Black Hills (BKH) 10-Q 2006 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 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 April 28, 2006
Common stock, $1.00 par value	33,248,090 shares

TABLE OF CONTENTS

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income –
	Three Months Ended March 31, 2006 and 2005	3
	Condensed Consolidated Balance Sheets –
	March 31, 2006, December 31, 2005 and March 31, 2005	4
	Condensed Consolidated Statements of Cash Flows –
	Three Months Ended March 31, 2006 and 2005	5
	Notes to Condensed Consolidated Financial Statements	6-28
Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	29-44
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45-48
Item 4.	Controls and Procedures	48
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 6.	Exhibits	50
	Signatures	51
	Exhibit Index	52

2

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

		Three Months Ended March 31,
		2006			2005
		(in thousands, except per share amounts)
Operating revenues	$	171,890		$		142,420
Operating expenses:
Fuel and purchased power		54,129				43,533
Operations and maintenance		22,003				17,110
Administrative and general		24,949				20,621
Depreciation, depletion and amortization		20,889				19,828
Taxes, other than income taxes		10,551				8,057
		132,521				109,149
Operating income		39,369				33,271
Other income (expense):
Interest expense		(12,000	)			(11,860	)
Interest income		668				363
Other income, net		288				288
		(11,044	)			(11,209	)
Income from continuing operations before equity in
earnings of unconsolidated subsidiaries, minority
interest and income taxes		28,325				22,062
Equity in earnings of unconsolidated subsidiaries		513				1,475
Minority interest		(86	)			(60	)
Income tax expense		(10,191	)			(8,223	)
Income from continuing operations		18,561				15,254
Income from discontinued operations, net of taxes		7,590				486
Net income		26,151				15,740
Preferred stock dividends		—				(79	)
Net income available for common stock	$	26,151		$		15,661
Weighted average common shares outstanding:
Basic		33,120				32,444
Diluted		33,460				33,009
Earnings per share:
Basic–
Continuing operations	$	0.56		$		0.46
Discontinued operations		0.23				0.02
Total	$	0.79		$		0.48
Diluted–
Continuing operations	$	0.55		$		0.46
Discontinued operations		0.23				0.02
Total	$	0.78		$		0.48
Dividends paid per share of common stock	$	0.33		$		0.32

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)

	March 31,		December 31,		March 31,
	2006		2005		2005
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	42,150	$	31,817	$	60,107
Restricted cash		—		—		3,769
Receivables (net of allowance for doubtful accounts of $5,016;
$4,685 and $5,300, respectively)		148,620		264,695		215,447
Materials, supplies and fuel		102,995		122,521		62,756
Derivative assets		23,268		20,681		11,462
Prepaid income taxes		—		—		809
Deferred income taxes		—		—		988
Other assets		7,791		7,842		7,336
Assets of discontinued operations		9,986		122,158		209,304
		334,810		569,714		571,978
Investments		24,708		27,558		20,934
Property, plant and equipment		2,036,198		1,928,559		1,904,720
Less accumulated depreciation and depletion		(536,188)		(518,525)		(483,979)
		1,500,010		1,410,034		1,420,741
Other assets:
Derivative assets		1,238		1,898		425
Goodwill		30,562		29,847		31,225
Intangible assets (net of accumulated amortization of
$23,513; $22,734 and $21,842, respectively)		26,768		27,548		35,540
Other		44,208		53,646		48,359
		102,776		112,939		115,549
	$	1,962,304	$	2,120,245	$	2,129,202
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	120,859	$	202,639	$	166,343
Accrued liabilities		70,644		72,514		64,104
Derivative liabilities		9,845		26,141		29,422
Deferred income taxes		1,591		1,443		—
Notes payable		58,000		55,000		25,000
Current maturities of long-term debt		11,852		11,771		16,318
Accrued income taxes		12,827		11,650		5,847
Liabilities of discontinued operations		11,424		92,818		69,923
		297,042		473,976		376,957
Long-term debt, net of current maturities		665,373		670,193		756,544
Deferred credits and other liabilities:
Deferred income taxes		140,904		134,533		164,823
Derivative liabilities		976		2,623		1,889
Other		95,352		95,116		86,413
		237,232		232,272		253,125
Minority interest in subsidiaries		5,011		4,925		4,894
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 33,281,278; 33,222,522 and 32,608,482 shares,
respectively		33,281		33,223		32,608
Additional paid-in capital		405,214		404,035		384,467
Retained earnings		326,369		313,217		327,261
Treasury stock at cost – 38,058; 66,938 and 71,675
shares, respectively		(962)		(1,766)		(1,727)
Accumulated other comprehensive loss		(6,256)		(9,830)		(12,094)
		757,646		738,879		730,515
Total stockholders’ equity		757,646		738,879		737,682
	$	1,962,304	$	2,120,245	$	2,129,202

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)

	Three Months Ended
	March 31,
	2006		2005
	(in thousands)
Operating activities:
Income from continuing operations	$	18,561	$	15,254
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization		20,889		19,828
Net change in derivative assets and liabilities		(2,040)		3,795
Deferred income taxes		5,028		5,551
Distributed earnings in associated companies		3,749		4,549
Change in operating assets and liabilities, net of acquisition-
Materials, supplies and fuel		7,383		41,289
Accounts receivable and other current assets		115,760		5,790
Accounts payable and other current liabilities		(103,131)		4,274
Other operating activities		4,648		9,241
Net cash provided by operating activities of continuing operations		70,847		109,571
Net cash provided by operating activities of discontinued operations		2,550		930
Net cash provided by operating activities		73,397		110,501
Investing activities:
Property, plant and equipment additions		(89,684)		(26,297)
Payment for acquisition, net of cash acquired		—		(67,331)
Other investing activities		(899)		(1,385)
Net cash used in investing activities of continuing operations		(90,583)		(95,013)
Net cash provided by (used in) investing activities of discontinued operations		43,608		(2,008)
Net cash used in investing activities		(46,975)		(97,021)
Financing activities:
Dividends paid		(10,968)		(10,488)
Common stock issued		1,237		41
Increase in short-term borrowings, net		3,000		1,000
Long-term debt – repayments		(4,739)		(3,273)
Other financing activities		804		2,363
Net cash used in financing activities of continuing operations		(10,666)		(10,357)
Net cash used in financing activities of discontinued operations		—		—
Net cash used in financing activities		(10,666)		(10,357)
Increase in cash and cash equivalents		15,756		3,123
Cash and cash equivalents:
Beginning of period		34,198*		64,506**
End of period	$	49,954*	$	67,629**
Supplemental disclosure of cash flow information:
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities	$	20,378	$	—
Cash paid during the period for-
Interest	$	11,549	$	12,877
Net income taxes paid (refunded)	$	3,609	$	(626)

_________________________

* Includes approximately $2.4 million at December 31, 2005 and $7.8 million at March 31, 2006 of cash included in discontinued operations.

** Includes approximately $8.6 million at December 31, 2004 and $7.5 million at March 31, 2005 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 March 31, 2006, December 31, 2005 and March 31, 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 months ended March 31, 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 ISSUED ACCOUNTING PRONOUNCEMENTS

EITF Issue No. 04-13

On September 28, 2005 the Financial Accounting Standards Board, or 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 will not have a significant effect on the Company’s consolidated financial position, results of operations or cash flows.

6

(4) RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

SFAS No. 123 (Revised 2004)

On December 16, 2004, the 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 months ended March 31, 2005 for stock options.

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 8, 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, as of January 1, 2006, stripping costs are expensed as a cost of inventory produced, at the time incurred.

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):

	March 31,		December 31,		March 31,
Major Classification	2006		2005		2005
Materials and supplies	$	28,042	$	24,567	$	23,137
Fuel*		5,753		7,544		2,450
Gas and oil held by energy marketing*		69,200		90,410		37,169
Total materials, supplies and fuel	$	102,995	$	122,521	$	62,756

___________________________

* As of March 31, 2006, December 31, 2005 and March 31, 2005, market adjustments related to gas and oil held by energy marketing and recorded in inventory were $(5.4) million, $6.6 million and $4.8 million, respectively. As of December 31, 2005, market adjustments related to fuel held by the electric utility were $(0.2) million (see Note 11 for further discussion of energy marketing and trading activities).

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) 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 March 31, 2006	Three Months
			Average
	Income		Shares
Income from continuing operations	$	18,561
Basic – available for common shareholders		18,561	33,120
Dilutive effect of:
Stock options		—	83
Estimated contingent shares issuable for prior acquisition		—	158
Others		—	99
Diluted – available for common shareholders	$	18,561	33,460

8

Period ended March 31, 2005	Three Months
			Average
	Income		Shares
Income from continuing operations	$	15,254
Less: preferred stock dividends		(79)
Basic – available for common shareholders		15,175	32,444
Dilutive effect of:
Stock options		—	117
Convertible preferred stock		79	195
Estimated contingent shares issuable for prior acquisition		—	158
Others		—	95
Diluted – available for common shareholders	$	15,254	33,009

(7) COMPREHENSIVE INCOME

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

(in thousands):

	Three Months Ended
	March 31,
	2006		2005
Net income	$	26,151	$	15,740
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives designated
as cash flow hedges		3,865		(4,646)
Reclassification adjustments on cash flow hedges
settled and included in net income		(291)		144
Unrealized gain on available-for-sale securities		—		15
Comprehensive income	$	29,725	$	11,253

9

(8) 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 1,083,943 shares available to grant at March 31, 2006.

At March 31, 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, we did recognize stock-based compensation expense for non-vested share awards including restricted stock and restricted stock units, performance shares and directors’ phantom shares.

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
	March 31, 2005
Net income available for common stock, as reported	$	15,661
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects		(141)
Pro forma net income available for common stock	$	15,520
Earnings per share:
Basic–as reported
Continuing operations	$	0.46
Discontinued operations		0.02
Total	$	0.48
Diluted–as reported
Continuing operations	$	0.46
Discontinued operations		0.02
Total	$	0.48
Basic–pro-forma
Continuing operations	$	0.46
Discontinued operations		0.02
Total	$	0.48
Diluted–pro-forma
Continuing operations	$	0.46
Discontinued operations		0.01
Total	$	0.47

10

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 March 31, 2006 and 2005 was $0.7 million ($0.5 million, after tax) and $0.8 million ($0.5 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 March 31, 2006, total unrecognized compensation expense related to stock options and non-vested stock awards is $5.2 million and is expected to be recognized over a weighted-average period of 2.2 years.

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.

11

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 March 31, 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	—		—
Forfeited/cancelled	(7)		29.50
Expired	—		—
Exercised	(21)		28.17
Balance at March 31, 2006	826	$	29.60	6.0	$	3,635
Exercisable at March 31, 2006	680	$	29.68	5.6	$	2,936

No options were granted during the first quarter of 2006. The weighted-average grant-date fair value of options granted during the three months ended March 31, 2005 was $6.42 per share. 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 three months ended March 31, 2006 and 2005 was $0.1 million for each period. The total fair value of shares vested during each of the three months ended March 31, 2006 and 2005 was $0.2 million.

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:

	Three Months
	Ended
Valuations Assumptions1	March 31, 2005
Weighted average risk-free interest rate2		3.92%
Weighted average expected price volatility3		42.32%
Weighted average expected dividend yield4		4.32%
Expected life in years5		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 historical volatility of our stock price.

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.

12

Net cash received from the exercise of options for the three months ended March 31, 2006 and 2005 was $0.6 million and $0.4 million, respectively. The tax benefit realized from the exercise of shares granted for the three months ended March 31, 2006 and 2005 was not material.

As of March 31, 2006, there was $0.5 million of unrecognized compensation expense related to stock options that is expected to be recognized over a weighted-average period of 1.4 years.

Restricted Stock and Restricted Stock Units

The fair value of restricted stock and restricted stock unit awards equals the market price of our 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.

A summary of the status of the restricted stock and non-vested restricted stock units at March 31, 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	35		35.48
Vested	(14)		30.05
Forfeited	(2)		31.42
Balance at March 31, 2006	109	$	32.32

The weighted-average grant-date fair value of restricted stock and restricted stock units granted in the three months ended March 31, 2006 and 2005 was $35.48 and $29.96, per share, respectively. The total fair value of shares vested during the three months ended March 31, 2006 and 2005 was $0.5 million and $21,000, respectively.

As of March 31, 2006, there was $2.7 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 2.4 years.

13

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 March 31, 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

The performance awards are paid 50 percent in cash and 50 percent in common stock.

A summary of the status of the Equity Portion of the Performance Share Plan at March 31, 2006 and changes during the three-month period ended March 31, 2006, is as follows:

		Weighted-
		Average
		Grant Date
	Shares	Fair Value
	(in thousands)
Balance at January 1, 2006	38	$	29.95
Granted	17		32.06
Forfeited	(1)		29.95
Vested	(6)		29.92
Balance at March 31, 2006	48	$	30.70

14

A summary of the status of the Liability Portion of the Performance Share Plan at March 31, 2006 and changes during the three-month period ended March 31, 2006, is as follows:

		Weighted-
		Average
		March 31, 2006
	Shares	Fair Value
	(in thousands)
Balance at January 1, 2006	38
Granted	17
Forfeited	(1)
Vested	(6)
Balance at March 31, 2006	48	$	36.16

The weighted-average grant-date fair value of performance share awards granted in the three months ended March 31, 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 first quarter of 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 March 31, 2006, there was $2.0 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 2.1 years.

Other Plans

The Company issued 25,685 shares of common stock with an intrinsic value of $910,000 in the three months ended March 31, 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

(9) 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 Services Company, Black Hills Power, Inc., Wyodak Resources Development Corp., and Black Hills Exploration and Production. The other Plan covers employees of the Company’s subsidiary, Cheyenne Light, who meet certain eligibility requirements.

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

	Three Months Ended
	March 31,
	2006		2005
Service cost	$	649	$	576
Interest cost		1,041		995
Expected return on plan assets		(1,247)		(1,157)
Amortization of prior service cost		38		54
Amortization of net loss		227		296
Net periodic benefit cost	$	708	$	764

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
	March 31,
	2006		2005
Service cost	$	87	$	86
Interest cost		270		252
Amortization of prior service cost		3		2
Amortization of net loss		199		157
Net periodic benefit cost	$	559	$	497

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
	March 31,
	2006		2005
Service cost	$	164	$	185
Interest cost		203		232
Amortization of net transition obligation		38		37
Amortization of prior service cost		(6)		(6)
Amortization of net loss		—		25
Net periodic benefit cost	$	399	$	473

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
	Ended
	March 31, 2006
Service cost	$	(25)
Interest cost		(28)
Amortization of net loss		(18)
Total decrease to net periodic postretirement benefit cost	$	(71)

17

(10)         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 March 31, 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, our 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 14). 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 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
March 31, 2006
Retail services:
Electric utility	$	43,804	$	164	$	4,899
Electric and gas utility		43,699		—		1,397
Wholesale energy:
Coal mining		5,996		3,274		1,415
Oil and gas		25,185		—		5,390
Energy marketing		16,957		—		6,318
Power generation		33,593		—		2,092
Corporate		16		—		(2,950)
Intersegment eliminations		—		(798)		—
Total	$	169,250	$	2,640	$	18,561

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
March 31, 2005
Retail services:
Electric utility	$	43,049	$	98	$	4,322
Electric and gas utility		27,075		—		512
Wholesale energy:
Coal mining		4,872		3,146		1,488
Oil and gas		19,041		—		4,960
Energy marketing		7,532		—		1,429
Power generation		38,162		—		3,885
Corporate		265		—		(1,342)
Intersegment eliminations		—		(820)		—
Total	$	139,996	$	2,424	$	15,254

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.

19

(11)         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 Marketing

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

(in thousands of MMbtus)	March 31, 2006			December 31, 2005			March 31, 2005
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)
Natural gas basis
swaps purchased		92,737	19		43,507	22		68,214	21
Natural gas basis
swaps sold		103,437	19		53,665	22		66,912	19
Natural gas fixed-for-
float swaps purchased		17,889	20		17,083	23		30,718	19
Natural gas fixed-for-
float swaps sold		28,432	20		24,871	23		25,775	13
Natural gas physical
purchases		91,422	31		59,855	34		94,393	21
Natural gas physical sales		110,332	43		88,302	46		118,420	55
Natural gas options
purchased		6,373	18		6,176	21		9,703	18
Natural gas options sold		6,373	18		6,176	21		9,703	18
(Dollars, in thousands)
Canadian dollars
purchased	$	17,000	1	$	88,000	2	$	1,000	1
Canadian dollars sold	$	32,500	8	$	29,000	5	$	22,700	7

20

Derivatives and certain natural gas marketing activities were marked to fair value on March 31, 2006, December 31, 2005 and March 31, 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)
March 31, 2006	$	20,590	$	215	$	7,034	$	32	$	13,739
December 31, 2005	$	20,326	$	1,747	$	20,751	$	2,086	$	(764)
March 31, 2005	$	11,253	$	425	$	20,467	$	571	$	(9,360)

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Balance Sheets and the related unrealized gain/loss on the Statements of Income. As of March 31, 2006, December 31, 2005 and March 31, 2005, the market adjustments recorded in inventory were $(5.4) million, $6.6 million and $4.8 million, respectively.

21

Activities Other Than Trading

Oil and Gas Exploration and Production

On March 31, 2006, December 31, 2005 and March 31, 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)
March 31,
2006
Crude oil
swaps/options	360,000	1.00	$	155	$	—	$	2,811	$	944	$	(3,755)	$	155
Natural gas
swaps	1,825,000	0.60		2,086		—		—		—		2,086		—
			$	2,241	$	—	$	2,811	$	944	$	(1,669)	$	155
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
March 31,
2005
Crude oil
swaps	300,000	1.00	$	—	$	—	$	5,199	$	1,206	$	(6,350)	$	(55)
Natural gas
swaps	2,517,500	0.50		—		—		2,989		—		(2,989)		—
			$	—	$	—	$	8,188	$	1,206	$	(9,339)	$	(55)

________________________

*crude in barrels, gas in MMbtu’s

Based on March 31, 2006 market prices, a $0.6 million loss 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.

22

Electric Utility

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

											Pre-tax
					Non-				Non-		Accumulated
		Maximum	Current		current		Current		current		Other
		Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Unrealized
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		Gain
March 31,
2006
Natural gas
swaps	155,000	1.00	$	31	$	—	$	—	$	—	$	31	$	—
December 31,
2005
Natural gas
swaps	275,000	0.25	$	192	$	—	$	219	$	—	$	(219)	$	192

________________________

*gas in MMbtu’s

Based on March 31, 2006 market prices, a gain of less than $0.1 million would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. Estimated and actual realized gains will likely change during the next twelve months as market prices change.

In addition, certain volumes of natural gas inventory were designated as the underlying hedged item in a fair value hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Balance Sheet and the related unrealized gain/loss on the Statement of Income. As of December 31, 2005, the market adjustments recorded in inventory were $(0.2) million.

23

Financing Activities

On March 31, 2006, December 31, 2005 and March 31, 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)
March 31,
2006
Swaps on
project
and other
financings	$	75,000	4.93%	10	$	406	$	1,023	$	—	$	—	$	1,412	$	17
December 31,
2005
Swaps on
project
financing	$	163,000	4.43%	10	$	13	$	—	$	76	$	230	$	(249)	$	(44)
March 31,
2005
Swaps on
project
financing	$	113,000	4.22%	1.50	$	209	$	—	$	767	$	112	$	(670)	$	—

Based on March 31, 2006 market interest rates and balances, approximately $0.4 million would be realized and reported in pre-tax earnings as a reduction of interest expense during the next twelve months. Estimated and realized amounts will likely change during the next twelve months as market interest rates change.

24

(12)         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. There have been no material developments in these proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first quarter of 2006.

(13) 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, which are substantially all gas. The acquisition includes 63 producing wells and majority interests in associated midstream and gathering assets.

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.

25

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):

	Three Month
	Period Ended
	March 31, 2005
Operating revenues	$	151,598
Income from
continuing operations		15,433
Net income		15,919
Earnings per share –
Basic:
Continuing operations	$	0.47
Total	$	0.49
Diluted:
Continuing operations	$	0.47
Total	$	0.48

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.

(14) DISCONTINUED OPERATIONS

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

Sale of Crude Oil Marketing and Transportation Assets

On January 5, 2006, the Company entered into an agreement to sell the operating assets of Black Hills Energy Resources, Inc. and related subsidiaries, its crude oil marketing and transportation business. The sale was completed on March 1, 2006 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.

26

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

	Three Months Ended
	March 31,
	2006		2005
Operating revenues	$	171,869	$	153,599
Pre-tax (loss) income from discontinued
operations (including severance payments)	$	(1,762)	$	2,284
Pre-tax gain on sale of assets		13,582		—
Income tax expense		(4,230)		(786)
Net income from discontinued operations	$	7,590	$	1,498

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

	March 31, 2006		December 31, 2005		March 31, 2005
Current assets	$	9,879	$	94,697	$	67,826
Property, plant and equipment, net		34		25,364		24,182
Other non-current assets		73		2,097		2,131
Current liabilities		(10,585)		(89,750)		(59,906)
Other non-current liabilities		(839)		(3,068)		(2,950)
Net (liabilities) assets	$	(1,438)	$	29,340	$	31,283

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
	Ended
	March 31,
	2005
Operating revenues	$	9,666
Pre-tax loss from discontinued operations	$	(1,382)
Income tax benefit		495
Net loss from discontinued operations	$	(887)

27

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

	March 31, 2005
Current assets	$	4,939
Property, plant and equipment, net		107,109
Other non-current assets		32
Current liabilities		(5,865	)
Other non-current liabilities		(545	)
Net assets	$	105,670

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
	Ended
	March 31,
	2005
Pre-tax loss from discontinued operations	$	(190)
Income tax benefit		65
Net loss from discontinued operations	$	(125)

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

	March 31,
	2005
Current assets	$	133
Non-current deferred tax asset		2,952
Other current liabilities		(149)
Non-current liabilities		(508)
Net assets of discontinued operations	$	2,428

28

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
	Oil and gas
	Coal mining
	Power generation

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.

29

Results of Operations

Consolidated Results

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

	Three Months Ended
	March 31,
	2006		2005
Revenues
Retail services	$	87,503	$	70,124
Wholesale energy		84,371		72,031
Corporate		16		265
	$	171,890	$	142,420
Income/(Loss) from
Continuing Operations
Retail services	$	6,296	$	4,834
Wholesale energy		15,215		11,762
Corporate		(2,950)		(1,342)
	$	18,561	$	15,254

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, will be 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

30

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 March 31, 2006 Compared to Three Months Ended March 31, 2005. Revenues for the three months ended March 31, 2006 increased 21 percent, or $29.5 million, compared to the same period in 2005. Increased revenues were primarily driven by a full quarter of activity and higher rates at Cheyenne Light, higher margins in our energy marketing activities and higher prices received from our oil and gas production, partially offset by lower revenues at our power generation business due to scheduled and unscheduled plant outages.

Operating expenses increased 21 percent, or $23.4 million, primarily due to a full quarter of operating costs for Cheyenne Light, increased operations and maintenance for scheduled and unscheduled plant outages, increased lease operating expense at our oil and gas operations and higher expensed project development costs.

Income from continuing operations increased $3.3 million due primarily to the following:

•   a $0.6 million increase in Electric utility earnings;

•   a $0.9 million increase in Electric and gas utility earnings;

•   a $4.9 million increase in Energy marketing earnings, partially offset by;

•   a $1.8 million decrease in Power generation earnings; and

•   a $1.6 million increase in corporate costs.

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.

31

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
	March 31,
	2006		2005
	(in thousands)
Revenue	$	43,968	$	43,147
Operating expenses		33,871		33,652
Operating income	$	10,097	$	9,495
Income from continuing operations and net income	$	4,899	$	4,322

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

	Electric Revenue
	(in thousands)
	Three Months Ended March 31,
			Percentage
Customer Base	2006		Change	2005
Commercial	$	11,422	—%	$	11,446
Residential		10,663	1		10,543
Industrial		5,011	3		4,854
Municipal sales		520	5		493
Total retail sales		27,616	1		27,336
Contract wholesale		6,108	2		5,986
Wholesale off-system		8,234	1		8,113
Total electric sales		41,958	1		41,435
Other revenue		2,010	17		1,712
Total revenue	$	43,968	2%	$	43,147

32

	Megawatt Hours Sold
	Three Months Ended March 31,
		Percentage
Customer Base	2006	Change	2005
Commercial	158,593	1%	157,518
Residential	141,794	3	137,947
Industrial	103,027	5	98,398
Municipal sales	7,059	9	6,462
Total retail sales	410,473	3	400,325
Contract wholesale	162,251	1	160,838
Wholesale off-system	180,163	(4)	188,114
Total electric sales	752,887	—%	749,277

	Three Months Ended
	March 31,
		Percentage
Resources	2006	Change	2005
Megawatt-hours generated:
Coal	454,133	4%	435,935
Gas	2,211	34	1,653
	456,344	4	437,588
Megawatt-hours purchased	312,287	(3)	321,671
Total resources	768,631	1%	759,259

	Three Months Ended
	March 31,
	2006	2005
Heating degree days
Actual
Heating degree days	2,946	2,990
Percent of normal
Heating degree days	90%	91%

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Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005. Income from continuing operations increased $0.6 million primarily due to increased revenues and lower depreciation expense and legal costs, partially offset by increased fuel costs and corporate allocations.

Electric utility revenues increased 2 percent for the three month period ended March 31, 2006, compared to the same period in the prior year. Total retail megawatt-hour sales increased 3 percent compared to the three months ended March 31, 2005. Heating degree days, which is a measure of weather trends, were 1 percent lower than the same period in the prior year. Wholesale off-system sales increased 1 percent due to a 6 percent increase in average price received, partially offset by a 4 percent decrease in megawatt-hours sold.

Electric operating expenses increased 1 percent for the three month period ended March 31, 2006, compared to the same period in the prior year. Fuel costs increased 12 percent due to a 4 percent increase in megawatt-hours generated at an 8 percent higher average cost. Megawatt-hours produced through coal-fired generation increased as we experienced an 18-day unscheduled plant outage at the Wyodak plant in the first quarter of 2005. Operating expense for the three months ended March 31, 2006 was also affected by increased corporate allocations, which were offset by a decrease in depreciation expense, due to a revision of depreciation rates resulting from an independent depreciation study commissioned by the Company, and a decrease in power marketing legal costs relative to costs incurred in the first quarter of 2005.

Electric and Gas Utility

	Three Months Ended		January 21, 2005
	March 31,		to
	2006		March 31, 2005
	(in thousands)
Revenue	$	43,699	$	27,075
Operating expenses		41,799		26,177
Operating income	$	1,900	$	898
Income from continuing operations and net income	$	1,397	$	512

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

Electric Revenue
(in thousands)
	Three Months Ended		Percentage	January 21, 2005 to
Customer Base	March 31, 2006		Change	March 31, 2005
Commercial	$	10,442	29%	$	8,099
Residential		7,573	35		5,603
Industrial		2,185	(2)		2,225
Municipal sales		203	72		118
Total electric sales		20,403	27		16,045
Other revenue		94	—		—
Total revenue	$	20,497	28%	$	16,045

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	Three Months Ended	Percentage	January 21, 2005 to
Resources	March 31, 2006	Change	March 31, 2005
Megawatt-hours purchased	246,702	34%	184,320

Gas Revenue
(in thousands)
	Three Months Ended		Percentage	January 21, 2005 to
Customer Base	March 31, 2006		Change	March 31, 2005
Commercial	$	7,051	107%	$	3,398
Residential		12,897	114		6,021
Industrial		3,032	115		1,406
Total gas sales		22,980	112		10,825
Other revenue		222	8		205
Total revenue	$	23,202	110%	$	11,030

	Three Months Ended	Percentage	January 21, 2005 to
Resources	March 31, 2006	Change	March 31, 2005
Dekatherms purchased	1,800,535	44%	1,249,856

	Three Months Ended	Percentage	January 21, 2005 to
	March 31, 2006	Change	March 31, 2005
Electric sales – MWh	232,827	31%	177,100
Gas sales - Dth	1,870,454	32%	1,412,101

Three Months Ended March 31, 2006 Compared to the Period January 21, 2005 to March 31, 2005. Income from continuing operations increased $0.9 million for the three months ended March 31, 2006, primarily due to a full period of operations in 2006, as Cheyenne Light was acquired on January 21, 2005, and an increase in base rates that went into effect January 1, 2006.

Revenue and operating expense increased primarily due to a full period of operations in 2006. In addition, revenues increased due to higher base rates and gas cost adjustments. Operating expense was also impacted by the higher price of gas sold and increased general and administrative costs.

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. We expect commercial operations to begin in early 2008.

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Wholesale Energy Group

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

Energy Marketing

	Three Months Ended
	March 31,
	2006		2005
	(in thousands)
Revenue	$	16,957	$	7,532
Operating expenses		7,155		5,080
Operating income	$	9,802	$	2,452
Income from continuing operations	$	6,318	$	1,429

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

	Three Months Ended
	March 31,
	2006	2005
Natural gas physical sales – MMbtus	1,275,900	1,357,600

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005. Income from continuing operations increased $4.9 million due to increased realized and unrealized gas marketing margins.

Realized gas marketing margins increased approximately $5.2 million over the prior year due to a 36 percent increase in average physical gas price received, partially offset by a 6 percent decrease in volumes sold. Gas marketing unrealized mark-to-market gains for the quarter ended March 31, 2006 were $4.5 million higher than unrealized mark-to-market losses 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 marketing operations see “Trading Activities” in Part 1, Item 3 of this Form 10-Q.) Operating expenses increased primarily due to increased compensation cost related to higher realized margins and an increase in bad debt accruals.

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 strategy for these activities will be consistent with our past crude oil marketing activities. This strategy primarily involves executing physical crude oil purchase contracts with producers, and reselling into various markets. These transactions are primarily entered into 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. Oil marketing operations began on April 1, 2006.

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Power Generation

	Three Months Ended
	March 31,
	2006		2005
	(in thousands)
Revenue	$	33,593	$	38,162
Operating expenses		24,039		26,394
Operating income	$	9,554	$	11,768
Income from continuing operations	$	2,092	$	3,885

	March 31,
	2006	2005
Independent power capacity:
MWs of independent power capacity in service	1,000	964

	Three Months Ended
	March 31,
	2006	2005
Contracted fleet plant availability	85.7%	98.9%

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005. Income from continuing operations decreased 46 percent due to decreased revenues and lower earnings from certain power fund investments, partially offset by decreases in operating expense. Revenues in the first quarter of 2006 decreased 12 percent compared to revenues in the first quarter of 2005. Lower revenues from the Las Vegas I and II facilities due to scheduled and unscheduled outages for repair and maintenance were 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 three months ended March 31, 2006, decreased 9 percent from the same period in the prior year. The decrease in operating expenses was primarily due to 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 in late April 2006, while Las Vegas II is scheduled to convert from simple-cycle operation to full combined-cycle operation in May 2006.

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Oil and Gas

	Three Months Ended
	March 31,
	2006		2005
	(in thousands)
Revenue	$	25,185	$	19,041
Operating expenses		15,901		11,418
Operating income	$	9,284	$	7,623
Income from continuing operations	$	5,390	$	4,960

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

	Three Months Ended
	March 31,
	2006	2005
Fuel production:
Barrels of oil sold	90,460	95,900
Mcf of natural gas sold	2,959,100	2,889,800
Mcf equivalent sales	3,501,860	3,465,000

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005. Income from continuing operations increased 9 percent in the three months ended March 31, 2006 compared to the same period in 2005 due to an increase in revenues, offset by increased operating expense and increased interest expense, due to higher borrowings to fund acquisition and development costs.

Revenue increased 32 percent for the three months ended March 31, 2006 compared to the three months ended March 31, 2005. Average gas price received, net of hedges and exclusive of gas liquids, for the three months ended March 31, 2006 was $6.98/Mcf, compared to $5.36/Mcf in the same period of 2005. Average oil price received, net of hedges, for the three months ended March 31, 2006 was $45.33/bbl, compared to $32.73/bbl in the same period of 2005.

Total operating expenses increased 39 percent for the three month period ended March 31, 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) for the three month period increased 49 percent to $1.19/Mcfe in 2006 from $0.80/Mcfe in 2005 due to the timing of certain production activities delayed from the first quarter of 2005. Depletion expense per Mcfe increased 64 percent over the prior year to $1.62/Mcfe in 2006 from $0.99/Mcfe in 2005. The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The increased rate is a reflection of higher commodity prices which in turn has led to increased demand for drilling services resulting in higher drilling costs and higher estimated future development costs as well as the addition of higher average cost of reserves recently acquired.

On March 17, 2006, we acquired certain oil and gas assets of Koch Exploration Company, LLC. The assets include approximately 40 Bcfe of proved developed and 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.

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Coal Mining

	Three Months Ended
	March 31,
	2006		2005
	(in thousands)
Revenue	$	9,270	$	8,018
Operating expenses		7,655		6,245
Operating income	$	1,615	$	1,773
Income from continuing operations	$	1,415	$	1,488

The following is a summary of coal sales quantities:

	Three Months Ended
	March 31,
	2006	2005
	(in thousands)
Fuel production:
Tons of coal sold	1,223	1,153

Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005.

Income from continuing operations from our Coal mining segment decreased 5 percent. Revenue increased 16 percent for the three month period ended March 31, 2006 compared to the same period in 2005 due to a 6 percent increase in tons of coal sold at a higher average price. Offsetting the increased revenues were increased operating expenses of 23 percent during the three months ended March 31, 2006 primarily due to increased overburden expense, resulting from a change in accounting rules requiring overburden removal to be expensed as incurred, increased mineral taxes and increased royalties in relation to the increased revenues.

Corporate

Higher losses in the first quarter of 2006, compared to the first quarter of 2005, are primarily the result of the expensing of certain project development costs including approximately $1.1 million of pre-tax costs related to the proposed acquisition of NorthWestern Corporation.

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Critical Accounting Policies

On January 1, 2006, we adopted the provisions of SFAS 123(R), as detailed in Note 8 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 for the three months ended March 31, 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.

Liquidity and Capital Resources

Cash Flow Activities

During the three month period ended March 31, 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 37.1 million for the three-month period ended March 31, 2006 compared to the same period in the prior year as a $3.3 million increase in net income was more than offset by the following:

•             An $31.3 million decrease from cash flows from working capital changes. In addition to normal fluctuations in working capital, the decrease was primarily driven by lower cash received due to decreased sales of natural gas held in storage by our gas marketing business. Current economic conditions warrant maintaining existing higher gas inventory levels of the current year winter season, to be sold forward into future seasons.

•             A $5.8 million decrease in cash flows from the net change in derivative assets and liabilities, primarily from derivatives associated with normal operations of our gas marketing business and related commodity price fluctuations.

During the three months ended March 31, 2006, we had cash outflows from investing activities of $47.0 million, which was primarily due to the following:

•             Cash outflows of $89.7 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 expenditures 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.

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During the three months ended March 31, 2006, we had cash outflows from financing activities of $10.7 million, primarily due to the payment of quarterly cash dividends on common stock.

Dividends

Dividends paid on our common stock totaled $11.0 million during the three months ended March 31, 2006, or $0.33 per share. This reflects a 3.0 percent increase, as approved by our board of directors in January 2006, from the 2005 quarterly dividend level. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facility and our future business prospects.

Short-Term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are our revolving bank facility and cash provided by operations. Our liquidity position remained strong during the first three months of 2006. As of March 31, 2006, we had approximately $42.2 million of cash unrestricted for operations and $400 million of credit through our revolving bank facility. Approximately $7.8 million of the cash balance at March 31, 2006 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company.

Our revolving credit facility can be used to fund our working capital needs and for general corporate purposes. At March 31, 2006, we had $58.0 million of borrowings and $91.6 million of letters of credit issued on our revolving credit facility; the remaining borrowing capacity under the facility was $250.4 million at March 31, 2006.

We have a $400 million revolving bank facility with ABN AMRO as Administrative Agent, Union Bank of California and US Bank as Co-Syndication Agents, Bank of America and Harris Nesbitt as Co-Documentation Agents, and other syndication participants. The 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 5.53 percent one-month borrowing rate as of March 31, 2006).

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

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

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

•             an interest 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.

41

��

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 $757.6 million at March 31, 2006, which was approximately $102.9 million in excess of the net worth we were required to maintain under the bank facility. Our long-term debt ratio at March 31, 2006 was 46.8 percent, our total debt leverage (long-term debt and short-term debt) was 49.2 percent, and our recourse leverage ratio was approximately 49.4 percent.

In addition, Enserco Energy Inc., our energy marketing unit, has a $200 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. The line of credit is secured by all of Enserco’s assets and expires on November 30, 2006. As of March 31, 2006, we had a $3.0 million guarantee to the lender associated with the line of credit. At March 31, 2006, there were outstanding letters of credit issued under the facility of $120.1 million, with no borrowing balances outstanding on the facility.

There were no changes in our corporate credit ratings during the first three months of 2006. 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 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

At March 31, 2006, we had guarantees totaling $162.2 million in place.

42

Capital Requirements

During the three months ended March 31, 2006, capital expenditures, including $20.4 million of accrued liabilities, were approximately $110.1 million for property, plant and equipment additions. We currently expect capital expenditures for the entire year 2006 to approximate $302.2 million, including acquisition and development costs of the assets acquired from Koch Exploration, LLC and as detailed in Item 7 of our 2005 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

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 Note 4 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment.

SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

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

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

•            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;

43

•            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;

•            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;

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

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

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

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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 three months ended March 31, 2006 (in thousands):

Total fair value of natural gas 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		(12,563)
Unrealized gain on new positions entered during the period and still existing at
March 31, 2006		2,156
Realized gain on positions that existed at December 31, 2005 and were settled during
the period		8,001
Unrealized gain on positions that existed at December 31, 2005 and still exist at
March 31, 2006		4,913
Total fair value of natural gas marketing positions at March 31, 2006	$	8,386

_____________________________

(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):

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

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

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	$	8,376	$	—	$	8,376
Prices provided by other external sources		(173)		183		10
Modeled		—		—		—
Total	$	8,203	$	183	$	8,386

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The following table presents a reconciliation of our March 31, 2006 natural gas marketing positions recorded at fair value under generally accepted accounting principles (GAAP) to a non-GAAP measure of the fair value of our natural gas forward book wherein all forward trading positions are marked-to-market (in thousands). The approach used in determining the non-GAAP measure is consistent with our previous accounting methods under EITF 98-10. 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 natural gas marketing positions marked-to-
market in accordance with GAAP (see footnote (a) above)	$	8,386
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		12,185
Fair value of all forward positions (Non-GAAP)		20,571
“Liquidity Reserve” included in GAAP marked-to-market fair value (b)		1,747
Fair value of all forward positions excluding the “Liquidity Reserve” (Non-GAAP)	$	22,318

_____________________________

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

There have been no material changes in market risk faced by us from those reported in our 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 11 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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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	Term	Volume	Price
			(Mmbtu/day)
San Juan El Paso	07/12/2005	04/06 – 10/06	5,000	$	7.00
San Juan El Paso	12/14/2005	11/06 – 03/07	5,000	$	10.25
San Juan El Paso	04/03/2006	11/06 – 03/07	5,000	$	8.50
San Juan El Paso	04/03/2006	04/07 – 10/07	5,000	$	7.46

Crude Oil

Location	Transaction Date	Term	Volume	Price
			(barrels/month)
NYMEX	10/06/2004	Calendar 2006	10,000	$	41.00
NYMEX	07/29/2005	Calendar 2007	5,000	$	61.00
NYMEX	08/04/2005	Calendar 2007	5,000	$	62.00
NYMEX Put	12/14/2005	Calendar 2006	5,000	$	55.00
NYMEX	01/04/2006	Calendar 2007	5,000	$	65.00
NYMEX Put	01/12/2006	02/06 – 12/06	5,000	$	65.50
NYMEX Put	04/03/2006	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 March 31, 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 March 31, 2006 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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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 12 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 12 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.

Share Repurchases

					(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
January 1, 2006 – January 31, 2006	3,662(1)	$	35.50	—		—
February 1, 2006 – February 28, 2006	—	$	—	—		—
March 1, 2006 – March 31, 2006	282(2)	$	34.80	—		—
Total	3,944	$	33.03	—		—

___________________________

(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.

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Item 6. Exhibits

(a) Exhibits–

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.

50

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: May 10, 2006

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EXHIBIT INDEX

Exhibit Number	Description
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.

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