	6	$	8,082
June 30, 2004	$	26,314	$	445	$	26,184	$	404	$	171

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Balance Sheet and the related unrealized gain/loss on the Statement of Income. As of June 30, 2005, December 31, 2004 and June 30, 2004, the market adjustments recorded in inventory were $2.9 million, $(9.0) million and $0.1 million, respectively.

17

Activities Other Than Trading

Crude Oil Marketing

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

	June 30, 2005		December 31, 2004		June 30, 2004
		Maximum		Maximum		Maximum
	Notional	Term in	Notional	Term in	Notional	Term in
(in thousands of barrels)	Amounts	Years	Amounts	Years	Amounts	Years
Crude oil purchased	1,919	0.75	1,669	1.0	2,622	0.5
Crude oil sold	1,878	0.75	1,651	1.0	2,679	0.5

The Company’s crude oil marketing contracts are accounted for under the accrual method of accounting. Settled contract amounts are reported in revenues on a gross basis in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal Versus Net as an Agent” (EITF 99-19) and established industry practice.

In 2004, the EITF initiated a review under EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” to determine if such transactions should be reported on a gross basis or a net basis. In its crude oil marketing activities, the Company uses a type of transaction commonly called a buy/sell, which generally consists of the purchase and sale of crude oil from the same counterparty. In a typical buy/sell transaction, Company A enters into a contract to sell a particular grade of crude oil at a specified location to Company B on a future date, and simultaneously agrees to buy from Company B a particular grade of crude oil at a different location at the same or another specified date.

The characteristics of buy/sell transactions include gross invoicing reflecting the quality and location differences of the crude oil and physical delivery requirements. Nonperformance by one party does not relieve the other party’s obligation to perform under the contract except for events of force majeure. The risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling and counterparty credit risk. Because of these characteristics, the Company reports the sale of the barrels as gross revenues and the purchase of the barrels as gross purchases in accordance with EITF 99-19.

Some registrants in our industry may report buy/sell transactions on a net rather than a gross presentation. The EITF is reviewing these transactions to determine if more specific guidance is needed for determining a net rather than gross presentation in consolidated earnings. While a net presentation of this issue would reduce both the Company’s revenues and purchases, our net income would not be impacted.

18

Oil and Gas Exploration and Production

On June 30, 2005, December 31, 2004 and June 30, 2004, the Company had the following swaps and related balances (in thousands):

											Pre-tax
											Accumulated
		Maximum	Current		Non current		Current		Non current		Other		Pre-tax
		Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
June 30, 2005
Crude oil swaps	240,000	1.00	$	—	$	—	$	4,417	$	873	$	(5,252)	$	(38)
Natural gas swaps	1,985,000	0.50		109		—		949		—		(840)		—
			$	109	$	—	$	5,366	$	873	$	(6,092)	$	(38)
December 31, 2004
Crude oil swaps	360,000	1.00	$	—	$	152	$	3,112	$	—	$	(2,886)	$	(74)
Natural gas swaps	3,810,000	0.50		1,710		155		493		—		1,372		—
			$	1,710	$	307	$	3,605	$	—	$	(1,514)	$	(74)
June 30, 2004
Crude oil swaps	540,000	1.50	$	—	$	—	$	2,635	$	626	$	(3,198)	$	(63)
Natural gas swaps	3,937,009	0.75		57		—		2,004		—		(1,947)		—
			$	57	$	—	$	4,639	$	626	$	(5,145)	$	(63)

________________________

*crude in barrels, gas in MMbtu’s

Based on June 30, 2005 market prices, a $5.2 million loss would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production. These estimated realized losses for the next twelve months were calculated using June 30, 2005 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

On June 30, 2005, December 31, 2004 and June 30, 2004, the Company’s interest rate swaps and related balances were as follows (in thousands):

			Weighted										Pre-tax
			Average										Accumulated
	Current		Fixed	Maximum	Current		Non current		Current		Non current		Other		Pre-tax
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		Loss		(Loss)
June 30, 2005
Swaps on project
and other financings	$	113,000	4.22%	1.25	$	116	$	—	$	528	$	80	$	(154)	$	(338)
December 31, 2004
Swaps on project
financing	$	113,000	4.22%	1.75	$	60	$	—	$	1,226	$	200	$	(1,366)	$	—
June 30, 2004
Swaps on project
financing	$	113,000	4.48%	2.25	$	456	$	—	$	2,331	$	797	$	(2,672)	$	—

Based on June 30, 2005 market interest rates and balances, approximately $0.1 million would be realized and reported in pre-tax earnings 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.

19

In June 2005, the Company repaid approximately $81.5 million of project level financing on its Fountain Valley power facility. The Company has an interest rate swap with a $25 million notional amount that was previously designated as a cash flow hedge of the variable rate interest payments on this project level debt. In accordance with FAS 133, upon repayment of the debt the Company re-designated the interest rate swap as a cash flow hedge and reclassified approximately $0.3 million from Accumulated Other Comprehensive Loss into earnings as additional interest expense. Without hedge designation, future variability in the fair value of this derivative will be recorded as a gain or loss in earnings.

(16) LEGAL PROCEEDINGS

The Company is subject to various legal proceedings, claims and litigation as described in Note 21 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K. There have been no material developments in these proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first six months of 2005.

(17) ACQUISITION

On January 13, 2004, the Company entered into a Stock Purchase Agreement to acquire from Xcel Energy, Inc. all of the outstanding capital stock of its subsidiary, CLF&P. On January 21, 2005, the Company completed this acquisition. The Company purchased all the common stock of CLF&P, including the assumption of outstanding debt of approximately $24.6 million, for approximately $90.7 million. The purchase price has been revised by approximately $(2.2) million to reflect a recent revision to the estimated working capital adjustment included in the purchase payment on the date of the transaction closing.

This acquisition has been accounted for under the purchase method of accounting, and accordingly, the purchase price has been 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 allocations are subject to adjustment, generally within one year of the date of acquisition. Allocation of the purchase price (as revised for the working capital adjustment described above) is as follows (in thousands):

Current assets	$	18,353
Property, plant and equipment		99,275
Deferred assets		16,224
	$	133,852
Current liabilities	$	12,761
Long-term debt		26,388
Deferred tax liabilities		7,503
Long-term liabilities		21,056
	$	67,708
Net assets	$	66,144

The results of operations of CLF&P have been included in the accompanying Condensed Consolidated Financial Statements since the acquisition date.

20

The following pro-forma consolidated results of operations have been prepared as if the CLF&P acquisition had occurred on January 1, 2005 and 2004, respectively (in thousands):

	Three Month Period Ended				Six Month Period Ended
	June 30, 2005		June 30, 2004		June 30, 2005		June 30, 2004
Operating revenues	$	309,443	$	290,435	$	614,640	$	583,486
Income from continuing operations		16,040		10,222		32,971		22,775
Net income		14,970		12,016		30,889		22,577
Earnings per share –
Basic:
Continuing operations	$	0.49	$	0.31	$	1.01	$	0.70
Total	$	0.46	$	0.37	$	0.95	$	0.69
Diluted:
Continuing operations	$	0.48	$	0.31	$	1.00	$	0.69
Total	$	0.45	$	0.37	$	0.93	$	0.69

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

(18) DISCONTINUED OPERATIONS

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

Communications Segment

On April 20, 2005, the Company entered into an agreement to sell its Communications business, Black Hills FiberSystems, Inc. to PrairieWave Communications, Inc. and completed the sale on June 30, 2005. Under the purchase and sale agreement, the Company received a cash payment of approximately $103 million.

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

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Operating revenues	$	12,211	$	11,418	$	21,877	$	19,874
Pre-tax income (loss) from discontinued
operations	$	5,361	$	(255)	$	3,978	$	(3,005)
Pre-tax loss on disposal		(7,235)		—		(7,235)		—
Income tax benefit		914		86		1,410		1,052
	$	(960)	$	(169)	$	(1,847)	$	(1,953)

21

Assets and liabilities of the Communications segment are as follows (in thousands):

	December 31, 2004		June 30, 2004
Current assets	$	5,941	$	6,667
Property, plant and equipment		108,804		111,740
Other non-current assets		57		62
Current liabilities		(6,112)		(6,360)
Other non-current liabilities		(916)		(860)
Net assets	$	107,774	$	111,249

Sale of Pepperell Plant

During the third quarter of 2003, the Company adopted a plan to sell the 40 megawatt gas-fired Pepperell plant. On April 8, 2005, the Company sold the Pepperell plant to an unrelated party, Pepperell Realty LLC for a nominal amount plus the assumption of certain obligations. The sale of this facility was considered an asset sale and the Company retained the deferred tax asset, which was originally classified into Discontinued operations. For business segment reporting purposes, the Pepperell plant results were previously included in the Power generation segment.

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

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Pre-tax loss from discontinued operations	$	(204)	$	(197)	$	(329)	$	(469)
Pre-tax loss on disposal		(39)		—		(39)		—
Income tax benefit		133		68		133		162
Net loss from discontinued operations	$	(110)	$	(129)	$	(235)	$	(307)

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

	December 31		June 30
	2004		2004
Current assets	$	107	$	102
Property, plant and equipment		—		1,064
Non-current deferred tax asset		2,952		2,580
Other current liabilities		(167)		(655)
Non-current liabilities		(484)		(430)
Net assets of discontinued operations	$	2,408	$	2,661

22

Sale of Landrica Development Corp.

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

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

	Three Months Ended		Six Months Ended
	June 30, 2004		June 30, 2004
Pre-tax loss from discontinued operations	$	(4)	$	(40)
Pre-tax gain on disposal		3,229		3,229
Income tax expense		(1,133)		(1,127)
Net income from discontinued operations	$	2,092	$	2,062

(19) SUBSEQUENT EVENT

On July 7, 2005, the 6,839 outstanding shares of the Company’s Preferred Stock Series 2000-A were automatically converted into 195,599 shares of the Company’s common stock. The preferred shares valued at $1,000 per share plus the accrued and unpaid dividends were converted into common shares based upon a $35.00 conversion price. No shares of preferred stock remain outstanding after this transaction.

23

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

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

Business Group	Financial Segment
Wholesale energy group	Power generation
	Oil and gas
	Coal mining
	Energy marketing and transportation
Retail services group	Electric utility
	Electric and gas utility

Our wholesale energy group, Black Hills Energy, Inc., engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing and transportation of fuel products. Our retail services group consists of our electric and gas utilities segments. Our electric utility generates, transmits and distributes electricity to an average of approximately 62,000 customers in South Dakota, Wyoming and Montana. Our electric and gas utility serves approximately 38,000 electric and 31,000 natural gas customers in Cheyenne, Wyoming and vicinity and was acquired on January 21, 2005.

In June 2005, we sold our subsidiary, Black Hills FiberSystems, Inc., previously reported as our Communications segment. In April 2005, we also sold our Pepperell power plant, our last remaining power plant in the eastern region and previously reported in our Power generation segment. In May 2004, we sold our subsidiary, Landrica Development Corp., which held some land and coal enhancement facilities that were previously reported in our Coal mining segment. Prior period results have been reclassified to present the financial information as Discontinued operations.

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 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

24

Results of Operations

Consolidated Results

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

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
Revenues
Wholesale energy	$ 239,785	78%	$ 228,992	85%	$ 465,416	77%	$ 452,929	85%
Retail services	69,369	22	39,788	15	139,492	23	81,414	15
Corporate	289	—	157	—	554	—	466	—
	$ 309,443	100%	$ 268,937	100%	$ 605,462	100%	$ 534,809	100%
Income / (Loss) from Continuing Operations
Wholesale energy	$14,795	92%	$8,961	92%	$28,055	86%	$16,290	76%
Retail services	4,052	25	1,810	19	8,887	27	6,848	32
Corporate	(2,807)	(17)	(1,050)	(11)	(4,150)	(13)	(1,639)	(8)
	$16,040	100%	$9,721	100%	$32,792	100%	$21,499	100%

Discontinued operations in 2005 and 2004 represent the operations of our 40 megawatt Pepperell power plant, which was sold in April, 2005 and Black Hills FiberSystems, Inc., which was sold in June, 2005; and in 2004, represents the operations of Landrica Development Corp., which was sold on May 21, 2004.

Discontinued operations for the three and six months ended June 30, 2005 primarily represent operations and loss on sale of the Communications segment. Operations benefited from discontinuance of depreciation upon entering the definitive agreement to sell, but this reduced depreciation resulted in higher book value than originally anticipated and consequently resulted in a higher after-tax loss on sale than originally estimated. After-tax loss on sale was $4.7 million, or $0.14 per share. See Note 18 of Notes to Condensed Consolidated Financial Statements for further description of our discontinued operations.

On January 21, 2005, we completed the acquisition of Cheyenne Light, Fuel & Power Company (CLF&P), an electric and natural gas utility serving customers in Cheyenne, Wyoming and vicinity. The Company purchased all of the common stock of CLF&P, including the assumption of outstanding debt of approximately $24.6 million, for approximately $91 million. The results of operations of CLF&P have been included in the accompanying Condensed Consolidated Financial Statements from the date of acquisition.

In July 2005, the electric utility experienced an unscheduled outage at its 90 megawatt Neil Simpson II power plant. That plant is expected to be out of service for the month of August. To meet our forecasted needs, we have obtained supplemental purchased power and additional natural gas supplies, which will affect third quarter 2005 financial results. The economic impact of this outage is expected to be in the range of $2.5 million to $3.0 million pre-tax, taking into account increased fuel costs, higher purchased power expenses and reduced coal sales.

25

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004. Revenues for the three months ended June 30, 2005 increased 15 percent, or $40.5 million, compared to the same period in 2004. Increased revenues were primarily the result of the acquisition and consolidation of CLF&P and higher revenues from oil and gas sales as a result of increased production and higher prices received.

Operating expenses increased 14 percent, or $32.9 million, primarily resulting from the cost of operations of CLF&P, and higher depletion and production and severance taxes at our oil and gas segment and increased corporate costs from higher compensation expense and professional fees.

Income from continuing operations increased 65 percent or $6.3 million due primarily to the following:

•      a $1.1 million increase in Energy marketing and transportation earnings;

•      a $0.9 million increase in Power generation earnings;

•      a $3.5 million increase in Oil and gas earnings;

•      a $1.6 million increase in Electric utility earnings; offset by

•      a $1.8 million increase in corporate costs.

See the following discussion of our business segments for more detail on our results of operations.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004. Revenues for the six months ended June 30, 2005 increased 13 percent, or $70.7 million, compared to the same period in 2004. Increased revenues are primarily due to the acquisition and consolidation of CLF&P and a 41 percent increase in revenues at our oil and gas segment.

Operating expenses increased 12 percent, or $57.7 million, primarily due to the cost of operations of CLF&P, increased power costs at our Electric utility and increased administrative and general costs due to increased compensation expense and professional fees. In addition, a $1.0 million pre-tax gain on the sale of assets was recorded as an offset to general and administrative expense in the first quarter of 2004. The gain on sale of assets is included in the 2004 “Corporate” results.

Income from continuing operations increased 53 percent, or $11.3 million, primarily due to the following:

•      a $6.8 million increase in Power generation earnings;

•      a $4.8 million increase in Oil and gas earnings;

•      a $0.9 million increase in Electric utility earnings; offset by

•      a $2.5 million increase in corporate costs.

See the following discussion of our business segments for more detail on our results of operations.

26

A discussion of results of operations from our operating segments is included in the following pages.

The following segment information does not include intercompany eliminations or discontinued operations. Accordingly, 2004 information has been revised as necessary to reclassify information related to operations that were discontinued.

Wholesale Energy Group

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	(in thousands)
Revenue:
Energy marketing and transportation	$	172,321	$	170,896	$	333,452	$	335,331
Power generation		40,128		40,355		78,290		75,492
Oil and gas*		19,662		10,966		38,703		27,370
Coal mining		8,360		7,543		16,379		16,271
Total revenue		240,471		229,760		466,824		454,464
Operating expenses		213,011		209,525		413,492		416,408
Operating income	$	27,460	$	20,235		53,332	$	38,056
Income from continuing operations	$	14,795	$	8,961	$	28,055	$	16,290

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

A discussion of results from our Wholesale Energy group’s operating segments follows:

Energy Marketing and Transportation

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	(in thousands)
Revenue	$	172,321	$	170,896	$	333,452	$	335,331
Operating income		3,952		2,592		8,661		8,892
Income from continuing operations		2,689		1,606		5,615		5,575

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

	Three Months Ended		Six Months Ended
	June 30		June 30
	2005	2004	2005	2004
Natural gas physical sales – MMbtus	1,562,600	1,040,000	1,460,700	1,126,700
Natural gas financial sales - MMbtus	742,200	512,800	708,700	450,400
Crude oil – barrels	35,700	51,000	35,600	50,600

27

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004. Revenue increases from crude oil marketing were more than offset by a decrease in oil transportation revenues, due to the suspension of shipments for routine regulatory testing of the Millennium pipeline system in June 2005. Shipments of crude oil through the pipeline resumed early August 2005.

Income from continuing operations increased $1.1 million primarily due to a $3.4 million unrealized mark-to-market gain for the quarter ended June 30, 2005, compared to a $0.1 million unrealized gain in the second quarter of 2004, resulting in a quarter-over-quarter, pre-tax increase of $3.3 million in unrealized mark-to-market adjustment at our gas marketing operations. (For discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas marketing operations see “Trading Activities” in Part 1, Item 3 of this Form 10-Q.) These items were partially offset by a $1.6 million decrease in realized gas marketing margins received and lower oil marketing and transportation volumes.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004. Revenue decreases from crude oil marketing were more than offset by a decrease in the cost of crude oil sold, resulting in increased crude oil marketing margins. Oil transportation revenues decreased due to the suspension of shipments for routine regulatory testing of the Millennium pipeline system in June 2005. Shipments of crude oil through the pipeline resumed early August 2005.

Income from continuing operations remained flat with the prior year. A $0.3 million unrealized mark-to-market gain for the six months ended June 30, 2005, compared to a $0.2 million unrealized mark-to-market loss in the six months ended June 30, 2004, resulted in a year-over-year, pre-tax increase of $0.5 million in unrealized mark-to-market adjustments at our gas marketing operations. Realized gas marketing margins increased $0.1 million.

Power Generation

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	(in thousands)
Revenue	$	40,128	$	40,355	$	78,290	$	75,492
Operating income		14,306		14,780		26,074		18,373
Income from continuing operations		6,101		5,233		9,987		3,155

	June 30
	2005	2004
Independent power capacity:
MWs of independent power capacity in service	964	964

	Three Months Ended		Six Months Ended
	June 30		June 30
	2005	2004	2005	2004
Contracted fleet plant availability	98.1%	98.3%	98.7%	98.4%

28

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004. Revenues in the second quarter of 2005 decreased $0.2 million compared to revenues in the second quarter of 2004. Decreased revenues at our Las Vegas facility were partially offset by increased revenues at our Harbor facility, primarily due to a new three-year tolling agreement which commenced April 1, 2005.

Income from continuing operations increased $0.9 million. Increased earnings were the result of increased income from equity investments due to the impact of mark-to-market adjustments at certain power fund investments that use a fair value method of accounting, partially offset by increased interest expense primarily related to a $0.7 million charge for the write-off of certain deferred costs associated with the project financing debt repaid during the quarter.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004. Revenues increased 4 percent in the six months ended June 30, 2005 compared to the same period in 2004. The increased revenues are primarily attributable to increased revenues at our Las Vegas II and Harbor facilities. In the first six months of 2005, our Las Vegas II facility sold capacity and energy to Nevada Power Company under a long-term tolling arrangement, which became effective April 1, 2004, as opposed to selling power into the market on a merchant basis for the first three months of 2004, when economic to do so. Revenues from our Harbor facility increased due to a new three-year tolling agreement, which commenced April 1, 2005.

Income from continuing operations increased $6.8 million. Increased earnings were the result of higher revenues and increased income from equity investments due to the impact of mark-to-market adjustments at certain power fund investments that use a fair value method of accounting, partially offset by increased interest expense related to a $0.7 million charge for the write-off of certain deferred costs associated with the project financing debt repaid during the second quarter of 2005. In addition, the Las Vegas II facility incurred fuel costs in the first three months of 2004, before the new, long-term tolling arrangement took effect.

Oil and Gas

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	(in thousands)
Revenue*	$	19,662	$	10,966	$	38,703	$	27,370
Operating income		7,172		1,366		14,795		7,259
Income from continuing operations		4,277		764		9,237		4,450

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

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

	Three Months Ended		Six Months Ended
	June 30		June 30
	2005	2004	2005	2004
Fuel production:
Barrels of oil sold	104,600	119,800	200,400	234,100
Mcf of natural gas sold	2,816,000	2,220,500	5,705,800	4,614,900
Mcf equivalent sales	3,443,600	2,939,300	6,908,200	6,019,500

29

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004. Revenue from oil and gas increased 79 percent for the three months ended June 30, 2005 compared to the three months ended June 30, 2004. Gas volumes sold increased 27 percent primarily due to increased production from recently completed wells, and oil volumes sold decreased 13 percent primarily due to a normal decline in our mature Wyoming oil field and reduced opportunities for enhanced oil recovery activities. Average gas and oil prices received, net of hedges, in the three months ended June 30, 2005 were $5.58/Mcf and $32.87/bbl, respectively, compared to $4.23/Mcf and $23.67/bbl, respectively, in the same period of 2004.

Total operating expenses increased 30 percent primarily due to increased production expenses related to the additional sales volumes. The 2005 lease operating expenses per Mcfe sold (LOE/MCFE) for the three month period increased 8 percent from $0.95/Mcfe in 2004 to $1.03/Mcfe in 2005 due to increased production activities in the second quarter of 2005. In addition, the second quarter of 2005 included workover and other LOE activities which were delayed from the first three months of 2005 due to inclement weather conditions. Depletion expense per Mcfe increased 39 percent over the prior year from $0.84/Mcfe in 2004 to $1.17/Mcfe in 2005. This increase is primarily a function of increases in average development costs per Mcfe as we develop existing fields. In addition, quarterly differences in depletion rates are influenced by the timing of additions to our cost pool when compared to the prior year.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004. Revenues from oil and gas increased 41 percent for the six months ended June 30, 2005 compared to the six months ended June 30, 2004. Gas volumes sold increased 24 percent due to increased production from recently completed wells, and oil volumes sold decreased 14 percent primarily due to a normal decline in our mature Wyoming oil field and reduced opportunities for enhanced oil recovery activities. Average gas and oil prices received, net of hedges, in the six months ended June 30, 2005 were $5.47/Mcf and $32.80/bbl, respectively, compared to $4.30/Mcf and $24.46/bbl, respectively, in the same period of 2004.

Total operating expenses increased 19 percent primarily due to increased production expenses related to the additional sales volumes. The 2005 lease operating expenses per Mcfe sold (LOE/MCFE) for the six month period decreased 3 percent from $0.95/Mcfe in 2004 to $0.92/Mcfe in 2005 due to production efficiencies realized from an increase in productive wells placed in service. Depletion expense per Mcfe increased 19 percent over the prior year from $0.91/Mcfe in 2004 to $1.08/Mcfe in 2005. This increase is primarily a function of increases in average development costs per Mcfe as we develop existing fields.

Coal Mining

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	(in thousands)
Revenue	$	8,360	$	7,543	$	16,379	$	16,271
Operating income		2,030		1,497		3,802		3,532
Income from continuing operations		1,728		1,358		3,216		3,110

The following is a summary of coal sales quantities:

	Three Months Ended		Six Months Ended
	June 30		June 30
	2005	2004	2005	2004
Fuel production:
Tons of coal sold	1,148,400	1,071,100	2,301,700	2,274,700

30

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004. Revenue from our coal mining segment increased 11 percent for the three month period ended June 30, 2005, compared to the same period in 2004. The increase in revenue was primarily attributable to increased production in 2005 relative to temporarily lower production levels caused by scheduled and unscheduled plant outages in the second quarter of 2004. The Wyodak plant, operated by PacifiCorp, has postponed a planned 2005 major maintenance outage and rescheduled the outage for 2006.

Operating expenses increased 5 percent or approximately $0.3 million, primarily due to increased production costs partially offset by lower depletion rates.

Income from continuing operations increased 27 percent primarily due to the increase in revenues and lower depletion costs, partially offset by increased production-related costs.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004. Revenue from our coal mining segment increased 1 percent for the six month period ended June 30, 2005 compared to the same period in 2004. Tons sold in the six month period ended June 30, 2005 increased 1 percent over the prior period. The Wyodak plant incurred unscheduled outages during the first three months of 2005.

Operating expenses decreased 1 percent for the six month period ended June 30, 2005 compared to 2004. Increased compensation and production costs were offset by lower depletion rates.

Income from continuing operations increased 3 percent due to the increase in revenues and lower depletion costs, partially offset by increased compensation and production costs.

Retail Services Group

Electric Utility

	Three Months Ended				Six Months Ended
	June 30				June 30
	2005		2004		2005		2004
	(in thousands)
Revenue	$	42,261	$	39,809	$	85,408		$	81,456
Operating expenses		34,141		33,249		67,793			63,488
Operating income	$	8,120	$	6,560	$	17,615		$	17,968
Income from continuing operations and net income	$	3,409	$	1,816	$	7,732		$	6,852

31

The following tables provide certain operating statistics:

	Electric Revenue
	(in thousands)
	Three Months Ended June 30			Six Months Ended June 30
		Percentage			Percentage
Customer Base	2005	Change	2004	2005	Change	2004
Commercial	$ 11,634	6%	$ 10,987	$ 23,065	4%	$ 22,162
Residential	8,649	9	7,936	19,207	5	18,356
Industrial	4,910	1	4,870	9,764	—	9,788
Municipal sales	555	1	549	1,048	2	1,025
Contract wholesale	5,672	12	5,049	11,657	6	10,977
Wholesale off-system	9,171	5	8,697	17,284	15	15,002
Total electric sales	$ 40,591	7%	$ 38,088	$ 82,025	6%	$ 77,310
Other revenue	1,670	(3)	1,721	3,383	(18)	4,146
Total revenue	$ 42,261	6%	$ 39,809	$ 85,408	5%	$ 81,456

	Megawatt Hours
	Three Months Ended June 30			Six Months Ended June 30
		Percentage			Percentage
Customer Base	2005	Change	2004	2005	Change	2004
Commercial	152,644	5%	145,802	310,162	4%	298,407
Residential	102,692	9	94,311	240,639	4	232,056
Industrial	103,695	5	98,745	202,093	2	197,266
Municipal sales	6,827	1	6,756	13,290	2	13,027
Contract wholesale	150,659	9	138,106	311,997	4	299,695
Wholesale off-system	212,460	(6)	226,099	400,074	4	384,887
Total electric sales	728,977	3%	709,819	1,478,255	4%	1,425,338

	Three Months Ended			Six Months Ended
	June 30			June 30
		Percentage			Percentage
Resources	2005	Change	2004	2005	Change	2004
Megawatt-hours generated:
Coal	426,400	15%	371,500	862,300	5%	823,100
Gas	3,830	(26)	5,200	5,500	(35)	8,400
	430,230	14	376,700	867,800	4	831,500
Megawatt-hours purchased	331,434	(8)	358,592	653,105	2	639,531
Total resources	761,664	4%	735,292	1,520,905	3%	1,471,031

32

	Three Months Ended			Six Months Ended
	June 30		Percentage	June 30		Percentage
	2005	2004	Change	2005	2004	Change
Heating and cooling degree days
Actual
Heating degree days	933	940	(1)%	3,923	4,048	(3)%
Cooling degree days	148	59	151%	148	59	151%
Variance from normal
Heating degree days	(6)%	(6)%	—	(9)%	(6)%	—
Cooling degree days	47%	(42)%	—	47%	(42)%	—

Three Months Ended June 30, 2005 Compared to Three Months Ended June 30, 2004. Electric utility revenues increased 6 percent for the three month period ended June 30, 2005, compared to the same period in the prior year. Firm commercial, residential, industrial and contract wholesale sales increased 6 percent, 9 percent, 1 percent and 12 percent, respectively. Wholesale off-system sales increased 5 percent with a 12 percent increase in average price received, partially offset by a 6 percent decrease in megawatt-hours sold. Cooling degree days, which is a measure of weather trends, were 151 percent higher than the same period in the prior year.

Electric operating expenses increased 3 percent for the three month period ended June 30, 2005, compared to the same period in the prior year. Higher operating expenses were primarily the result of a $0.6 million increase in fuel and purchased power costs. The increase in fuel and purchased power was due to a $0.4 million increase in purchased power, resulting from a 12 percent increase in average price per megawatt-hour partially offset by an 8 percent decrease in megawatt-hours purchased, and a $0.2 million increase in fuel costs due to a 14 percent increase in megawatt-hours generated partially offset by a 7 percent decrease in average cost. Megawatt hours produced through coal-fired generation increased in the three months ended June 30, 2005 as we incurred scheduled and unscheduled plant outages during the second quarter of 2004. Prevailing gas prices have made it more economical for us to purchase power for our peaking needs rather than generate energy from our gas turbines. The increase in operating expense was also affected by increased legal expense and compensation costs, partially offset by lower maintenance costs.

Income from continuing operations increased $1.6 million primarily due to increased revenues, lower maintenance costs and lower interest expense, due to the pay down of debt, partially offset by increased fuel and purchased power costs, legal expense and compensation costs.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004. Electric utility revenues increased 5 percent for the six month period ended June 30, 2005 compared to the same period in the prior year. Firm commercial, residential and contract wholesale sales increased 4 percent, 5 percent and 6 percent, respectively. Wholesale off-system sales increased 15 percent due to an 11 percent increase in average price received and a 4 percent increase in megawatt-hours sold. Cooling degree days for the six month period were 151 percent higher than the same period in 2004 and heating degree days were 3 percent lower than the same period in 2004.

Electric operating expenses increased 7 percent for the six month period ended June 30, 2005, compared to the same period in the prior year. Higher operating expenses were primarily the result of a $3.0 million increase in fuel and purchased power costs. The increase in fuel and purchased power was due to a $3.1 million increase in purchased power, resulting from a 12 percent increase in average price per megawatt-hour and a 3 percent increase in megawatt-hours purchased, offset by a nominal decrease in fuel costs due to a 6 percent decrease in average costs partially offset by a 4 percent increase in megawatt-hours generated. Megawatt hours produced through coal-fired generation increased in the six months ended June 30, 2005 as we incurred scheduled and unscheduled plant outages during the second quarter of 2004. Prevailing gas prices have made it more economical for us to purchase power for our peaking needs and increased off-system sales rather than generate energy from our gas turbines. The increase in operating expense was also affected by increased legal expense and compensation costs, partially offset by lower maintenance costs.

33

Income from continuing operations increased $0.9 million primarily due to increased revenues, lower maintenance costs and lower interest expense, due to the pay down of debt, partially offset by increased fuel and purchased power costs, legal expense and compensation costs.

Other Event

In July 2005, the electric utility experienced an unscheduled outage at its 90 megawatt Neil Simpson II power plant. That plant is expected to be out of service for the month of August. To meet our forecasted needs, we have obtained supplemental purchased power and additional natural gas supplies, which will negatively affect third quarter 2005 financial results. The economic impact of this outage is expected to be in the range of $2.5 million to $3.0 million pre-tax, taking into account increased fuel costs, higher purchased power expenses and reduced coal sales.

Electric and Gas Utility

	Three Months Ended		January 21, 2005 to
	June 30		June 30
	2005		2005
	(in thousands)
Revenue	$	27,459	$	54,533
Operating expenses		26,527		52,703
Operating income	$	932	$	1,830
Income from continuing operations and net income	$	643	$	1,155

For the three month period ended June 30, 2005, natural gas sales comprised 32 percent or $8.7 million of total revenues, and electric sales comprised 68 percent or $18.8 million of total revenues for this segment. Results for the period included revenues of approximately $0.5 million for billing adjustments primarily related to pre-acquisition periods.

For the period January 21, 2005 through June 30, 2005, natural gas sales comprised 36 percent, or $19.7 million of total revenues and electric sales comprised 64 percent, or $34.8 million of total revenues. Results for the period included revenues of approximately $0.5 million for billing adjustments primarily related to pre-acquisition periods.

The following table provides certain operating statistics:

	Three Months Ended	January 21, 2005 to
	June 30	June 30
	2005	2005
Electric sales – MWh	251,550	428,650
Gas sales – Dth	1,010,900	2,347,700
Gas transport – Dth	2,023,400	4,241,000

On April 18, 2005, applications were filed with the Wyoming Public Service Commission (WPSC) to increase the base rates for retail electric and natural gas service effective January 1, 2006. The applications request a 3.94 percent and 5.62 percent increase in electric and gas revenues, respectively. We expect that these increases, if approved by the WPSC, would result in an annual revenue increase of approximately $5.2 million. In addition, we expect additional costs in 2006 related to allocated corporate costs and increased costs for operational projects to total approximately $1.5 million.

34

We are progressing with our plans to build Wygen II, a 90 megawatt, coal-fired power plant to be sited at our Wyodak energy complex near Gillette, Wyoming. Wygen II would be a regulated asset of CLF&P. The cost of construction is estimated to be approximately $169 million. Several permits are required before construction can commence, and to date, we have been successful in obtaining an air quality permit and an industrial siting permit from the Wyoming Department of Environmental Quality. We expect to obtain the final permit, a Certificate of Public Convenience and Necessity, from the Wyoming Public Service Commission around September 1, 2005. Upon receipt of permits, we would begin construction yet this year. Wygen II is expected to commence commercial operations in early 2008.

Corporate

Losses from corporate activities primarily represent unallocated corporate costs. Higher losses are primarily the result of increases in accrued incentive compensation, in anticipation of achieving certain incentive plan goals, of approximately $1.3 million and $1.9 million, for the three and six month periods ended June 30, 2005, respectively, and increases in professional fees of approximately $0.8 million and $1.1 million for the three and six month periods ended June 30, 2005, respectively, primarily related to project development costs.

Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission. For more information on our critical accounting policies, see Part II, Item 7 of our 2004 Annual Report on Form 10-K.

Liquidity and Capital Resources

Cash Flow Activities

During the six-month period ended June 30, 2005, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our long-term debt maturities, and to fund our property, plant and equipment additions. We plan to fund future property and investment additions primarily through a combination of operating cash flow and increased short-term and long-term debt.

Cash flows from operations increased $76.4 million for the six-month period ended June 30, 2005 compared to the same period in the prior year primarily due to a $9.4 million increase in net income, an $11.7 million increase in our cash flows from net derivative assets and liabilities and a $54.8 million increase in operating assets and liabilities.

During the six months ended June 30, 2005, we had cash outflows from investing activities of $23.0 million, which was primarily related to property, plant and equipment additions in the normal course of business and the $67.3 million cash payment related to the acquisition of CLF&P, offset by a $103.0 million cash payment received for the sale of Black Hills FiberSystems.

During the six months ended June 30, 2005, we had cash outflows from financing activities of $116.0 million, primarily due to the repayment of $81.5 million of project level debt at our Fountain Valley facility and due to the payment of quarterly cash dividends on common stock and a decrease in short term borrowings.

35

Dividends

Dividends paid on our common stock totaled $20.9 million during the six months ended June 30, 2005, or $0.32 per share, per quarter in the first and second quarters of 2005. This reflects a 3.2 percent increase, as approved by our board of directors in January 2005, from the 2004 quarterly dividend level. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under PUHCA, restrictions under our credit facilities and our future business prospects.

Short-Term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are our revolving bank facility and cash provided by operations. Our liquidity position remained strong during the first six months of 2005. As of June 30, 2005, we had approximately $60.6 million of cash unrestricted for operations and $400 million of credit through revolving bank facilities. Approximately $12.1 million of the cash balance at June 30, 2005 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company.

Our revolving credit facility can be used to fund our working capital needs, for general corporate purposes, and to provide liquidity for a commercial paper program if implemented. At June 30, 2005, we had $13.0 million of borrowings outstanding under these facilities. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $335.0 million at June 30, 2005.

On May 5, 2005, we entered into a new $400 million revolving bank facility with ABN AMRO as Administrative Agent, Union Bank of California and US Bank as Co-Syndication Agents, Bank of America and Harris Nesbitt as Co-Documentation Agents, and other syndication participants. The new facility has a five year term, expiring May 4, 2010. The facility contains a provision which allows the facility size to be increased by up to an additional $100 million through the addition of new lenders, or through increased commitments from existing lenders, but only with the consent of such lenders. The cost of borrowings or letters of credit issued under the new facility is determined based on our credit ratings; at our current ratings levels, the facility has an annual facility fee of 17.5 basis points, and has a borrowing spread of 70.0 basis points over the LIBOR (which equates to a 4.04 percent one-month borrowing rate as of June 30, 2005). In conjunction with entering into the new revolving bank facility, we terminated our $125 million revolving bank facility due May 12, 2005 and our $225 million facility due August 20, 2006.

The bank facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and maintenance of the following financial covenants:

•             a consolidated net worth in an amount of not less than the sum of $625 million and 50 percent of our aggregate consolidated net income beginning January 1, 2005;

•             a recourse leverage ratio not to exceed 0.65 to 1.00; and

•             an interest coverage ratio of not less than 2.5 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.

36

A default under the bank facility may be triggered by events such as a failure to comply with financial covenants or certain other covenants under the bank facility, a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, debt obligations of $20 million or more. A default under the bank facility would permit the participating banks to restrict the Company’s ability to further access the credit facility for loans or new letters of credit, require the immediate repayment of any outstanding loans with interest and require the cash collateralization of outstanding letter of credit obligations.

The bank facility prohibits the Company from paying cash dividends unless no default or no event of default exists prior to, or would result after, giving effect to such action.

Our consolidated net worth was $750.6 million at June 30, 2005, which was approximately $110.3 million in excess of the net worth we were required to maintain under the bank facilities in place at June 30, 2005. The long-term debt component of our capital structure at June 30, 2005 was 47.3 percent, our total debt leverage (long-term debt and short-term debt) was 48.2 percent, and our recourse leverage ratio was approximately 46.6 percent.

In addition, Enserco Energy Inc., our gas marketing unit, has a $150 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. As of June 30, 2005, we had a $3.0 million guarantee to the lender under this facility. At June 30, 2005, there were outstanding letters of credit issued under the facility of $114.5 million, with no borrowing balances outstanding on the facility.

Similarly, Black Hills Energy Resources, Inc. (BHER), our oil marketing unit, has an uncommitted, discretionary credit facility. The facility allows BHER to elect from $25 million up to $40 million of available credit via notification to the bank at the beginning of each calendar quarter. This line of credit provides credit support for the purchases of crude oil by BHER. We provided no guarantee to the lender under this facility. At June 30, 2005, BHER had elected to have $40.0 million of available credit and had letters of credit outstanding of $24.8 million.

There were no changes in our corporate credit ratings during the first six months of 2005; in June 2005, Moody’s revised the outlook on our ratings from negative to stable.

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 material changes in our forecasted liquidity requirements from those reported in Item 7 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Guarantees

During the first quarter of 2005, a $0.5 million guarantee related to payments under various transactions with Idaho Power Company was reduced to $0.3 million. During the second quarter of 2005, a $0.8 million guarantee related to payments under various transactions with Southern California Edison Company expired and was not renewed. At June 30, 2005, we had guarantees totaling $182.2 million in place.

Capital Requirements

During the six months ended June 30, 2005, capital expenditures were approximately $63.8 million for property, plant and equipment additions and $67.3 million for the acquisition of CLF&P (exclusive of debt assumed). We currently expect capital expenditures for the entire year 2005 to approximate $200 million, as detailed in Item 7 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission excluding debt assumed in the CLF&P acquisition and the elimination of capital expenditures related to the discontinued Communications segment.

37

We continue to actively evaluate potential future acquisitions and other growth opportunities in accordance with our disclosed business strategy. We are not obligated to a project until a definitive agreement is entered into and cannot guarantee we will be successful on any potential projects. Future projects are dependent upon the availability of economic opportunities and, as a result, actual expenditures may vary significantly from forecasted estimates.

RISK FACTORS

Other than as set forth below, there have been no material changes in our Risk Factors from those reported in Items 1 and 2 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

Our utilities may not raise their retail rates without prior approval of the South Dakota Public Utilities Commission (SDPUC) or the Wyoming Public Services Commission (WPSC). Any delays in obtaining approvals or having cost recovery disallowed in such rate proceedings could have an adverse effect on our revenues and results of operation.

The rate freeze agreement with the SDPUC for our Black Hills Power electric utility expired on January 1, 2005. Until such time as we petition the SDPUC or the WPSC for rate relief, or either commission requests a rate review, Black Hills Power may not increase its retail rates. Additionally, Black Hills Power may not invoke any fuel and purchased power adjustment tariff that would take effect prior to the completion of a rate proceeding, absent extraordinary circumstances. Because our utilities are generally unable to increase their base rates without prior approval from the SDPUC and the WPSC, our returns could be threatened by plant outages, machinery failure, increases in fuel and purchased power costs over which our utilities have no control, acts of nature, acts of terrorism or other unexpected events that could cause operating costs to increase and operating margins to decline. Moreover, in the event of unexpected plant outages or machinery failures, Black Hills Power may be required to purchase replacement power in wholesale power markets at prices that exceed the rates it is permitted to charge its retail customers.

As part of the process for obtaining approval to acquire CLF&P, we agreed with the WPSC that CLF&P and Black Hills Power would not raise retail rates for their respective Wyoming customers prior to January 1, 2006. In consideration of such date, our CLF&P utility filed rate cases with the WPSC on April 18, 2005 with respect to its retail gas and electric rates, requesting 5.62% and 3.94% increases in such rates, respectively. In its review of the rate cases, the WPSC will consider, among other things, the return on common equity, overall rate of return, depreciation expenses and cost of capital for CLF&P. Any costs found by the WPSC that have not been prudently incurred would not be recoverable from CLF&P’s customers. Such a finding, among any other unfavorable rulings by the WPSC in these rate cases, could negatively affect our revenues and results of operations.

NEW ACCOUNTING PRONOUNCEMENTS

Other than the new pronouncements reported in our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission and those discussed in Note 4 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment.

38

FUTURE ISSUES

Energy Policy Act of 2005

In July 2005, Congress passed the Energy Policy Act of 2005 (the Act) and on August 8, 2005 the President signed the act into law. The Act includes numerous provisions meant to increase domestic gas and oil supplies, improve energy system reliability, build new nuclear power plants and expand renewable energy sources. The legislation would also repeal the Public Utility Holding Company Act of 1935. We are currently evaluating the impact that the Act may have on our results of operations and financial condition.

SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Items 1 and 2 of our 2004 Annual Report on Form 10-K and in Item 2 of Part I of this quarterly report on Form 10-Q filed with the SEC, and the following:

•              The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock;

•              The volumes of our production from oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;

•              The extent of our success in connecting natural gas supplies to gathering, processing and pipeline systems;

•              Our ability to successfully integrate CLF&P into our operations;

•              Unfavorable rulings in the rate cases filed by CLF&P with the WPSC and in the periodic applications to recover costs for fuel and purchased power;

•              Changes in business and financial reporting practices arising from the repeal of the Public Utilities Holding Company Act and other provisions of the recently enacted Energy Policy Act of 2005;

•              Our ability to remedy any deficiencies that may be identified in the periodic review of our internal controls;

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

•              The timing and extent of scheduled and unscheduled outages of power generation facilities;

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

•              Our use of derivative financial instruments to hedge commodity, currency exchange rate and interest rate risks;

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

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

39

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

•              Changes in state laws or regulations that could cause us to curtail our independent power production;

•              Weather and other natural phenomena;

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

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

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

•              Capital market conditions, which may affect our ability to raise capital on favorable terms;

•              Price risk due to marketable securities held as investments in benefit plans;

•              Obtaining adequate cost recovery for our retail operations through regulatory proceedings; and

•              Other factors discussed from time to time in our other 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.

40

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Trading Activities

The following table provides a reconciliation of our activity in energy trading contracts that meet the definition of a derivative under SFAS 133 and that were marked-to-market during the six months ended June 30, 2005 (in thousands):

Total fair value of natural gas marketing positions marked-to-market at December 31, 2004	$	(930)(a)
Net cash settled during the period on positions that existed at December 31, 2004		907
Change in fair value due to change in techniques and assumptions		—
Unrealized loss on new positions entered during the period and still existing at June 30, 2005		(95)
Realized gain on positions that existed at December 31, 2004 and were settled during the period		131
Unrealized loss on positions that existed at December 31, 2004 and still exist at June 30, 2005		(110)
Total fair value of natural gas marketing positions at June 30, 2005	$	(97)(a)

(a) The fair value of positions marked-to-market consists of derivative assets/liabilities and natural gas inventory that has been designated as a hedged item and marked-to-market as part of a fair value hedge, as follows (in thousands):

	June 30, 2005		March 31, 2005		December 31, 2004
Net derivative assets/(liabilities)	$	(2,973)	$	(9,360)	$	8,082
Fair value adjustment recorded in material,
supplies and fuel		2,876		4,762		(9,012)
	$	(97)	$	(4,598)	$	(930)

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

41

The sources of fair value measurements for natural gas marketing derivative contracts were as follows (in thousands):

	Maturities
Source of Fair Value	Less than 1 year		1 – 2 years		Total Fair Value
Actively quoted (i.e., exchange-traded) prices	$	2,014	$	830	$	2,844
Prices provided by other external sources		(1,998)		(943)		(2,941)
Modeled		—		—		—
Total	$	16	$	(113)	$	(97)

The following table presents a reconciliation of our June 30, 2005 natural gas marketing positions recorded at fair value under generally accepted accounting principles (GAAP) to a non-GAAP measure of the fair value of our natural gas forward book wherein all forward trading positions are marked-to-market (in thousands). The approach used in determining the non-GAAP measure is consistent with our previous accounting methods under EITF 98-10. As part of our GAAP fair value calculations we include a “Liquidity Reserve” to reflect a scenario in which there is immediate liquidation of our natural gas contracts on the balance sheet date. We have added back this liquidity reserve in the non-GAAP presentation below as we anticipate holding our natural gas contracts until their settlement and therefore not incur the impact of the bid/ask spread in our realized gross margin.

Fair value of our natural gas marketing positions marked-to-market in accordance with GAAP
(see footnote (a) above)	$	(97)
Increase in fair value of inventory, storage and transportation positions that are
part of our forward trading book, but that are not marked-to-market under GAAP		5,670
Fair value of all forward positions (Non-GAAP)		5,573
“Liquidity Reserve” included in GAAP marked-to-market fair value (b)		2,620
Fair value of all forward positions excluding the “Liquidity Reserve” (Non-GAAP)	$	8,193

(b) In accordance with generally accepted accounting principles and industry practice, the Company includes a “Liquidity Reserve” in its GAAP marked-to-market fair value. This “Liquidity Reserve” accounts for the estimated impact of the bid/ask spread in a liquidation scenario under which the Company is forced to liquidate its forward book on the balance sheet date.

There have been no material changes in market risk faced by us from those reported in our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission. For more information on market risk, see Part II, Item 7 in our 2004 Annual Report on Form 10-K, and Note 15 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

42

Activities Other Than Trading

The Company has entered into agreements to hedge a portion of its estimated 2005, 2006 and 2007 natural gas and crude oil production. The hedge agreements in place are as follows:

Natural Gas

Location	Transaction Date	Term	Volume	Price
			(Mmbtu/day)
San Juan El Paso	08/01/2004	04/05 – 10/05	2,500	$	5.30
San Juan El Paso	09/22/2004	04/05 – 10/05	2,500	$	5.40
San Juan El Paso	10/20/2004	04/05 – 10/05	2,500	$	6.04
San Juan El Paso	12/29/2004	04/05 – 10/05	2,500	$	5.40
San Juan El Paso	11/04/2004	11/05 – 03/06	2,500	$	7.08
San Juan El Paso	04/04/2005	11/05 – 03/06	2,500	$	7.77
San Juan El Paso	07/12/2005	11/05 – 03/06	2,500	$	8.03
San Juan El Paso	07/12/2005	04/06 – 10/06	2,500	$	7.00

Crude Oil

Location	Transaction Date	Term	Volume	Price
			(barrels/month)
NYMEX	01/08/2004	Calendar 2005	10,000	$	27.90
NYMEX	05/12/2004	Calendar 2005	10,000	$	34.08
NYMEX	10/06/2004	Calendar 2006	10,000	$	41.00
NYMEX	07/12/2005	Calendar 2007	5,000	$	61.00
NYMEX	08/04/2005	Calendar 2007	5,000	$	62.00

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of June 30, 2005. 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.

On January 21, 2005, we acquired Cheyenne Light, Fuel and Power (CLF&P). We have not been able to complete an assessment of CLF&P’s internal control over financial reporting between the acquisition date and the end of this reporting period. The Securities and Exchange Commission allows companies one year after acquisition to complete their assessment.

Since the acquisition of CLF&P, we have been focusing on integrating it into our company. We have and will continue to analyze and implement changes in CLF&P’s procedures and controls to ensure their effectiveness.

Other than changes resulting from our acquisition of CLF&P, 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.

43

BLACK HILLS CORPORATION

Part II – Other Information

Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 21 in Item 8 of the Company’s 2004 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities

On July 7, 2005, we caused the mandatory conversion of all outstanding Series 2000-A Preferred Stock into 195,599 shares of our common stock and $165.78 in cash in lieu of fractional shares pursuant to the automatic conversion feature in Section 8 of our Statement of Designations, Preferences and Relative Rights and Limitations of No Par Preferred Stock, Series 2000-A (the “Statement of Designations”). As a result of this transaction, we have no outstanding shares of Preferred Stock. As set forth in Section 8 of the Statement of Designations, each share of Series 2000-A Preferred Stock was converted into a number of shares of our common stock equal to the liquidation preference amount of $1,000 per share of Series 2000-A Preferred Stock, plus accrued and unpaid dividends thereon, divided by the conversion price of $35.00 per share.

The issuance of 195,599 shares of our common stock upon conversion of all of the outstanding shares of Series 2000-A Preferred Stock was exempt from registration pursuant to Section 3(a)(9) of the Securities Act of 1933. We received no additional proceeds from the issuance of the shares of common stock in exchange for the Series 2000-A Preferred Stock.

44

Share Repurchases

					(d) Maximum
					Number (or
				(c) Total Number	Approximate Dollar
				of Shares	Value) of Shares
				Purchased as	That May Yet Be
	(a) Total	(b) Average		Part of Publicly	Purchased Under
	Number of	Price Paid		Announced Plans	the Plans
Period	Shares Purchased	per Share		or Programs	or Programs
April 1, 2005 – April 30, 2005	682(1)	$	35.07	—		—
May 1, 2005 – May 31, 2005	3,819(1)	$	35.65	—		—
June 1, 2005 – June 30, 2005	7,711(2)	$	37.42	—		—
Total	12,212	$	36.74	—		—

___________________________

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

(2) Includes 7,463 shares acquired under the share withholding provisions of the Restricted Stock Plan as explained in (1) above, and 248 shares acquired by a Rabbi Trust for the Outside Directors Stock Based Compensation Plan.

Item 4. Submission of Matters to a Vote of Security Holders

(a) The Annual Meeting of Shareholders was held on May 25, 2005.

(b) The following Directors were elected to serve until the Annual Meeting of Shareholders in 2008:

David R. Emery

Kay S. Jorgensen

William G. Van Dyke

John B. Vering

Other Directors whose term of office continue are:

David C. Ebertz

Jack W. Eugster

John R. Howard

Richard Korpan

Stephen D. Newlin

Thomas J. Zeller

45

(c) Matters Voted Upon at the Meeting

1. Elected four Class II Directors to serve until the Annual Meeting of Shareholders in 2008.

David R. Emery
Votes For	27,374,386
Votes Withheld	411,007
Kay S. Jorgensen
Votes For	27,112,065
Votes Withheld	673,328
William G. Van Dyke
Votes For	27,297,724
Votes Withheld	487,670
John B. Vering
Votes For	27,359,262
Votes Withheld	426,131

2. Approval of the Black Hills Corporation 2005 Omnibus Incentive Plan.

Votes For	19,450,165
Votes Against	2,364,549
Abstain	475,810
Broker Non-Votes	5,494,869

3. Ratified the appointment of Deloitte & Touche LLP to serve as Black Hills Corporation’s independent auditors in 2005.

Votes For	27,473,769
Votes Against	91,798
Abstain	219,826
Broker Non-Votes	—

46

Item 6. Exhibits

(a) Exhibits–

Exhibit 10.1	Change in Control Agreement dated June 30, 2005 between Black Hills Corporation and David R. Emery (incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on July 1, 2005).
Exhibit 10.2	Form of Change of Control Agreement between Black Hills Corporation and its Non-CEO Senior Executive Officers (incorporated by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on July 1, 2005).
Exhibit 10.3	Third Amendment to the Outside Directors Stock Based Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on June 2, 2005).
Exhibit 10.4	Black Hills Corporation 2005 Omnibus Incentive Plan (incorporated herein by reference to Appendix A to the Company’s 2005 Proxy Statement filed April 13, 2005).
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.

47

BLACK HILLS CORPORATION

Signatures

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

	BLACK HILLS CORPORATION
	/s/ David R. Emery
	David R. Emery, Chairman, President and
	Chief Executive Officer
	/s/ Mark T. Thies
	Mark T. Thies, Executive Vice President and
	Chief Financial Officer
Dated: August 9, 2005

48

EXHIBIT INDEX

Exhibit Number	Description
Exhibit 10.1	Change in Control Agreement dated June 30, 2005 between Black Hills Corporation and David R. Emery (incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on July 1, 2005).
Exhibit 10.2	Form of Change of Control Agreement between Black Hills Corporation and its Non-CEO Senior Executive Officers (incorporated by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on July 1, 2005).
Exhibit 10.3	Third Amendment to the Outside Directors Stock Based Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on June 2, 2005).
Exhibit 10.4	Black Hills Corporation 2005 Omnibus Incentive Plan (incorporated herein by reference to Appendix A to the Company’s 2005 Proxy Statement filed April 13, 2005).
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.

49