Black Hills (BKH) 10-Q 2006 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2006.

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 a large accelerated filer, an accelerated filer or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer x Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

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

Class	Outstanding at July 31, 2006
Common stock, $1.00 par value	33,258,700 shares

TABLE OF CONTENTS

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income –
	Three and Six Months Ended June 30, 2006 and 2005	3
	Condensed Consolidated Balance Sheets –
	June 30, 2006, December 31, 2005 and June 30, 2005	4
	Condensed Consolidated Statements of Cash Flows –
	Six Months Ended June 30, 2006 and 2005	5
	Notes to Condensed Consolidated Financial Statements	6-29
Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	30-51
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52-54
Item 4.	Controls and Procedures	54
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	55
Item 1A.	Risk Factors	55
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	55
Item 4.	Submission of Matters to a Vote of Security Holders	56
Item 6.	Exhibits	57
	Signatures	58
	Exhibit Index	59

2

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(in thousands, except per share amounts)
Operating revenues	$	153,813	$	142,385	$	325,704	$	284,805
Operating expenses:
Fuel and purchased power		49,280		41,558		103,409		85,091
Operations and maintenance		22,073		19,947		44,077		37,057
Administrative and general		20,105		18,677		45,056		39,298
Depreciation, depletion and amortization		22,378		20,495		43,266		40,323
Taxes, other than income taxes		7,546		8,557		18,097		16,614
		121,382		109,234		253,905		218,383
Operating income		32,431		33,151		71,799		66,422
Other income (expense):
Interest expense		(12,910)		(13,472)		(24,910)		(25,332)
Interest income		346		600		1,014		963
Other income, net		123		392		412		680
		(12,441)		(12,480)		(23,484)		(23,689)
Income from continuing operations before
equity in earnings of unconsolidated
subsidiaries, minority interest and income
taxes		19,990		20,671		48,315		42,733
Equity in earnings of unconsolidated
subsidiaries		(1,145)		2,879		(632)		4,354
Minority interest		(91)		(65)		(177)		(125)
Income tax expense		(6,386)		(8,170)		(16,577)		(16,393)
Income from continuing operations		12,368		15,315		30,929		30,569
Income (loss) from discontinued operations,
net of taxes		(611)		(345)		6,979		141
Net income		11,757		14,970		37,908		30,710
Preferred stock dividends		—		(80)		—		(159)
Net income available for common stock	$	11,757	$	14,890	$	37,908	$	30,551
Weighted average common shares
outstanding:
Basic		33,164		32,562		33,142		32,503
Diluted		33,506		33,203		33,493		33,121
Earnings per share:
Basic–
Continuing operations	$	0.37	$	0.47	$	0.93	$	0.93
Discontinued operations		(0.02)		(0.01)		0.21		0.01
Total	$	0.35	$	0.46	$	1.14	$	0.94
Diluted–
Continuing operations	$	0.37	$	0.46	$	0.92	$	0.92
Discontinued operations		(0.02)		(0.01)		0.21		0.01
Total	$	0.35	$	0.45	$	1.13	$	0.93
Dividends paid per share of common stock	$	0.33	$	0.32	$	0.66	$	0.64

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,
	2006		2005		2005
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	42,234	$	31,817	$	54,151
Restricted cash		—		—		700
Receivables (net of allowance for doubtful accounts of $4,077;
$4,685 and $5,292, respectively)		195,090		264,695		217,947
Materials, supplies and fuel		96,871		122,521		102,618
Derivative assets		29,204		20,681		9,201
Deferred income taxes		—		—		1,766
Other assets		8,353		7,842		7,452
Assets of discontinued operations		6,058		122,158		97,719
		377,810		569,714		491,554
Investments		23,244		27,558		24,253
Property, plant and equipment		2,093,519		1,928,559		1,926,884
Less accumulated depreciation and depletion		(554,167)		(518,525)		(491,134)
		1,539,352		1,410,034		1,435,750
Other assets:
Derivative assets		3,149		1,898		911
Goodwill		30,563		29,847		28,455
Intangible assets (net of accumulated amortization of
$24,293; $22,734 and $22,666, respectively)		25,989		27,548		34,716
Other		40,993		53,646		51,696
		100,694		112,939		115,778
	$	2,041,100	$	2,120,245	$	2,067,335
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	159,207	$	202,639	$	198,216
Accrued liabilities		66,775		72,514		59,417
Derivative liabilities		14,959		26,141		17,788
Deferred income taxes		1,450		1,443		—
Notes payable		98,500		55,000		13,000
Current maturities of long-term debt		11,125		11,771		11,609
Accrued income taxes		8,311		11,650		16,787
Liabilities of discontinued operations		5,979		92,818		65,600
		366,306		473,976		382,417
Long-term debt, net of current maturities		660,147		670,193		674,860
Deferred credits and other liabilities:
Deferred income taxes		149,129		134,533		165,034
Derivative liabilities		1,249		2,623		1,977
Other		98,309		95,116		87,475
		248,687		232,272		254,486
Minority interest in subsidiaries		5,103		4,925		4,960
Stockholders’ equity:
Preferred stock – no par Series 2000-A; 0; 0 and 21,500 shares
authorized, respectively; 0; 0 and 6,839 issued and
outstanding, respectively		—		—		7,167
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized;
Issued 33,294,945; 33,222,522 and 32,811,919 shares,
respectively		33,295		33,223		32,812
Additional paid-in capital		406,196		404,035		390,433
Retained earnings		327,135		313,217		331,697
Treasury stock at cost – 36,245; 66,938 and 74,330
shares, respectively		(931)		(1,766)		(1,918)
Accumulated other comprehensive loss		(4,838)		(9,830)		(9,579)
		760,857		738,879		743,445
Total stockholders’ equity		760,857		738,879		750,612
	$	2,041,100	$	2,120,245	$	2,067,335

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,
	2006		2005
	(in thousands)
Operating activities:
Income from continuing operations	$	30,929	$	30,569
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization		43,266		40,321
Net change in derivative assets and liabilities		(3,138)		11,617
Deferred income taxes		11,809		8,937
Distributed (undistributed) earnings in associated companies		4,818		(2,188)
Change in operating assets and liabilities, net of acquisition-
Materials, supplies and fuel		14,672		(12,347)
Accounts receivable and other current assets		70,079		6,348
Accounts payable and other current liabilities		(77,541)		44,483
Other operating activities		12,417		9,008
Net cash provided by operating activities of continuing operations		107,311		136,748
Net cash (used in) provided by operating activities of discontinued operations		(665)		3,609
Net cash provided by operating activities		106,646		140,357
Investing activities:
Property, plant and equipment additions		(150,201)		(63,152)
Proceeds from sale of assets		—		103,010
Payment for acquisition, net of cash acquired		—		(67,331)
Other investing activities		(505)		5,099
Net cash used in investing activities of continuing operations		(150,706)		(22,374)
Net cash provided by (used in) investing activities of discontinued operations		43,674		(5,732)
Net cash used in investing activities		(107,032)		(28,106)
Financing activities:
Dividends paid		(21,959)		(21,022)
Common stock issued		2,233		6,211
Increase (decrease) in short-term borrowings, net		43,500		(11,000)
Long-term debt – repayments		(10,692)		(89,666)
Other financing activities		(5)		(653)
Net cash provided by (used in) financing activities of continuing operations		13,077		(116,130)
Net cash used in financing activities of discontinued operations		—		—
Net cash used in financing activities		13,077		(116,130)
Increase (decrease) in cash and cash equivalents		12,691		(3,879)
Cash and cash equivalents:
Beginning of period		34,198*		64,507**
End of period	$	46,889*	$	60,628**
Supplemental disclosure of cash flow information:
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities	$	20,801	$	—
Cash paid during the period for-
Interest	$	26,095	$	25,665
Net income taxes paid (refunded)	$	12,514	$	(1,632)

_________________________

*Includes approximately $4.7 million at June 30, 2006 and $2.4 million at December 31, 2005 of cash included in discontinued operations.

**Includes approximately $6.5 million at June 30, 2005 and $8.6 million at December 31, 2004 of cash included in discontinued operations.

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 2005 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 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC).

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, 2006, December 31, 2005 and June 30, 2005 financial information and are of a normal recurring nature. Some of the Company’s operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as changes in market price. The results of operations for the three and six months ended June 30, 2006, 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 2005 amounts in the financial statements have been reclassified to conform to the 2006 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) RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

SFAS No. 123 (Revised 2004)

On December 16, 2004, the Financial Accounting Standards Board, or FASB, issued FASB Statement No. 123 (Revised 2004) “Share-Based Payment,” or SFAS 123(R), which is a revision of SFAS Statement No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values.

The Company previously accounted 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 for the three and six month periods ended June 30, 2005 for stock options.

6

As of January 1, 2006, the Company applied the provisions of SFAS 123(R) using the modified prospective method, recognizing compensation expense for all awards granted after the date of adoption and for the unvested portion of previously granted awards that were outstanding at the date of adoption. Adoption of SFAS 123(R) did not have a significant effect on the Company’s consolidated financial position, results of operations or cash flows. See Note 9, Common Stock, for further discussion of stock-based compensation plans.

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. Upon adoption of EITF 04-6 on January 1, 2006, the Company recorded a $2.0 million cumulative effect adjustment to write-off previously recorded deferred charges, with the offset decreasing retained earnings. Additionally, since January 1, 2006, stripping costs are expensed as a cost of inventory produced, at the time incurred.

EITF Issue No. 04-13

On September 28, 2005 the FASB ratified the consensus reached under EITF Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” (EITF 04-13) which determines if such transactions should be reported on a gross basis or a net basis.

EITF 04-13 is effective for new arrangements entered into, and modifications or renewals of existing arrangements, in reporting periods beginning after March 16, 2006. The adoption did not have a significant effect on the Company’s consolidated financial position, results of operations or cash flows.

(4) RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

FIN 48

In June, 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109 “Accounting for Income Taxes” (FAS 109) and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006 with the impact of adoption to be reported as a cumulative effect of an accounting change. Management is currently evaluating the impact FIN 48 will have on the Company’s consolidated financial statements.

7

(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	2006		2005		2005
Materials and supplies	$	28,077	$	24,567	$	23,779
Fuel		8,580		7,544		4,081
Gas held by energy marketing*		60,214		90,410		74,758
Total materials, supplies and fuel	$	96,871	$	122,521	$	102,618

___________________________

* As of June 30, 2006, December 31, 2005 and June 30, 2005, market adjustments related to natural gas held by energy marketing and recorded in inventory were $(4.3) million, $6.6 million and $2.9 million, respectively.

The gas inventory held by our energy marketing company is held under various contractual storage arrangements. The gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future. A substantial majority of the gas was economically hedged at the time of purchase either through a fixed price physical or financial forward sale.

(6) LONG-TERM DEBT

On May 24, 2006 the Company entered into an Amended and Restated Credit Agreement for the project financing floating rate debt for Wygen I. The agreement extended the maturity date of the $111.1 million tranche of the financing from June 2006 to June 2008 to coincide with the maturity date of the remaining $17.2 million tranche. The cost of borrowings under the financing is determined based upon the Company’s corporate credit ratings; at the Company’s current levels, the financing has a borrowing spread on Eurodollar loans of 62.5 basis points over LIBOR. In conjunction with the Amended and Restated Credit Agreement, the Company entered into an Amended and Restated Guarantee in favor of Wygen Funding, Limited Partnership, which continues the Company’s guarantee obligations under the Wygen I plant lease.

8

(7) 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, 2006	Three Months			Six Months
			Average			Average
	Income		Shares	Income		Shares
Income from continuing operations	$	12,368		$	30,929
Basic – available for common shareholders		12,368	33,164		30,929	33,142
Dilutive effect of:
Stock options		—	79		—	81
Estimated contingent shares issuable
for prior acquisition		—	159		—	159
Others		—	104		—	111
Diluted–available for common shareholders	$	12,368	33,506	$	30,929	33,493

Period ended June 30, 2005	Three Months			Six Months
			Average			Average
	Income		Shares	Income		Shares
Income from continuing operations	$	15,315		$	30,569
Less: preferred stock dividends		(80)			(159)
Basic – available for common shareholders		15,235	32,562		30,410	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	$	15,315	33,203	$	30,569	33,121

9

(8) 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,
	2006		2005		2006		2005
Net income	$	11,757	$	14,970	$	37,908	$	30,710
Other comprehensive income (loss),
net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges		1,297		480		5,162		(4,166)
Reclassification adjustments on cash flow
hedges settled and included in net
income		121		2,035		(170)		2,179
Unrealized gain on available-for-sale
securities		—		—		—		15
Comprehensive income	$	13,175	$	17,485	$	42,900	$	28,738

(9) COMMON STOCK

Equity Compensation Plans

The Company has several employee equity compensation plans, which allow for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. The Company has 1,083,903 shares available to grant at June 30, 2006.

At June 30, 2006, the Company had one stock-based employee compensation plan under which it can grant stock options to its employees and three prior plans with stock options outstanding. Prior to January 1, 2006, the Company accounted 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. Prior to 2006, no stock-based compensation expense related to stock options was reflected in net income as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. However, the Company did recognize stock-based compensation expense for non-vested share awards including restricted stock and restricted stock units, performance shares and directors’ phantom shares.

10

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS 123 to stock-based employee compensation (in thousands, except per share amounts):

	Three Months Ended		Six Months Ended
	June 30, 2005		June 30, 2005
Net income available for common stock, as reported	$	14,890	$	30,551
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects		(122)		(263)
Pro forma net income available for common stock	$	14,768	$	30,288
Earnings per share:
Basic–as reported
Continuing operations	$	0.47	$	0.93
Discontinued operations		(0.01)		0.01
Total	$	0.46	$	0.94
Diluted–as reported
Continuing operations	$	0.46	$	0.92
Discontinued operations		(0.01)		0.01
Total	$	0.45	$	0.93
Basic–pro-forma
Continuing operations	$	0.47	$	0.92
Discontinued operations		(0.01)		0.01
Total	$	0.46	$	0.93
Diluted–pro-forma
Continuing operations	$	0.46	$	0.91
Discontinued operations		(0.01)		0.01
Total	$	0.45	$	0.92

On January 1, 2006 the Company adopted the fair value recognition provisions of SFAS 123(R) requiring the recognition of expense related to the fair value of stock-based compensation awards. The Company elected the modified prospective transition method. Under this method, compensation expense is recognized for all stock-based awards granted prior to, but not yet vested as of January 1, 2006 and all stock-based awards granted subsequent to January 1, 2006. Adoption of SFAS 123(R) did not have a material effect on the Company’s consolidated financial position, results of operations or cash flows. Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of SFAS 123(R) and is recognized over the vesting periods of the individual plans. Total stock-based compensation expense for the three months ended June 30, 2006 and 2005 was $0.9 million ($0.6 million, after tax) and $1.1 million ($0.7 million, after tax), respectively, and for the six months ended June 30, 2006 and 2005 was $1.7 million ($1.1 million, after tax) and $1.9 million ($1.3 million, after tax), respectively, and is included in administrative and general expense on the accompanying Condensed Consolidated Statements of Income. In accordance with the modified prospective transition method of SFAS 123(R), financial results for prior periods have not been restated. As of June 30, 2006, total unrecognized compensation expense related to stock options and non-vested stock awards is $4.5 million and is expected to be recognized over a weighted-average period of 2.0 years.

11

In November 2005, the FASB issued FASB Staff Position (FSP) No. FAS 123 (R)-3, “Transition Election Related to Accounting for the Tax Effects of Share-Based Payment Awards.” FSP 123(R)-3 provides an alternative method of calculating the excess tax benefits available to absorb tax deficiencies recognized subsequent to the adoption of SFAS 123(R). The calculation of excess tax benefits reported as an operating cash outflow and a financing inflow in the Consolidated Statements of Cash Flows required by FSP No. 123(R)-3 differs from that required by SFAS 123(R). The Company has until January 1, 2007 to make a one-time election to adopt the transition method described in FSP No. 123 (R)-3. The Company is currently evaluating FSP No. FAS 123 (R)-3; however, the one-time election is not expected to affect the Company’s results of operations.

Stock Options

The Company has granted options with an option exercise price equal to the fair market value of the stock on the day of the grant. The options granted vest one-third each year for three years and expire after ten years from the grant date.

A summary of the status of the stock option plans at June 30, 2006 is as follows:

				Weighted-
		Weighted-		Average
		Average		Remaining	Aggregate
		Exercise		Contractual	Intrinsic
	Shares	Price		Term	Value
	(in thousands)			(in years)	(in thousands)
Balance at January 1, 2006	854	$	29.56
Granted	15		33.17
Forfeited/cancelled	(17)		33.72
Expired	—		—
Exercised	(35)		28.30
Balance at June 30, 2006	817	$	29.59	5.8	$	3,870
Exercisable at June 30, 2006	716	$	29.49	5.4	$	3,467

The weighted-average grant-date fair value of options granted during the six months ended June 30, 2006 and 2005 was $3.79 and $6.93, respectively. The total intrinsic value of options (the amount by which the market price of the stock on the date of exercise exceeded the exercise price of the option) exercised during the six months ended June 30, 2006 and 2005 was $0.2 million and $2.4 million, respectively. The total fair value of shares vested during each of the six months ended June 30, 2006 and 2005 was $0.4 million and $0.7 million, respectively.

12

The fair value of share-based awards is estimated on the date of grant using the Black-Scholes option pricing model. The fair value is affected by the Company’s stock price as well as a number of assumptions. The assumptions used to estimate the fair value of share-based awards are as follows:

	Six Months		Six Months
	Ended		Ended
Valuations Assumptions1	June 30, 2006		June 30, 2005
Weighted average risk-free interest rate2		4.94%	3.90%
Weighted average expected price volatility3		21.54%	42.27%
Weighted average expected dividend yield4		3.98%	4.17%
Expected life in years5		7	7

_____________________________

 

1	Forfeitures are estimated using historical experience and employee turnover.
2	Based on treasury interest rates with terms consistent with the expected life of the options.
3	Based on a blended historical and implied volatility of the Company’s stock price in 2006 and historical volatility only in 2005.
4	Based on the Company’s historical and expectation of future dividend payouts and may be subject to substantial change in the future.
5	Based upon historical experience.

  

Net cash received from the exercise of options for the six months ended June 30, 2006 and 2005 was $1.0 million and $4.9 million, respectively. The tax benefit realized from the exercise of shares granted for the six months ended June 30, 2006 and 2005 was $0.1 million and $0.9 million, respectively, and was recorded as an increase to equity.

As of June 30, 2006, there was $0.4 million of unrecognized compensation expense related to stock options that is expected to be recognized over a weighted-average period of 1.1 years.

Restricted Stock and Restricted Stock Units

The fair value of restricted stock and restricted stock unit awards equals the market price of the Company’s stock on the date of grant.

The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest one-third per year over three years, contingent on continued employment. Compensation cost related to the awards is recognized over the vesting period.

13

A summary of the status of the restricted stock and non-vested restricted stock units at June 30, 2006 is as follows:

		Weighted
	Stock	Average
	And	Grant Date
	Stock Units	Fair Value
	(in thousands)
Balance at January 1, 2006	90	$	30.71
Granted	40		35.18
Vested	(36)		29.14
Forfeited	(2)		31.90
Balance at June 30, 2006	92	$	33.24

The weighted-average grant-date fair value of restricted stock and restricted stock units granted in the six months ended June 30, 2006 and 2005 was $35.18 and $29.99, per share, respectively. The total fair value of shares vested during the six months ended June 30, 2006 and 2005 was $1.3 million and $1.1 million, respectively.

As of June 30, 2006, there was $2.3 million of unrecognized compensation expense related to non-vested restricted stock and non-vested restricted stock units that is expected to be recognized over a weighted-average period of 2.1 years.

Performance Share Plan

Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. 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.

Participants may earn additional performance shares if the Company’s total shareholder return exceeds the 50^th percentile of the selected peer group. The final value of the performance shares may vary according to the number of shares of common stock that are ultimately granted based upon the performance criteria.

Outstanding Performance Periods at June 30, 2006 are as follows:

Grant Date	Performance Period	Target Grant of Shares
		(in thousands)
March 1, 2004	March 1, 2004 – December 31, 2006	23
January 1, 2005	January 1, 2005 – December 31, 2007	39
January 1, 2006	January 1, 2006 – December 31, 2008	34

14

The performance awards are paid 50 percent in cash and 50 percent in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as temporary equity. In the event of a change-in-control performance awards are paid 100 percent in cash. If it is ever determined that a change-in-control is probable, the equity portion will be reclassified as a liability. At June 30, 2006, the Company had $0.8 million of temporary equity.

A summary of the status of the Performance Share Plan at June 30, 2006 and changes during the six-month period ended June 30, 2006, is as follows:

	Equity Portion			Liability Portion
		Weighted-			Weighted-
		Average			Average
		Grant Date			June 30, 2006
	Shares	Fair Value		Shares	Fair Value
	(in thousands)			(in thousands)
Balance at January 1, 2006	38	$	29.95	38
Granted	17		32.06	17
Forfeited	(1)		29.95	(1)
Vested	(6)		29.92	(6)
Balance at June 30, 2006	48	$	30.70	48	$	34.35

The weighted-average grant-date fair value of performance share awards granted in the six months ended June 30, 2006 and 2005 was $32.06 and $29.97, per share, respectively. The grant date fair value for the performance shares issued in 2006 was determined using a Monte Carlo simulation using a blended volatility of 21 percent comprised of 50 percent historical volatility and 50 percent implied volatility and the average risk-free interest rate of the three-year U.S. Treasury security rate in effect as of the grant date. The grant date fair value for the performance shares issued in 2005 was equal to the market value of the common stock on the grant date.

During the six months ended June 30, 2006, the Company issued 11,677 shares of common stock and paid $0.4 million for the Performance Period of March 1, 2004 to December 31, 2005, for a total intrinsic value of $0.8 million. The payout was fully accrued at December 31, 2005.

As of June 30, 2006, there was $1.7 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.9 years.

Other Plans

The Company issued 25,685 shares of common stock with an intrinsic value of $910,000 in the six months ended June 30, 2006 to certain key employees under the Short-term Annual Incentive Plan, a performance-based plan. The payout was fully accrued at December 31, 2005.

15

(10) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The Company has two non-contributory defined benefit pension plans (Plans). One Plan covers employees of the Company and the following subsidiaries who meet certain eligibility requirements: Black Hills Service Company, LLC, Black Hills Power, Inc., Wyodak Resources Development Corp., and Black Hills Exploration and Production, Inc. The other Plan covers employees of the Company’s subsidiary, Cheyenne Light, Fuel and Power Company, 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,
	2006		2005		2006		2005
Service cost	$	649	$	576	$	1,298	$	1,152
Interest cost		1,041		995		2,082		1,990
Expected return on plan assets		(1,247)		(1,157)		(2,494)		(2,314)
Amortization of prior service cost		38		54		76		108
Amortization of net loss		227		296		454		592
Net periodic benefit cost	$	708	$	764	$	1,416	$	1,528

The Company made a $1.2 million contribution to the Cheyenne Light Pension Plan in the first quarter of 2006; no additional contributions are anticipated to be made to the Plans during the 2006 fiscal year.

Supplemental Non-qualified Defined Benefit Plans

The Company has various supplemental retirement plans for key executives of the Company (Supplemental Plans). The Supplemental Plans are non-qualified 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,
	2006		2005		2006		2005
Service cost	$	87	$	86	$	174	$	172
Interest cost		270		252		540		504
Amortization of prior service cost		3		2		6		4
Amortization of net loss		199		157		398		314
Net periodic benefit cost	$	559	$	497	$	1,118	$	994

16

The Company anticipates that it will need to make contributions to the Supplemental Plans for the 2006 fiscal year of approximately $0.7 million. The contributions are expected to be made in the form of benefit payments.

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.

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,
	2006		2005		2006		2005
Service cost	$	164	$	185	$	328	$	370
Interest cost		203		232		406		464
Amortization of net transition
obligation		38		37		76		74
Amortization of prior service cost		(6)		(6)		(12)		(12)
Amortization of net loss		—		25		—		50
Net periodic benefit cost	$	399	$	473	$	798	$	946

The Company anticipates that it will make contributions to the Healthcare Plans for the 2006 fiscal year of approximately $0.2 million. The contributions are expected to be made in the form of benefits payments.

It has been determined that the Company’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy is as follows (in thousands):

	Three Months		Six Months
	Ended		Ended
	June 30, 2006		June 30, 2006
Service cost	$	(25)	$	(50)
Interest cost		(28)		(56)
Amortization of net loss		(18)		(36)
Total decrease to net periodic postretirement benefit cost	$	(71)	$	(142)

17

(11) 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, 2006, substantially all of the Company’s operations and assets are located within the United States. On March 1, 2006, the Company completed the sale of the operating assets of Black Hills Energy Resources, Inc. and related subsidiaries, the Company’s crude oil marketing and pipeline transportation business which for segment reporting was classified in the Energy marketing and transportation segment; and 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 15). The financial information of the related crude oil marketing and pipeline transportation business and communications segment has been reclassified into Discontinued operations on the accompanying condensed consolidated financial statements.

The Company conducts its operations through the following six reporting segments: 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; and 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, Oklahoma and other states; Energy marketing, which markets natural gas, oil and related services to customers in the Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions; and Power generation, which produces and sells power and capacity to wholesale customers with plants concentrated in Colorado, Nevada, Wyoming and California.

Segment information follows the same accounting policies as described in Note 22 of the Company’s 2005 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.

18

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

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
June 30, 2006
Retail services:
Electric utility	$	46,405	$	631	$	2,436
Electric and gas utility		29,730		—		864
Wholesale energy:
Coal mining		3,854		2,913		768
Oil and gas		21,313		—		2,042
Energy marketing		11,624		—		4,553
Power generation		38,697		—		2,379
Corporate		16		—		(674)
Intersegment eliminations		—		(1,370)		—
Total	$	151,639	$	2,174	$	12,368

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
June 30, 2005
Retail services:
Electric utility	$	41,910	$	351	$	3,409
Electric and gas utility		27,459		—		643
Wholesale energy:
Coal mining		5,307		3,053		1,728
Oil and gas		19,662		—		4,277
Energy marketing		5,263		—		1,964
Power generation		40,128		—		6,101
Corporate		289		—		(2,807)
Intersegment eliminations		—		(1,037)		—
Total	$	140,018	$	2,367	$	15,315

19

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Six Month Period Ended
June 30, 2006
Retail services:
Electric utility	$	90,209	$	795	$	7,335
Electric and gas utility		73,428		—		2,261
Wholesale energy:
Coal mining		9,850		6,188		2,183
Oil and gas		46,550		—		7,432
Energy marketing		28,581		—		10,872
Power generation		72,290		—		4,471
Corporate		32		—		(3,625)
Intersegment eliminations		—		(2,219)		—
Total	$	320,940	$	4,764	$	30,929

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Six Month Period Ended
June 30, 2005
Retail services:
Electric utility	$	84,959	$	449	$	7,732
Electric and gas utility		54,533		—		1,155
Wholesale energy:
Coal mining		10,180		6,199		3,216
Oil and gas		38,703		—		9,237
Energy marketing		12,795		—		3,392
Power generation		78,290		—		9,987
Corporate		554		—		(4,150)
Intersegment eliminations		—		(1,857)		—
Total	$	280,014	$	4,791	$	30,569

Other than the sale of the assets of the crude oil marketing and transportation business and its reclassification to Discontinued operations, and the acquisition of certain oil and gas assets in the Piceance Basin in Colorado, the Company had no material changes in the assets of its reporting segments, as reported in Note 22 of the Notes to Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

20

(12) 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 2005 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 and Crude Oil Marketing

The Company’s natural gas and crude oil marketing subsidiary, Enserco Energy Inc., recently began marketing crude oil in the Rocky Mountain region out of the Company’s Golden, Colorado offices. Our primary strategy involves executing physical crude oil purchase contracts with producers, and reselling into various markets. These transactions are primarily entered into as back-to-back purchases and sales, effectively locking in a marketing fee equal to the difference between the sales price and the purchase price, less transportation costs. Under FAS 133, mark-to-market accounting for the related commodity contracts in the Company’s back-to-back strategy results in an acceleration of marketing margins locked in for the term of the contracts. These are generally short-term contracts with automatic renewals (typically monthly) if there is no notice of cancellation. The realized and unrealized gains and losses from the oil marketing activities are shown net on the accompanying Condensed Consolidated Income Statement within “Operating revenues”.

The contract or notional amounts and terms of the Company’s natural gas and crude oil marketing activities and derivative commodity instruments are as follows:

	June 30, 2006			December 31, 2005			June 30, 2005
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)
(in thousands of MMbtus)
Natural gas basis
swaps purchased		110,281	16		43,507	22		61,431	21
Natural gas basis
swaps sold		118,342	16		53,665	22		59,426	16
Natural gas fixed-for-float
swaps purchased		29,537	17		17,083	23		24,532	21
Natural gas fixed-for-float
swaps sold		40,604	17		24,871	23		25,562	16
Natural gas physical
purchases		80,193	28		59,855	34		88,729	18
Natural gas physical sales		128,747	40		88,302	46		127,996	53
Natural gas options
purchased		18,145	18		6,176	21		7,568	27
Natural gas options sold		18,145	18		6,176	21		7,568	27
(in thousands of barrels)
Crude oil physical
purchases		1,785	4		—			—
Crude oil physical sales		1,568	4		—			—

21

	June 30, 2006			December 31, 2005			June 30, 2005
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)
(Dollars, in thousands)
Canadian dollars
purchased	$	18,000	2	$	88,000	2	$	4,300	1
Canadian dollars sold	$	11,000	5	$	29,000	5	$	25,700	7

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on June 30, 2006, December 31, 2005 and June 30, 2005, 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, 2006	$	24,631	$	697	$	11,673	$	70	$	13,585
December 31, 2005	$	20,326	$	1,747	$	20,751	$	2,086	$	(764)
June 30, 2005	$	8,976	$	911	$	11,836	$	1,024	$	(2,973)

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 Condensed Consolidated Balance Sheets and the related unrealized gain/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of June 30, 2006, December 31, 2005 and June 30, 2005, the market adjustments recorded in inventory were $(4.3) million, $6.6 million and $2.9 million, respectively.

22

Activities Other Than Trading

Oil and Gas Exploration and Production

On June 30, 2006, December 31, 2005 and June 30, 2005, the Company had the following swaps and related balances (in thousands):

											Pre-tax
		Maximum			Non-				Non-		Accumulated
		Terms	Current		current		Current		current		Other		Pre-tax
		in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
June 30,
2006
Crude oil
swaps/options	360,000	1.00	$	302	$	—	$	3,286	$	1,179	$	(4,465)	$	302
Natural gas
swaps	4,485,000	0.60		3,748		202		—		—		3,950		—
			$	4,050	$	202	$	3,286	$	1,179	$	(515)	$	302
December 31,
2005
Crude oil
swaps/options	300,000	1.00	$	150	$	—	$	2,535	$	307	$	(2,842)	$	150
Natural gas
swaps	2,950,000	0.60		—		151		2,560		—		(2,409)		—
			$	150	$	151	$	5,095	$	307	$	(5,251)	$	150
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)

________________________

*crude in barrels, gas in MMbtu’s

Based on June 30, 2006 market prices, a $0.2 million gain would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

23

Financing Activities

On June 30, 2006, December 31, 2005 and June 30, 2005, the Company’s interest rate swaps and related balances were as follows (in thousands):

			Weighted										Pre-tax
			Average				Non-				Non-		Accumulated
	Current		Fixed	Maximum	Current		current		Current		current		Other		Pre-tax
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
June 30,
2006
Swaps on
project
and other
financings	$	75,000	4.93%	9.5	$	350	$	2,250	$	—	$	—	$	2,566	$	34
December 31,
2005
Swaps on
project
financing	$	163,000	4.43%	10	$	13	$	—	$	76	$	230	$	(249)	$	(44)
June 30,
2005
Swaps on
project
financing	$	113,000	4.22%	1.25	$	116	$	—	$	528	$	80	$	(154)	$	(338)

Based on June 30, 2006 market interest rates and balances, a gain of approximately $0.4 million would be realized and reported in pre-tax earnings during the next twelve months. Estimated and realized amounts will likely change during the next twelve months as market interest rates change.

24

(13) LEGAL PROCEEDINGS

The Company is subject to various legal proceedings, claims and litigation as described in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K.

PPM Energy, Inc. Demand for Arbitration

As disclosed in previous filings with the SEC, the Company’s subsidiary, Black Hills Power, Inc. received a Demand for Arbitration from PPM Energy, Inc. (PPM) on January 2, 2004, that alleged claims for breach of contract and requested a declaration of the parties’ rights and responsibilities under an Exchange Agreement executed in April of 2001. PPM asserted the Exchange Agreement obligated Black Hills Power to accept receipt and cause corresponding delivery of electric energy, and to grant access to transmission rights allegedly covered by the Agreement. PPM requested an award of damages in an amount not less than $20.0 million. Black Hills Power filed its Response to Demand, including a counterclaim that sought recovery of sums PPM had refused to pay pursuant to the Exchange Agreement. The dispute was presented to the arbitrator in August 2005 and the arbitrator delivered his decision on June 5, 2006.

The arbitrator concluded both parties failed to perform the Exchange Agreement, in certain respects. Black Hills Power has paid PPM a net settlement of $1.1 million in accordance with the decision. The Company does not believe that the decision will have a material impact on its ability to market surplus power in the future.

Price Reporting Class Actions

As disclosed in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2005 Annual Report on Form 10-K, the Company reached a tentative settlement with the Plaintiffs on October 28, 2005. Approval of the final settlement documents occurred on May 19, 2006 and the litigation is now concluded.

Except as described above, there have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first six months of 2006.

(14) ACQUISITIONS

Oil and Gas Assets

On March 17, 2006, the Company acquired certain oil and gas assets of Koch Exploration Company, LLC, for approximately $51.4 million. The associated acreage position is located in the Piceance Basin in Colorado and includes approximately 40 Bcfe of proved reserves, including approximately 31 Bcfe of proved undeveloped reserves, which are substantially all gas. The acquisition includes 63 producing wells and majority interests in associated midstream and gathering assets. Operations of these assets prior to acquisition were not material to the Company’s consolidated operations; therefore no pro-forma information has been presented herein.

25

Cheyenne Light, Fuel and Power

On January 21, 2005, the Company completed the acquisition of Cheyenne Light. The Company purchased all the common stock of Cheyenne Light, including the assumption of outstanding debt of approximately $24.6 million, for approximately $90.7 million.

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. Allocation of the purchase price as revised for working capital adjustments is as follows (in thousands):

Current assets	$	18,036
Property, plant and equipment		91,442
Deferred assets		24,282
	$	133,760
Current liabilities	$	12,793
Long-term debt		26,388
Deferred tax liabilities		7,888
Long-term liabilities		20,547
	$	67,616
Net assets	$	66,144

The results of operations of Cheyenne Light have been included in the accompanying Condensed Consolidated Financial Statements since the acquisition date.

The following pro-forma consolidated results of operations for the Company have been prepared as if the Cheyenne Light acquisition had occurred on January 1, 2005 (in thousands):

	Six Month
	Period Ended
	June 30, 2005
Operating revenues	$	293,983
Income from
continuing operations		30,748
Net income		30,889
Earnings per share –
Basic:
Continuing operations	$	0.94
Total	$	0.95
Diluted:
Continuing operations	$	0.93
Total	$	0.93

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.

26

(15) 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 (loss) from discontinued operations, net of taxes” in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis.

Sale of Crude Oil Marketing and Transportation Assets

On March 1, 2006, the Company sold the operating assets of Black Hills Energy Resources, Inc. and related subsidiaries, its crude oil marketing and transportation business for approximately $41 million. Assets sold include the 200-mile Millennium and the 190-mile Kilgore Pipelines, oil marketing contracts and certain other ancillary assets. Following the sale, the Company closed the operations of the Houston, Texas based business. For business segment reporting purposes, Black Hills Energy Resources was included in the Energy marketing and transportation segment.

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Operating revenues	$	36	$	167,058	$	171,905	$	320,657
Pre-tax (loss) income from
discontinued operations
(including 2006 severance
payments)	$	(376)	$	1,062	$	(2,218)	$	3,347
Pre-tax (loss) gain on sale of
assets		(558)		—		13,104		—
Income tax benefit (expense)		323		(337)		(3,907)		(1,124)
Net (loss) income from
discontinued operations	$	(611)	$	725	$	6,979	$	2,223

Losses incurred subsequent to the asset sale resulted from the settlement of certain contract disputes with the purchaser and other costs incurred in closing down the business operations.

27

Assets and liabilities of the Crude oil marketing and transportation business were as follows (in thousands):

	June 30, 2006		December 31, 2005		June 30, 2005
Current assets	$	6,058	$	94,697	$	71,324
Property, plant and equipment, net		—		25,364		24,265
Other non-current assets		—		2,097		2,130
Current liabilities		(5,122)		(89,750)		(62,532)
Other non-current liabilities		(857)		(3,068)		(3,068)
Net assets	$	79	$	29,340	$	32,119

Communications Segment

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

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

	Three Months		Six Months
	Ended		Ended
	June 30,		June 30,
	2005		2005
Operating revenues	$	12,211	$	21,877
Pre-tax income from discontinued operations	$	5,361	$	3,978
Pre-tax loss on disposal		(7,235)		(7,235)
Income tax benefit		914		1,410
Net loss from discontinued operations	$	(960)	$	(1,847)

Sale of Pepperell Plant

On April 8, 2005, the Company sold the 40 megawatt gas-fired Pepperell plant to an unrelated party for a nominal amount plus the assumption of certain obligations. 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		Six Months
	Ended		Ended
	June 30,		June 30,
	2005		2005
Pre-tax loss from discontinued operations	$	(204)	$	(329)
Pre-tax loss on disposal		(39)		(39)
Income tax benefit		133		133
Net loss from discontinued operations	$	(110)	$	(235)

28

(16) SUBSEQUENT EVENTS

Credit Agreement

On July 12, 2006 the Company’s subsidiary, Black Hills Colorado, LLC, entered into a Second Amended and Restated Credit Agreement to refinance the floating rate project debt for the Valmont and Arapahoe plants in the amount of $90.0 million. In conjunction with the refinancing, the Company made a payment in the amount of $21.3 million on the $111.3 million principal outstanding at June 30, 2006 and expensed $0.7 million of unamortized deferred finance costs associated with the First Amended and Restated Credit Agreement. In addition, as of July 12, 2006, the Company has guaranteed the payment obligations of Black Hills Colorado, LLC, to the Bank of Nova Scotia, as administrative agent, in the amount of $30 million. The cost of borrowings under the facility is determined based upon on our corporate credit ratings; at our current ratings levels, the facility has a borrowing spread on Eurodollar loans of 87.5 basis points over LIBOR.

Agreements to Acquire Additional Oil and Gas Interests

The Company has signed definitive agreements to acquire from a third party most of the remaining working interests associated with the property acquired in March 2006 from Koch Exploration Company. The acquisition includes approximately 22.4 billion cubic feet equivalent (Bcfe) of proven reserves, of which 17.9 billion cubic feet equivalent are proved undeveloped reserves. Current annual net production from such assets is slightly less than 0.5 Bcfe. As part of the transaction, the Company will also acquire rights to more than 15,000 net acres of undeveloped leasehold adjacent or near existing operations in the Piceance Basin of Colorado. Upon completion, the Company's leasehold position in the Piceance Basin would total approximately 75,000 net acres. The purchase price for the transaction is approximately $24.1 million. The Company anticipates completion of the acquisition in the third quarter of 2006.

29

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

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

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

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 63,500 customers in South Dakota, Wyoming and Montana. Our electric and gas utility, acquired on January 21, 2005, serves approximately 38,700 electric and 32,500 natural gas customers in Cheyenne, Wyoming and vicinity. Our wholesale energy group 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 of fuel products.

In March 2006, we sold the operating assets of Black Hills Energy Resources, Inc. and related subsidiaries, our crude oil marketing and pipeline transportation business headquartered in Houston, Texas. These activities were previously reported in our Energy marketing and transportation segment. 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, which was previously reported in our Power generation 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 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

30

Results of Operations

Consolidated Results

Revenues and Income (Loss) from continuing operations provided by each business group were as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Revenues
Retail services	$	76,135	$	69,369	$	163,637	$	139,492
Wholesale energy		77,662		72,727		162,035		144,759
Corporate		16		289		32		554
	$	153,813	$	142,385	$	325,704	$	284,805
Income/(Loss) from
Continuing Operations
Retail services	$	3,300	$	4,052	$	9,596	$	8,887
Wholesale energy		9,742		14,070		24,958		25,832
Corporate		(674)		(2,807)		(3,625)		(4,150)
	$	12,368	$	15,315	$	30,929	$	30,569

Discontinued operations in 2006 and 2005 represent the operations of our crude oil marketing and transportation business, sold in March 2006; our Communications segment, Black Hills FiberSystems, Inc., which was sold in June 2005; and our 40 megawatt Pepperell power plant, which was sold in April 2005.

Prior to the reclassification of the financial results of our crude oil marketing and transportation business into discontinued operations, the related revenues and cost of sales were presented on a gross basis. Accordingly, our operating revenues and expenses, as previously presented in the 2005 interim financial statements, are adjusted by the following to reflect crude oil marketing and transportation revenues and cost of sales in discontinued operations (in millions):

	Three month period ended								Total
	March 31, 2005		June 30, 2005		September 30, 2005		December 31, 2005		2005
Operating
revenues	$	153.6	$	167.1	$	224.0	$	233.4	$	778.1
Cost of sales	$	149.3	$	163.9	$	221.6	$	230.4	$	765.2

31

On January 21, 2005, we completed the acquisition of Cheyenne Light, Fuel and Power Company (Cheyenne Light), an electric and natural gas utility serving customers in Cheyenne, Wyoming and vicinity. The results of operations of Cheyenne Light have been included in the accompanying Condensed Consolidated Financial Statements from the date of acquisition.

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005. Revenues for the three months ended June 30, 2006 increased 8 percent, or $11.4 million, compared to the same period in 2005. Increased revenues were primarily driven by higher wholesale sales at Black Hills Power, higher rates at Cheyenne Light, higher margins in our energy marketing activities and higher revenues from our oil and gas production, partially offset by lower revenues at our power generation and coal mining businesses due to scheduled and unscheduled plant outages.

Operating expenses increased 11 percent, or $12.1 million, primarily due to higher fuel and purchased power costs, increased operations and maintenance for scheduled and unscheduled plant outages and increased depletion expense at our oil and gas operations.

Income from continuing operations decreased $2.9 million due primarily to the following:

•      $1.0 million decrease in Electric utility earnings;

•      a $1.0 million decrease in Coal mining earnings;

•      a $2.2 million decrease in Oil and gas earnings;

•      a $3.7 million decrease in Power generation earnings,

partially offset by the following increases:

•      a $2.6 million increase in Energy marketing earnings; and

•      a $2.1 million decrease in unallocated corporate costs.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005. Revenues for the six months ended June 30, 2006 increased 14 percent, or $40.9 million, compared to the same period in 2005. Increased revenues were primarily driven by higher retail and wholesale sales at Black Hills Power, a full six months of activity and higher rates at Cheyenne Light, higher margins in our energy marketing activities and higher revenues from oil and gas production, partially offset by lower revenues at our power generation and coal mining businesses due to scheduled and unscheduled plant outages.

Operating expenses increased 16 percent, or $35.5 million, primarily due to higher fuel and purchased power costs, increased operations and maintenance for scheduled and unscheduled plant outages and increased lease operating expense and depletion expense at our oil and gas operations.

32

Income from continuing operations increased $0.4 million due primarily to the following:

•      a $7.5 million increase in Energy marketing earnings;

•      a $1.1 million increase in Electric and gas utility earnings;

•      a $0.5 million decrease in unallocated corporate costs,

partially offset by the following decreases:

•      a $0.4 million decrease in Electric utility earnings;

•      a $1.0 million decrease in Coal mining earnings;

•      a $1.8 million decrease in Oil and gas earnings; and

•      a $5.5 million decrease in Power generation earnings.

See the following discussion of our business segments under the captions “Retail Services Group” and “Wholesale Energy Group” for more detail on our results of operations.

The following business group and segment information does not include intercompany eliminations or discontinued operations. Accordingly, 2005 information has been revised as necessary to reclassify information related to operations that were discontinued.

Retail Services Group

Electric Utility

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(in thousands)
Revenue	$	47,036	$	42,261	$	91,004		$	85,408
Operating expenses		40,545		34,141		74,416			67,793
Operating income	$	6,491	$	8,120	$	16,588		$	17,615
Income from continuing operations
and net income	$	2,436	$	3,409	$	7,335		$	7,732

33

The following tables provide certain operating statistics for the Electric utility segment:

	Electric Revenue
	(in thousands)
	Three Months Ended June 30,					Six Months Ended June 30,
			Percentage					Percentage
Customer Base	2006		Change	2005		2006		Change	2005
Commercial	$	11,892	2%	$	11,634	$	23,290	1%	$	23,065
Residential		8,868	3		8,649		19,556	2		19,207
Industrial		5,187	6		4,910		10,198	4		9,764
Municipal sales		591	6		555		1,111	6		1,048
Total retail sales		26,538	3		25,748		54,155	2		53,084
Contract wholesale		5,920	4		5,672		12,028	3		11,657
Wholesale off-system		10,575	15		9,171		18,809	9		17,284
Total electric sales		43,033	6		40,591		84,992	4		82,025
Other revenue		4,003	140		1,670		6,012	78		3,383
Total revenue	$	47,036	11%	$	42,261	$	91,004	7%	$	85,408

	Megawatt Hours Sold
	Three Months Ended June 30,			Six Months Ended June 30,
		Percentage			Percentage
Customer Base	2006	Change	2005	2006	Change	2005
Commercial	158,046	4%	152,644	316,639	2%	310,162
Residential	105,484	3	102,692	247,278	3	240,639
Industrial	108,333	4	103,695	211,360	5	202,093
Municipal sales	7,652	12	6,827	14,711	11	13,290
Total retail sales	379,515	4	365,858	789,988	3	766,184
Contract wholesale	154,694	3	150,659	316,945	2	311,997
Wholesale off-system	268,174	26	212,460	448,337	12	400,074
Total electric sales	802,383	10%	728,977	1,555,270	5%	1,478,255

	Three Months Ended			Six Months Ended
	June 30,			June 30,
		Percentage			Percentage
Resources	2006	Change	2005	2006	Change	2005
Megawatt-hours generated:
Coal	366,821	(14)%	426,400	820,954	(5)%	862,300
Gas	11,482	200	3,830	13,693	149	5,500
	378,303	(12)	430,230	834,647	(4)	867,800
Megawatt - hours purchased	464,219	40	331,434	776,506	19	653,105
Total resources	842,522	11%	761,664	1,611,153	6%	1,520,905

34

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
Heating and cooling degree days:
Actual
Heating degree days	710	933	3,656	3,923
Cooling degree days	211	148	211	148
Percent of normal
Heating degree days	71%	94%	85%	91%
Cooling degree days	209%	147%	209%	147%

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005. Income from continuing operations decreased $1.0 million primarily due to increased operations and maintenance expense and fuel and purchased power costs, partially offset by increased revenues.

Electric utility revenues increased 11 percent for the three month period ended June 30, 2006, compared to the same period in the prior year. Total retail megawatt-hour sales increased 4 percent compared to the three months ended June 30, 2005. Heating degree days, which is a measure of weather trends, were 24 percent lower and cooling degree days were 43 percent higher, than the same period in the prior year. Wholesale off-system sales increased 15 percent due to a 26 percent increase in megawatt-hours sold partially offset by a 9 percent decrease in average price received.

Electric operating expenses increased 19 percent for the three month period ended June 30, 2006, compared to the same period in the prior year. Fuel and purchased power costs increased 32 percent due to a 10 percent increase in megawatt-hours sold combined with increased cost per megawatt-hour primarily due to the impact of replacing low cost base load power with higher priced alternatives during the 48 day scheduled outage of the Wyodak plant. Operating expense for the three months ended June 30, 2006 was also affected by increased repairs and maintenance expense incurred for the Wyodak Plant maintenance and higher corporate allocations, partially offset by a decrease in power marketing legal costs relative to costs incurred in the second quarter of 2005 (See Notes to Condensed Consolidated Financial Statements, Note 13 Legal Proceedings, for discussion of power marketing legal settlement).

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005. Income from continuing operations decreased 5 percent primarily due to increased operations and maintenance expense and fuel and purchased power costs, partially offset by increased revenues.

Electric utility revenues increased 7 percent for the six month period ended June 30, 2006, compared to the same period in the prior year. Total retail megawatt-hour sales increased 3 percent compared to the six months ended June 30, 2005. Heating degree days, which is a measure of weather trends, were 7 percent lower and cooling degree days were 43 percent higher, than the same period in the prior year. Wholesale off-system sales increased 9 percent due to a 12 percent increase in megawatt-hours sold partially offset by a 3 percent decrease in average price received.

35

Electric operating expenses increased 10 percent for the six month period ended June 30, 2006, compared to the same period in the prior year. Fuel and purchased power costs increased 17 percent due to a 5 percent increase in megawatt-hours sold combined with increased cost per megawatt- hour primarily due to the impact of replacing low cost base load power with higher priced alternatives during the 48 day scheduled outage of the Wyodak plant. Operating expense for the six months ended June 30, 2006 was also affected by increased repairs and maintenance expense incurred for the Wyodak Plant maintenance and higher corporate allocations, partially offset by a decrease in power marketing legal costs relative to costs incurred in 2005 (See Notes to Condensed Consolidated Financial Statements, Note 13 Legal Proceedings, for discussion of power marketing legal settlement).

Request for Rate Increase. On June 30, 2006 our electric utility filed an application with the South Dakota Public Utilities Commission (SDPUC) for an electric rate increase to be effective January 1, 2007. The application requests a 9.5 percent rate increase for all customer classes. In addition, the application proposes annual energy cost adjustments. The proposed cost adjustments would require the electric utility to absorb a portion of power cost increases, depending in part on earnings on certain short-term wholesale sales of electricity. The current rate structure, in place since 1995, does not contain fuel or purchased power adjustment clauses and only provides the ability to request rate relief from energy costs in certain defined situations. We expect these increases, if approved by the SDPUC, would result in an annual revenue increase of approximately $9.5 million. South Dakota retail customers account for approximately 90 percent of the electric utility’s total retail revenues. A rate freeze has been in place for the electric utility since 1995.

Electric and Gas Utility

	Three Months Ended				Six Months		January 21,
	June 30,				Ended		2005 to
	2006		2005		June 30, 2006		June 30, 2005
	(in thousands)
Revenue	$	29,730	$	27,459	$	73,428	$	54,533
Purchased gas and electricity		23,427		21,670		59,603		44,945
Gross margin		6,303		5,789		13,825		9,588
Operating expenses		5,297		4,857		10,919		7,758
Operating income	$	1,006	$	932	$	2,906	$	1,830
Income from continuing operations
and net income	$	864	$	643	$	2,261	$	1,155

36

The following tables provide certain operating statistics for the Electric and gas utility segment:

	Electric Revenue
	(in thousands)
	Three Months			Three Months		Six Months			January 21,
	Ended		Percentage	Ended		Ended		Percentage	2005 to
Customer Base	June 30, 2006		Change	June 30, 2005		June 30, 2006		Change	June 30, 2005
Commercial	$	10,873	7%	$	10,159	$	21,315	17%	$	18,259
Residential		6,417	2		6,290		13,990	18		11,892
Industrial		2,140	(2)		2,180		4,325	(2)		4,405
Municipal sales		201	32		152		404	50		269
Total electric sales		19,631	5		18,781		40,034	15		34,825
Other revenue		131	—		5		224	—		4
Total revenue	$	19,762	5%	$	18,786	$	40,258	16%	$	34,829

	Three Months		Three Months	Six Months		January 21,
	Ended	Percentage	Ended	Ended	Percentage	2005 to
	June 30,	Change	June 30,	June 30,	Change	June 30,
Resources	2006		2005	2006		2005
Megawatt-hours purchased	241,034	2%	236,252	487,736	16%	420,572

	Gas Revenue
	(in thousands)
	Three Months			Three Months		Six Months			January 21,
	Ended		Percentage	Ended		Ended		Percentage	2005 to
Customer Base	June 30, 2006		Change	June 30, 2005		June 30, 2006		Change	June 30, 2005
Commercial	$	2,920	21%	$	2,420	$	9,971	71%	$	5,819
Residential		5,648	11		5,099		18,544	67		11,120
Industrial		1,144	19		964		4,177	76		2,370
Total gas sales		9,712	14		8,483		32,692	69		19,309
Other revenue		256	35		190		478	21		395
Total revenue	$	9,968	15%	$	8,673	$	33,170	68%	$	19,704

	Three Months		Three Months	Six Months		January 21,
	Ended		Ended	Ended		2005 to
	June 30,	Percentage	June 30,	June 30,	Percentage	June 30,
Resources	2006	Change	2005	2006	Change	2005
Dekatherms purchased	706,956	(16)%	842,380	2,507,491	20%	2,092,236

	Three Months		Three Months	Six Months		January 21,
	Ended		Ended	Ended		2005 to
	June 30,	Percentage	June 30,	June 30,	Percentage	June 30,
	2006	Change	2005	2006	Change	2005
Electric sales - MWh	218,795	(4)%	228,685	451,622	8%	417,239
Gas sales - Dth	823,868	(14)%	961,633	2,694,322	14%	2,373,734

37

	Three Months Ended			Six Months	January 21,
	June 30			Ended June 30,	2005 to June 30,
	2006		2005	2006	2005
Heating and cooling degree days:
Actual
Heating degree days	877	1,201		3,868	4,007
Cooling degree days	124	65		124	65
Percent of normal
Heating degree days	71%	97%		88%	92%
Cooling degree days	295%	155%		295%	155%

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005. Income from continuing operations increased $0.2 million for the three months ended June 30, 2006 compared to the three months ended June 30, 2005.

Gross margin increased 9 percent primarily due to an increase in base rates that went into effect January 1, 2006 partially offset by a 4 percent decrease in electric usage and a 14 percent decrease in gas usage. Heating degree days were 27 percent lower, and cooling degree days were 91 percent higher, than the same period in the prior year. We believe gross margin is a better performance measure as fluctuations in cost of gas and electricity flow through to revenues through cost recovery adjustments.

Operating expenses increased 9 percent primarily due to increased general and administrative costs and depreciation expense.

Six Months Ended June 30, 2006 Compared to the Period January 21, 2005 to June 30, 2005. Income from continuing operations increased $1.1 million for the six months ended June 30, 2006 compared to the period January 21 to June 30, 2005.

Gross margin increased 44 percent primarily due to an increase in base rates that went into effect January 1, 2006 and an 8 percent increase in electric usage and a 14 percent increase in gas usage. Heating degree days were 3 percent lower, and cooling degree days were 91 percent higher, than the same period in the prior year. We believe gross margin is a better performance measure as fluctuations in cost of gas and electricity flow through to revenues through cost recovery adjustments.

Operating expenses increased 41 percent due to increased general and administrative costs, depreciation expense and increased operating costs due to a full six months of operations in 2006.

We are progressing with the construction of Wygen II, a 90 megawatt, coal-fired power plant sited at our Wyodak energy complex near Gillette, Wyoming. Wygen II will be a regulated asset of Cheyenne Light. The power plant is expected to be in commercial operation by early 2008 and will require a future rate review with the Wyoming Public Service Commission in order to recover capital and provide a return on invested capital.

38

Wholesale Energy Group

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

Energy Marketing

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006		2005
	(in thousands)
Revenue	$	11,624		$	5,263	$	28,581	$	12,795
Operating expenses		4,893			2,335		12,048		7,415
Operating income	$	6,731		$	2,928	$	16,533	$	5,380
Income from continuing operations	$	4,553		$	1,964	$	10,872	$	3,392

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
Natural gas physical sales – MMbtus	1,504,300	1,562,600	1,390,700	1,460,700
Crude oil physical barrels – barrels(a)	8,945	—	8,945	—

____________________

(a) Daily oil volumes are calculated as of May 1, 2006

Our natural gas marketing subsidiary, Enserco Energy Inc., recently began marketing crude oil in the Rocky Mountain region out of our Golden, Colorado offices. Our primary strategy involves executing physical crude oil purchase contracts with producers, and reselling into various markets. These transactions are primarily entered into as back-to-back purchases and sales, effectively locking in a marketing fee equal to the difference between the sales price and the purchase price, less transportation costs. Under FAS 133, mark-to-market accounting for the related commodity contracts in our back-to-back strategy results in an acceleration of marketing margins locked in for the term of the contracts. These are generally short-term contracts with automatic renewals if there is no notice of cancellation. The realized and unrealized gains and losses from the oil marketing activities are shown net within “Operating revenues” on the Condensed Consolidated Statement of Income.

39

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005. Income from continuing operations increased $2.6 million due to increased realized marketing margins, partially offset by a decrease in unrealized marketing gains/losses.

Realized marketing margins increased approximately $8.6 million over the prior year due to higher average margins received partially offset by a 4 percent decrease in natural gas volumes marketed. Unrealized mark-to-market gains decreased $2.7 million from unrealized mark-to-market gains for the same period in 2005. (For discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas and oil marketing operations see “Trading Activities” in Part 1, Item 3 of this Form 10-Q.) Results also reflect earnings from the addition of crude oil marketing to our Rocky Mountain region producer services. Operating expenses increased primarily due to increased compensation cost related to higher realized margins.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005. Income from continuing operations increased $7.5 million due to increased realized and unrealized marketing margins.

Realized marketing margins increased approximately $13.8 million over the prior year primarily due to higher average margins received for gas marketing partially offset by a 5 percent decrease in natural gas volumes sold. Unrealized mark-to-market gains for the six months ended June 30, 2006 were $1.8 million higher than unrealized mark-to-market gains for the same period in 2005. (For discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas and oil marketing operations see “Trading Activities” in Part 1, Item 3 of this Form 10-Q.) Results also reflect earnings from the addition of crude oil marketing to our Rocky Mountain region producer services. Operating expenses increased primarily due to increased compensation cost related to higher realized margins and an increase in bad debt accruals.

Power Generation

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(in thousands)
Revenue	$	38,697	$	40,128	$	72,290		$	78,290
Operating expenses		24,858		25,822		48,897			52,216
Operating income	$	13,839	$	14,306	$	23,393		$	26,074
Income from continuing operations	$	2,379	$	6,101	$	4,471		$	9,987

	June 30,
	2006	2005
Independent power capacity:
MWs of independent power capacity	1,000	964

40

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
Contracted fleet plant availability	89.0%	98.1%	87.4%	98.7%

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005. Income from continuing operations decreased 61 percent due to decreased revenues, lower earnings from certain power fund investments and increased interest expense, partially offset by decreases in operating expense. Revenues in the second quarter of 2006 decreased 4 percent compared to revenues in the second quarter of 2005. Lower revenues are primarily due to scheduled and unscheduled outages for repair and maintenance at the Las Vegas I and II facilities.

Operating expense for the three months ended June 30, 2006, decreased 4 percent from the same period in the prior year. The decrease in operating expenses resulted from lower variable operating costs at the Las Vegas facilities during the plant outages, partially offset by the associated repair and maintenance costs. Las Vegas I returned to operation on April 22, 2006, while the two Las Vegas II heat recovery units returned to service on June 13, 2006 and July 4, 2006.

Income from continuing operations was also affected by lower earnings from certain power fund investments and increased interest expense due to changes in the corporate interest allocations. Earnings from power fund investments decreased $2.6 million after-tax due to the particularly strong fund earnings in 2005 and diminished earnings potential related to the ongoing liquidation of the funds.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005. Income from continuing operations decreased 55 percent due to decreased revenues, lower earnings from certain power fund investments and increased interest expense, partially offset by decreases in operating expense. Revenues in the six months ended June 30, 2006 decreased 8 percent compared to revenues in the same period of 2005. Lower revenues are primarily due to scheduled and unscheduled outages for repair and maintenance at the Las Vegas I and II facilities, partially offset by higher capacity revenue at the Harbor facility due to a three-year, year-round tolling agreement, which commenced April 1, 2005 and replaced a seasonal contract.

Operating expense for the six months ended June 30, 2006, decreased 6 percent from the same period in the prior year. The decrease in operating expenses resulted from lower variable operating costs at the Las Vegas facilities during the plant outages, partially offset by the associated repair and maintenance costs. Las Vegas I returned to operation on April 22, 2006, while the two Las Vegas II heat recovery units returned to service on June 13, 2006 and July 4, 2006.

Income from continuing operations was also affected by lower earnings from certain power fund investments and increased interest expense due to changes in the corporate interest allocations. Earnings from power fund investments decreased $2.9 million after-tax due to the particularly strong fund earnings in 2005 and diminished earnings potential related to the ongoing liquidation of the funds.

41

Oil and Gas

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(in thousands)
Revenue	$	21,313	$	19,662	$	46,550		$	38,703
Operating expenses		16,271		12,490		32,224			23,908
Operating income	$	5,042	$	7,172	$	14,326		$	14,795
Income from continuing operations	$	2,042	$	4,277	$	7,432		$	9,237

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
Fuel production:
Barrels of oil sold	96,300	104,600	186,800	200,400
Mcf of natural gas sold	3,088,500	2,816,000	6,047,600	5,705,800
Mcf equivalent sales	3,666,300	3,443,600	7,168,400	6,908,200

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006		2005			2006			2005
Average price received*:
Gas/Mcf**	$	5.19		$	5.58		$	6.07		$	5.47
Oil/bbl	$	48.40		$	32.87		$	46.91		$	32.80
Lease operating expenses/Mcfe	$	1.18		$	1.03		$	1.19		$	0.92
Depletion expense/Mcfe	$	1.77		$	1.17		$	1.70		$	1.08

________________________

* Net of hedges

** Exclusive of gas liquids

42

Location detail of our proven reserves as of December 31, 2005, not reflecting 2006 drilling activity, acquisitions or price changes, is as follows:

		San Juan Basin	Powder River	Piceance
		New Mexico	Basin	Basin
	Total	and Colorado	Wyoming	Colorado	All Other
Proved developed (Mmcfe)	109,123	58,528	33,935	2,070	14,590
Proved undeveloped(Mmcfe)	60,460	43,953	10,612	2,278	3,617
Total	169,583	102,481	44,547	4,348	18,207

Reserves reflect year end pricing of:

December 31, 2005 gas prices:
Year-end prices NYMEX	$	11.23
Year-end prices wellhead	$	9.06	$	9.36	$	8.26	$	8.87	$	8.79
December 31, 2005 oil prices:
Year-end prices NYMEX	$	61.04
Year-end prices wellhead	$	58.52	$	54.27	$	58.61	$	-	$	57.99

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005. Income from continuing operations decreased 52 percent in the three months ended June 30, 2006 compared to the same period in 2005 due to increased production expenses and increased interest expense, due to higher borrowings to fund acquisition and development costs, offset by an increase in revenues.

Revenue increased 8 percent for the three months ended June 30, 2006 compared to the three months ended June 30, 2005. A 10 percent increase in gas production was partially offset by a 7 percent decrease in average gas price received. An 8 percent decrease in oil production is primarily due to an increase in the federal royalty on qualified stripper wells, which began on February 1, 2006 and in effect reduces our net share of production, partially offset by a 47 percent increase in average oil price received.

Total operating expenses increased 30 percent for the three month period ended June 30, 2006 primarily due to generally higher field service costs experienced industry-wide and the increase in number of producing wells as a result of the current drilling program. The lease operating expenses per Mcfe sold (LOE/MCFE) increased 15 percent primarily as a result of higher industry costs, possessory taxes and the East Blanco amine plant start up costs. Depletion expense per Mcfe increased 51 percent. The average depletion rate per Mcfe is a function of capitalized costs, projected future development costs and the related underlying reserves in the periods presented. The increased depletion rate is due to increases in current year finding costs and higher estimated future development costs as well as the addition of higher average cost of recently acquired reserves.

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005. Income from continuing operations decreased 20 percent in the six months ended June 30, 2006 compared to the same period in 2005 due to increased production expenses and increased interest expense, due to higher borrowings to fund acquisition and development costs offset by an increase in revenues.

Revenue increased 20 percent for the six months ended June 30, 2006 compared to the six months ended June 30, 2005. Gas production increased 6 percent and average gas price received increased 11 percent. A 7 percent decrease in oil production is primarily due to an increase in the federal royalty on qualified stripper wells, which began on February 1, 2006 and in effect reduces our net share of production, partially offset by a 43 percent increase in average oil price received.

43

Total operating expenses increased 35 percent for the six month period ended June 30, 2006 primarily due to generally higher field service costs experienced industry-wide and the increase in number of producing wells as a result of the current drilling program. The lease operating expenses per Mcfe sold (LOE/MCFE) increased 29 percent primarily as a result of higher industry costs, possessory taxes and the East Blanco amine plant start up costs. Depletion expense per Mcfe increased 57 percent. The average depletion rate per Mcfe is a function of capitalized costs, projected future development costs and the related underlying reserves in the periods presented. The increased rate is due to increases in current year finding costs and higher estimated future development costs as well as the addition of higher average cost of recently acquired reserves.

On March 17, 2006, we acquired certain oil and gas assets of Koch Exploration Company, LLC. The assets include approximately 40 Bcfe of proved reserves, including approximately 31 Bcfe of proved undeveloped reserves which are substantially all gas, and associated midstream and gathering assets. The associated acreage position is located in the Piceance Basin in Colorado.

Coal Mining

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
	(in thousands)
Revenue	$	6,767	$	8,360	$	16,038		$	16,379
Operating expenses		6,156		6,330		13,812			12,577
Operating income	$	611	$	2,030	$	2,226		$	3,802
Income from continuing operations	$	768	$	1,728	$	2,183		$	3,216

The following is a summary of coal sales quantities:

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2006	2005	2006	2005
	(in thousands)
Fuel production:
Tons of coal sold	1,012	1,148	2,234	2,302

Three Months Ended June 30, 2006 Compared to Three Months Ended June 30, 2005.

Income from continuing operations from our Coal mining segment decreased 56 percent. Revenue decreased 19 percent for the three month period ended June 30, 2006 compared to the same period in 2005 due to a 12 percent decrease in tons of coal sold. Coal production decreased primarily due to scheduled and unscheduled plant outages, partially offset by increased train load-out sales. Operating expenses decreased 3 percent during the three months ended June 30, 2006 primarily due to decreased coal taxes resulting from the lower revenues and a federal black lung tax credit resulting from the determination of the presence of lignite within the coal seam, partially offset by increased overburden expense, resulting from a change in accounting rules requiring overburden removal to be expensed as incurred.

44

Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005.

Income from continuing operations from our Coal mining segment decreased 32 percent. Revenue decreased 2 percent for the six month period ended June 30, 2006 compared to the same period in 2005 due to a 3 percent decrease in tons of coal sold. Coal production decreased primarily due to scheduled and unscheduled plant outages, partially offset by increased train load-out sales. Operating expenses increased 10 percent during the six months ended June 30, 2006 primarily due to increased overburden expense, resulting from a change in accounting rules requiring overburden removal to be expensed as incurred and higher fuel and tire costs partially offset by decreased coal taxes.

Corporate

Decreased costs in the three and six months ended June 30, 2006, compared to the same periods in 2005, are primarily the result of the sale of certain development projects as compared to the write-off to expense of 2005 project development costs, increased allocation of corporate costs down to the subsidiary level and the allocation of certain interest costs to the power generation segment.

Critical Accounting Policies

On January 1, 2006, we adopted the provisions of SFAS 123(R), as detailed in Note 9 of the Notes to Condensed Consolidated Financial Statements included herein. The primary change resulting from adoption was the required recognition of compensation expense for stock options issued. Compensation expense for stock options was approximately $0.1 million and $0.3 million for the three and six month periods ended June 30, 2006. The adoption did not have a significant effect on how we recognize compensation expense for our other forms of stock-based compensation.

Other than noted above, there have been no other material changes in our critical accounting policies from those reported in our 2005 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 2005 Annual Report on Form 10-K.

45

Liquidity and Capital Resources

Cash Flow Activities

During the six month period ended June 30, 2006, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on our common stock, to pay our long-term debt maturities, and to fund a portion of 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 decreased $33.7 million for the six-month period ended June 30, 2006 compared to the same period in the prior year as a $0.4 million increase in income from continuing operations was more than offset by the following:

•             A $31.3 million decrease from cash flows from working capital changes. This decrease resulted from cash outflows from changes in net accounts receivable and accounts payable partially offset by a $27.0 million increase in cash flows from sales or purchases of materials, supplies and fuel. This is primarily related to natural gas held in storage by our natural gas and crude oil marketing business which fluctuates based on economic decisions reflecting current market conditions.

•             A $14.8 million decrease in cash flows from the net change in derivative assets and liabilities, primarily from derivatives associated with normal operations of our gas and oil marketing business and related commodity price fluctuations.

During the six months ended June 30, 2006, we had cash outflows from investing activities of $107.0 million, which was primarily due to the following:

•             Cash outflows of $150.2 million from property, plant and equipment additions. These outflows include approximately $51.4 million for the acquisition of oil and gas assets from Koch Exploration Company LLC, and approximately $45.1 million related to the construction of our Wygen II plant.

•             Cash inflows of approximately $40.7 million resulting from the sale of our crude oil marketing and transportation assets.

During the six months ended June 30, 2006, we had cash flows from financing activities of $13.1 million, primarily due to increased borrowings on our credit facility, partially offset by the payment of cash dividends on common stock and the payment of long-term debt maturities.

Dividends

Dividends paid on our common stock totaled $22.0 million during the six months ended June 30, 2006, or $0.66 per share. This reflects a 3.0 percent increase, as approved by our board of directors in January 2006, from the 2005 dividend level. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facility and our future business prospects.

46

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 2006. As of June 30, 2006, we had approximately $42.2 million of cash unrestricted for operations. Approximately $8.1 million of the cash balance at June 30, 2006 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company.

The $400 million revolving bank 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 LIBOR (which equates to a 6.03 percent one-month borrowing rate as of June 30, 2006).

Our revolving credit facility can be used to fund our working capital needs and for general corporate purposes. At June 30, 2006, we had $98.5 million of borrowings and $56.7 million of letters of credit issued on our revolving credit facility with a remaining borrowing capacity of $244.8 million available.

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 expense 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.

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, other 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 $760.9 million at June 30, 2006, which was approximately $100.2 million in excess of the net worth we were required to maintain under the bank facility. Our long-term debt ratio at June 30, 2006 was 46.5 percent, our total debt leverage (long-term debt and short-term debt) was 50.3 percent, and our recourse leverage ratio was approximately 49.2 percent.

47

On May 24, 2006 the Company entered into an Amended and Restated Credit Agreement for the project financing floating rate debt for Wygen I. The agreement extended the maturity date of the $111.1 million tranche of the financing from June 2006 to June 2008 to coincide with the maturity date of the remaining $17.2 million tranche.

In addition, Enserco Energy Inc., our energy marketing unit, entered into a Second Amended and Restated Credit Agreement on June 1, 2006 for a $260 million uncommitted, discretionary line of credit to provide support for the purchase and sale of natural gas and crude oil. The line of credit is secured by all of Enserco’s assets and expires on May 11, 2007. At June 30, 2006, there were outstanding letters of credit issued under the facility of $121.5 million, with no borrowing balances outstanding on the facility.

Our corporate credit rating by Moody’s Investors Service remained unchanged at “Baa3”during the first six months of 2006; the outlook is stable. On May 1, 2006, Standard & Poor’s Ratings Services affirmed its
“BBB-” corporate credit rating on Black Hills Corporation and removed the rating from CreditWatch with negative implications; the outlook is negative.

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

There have been no other material changes in our forecasted liquidity requirements from those reported in Item 7 of our 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Guarantees

During the six months ended June 30, 2006 the Company had the following changes to its guarantees:

•      Issued a Guarantee for payment under various transactions by Cheyenne Light with Tenaska Marketing Ventures for $2.0 million, expiring in 2006.

•      Issued an Amended and Restated Guarantee in favor of Wygen Funding, Limited Partnership, which continues the Company’s guarantee obligations under the Wygen I plant lease.

•      Extinguished a guarantee of up to $3.0 million of Enserco Energy Inc.’s obligations to Fortis Capital Corp. and other lenders under its credit facility.

At June 30, 2006, we had guarantees totaling $158.5 million in place.

In addition, as of July 12, 2006, the Company has guaranteed $30 million of the payment obligations for the Valmont and Arapahoe project financing floating rate debt of Black Hills Colorado, LLC, to the Bank of Nova Scotia, as administrative agent.

48

Capital Requirements

During the six months ended June 30, 2006, capital expenditures, including $20.8 million of accrued liabilities were approximately $171.0 million for property, plant and equipment additions. We currently expect capital expenditures for the entire year 2006 to approximate $302.2 million. This amount does not include the acquisition and future development costs of oil and gas properties acquired in August 2006.

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.

New Accounting Pronouncements

Other than the new pronouncements reported in our 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission and those discussed in Notes 3 and 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.

49

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 Item 1A. of Part I of our 2005 Annual Report on Form 10-K and in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:

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

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

•            The completion of acquisitions or divestitures for which definitive agreements have been executed could be delayed or may not occur or may not receive regulatory approval if required;

•            The volumes of production from our 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;

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

•            Our ability to successfully integrate and profitably operate any future acquisitions;

•            Unfavorable rulings in the periodic applications to recover costs for fuel and purchased power in our regulated utilities;

•            The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

•            Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs;

•            Changes in business and financial reporting practices arising from the repeal of the Public Utility Holding Company Act of 1935 and other provisions of the recently enacted Energy Policy Act of 2005;

•            Our ability to remedy any deficiencies that may be identified in the 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 and availability 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;

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

•            Our effective 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;

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

50

•            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 natural disasters and responses to such actions or events;

•            The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements;

•            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; 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.

51

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, 2006 (in thousands):

Total fair value of energy marketing positions marked-to-market at December 31, 2005	$	5,879(a)
Net cash settled during the period on positions that existed at December 31, 2005		(18,842)
Unrealized gain on new positions entered during the period and still existing at
June 30, 2006		9,529
Realized gain on positions that existed at December 31, 2005 and were settled during
the period		12,862
Unrealized loss on positions that existed at December 31, 2005 and still exist at
June 30, 2006		(131)
Total fair value of energy marketing positions at June 30, 2006	$	9,297

_____________________________

(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, 2006		March 31, 2006		December 31, 2005
Net derivative assets/(liabilities)	$	13,585	$	13,739	$	(764)
Fair value adjustment recorded in
material, supplies and fuel		(4,288)		(5,353)		6,643
	$	9,297	$	8,386	$	5,879

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 and crude oil 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 energy 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

52

(transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements.

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	$	10,864	$	—	$	10,864
Prices provided by other external sources		(2,194)		627		(1,567)
Modeled		—		—		—
Total	$	8,670	$	627	$	9,297

The following table presents a reconciliation of our June 30, 2006 energy marketing positions recorded at fair value under generally accepted accounting principles (GAAP) to a non-GAAP measure of the fair value of our energy marketing 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. 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.

Fair value of our energy marketing positions marked-to-market in accordance with GAAP
(see footnote (a) above)	$	9,297
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		13,563
Fair value of all forward positions (Non-GAAP)		22,860
“Liquidity Reserve” included in GAAP marked-to-market fair value		1,899
Fair value of all forward positions excluding the “Liquidity Reserve” (Non-GAAP)	$	24,759

There have been no material changes in market risk faced by us from those reported in our 2005 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 2005 Annual Report on Form 10-K, and Note 12 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

53

Activities Other Than Trading

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

Natural Gas

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(Mmbtu/day)
San Juan El Paso	07/12/2005	Swap	04/06 – 10/06	5,000	$	7.00
San Juan El Paso	12/14/2005	Swap	11/06 – 03/07	5,000	$	10.25
San Juan El Paso	04/03/2006	Swap	11/06 – 03/07	5,000	$	8.50
San Juan El Paso	06/15/2006	Swap	11/06 – 03/07	2,500	$	8.52
San Juan El Paso	06/15/2006	Swap	11/06 – 03/07	2,500	$	8.59
San Juan El Paso	04/03/2006	Swap	04/07 – 10/07	5,000	$	7.46
San Juan El Paso	06/02/2006	Swap	04/07 – 10/07	2,500	$	7.20
CIG	07/28/2006	Swap	09/06 – 03/08	2,500	$	7.60
CIG	07/31/2006	Swap	09/06 – 03/08	2,500	$	7.85

Crude Oil

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(barrels/month)
NYMEX	10/06/2004	Swap	Calendar 2006	10,000	$	41.00
NYMEX	12/14/2005	Put	Calendar 2006	5,000	$	55.00
NYMEX	01/12/2006	Put	02/06 – 12/06	5,000	$	65.50
NYMEX	07/29/2005	Swap	Calendar 2007	5,000	$	61.00
NYMEX	08/04/2005	Swap	Calendar 2007	5,000	$	62.00
NYMEX	01/04/2006	Swap	Calendar 2007	5,000	$	65.00
NYMEX	04/03/2006	Put	Calendar 2007	5,000	$	70.00

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, 2006. 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.

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2006 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

54

BLACK HILLS CORPORATION

Part II – Other Information

Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 20 in Item 8 of the Company’s 2005 Annual Report on Form 10-K and Note 13 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 13 is incorporated by reference into this item.

Item 1A. Risk Factors

There have been no material changes in our Risk Factors from those reported in Item 1A. of Part I of our 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

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

Unregistered Sales of Equity Securities

None.

Issuer Purchases of Equity Securities

					(d) Maximum
				(c) Total	Number (or
				Number	Approximate
				of Shares	Dollar
	(a) Total			Purchased as	Value) of Shares
	Number			Part of Publicly	That May Yet Be
	of	(b) Average		Announced	Purchased Under
	Shares	Price Paid		Plans	the Plans
Period	Purchased	per Share		or Programs	or Programs
April 1, 2006 – April 30, 2006	131(1)	$	36.40	—		—
May 1, 2006 – May 31, 2006	2,567(1)	$	35.80	—		—
June 1, 2006 – June 30, 2006	290(2)	$	34.11	—		—
Total	2,988	$	35.66	—		—

___________________________

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

55

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

(a) The Annual Meeting of Shareholders was held on May 24, 2006.

(b) The following Directors were elected to serve until the Annual Meeting of Shareholders in 2009:

David C. Ebertz

John R. Howard

Stephen D. Newlin

Other Directors whose terms of office continue are:

David R. Emery

Jack W. Eugster

Kay S. Jorgensen

Richard Korpan

William J. Van Dyke (resigned June 8, 2006)

John B. Vering

Thomas J. Zeller

(c) Matters Voted Upon at the Meeting

1. Elected three Class III Directors to serve until the Annual Meeting of Shareholders in 2009.

David C. Ebertz
Votes For	29,709,120
Votes Withheld	319,629
John R. Howard
Votes For	29,473,114
Votes Withheld	555,635
Stephen D. Newlin
Votes For	29,709,882
Votes Withheld	318,867

2. Ratified the appointment of Deloitte & Touche LLP to serve as Black Hills Corporation’s independent auditors in 2006.

Votes For	29,799,265
Votes Against	158,307
Abstain	71,177
Broker Non-Votes	—

56

Item 6. Exhibits

Exhibits–

Exhibit 10.1	Second Amended and Restated Credit Agreement made as of the 1st day of June, 2006, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, US Bank National Association, Societe Generale, and the Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 7, 2006.)
Exhibit 10.2	Amended and Restated Credit Agreement dated as of May 24, 2006, among Wygen Funding, Limited Partnership, the Lenders parties thereto, the Financial Institutions parties thereto, as Liquidity Purchasers; and Calyon New York Branch, as Administrative Agent, Bookrunner and Lead Arranger.
Exhibit 10.3	Amended and Restated Guarantee dated as of May 24, 2006, from Black Hills Corporation, as Guarantor, in favor of Wygen Funding, Limited Partnership.
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.

57

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, 2006

58

EXHIBIT INDEX

Exhibit Number	Description
Exhibit 10.1	Second Amended and Restated Credit Agreement made as of the 1st day of June, 2006, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, documentation agent and collateral agent, BNP Paribas, US Bank National Association, Societe Generale, and the Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch. (Incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 7, 2006.)
Exhibit 10.2	Amended and Restated Credit Agreement dated as of May 24, 2006, among Wygen Funding, Limited Partnership, the Lenders parties thereto, the Financial Institutions parties thereto, as Liquidity Purchasers; and Calyon New York Branch, as Administrative Agent, Bookrunner and Lead Arranger.
Exhibit 10.3	Amended and Restated Guarantee dated as of May 24, 2006, from Black Hills Corporation, as Guarantor, in favor of Wygen Funding, Limited Partnership.
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.

59