Black Hills 10Q 2005 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2005.

•	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

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

Yes

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 30, 2005

Common stock, $1.00 par value	32,544,957 shares

TABLE OF CONTENTS

		Page

PART 1.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income –
	Three Months Ended March 31, 2005 and 2004	3

	Condensed Consolidated Balance Sheets –
	March 31, 2005, December 31, 2004 and March 31, 2004	4

	Condensed Consolidated Statements of Cash Flows –
	Three Months Ended March 31, 2005 and 2004	5

	Notes to Condensed Consolidated Financial Statements	6-22

Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	22-35

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36-38

Item 4.	Controls and Procedures	38

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39

Item 6.	Exhibits	39

	Signatures	40

	Exhibit Index	41

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended
	March 31
	2005		2004
	(in thousands,
	except per share amounts)

Operating revenues	$	305,685	$	274,328

Operating expenses:
Fuel and purchased power		190,978		172,906
Operations and maintenance		24,524		24,454
Administrative and general		23,253		17,963
Depreciation, depletion and amortization		23,519		22,272
Taxes, other than income taxes		8,369		8,427
		270,643		246,022

Operating income		35,042		28,306

Other income (expense):
Interest expense		(12,769)		(14,351)
Interest income		390		392
Other expense		(73)		(103)
Other income		374		373
		(12,078)		(13,689)

Income from continuing operations before equity in earnings (losses)
of unconsolidated subsidiaries, minority interest and income taxes		22,964		14,617
Equity in earnings (losses) of unconsolidated subsidiaries		1,475		(249)
Minority interest		(60)		(42)
Income taxes		(8,514)		(4,332)

Income from continuing operations		15,865		9,994
Loss from discontinued operations, net of taxes		(125)		(208)

Net income		15,740		9,786
Preferred stock dividends		(79)		(88)
Net income available for common stock	$	15,661	$	9,698

Weighted average common shares outstanding:
Basic		32,444		32,291
Diluted		33,009		32,811

Earnings per share:
Basic–
Continuing operations	$	0.48	$	0.31
Discontinued operations		—		(0.01)
Total	$	0.48	$	0.30

Diluted–
Continuing operations	$	0.48	$	0.30
Discontinued operations		—		—
Total	$	0.48	$	0.30

Dividends paid per share of common stock	$	0.32	$	0.31

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

	March 31		December 31		March 31
	2005		2004		2004
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	67,629	$	64,506	$	191,484
Restricted cash		3,769		3,069		1,070
Receivables (net of allowance for doubtful accounts of $5,720; $4,698 and $7,582, respectively)		275,849		256,505		205,051
Notes receivable		—		239		239
Materials, supplies and fuel		66,873		89,732		50,980
Derivative assets		34,775		47,977		23,214
Prepaid income taxes		1,048		3,978		—
Deferred income taxes		1,184		4,237		5,350
Other assets		7,625		7,005		5,678
Assets of discontinued operations		3,085		3,059		4,028
		461,837		480,307		487,094

Investments		20,934		24,436		27,560

Property, plant and equipment		2,141,912		1,971,119		1,897,920
Less accumulated depreciation and depletion		(587,110)		(525,387)		(463,563)
		1,554,802		1,445,732		1,434,357
Other assets:
Derivative assets		613		593		257
Goodwill		30,144		30,144		30,144
Intangible assets (net of accumulated amortization of $22,579; $21,744 and $19,252, respectively)		35,914		36,750		39,241
Other		48,459		38,201		36,717
		115,130		105,688		106,359
	$	2,152,703	$	2,056,163	$	2,055,370
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	221,449	$	196,619	$	199,995
Accrued liabilities		74,039		69,306		68,146
Derivative liabilities		52,606		43,206		30,326
Notes payable		25,000		24,000		—
Current maturities of long-term debt		16,318		16,166		15,723
Accrued income taxes		6,577		7,799		5,953
Liabilities of discontinued operations		657		651		3,391
		396,646		357,747		323,534

Long-term debt, net of current maturities		756,544		733,581		822,289

Deferred credits and other liabilities:
Deferred income taxes		167,766		159,623		129,193
Derivative liabilities		2,206		206		2,894
Other		86,965		64,406		62,060
		256,937		224,235		194,147

Minority interest in subsidiaries		4,894		4,835		4,731

Stockholders’ equity:
Preferred stock – no par Series 2000-A; 21,500 shares authorized; Issued and outstanding:
6,839 shares all periods		7,167		7,167		7,167
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized; Issued 32,608,482; 32,595,285
and 32,552,878 shares, respectively		32,608		32,595		32,553
Additional paid-in capital		384,467		384,439		382,782
Retained earnings		327,261		322,009		304,249
Treasury stock at cost – 71,675; 117,567 and 144,001 shares, respectively		(1,727)		(2,838)		(3,435)
Accumulated other comprehensive loss		(12,094)		(7,607)		(12,647)
		730,515		728,598		703,502
Total stockholders’ equity		737,682		735,765		710,669
	$	2,152,703	$	2,056,163	$	2,055,370

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(unaudited)

	Three Months Ended
	March 31
	2005		2004
	(in thousands)
Operating activities:
Net income available for common	$	15,661	$	9,698
Adjustments to reconcile net income available for common to net cash provided by operating activities:
Loss from discontinued operations		125		208
Change in provision for valuation allowances		(613)		112
Depreciation, depletion and amortization		23,519		22,272
Net change in derivative assets and liabilities		17,569		(1,139)
Deferred income taxes		5,551		3,913
Distributed (undistributed) earnings in associated companies		4,549		(234)
Minority interest		60		42
Change in operating assets and liabilities, net of acquisition-
Accounts receivable and other current assets		20,651		12,311
Accounts payable and other current liabilities		16,028		39,018
Other operating activities		7,322		(54)
		110,422		86,147

Investing activities:
Property, plant and equipment additions		(28,305)		(13,544)
Payment for acquisition, net of cash acquired		(67,331)		—
Other investing activities		(1,385)		1,529
		(97,021)		(12,015)

Financing activities:
Dividends paid		(10,409)		(10,016)
Common stock issued		41		2,640
Increase in short-term borrowings, net		1,000		—
Long-term debt – repayments		(3,273)		(48,106)
Other financing activities		2,363		75
		(10,278)		(55,407)

Increase in cash and cash equivalents		3,123		18,725

Cash and cash equivalents:
Beginning of period		64,506		172,759
End of period	$	67,629	$	191,484

Supplemental disclosure of cash flow information:

Cash paid during the period for-
Interest	$	12,877	$	10,744
Net income taxes refunded	$	(626)	$	(18,819)

Common stock issued in conversion of preferred shares	$	—	$	976

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

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2004 Annual Report on Form 10-K)

(1)	MANAGEMENT’S STATEMENT

The financial statements included herein have been prepared by Black Hills Corporation (the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in the Company’s 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

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

(2)	RECLASSIFICATIONS

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

(3)	STOCK-BASED COMPENSATION

At March 31, 2005, the Company had three stock-based employee compensation plans under which it can issue stock options to its employees. The Company accounts for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees (APB 25),” and related interpretations. No employee compensation cost related to stock options is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation (SFAS 123),” to stock-based employee compensation (in thousands, except per share amounts):

	Three Months Ended
	March 31
	2005		2004

Net income available for common stock, as reported	$	15,661	$	9,698
Deduct: Total stock-based employee compensation expense
determined under fair value based method for all awards,
net of related tax effects		(141)		(188)
Pro forma net income available for common stock	$	15,520	$	9,510

Earnings per share:

As reported–
Basic
Continuing operations	$	0.48	$	0.31
Discontinued operations		—		(0.01)
Total	$	0.48	$	0.30
Diluted
Continuing operations	$	0.48	$	0.30
Discontinued operations		—		—
Total	$	0.48	$	0.30

Pro forma–
Basic
Continuing operations	$	0.48	$	0.30
Discontinued operations		—		(0.01)
Total	$	0.48	$	0.29
Diluted
Continuing operations	$	0.47	$	0.29
Discontinued operations		—		—
Total	$	0.47	$	0.29

(4)	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS No. 123 (Revised 2004)

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (Revised 2004) “Share Based Payment” (SFAS 123 (Revised 2004)). SFAS 123 (Revised 2004) requires the measurement and recognition of the cost of employee services received in exchange for an award of equity instruments, based on the grant-date fair value of the award. The cost is to be recognized over the requisite service period. In April 2005, the Securities and Exchange Commission (SEC) adopted a final rule amending the effective date of SFAS 123 (Revised 2004) to the first interim or annual reporting period of the fiscal year beginning after June 15, 2005. The Company currently accounts for its employee equity compensation stock option plans under the provisions of APB No. 25 and no stock-based employee compensation cost is reflected in net income (see Note 3, Stock-Based Compensation). The effect of adoption of SFAS 123 (Revised 2004) will be to recognize compensation expense for the fair value of the stock options granted at the grant date. Total stock-based employee compensation expense, net of related tax effects would have been $0.1 million and $0.2 million for the three month periods ending March 31, 2005 and 2004, respectively, had the Company applied the fair value recognition provisions of SFAS 123 during those periods.

FIN 47

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

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

EITF Issue No. 04-6

On March 17, 2005, the Emerging Issues Task Force (EITF) issued EITF Issue No. 04-6, “Accounting for Stripping Costs Incurred during Production in the Mining Industry” (EITF 04-6). EITF 04-6 provides that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005. The Company is currently evaluating the effect of EITF 04-6 on the Company’s consolidated results of operations, financial position and cash flows.

(5)	MATERIALS, SUPPLIES AND FUEL

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

	March 31,		December 31,		March 31,
Major Classification	2005		2004		2004

Materials and supplies	$	24,370	$	22,661	$	20,884
Fuel for generation		2,450		2,211		1,248
Gas and oil held by energy marketing		40,053		64,860		28,848

Total materials, supplies and fuel	$	66,873	$	89,732	$	50,980

(6)	ASSET RETIREMENT OBLIGATIONS

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

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

	Balance at		Liabilities		Liabilities				Cash Flow		Balance at
	12/31/04		Incurred		Settled		Accretion		Revisions		3/31/05

Oil and gas	$	7,942	$	—	$	—	$	138	$	—	$	8,080
Coal mining		15,867		153		(43)		189		—		16,166
Total	$	23,809	$	153	$	(43)	$	327	$	—	$	24,246

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

NET

Cheyenne Light, Fuel and Power (CLF&P) recovers purchased power and natural gas costs from customers through an electric cost adjustment (ECA) and a gas cost adjustment (GCA) mechanism. The ECA and GCA rate structure provides for a fixed energy supply rate charged to CLF&P’s customers through 2005; the continuation of the ECA and GCA with certain modifications, including the amortization through December 2005 of unrecovered costs incurred during 2001 up to the agreed upon fixed supply rates; and an agreement that CLF&P’s energy supply needs will be provided, in whole or in part, by Public Service Company of Colorado (PSCo) in accordance with wholesale tariff rates. In 2005, CLF&P will request recovery of its actual cost incurred plus the outstanding balance of any deferral from earlier years. New cost levels have been reflected in CLF&P’s expenses, and in deferred costs based on current ECA and GCA recovery levels, with an effective date of June 1, 2001, and retroactive adjustments back to the date of the increase in costs on February 25, 2001. At March 31, 2005, the ECA and GCA deferred balance is $8.4 million and is included in "Other" under "Other assets" on the accompanying Condensed Consolidated Balance Sheet.

(8)	EARNINGS PER SHARE

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

Period ended March 31, 2005	Three Months
			Average
	Income		Shares

Income from continuing operations	$	15,865
Less: preferred stock dividends		(79)

Basic – available for common shareholders		15,786	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	$	15,865	33,009

Period ended March 31, 2004	Three Months
			Average
	Income		Shares

Income from continuing operations	$	9,994
Less: preferred stock dividends		(88)

Basic – available for common shareholders		9,906	32,291
Dilutive effect of:
Stock options		—	115
Convertible preferred stock		88	195
Estimated contingent shares issuable for prior acquisition		—	158
Others		—	52
Diluted – available for common shareholders	$	9,994	32,811

(9)	COMPREHENSIVE INCOME

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

	Three Months Ended
	March 31
	2005		2004

Net income	$	15,740	$	9,786
Other comprehensive (loss) income, net of tax:
Fair value adjustment on derivatives designated as cash flow hedges		(4,502)		(1,504)
Unrealized gain (loss) on available-for-sale securities		15		(21)

Comprehensive income	$	11,253	$	8,261

(10)	CHANGES IN COMMON STOCK

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

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

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

Grants under this performance share plan are in addition to grants under two other performance share plans awarded March 1, 2004. Compensation expense recognized for all of the performance share awards for the quarter ended March 31, 2005 was $0.3 million.

• During the first quarter of 2005, the Company granted 12,400 stock options at a weighted-average exercise price of $29.63 per share.

• 13,202 stock options were exercised at a weighted-average price of $26.85 per share.

• The Company issued 3,266 shares of common stock from treasury shares under the short-term incentive compensation plan during the first quarter of 2005. Compensation cost related to the award was approximately $0.1 million, which was accrued for in 2004.

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

(11)	CHANGES IN LONG-TERM DEBT

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

(12)	GUARANTEES

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

As of March 31, 2005, the Company had the following guarantees in place (in thousands):

	Outstanding at	Year
Nature of Guarantee	March 31, 2005	Expiring

Guarantee payments under the Las Vegas Cogen I Power Purchase		Upon 5 days
and Sales Agreement with Sempra Energy Solutions	$10,000	written notice
Guarantee of certain obligations under Enserco’s credit facility	3,000	2005
Guarantee of obligation of Las Vegas Cogen II (LVII) under an
interconnection and operation agreement	750	2005
Guarantee payments of Black Hills Power under various
transactions with Idaho Power Company	250	2006
Guarantee payments of Black Hills Power (BHP) under various
transactions with Southern California Edison Company	750	2005
Guarantee obligations under the Wygen Plant Lease	111,018	2008
Guarantee payment and performance under credit agreements for
two combustion turbines	27,714	2010
Guarantee payments of Las Vegas Cogen II to Nevada Power
Company under a power purchase agreement	5,000	2013
Indemnification for subsidiary reclamation/surety bonds	25,000	Ongoing
	$183,482

(13)	EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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

The components of net periodic benefit cost for the two Plans for the three months ended March 31 are as follows (in thousands):

	2005		2004

Service cost	$	576	$	443
Interest cost		995		909
Expected return on plan assets		(1,157)		(1,129)
Amortization of prior service cost		54		58
Amortization of net loss		296		375

Net periodic benefit cost	$	764	$	656

The Company does not anticipate that contributions will be made to the Plans in the 2005 fiscal year.

Supplemental Nonqualified Defined Benefit Plan

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

The components of net periodic benefit cost for the supplemental nonqualified plans for the three months ended March 31 are as follows (in thousands):

	2005		2004

Service cost	$	86	$	134
Interest cost		252		241
Amortization of prior service cost		2		2
Amortization of net loss		157		187

Net periodic benefit cost	$	497	$	564

The Company anticipates that contributions to the Plan for the 2005 fiscal year will be approximately $0.3 million; the contributions are expected to be in the form of benefit payments.

Non-pension Defined Benefit Postretirement Plan

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

The components of net periodic benefit cost for the Postretirement Healthcare Plans for the three months ended March 31 are as follows (in thousands):

	2005		2004

Service cost	$	185	$	140
Interest cost		232		166
Amortization of net transition obligation		37		37
Amortization of prior service cost		(6)		(6)
Amortization of net loss		25		47

Net periodic benefit cost	$	473	$	384

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

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

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of March 31, 2005, substantially all of the Company’s operations and assets are located within the United States. The Company’s operations are conducted through seven reporting segments that include: Wholesale Energy group consisting of the following segments: Coal mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and gas, which produces, explores and operates oil and gas interests located in the Rocky Mountain region, Texas, California and other states; Energy marketing and transportation, which markets natural gas, oil and related services to customers in the Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions and transports crude oil in Texas; and Power generation, which produces and sells power and capacity to wholesale customers; and Retail Services group consisting of the following segments: Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; Electric and gas utility, acquired January 21, 2005, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity; and Communications, which primarily markets broadband communications services in Rapid City and the northern Black Hills region of South Dakota. The Company entered into an agreement on April 20, 2005 to sell Black Hills FiberSystems, Inc., which is reported as the Communications segment (see Note 19).

Segment information follows the same accounting policies as described in Note 23 of the Company’s 2004 Annual Report on Form 10-K. In accordance with the provisions of SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” (SFAS 71), intercompany fuel sales to the electric utility are not eliminated.

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

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

Quarter to Date and Year to Date
March 31, 2005

Wholesale energy:
Coal mining	$	4,872	$	3,146	$	1,488
Oil and gas		19,041		—		4,960
Energy marketing and transportation		161,131		—		2,927
Power generation		38,162		—		3,885
Retail Services:
Electric utility		43,049		98		4,322
Electric and gas utility		27,075		—		512
Communications		9,666		—		(887)
Corporate		265		—		(1,342)
Intersegment eliminations		—		(820)		—

Total	$	303,261	$	2,424	$	15,865

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

Quarter to Date and Year to Date
March 31, 2004

Wholesale energy:
Coal mining	$	5,546	$	3,182	$	1,752
Oil and gas		16,321		83		3,687
Energy marketing and transportation		164,435		—		3,969
Power generation		35,137		—		(2,077)
Retail services:
Electric utility		41,626		21		5,037
Communications		8,455		—		(1,784)
Corporate		310		561		(590)
Intersegment eliminations		—		(1,349)		—

Total	$	271,830	$	2,498	$	9,994

Other than the acquisition and consolidation of CLF&P into the Company’s Condensed Consolidated Balance Sheet (see Note 17), the Company had no material changes in total assets of its reporting segments, as reported in Note 23 of the Company’s 2004 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

(15)	RISK MANAGEMENT ACTIVITIES

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

Trading Activities

Natural Gas Marketing

The contract or notional amounts and terms of our natural gas marketing activities and derivative commodity instruments at March 31, 2005, December 31, 2004 and March 31, 2004 are as follows:

(in thousands of MMbtus)	March 31, 2005			December 31, 2004			March 31, 2004
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)

Natural gas basis swaps purchased		68,214	21		24,972	15		36,180	24
Natural gas basis swaps sold		66,912	19		27,145	15		38,340	24
Natural gas fixed-for-float
swaps purchased		30,718	19		27,274	15		16,578	16
Natural gas fixed-for-float
swaps sold		25,775	13		32,206	12		26,779	20
Natural gas physical purchases		94,393	21		64,799	15		72,888	20
Natural gas physical sales		118,420	55		95,996	58		59,969	24

(thousands of U.S. dollars)

Canadian dollars purchased	$	1,000	1	$	10,800	1	$	—	—
Canadian dollars sold	$	22,700	7	$	38,000	4	$	—	—

Derivatives and certain natural gas marketing activities were marked to fair value on March 31, 2005, December 31, 2004 and March 31, 2004, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows (in thousands):

	Current		Non-current		Current		Non-current
	Derivative		Derivative		Derivative		Derivative		Unrealized
	Assets		Assets		Liabilities		Liabilities		Gain (loss)

March 31, 2005	$	34,566	$	613	$	43,651	$	888	$	(9,360)

December 31, 2004	$	46,177	$	286	$	38,375	$	6	$	8,082

March 31, 2004	$	22,918	$	257	$	22,372	$	165	$	638

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Balance Sheet and the related unrealized gain/loss on the Statement of Income. As of March 31, 2005, December 31, 2004 and March 31, 2004, the market adjustments recorded in inventory were $4.8 million, $(9.0) million and $0.2 million, respectively.

Activities Other Than Trading

Crude Oil Marketing

The contract or notional amounts and terms of our crude oil contracts, are set forth below (in thousands of barrels):

	March 31, 2005		December 31, 2004		March 31, 2004
		Maximum		Maximum		Maximum
	Notional	Term in	Notional	Term in	Notional	Term in
	Amounts	Years	Amounts	Years	Amounts	Years

Crude oil purchased	1,742	.75	1,669	1.0	1,574	.75
Crude oil sold	1,738	.75	1,651	1.0	2,215	.75

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

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

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

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

Oil and Gas Exploration and Production

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

											Pre-tax
											Accumulated
		Maximum	Current		Non-current		Current		Non-current		Other		Pre-tax
		Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
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)
December 31, 2004

Crude oil swaps	360,000	1.00	$	—	$	152	$	3,112	$	—	$	(2,886)	$	(74)
Natural gas swaps	3,810,000	0.50		1,710		155		493		—		1,372		—
			$	1,710	$	307	$	3,605	$	—	$	(1,514)	$	(74)
March 31, 2004

Crude oil swaps	390,000	1.00	$	—	$	—	$	2,228	$	258	$	(2,448)	$	(38)
Natural gas swaps	2,870,000	1.00		25		—		2,548		—		(2,523)		—
			$	25	$	—	$	4,776	$	258	$	(4,971)	$	(38)

________________________

*crude in barrels, gas in MMbtu’s

Based on March 31, 2005 market prices, an $8.1 million loss would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production. These estimated realized losses for the next twelve months were calculated using March 31, 2005 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

Financing Activities

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

			Weighted										Pre-tax
			Average										Accumulated
	Current		Fixed	Maximum	Current		Non-current		Current		Non-current		Other
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		Loss
March 31, 2005

Swaps on project
financing	$	113,000	4.22%	1.50	$	209	$	—	$	767	$	112	$	(670)

December 31, 2004

Swaps on project
financing	$	113,000	4.22%	1.75	$	60	$	—	$	1,226	$	200	$	(1,366)

March 31, 2004

Swaps on project
financing	$	113,000	4.48%	2.5	$	271	$	—	$	3,178	$	2,471	$	(5,378)

Based on March 31, 2005 market interest rates and balances, approximately $0.6 million would be realized as additional interest expense during the next twelve months. Estimated and realized amounts will likely change during the next twelve months as market interest rates change.

(16)	LEGAL PROCEEDINGS

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

(17)	ACQUISITION

On January 13, 2004, the Company entered into a Stock Purchase Agreement to acquire from Xcel Energy, Inc. all of the outstanding capital stock of its subsidiary, CLF&P, a Wyoming corporation. On January 21, 2005, the Company completed this acquisition. The Company purchased all the common stock of CLF&P, including the assumption of outstanding debt of approximately $24.6 million, for approximately $93 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. The estimated purchase price allocations are subject to adjustment, generally within one year of the date of acquisition. Preliminary allocation of the purchase price is as follows (in thousands):

Current assets	$	18,239
Property, plant and equipment		100,447
Deferred assets		17,392
	$	136,078

Current liabilities	$	(12,313)
Long-term debt		(24,600)
Deferred tax liabilities		(7,892)
Long-term liabilities		(22,917)
	$	(67,722)

Net assets	$	68,356

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

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

	Three Month Period Ended
	March 31, 2005		March 31, 2004

Operating revenues	$	314,863	$	301,507
Income from continuing operations		16,044		10,769
Net income		15,919		10,561
Earnings per share –
Basic:
Continuing operations	$	0.49	$	0.33
Total	$	0.49	$	0.32
Diluted:
Continuing operations	$	0.49	$	0.33
Total	$	0.48	$	0.32

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

(18)	DISCONTINUED OPERATIONS

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

Sale of Landrica Development Corp.

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

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

	Three Months Ended
	March 31, 2004

Pre-tax loss from discontinued operations	$	(36)
Income tax benefit		6
Net loss from discontinued operations	$	(30)

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

		March 31, 2004

Current assets	$	1
Property, plant and equipment		151
Other current liabilities		(39)
Deferred reclamation		(2,858)
Other non-current liabilities		(1)
Net liabilities of discontinued operations	$	(2,746)

Sale of Pepperell Plant

During the third quarter of 2003, the Company adopted a plan to sell the 40 megawatt gas-fired Pepperell plant, and on April 8, 2005, the Company sold the Pepperell plant (see Note 19). For business segment reporting purposes, the Pepperell plant results were previously included in the Power generation segment.

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

	Three Months Ended
	March 31
	2005		2004

Pre-tax loss from discontinued operations	$	(190)	$	(272)
Income tax benefit		65		94
Net loss from discontinued operations	$	(125)	$	(178)

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

	March 31		December 31		March 31
	2005		2004		2004

Current assets	$	133	$	107	$	232
Property, plant and equipment		—		—		1,064
Non-current deferred tax asset		2,952		2,952		2,580
Other current liabilities		(149)		(167)		(88)
Non-current liabilities		(508)		(484)		(405)
Net assets of discontinued operations	$	2,428	$	2,408	$	3,383

(19)	SUBSEQUENT EVENTS

Communications Segment

On April 20, 2005, the Company entered into an agreement to sell its Communications business, Black Hills FiberSystems, Inc. to PrairieWave Communications, Inc. Under the purchase and sale agreement, the Company will receive a cash payment of approximately $103 million. The transaction is subject to certain state and federal regulatory approvals and is expected to be completed prior to June 30, 2005. The Company expects to record a loss of approximately $0.09 per share on the sale.

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

	March 31, 2005		December 31, 2004		March 31, 2004

Current assets	$	5,740	$	6,468	$	6,791
Property, plant and equipment		107,851		109,566		113,299
Other non-current assets		187		198		144
Current liabilities		(5,864)		(6,112)		(6,171)
Other non-current liabilities		(759)		(916)		(677)

Net assets	$	107,155	$	109,204	$	113,386

Pepperell Plant

On April 8, 2005, the Company sold the Pepperell plant to an unrelated party, Pepperell Realty LLC, for a nominal amount plus the assumption of certain obligations. The Company currently reports the results of operations of the Pepperell facility as discontinued operations (see Note 18).

Bank Facility

On May 5, 2005, the Company entered into a new $400 million revolving bank facility. The new facility has a five year term, expiring May 4, 2010. The facility contains a provision which allows the facility size to be increased by up to an additional $100 million through the addition of new lenders, or through increased commitments from existing lenders but only with the consent of such lenders. The cost of borrowings or letters of credit issued under the new facility is determined based on the Company’s credit ratings. At the Company’s current credit ratings, the facility has an annual facility fee of 17.5 basis points, and a borrowing spread of 70.0 basis points over the one month LIBOR (3.57 percent as of March 31, 2005).

In conjunction with entering into the new revolving bank facility, the Company terminated its $125 million revolving bank facility due May 12, 2005 and its $225 million facility due August 20, 2006.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Business Group	Financial Segment

Wholesale energy group	Power generation
	Oil and gas
	Coal mining
	Energy marketing and transportation
Retail services group	Electric utility
	Electric and gas utility
	Communications

Our wholesale energy group, Black Hills Energy, Inc., engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing and transportation of fuel products. Our retail services group consists of our electric and gas utilities and communications segments. Our electric utility generates, transmits and distributes electricity to an average of approximately 62,000 customers in South Dakota, Wyoming and Montana. Our electric and gas utility serves approximately 38,000 electric and 31,000 natural gas customers in Cheyenne, Wyoming and vicinity. Our communications segment primarily provides broadband communications services to over 27,000 residential and business customers in Rapid City and the northern Black Hills region of South Dakota through Black Hills FiberCom, LLC.

In April 2005, we entered into a definitive agreement to sell our subsidiary, Black Hills FiberSystems, Inc., reported as our Communications segment, which primarily markets broadband communications services and which holds two telephone directory businesses. To conform with Generally Accepted Accounting Principles, results of operations for the Communications segment will be reclassified to Discontinued Operations in the second quarter of 2005.

In April 2005, we also sold our Pepperell power plant, our last power plant in the eastern region.

In May 2004, we sold our subsidiary, Landrica Development Corp., which held some land and coal enhancement facilities that were previously reported in our Coal mining segment.

The following discussion should be read in conjunction with Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – included in our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Results of Operations

Consolidated Results

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

	Three Months Ended
	March 31
	2005	2004

Revenues

Wholesale energy	74%	82%
Retail services	26	18
	100%	100%

Income/(Loss) from Continuing Operations

Wholesale energy	84%	73%
Retail services	24	33
Corporate	(8)	(6)
	100%	100%

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

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004. On January 21, 2005, we completed the acquisition of CLF&P, an electric and natural gas utility serving customers in Cheyenne, Wyoming and vicinity. The Company purchased all of the common stock of CLF&P, including the assumption of outstanding debt of approximately $24.6 million, for approximately $93 million. The results of operations of CLF&P have been included in the accompanying Condensed Consolidated Financial Statements from the date of acquisition.

Revenues for the three months ended March 31, 2005 increased 11 percent or $31.4 million compared to the same period in 2004. Increased revenues are primarily the result of the acquisition and consolidation of CLF&P.

Operating expenses increased 10 percent, or $24.6 million resulting from an increase in fuel and purchased power costs primarily due to the operations of CLF&P and increased administrative and general costs due to increased compensation expense and professional fees. In addition, a $1.0 million pre-tax gain on the sale of assets was recorded as an offset to general and administrative expense in the first quarter of 2004. The gain on sale of assets is included in the 2004 “Corporate” results.

Income from continuing operations increased 59 percent or $5.9 million due to the increased revenues, and a decrease in interest expense due to a reduction in debt, exclusive of the assumption of the CLF&P debt, offset by increased fuel and purchased power and administrative and general costs.

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

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

Wholesale Energy Group

	Three Months Ended
	March 31
	2005		2004
	(in thousands)
Revenue:
Energy marketing and transportation	$	161,131	$	164,435
Power generation		38,162		35,137
Oil and gas		19,041		16,404
Coal mining		8,018		8,728
Total revenue		226,352		224,704
Operating expenses		200,479		206,883
Operating income	$	25,873	$	17,821

Income from continuing operations	$	13,260	$	7,331

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

Energy Marketing and Transportation

	Three Months Ended
	March 31
	2005		2004
	(in thousands)

Revenue*	$	161,131		$	164,435
Operating income		4,709			6,301
Income from continuing operations		2,927			3,969

________________________

All periods presented reflect a net presentation of revenues at our gas marketing subsidiary and a gross presentation of revenues at our crude oil marketing and transportation subsidiary in accordance with EITF Issue No. 02-3 “Accounting for Contracts Involving Energy Trading and Risk Management Activities” (EITF 02-3) and EITF Issue No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19).

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

	Three Months Ended
	March 31
	2005	2004

Natural gas physical sales – MMbtus	1,357,600	1,201,000
Natural gas financial sales - MMbtus	674,800	383,200
Crude oil – barrels	35,500	49,700

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004. The decrease in revenues is primarily the result of a 29 percent decrease in crude oil volumes marketed, partially offset by a 42 percent increase in the average price per barrel marketed. Revenue decreases from crude oil marketing were more than offset by a decrease in the cost of crude oil sold resulting in increased crude oil marketing margins.

Income from continuing operations decreased $1.0 million due to a $3.1 million unrealized mark-to-market loss for the quarter ended March 31, 2005, compared to a $0.3 million unrealized loss in the first quarter of 2004, resulting in a quarter-over-quarter, pre-tax decrease of $2.8 million in unrealized mark-to-market adjustment at our gas marketing operations (for discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas marketing operations see “Trading Activities” in Part 1, Item 3 of this Form 10-Q). These items were partially offset by a $1.7 million increase in realized gas marketing margins received and a 13 percent increase in natural gas physical volumes marketed.

Power Generation

	Three Months Ended
	March 31
	2005		2004
	(in thousands)

Revenue	$	38,162	$	35,137
Operating income		11,768		3,593
Income (loss) from continuing operations		3,885		(2,077)

	March 31
	2005	2004

Independent power capacity:
MWs of independent power capacity in service	964	964

Contracted fleet plant availability	98.9%	98.5%

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004. Revenue increased 9 percent in the first quarter of 2005 compared to the first quarter of 2004 primarily as a result of a $2.4 million increase in revenues at our Las Vegas facility. In the first three months of 2005, our Las Vegas II facility sold capacity and energy to Nevada Power Company under a long-term tolling arrangement, which became effective April 1, 2004, as opposed to selling power into the market on a merchant basis, for the same period in 2004, when economic to do so.

Income from continuing operations increased $6.0 million. Increased earnings were the result of higher revenues, decreased fuel cost primarily related to generating costs at our Las Vegas facility, and lower interest expense from debt reduction and increased income from equity investments.

Oil and Gas

	Three Months Ended
	March 31
	2005			2004
	(in thousands)

Revenue	$	19,041	$		16,404
Operating income		7,623			5,892
Income from continuing operations		4,960			3,687

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

	Three Months Ended
	March 31
	2005	2004

Fuel production:
Barrels of oil sold	95,900	114,300
Mcf of natural gas sold	2,889,800	2,394,300
Mcf equivalent sales	3,465,000	3,079,900

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004. Income from continuing operations for the first quarter of 2005 increased $1.3 million over the comparable period in 2004. Volumes sold increased 13 percent, primarily related to increased production. Average gas and oil prices received, net of hedges, in the first three months of 2005 were $5.36/Mcf and $32.73/bbl, respectively, compared to $5.15/Mcf and $26.87/bbl in the first three months of 2004. Total operating expenses increased 9 percent primarily due to increased production expenses related to the additional sales volumes. The 2005 lease operating expenses per Mcf sold (LOE/MCF) decreased 16 percent from $0.99/Mcf in 2004 to $0.83/Mcf in 2005 due to production efficiencies realized from an increase in productive wells placed in service.

The following is a summary of our internally estimated, economically recoverable oil and gas reserves. These estimates are measured using constant product prices. The increases in reserves are primarily the result of increased product prices. Estimates of economically recoverable reserves for interim periods are based on independent year-end reserve studies updated for acquisitions, drilling activity, property sales and actual production during the interim period. These internally estimated reserves may differ from actual results.

	March 31, 2005	December 31,2004

Barrels of oil (in thousands)	5,400	5,239
Mmcf of natural gas	139,846	141,983
Total in Mmcf equivalents	172,246	173,417

Reserves reflect pricing of:

	March 31,		December 31,
	2005		2004

	Oil	Gas	Oil	Gas

NYMEX	$55.40	$7.65	$43.45	$6.15

Average well-head	$53.14	$7.13	$41.19	$5.55

Coal Mining

	Three Months Ended
	March 31
	2005		2004
	(in thousands)

Revenue	$	8,018	$	8,728
Operating income		1,773		2,035
Income from continuing operations		1,488		1,752

The following is a summary of coal sales quantities:

	Three Months Ended
	March 31
	2005	2004

Fuel production:
Tons of coal sold	1,153,300	1,203,600

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004. Revenue from our coal mining segment decreased 8 percent for the three-month period ended March 31, 2005, compared to the same period in 2004. The decrease in revenue was primarily attributable to unscheduled outages at the Wyodak plant. The Wyodak plant, operated by our joint interest partner (PacifiCorp), has postponed a planned 2005 major maintenance outage and rescheduled the outage for 2006.

Operating expenses decreased 7 percent or approximately $0.4 million, primarily due to lower depletion rates and lower mineral tax expense, related to the decrease in revenues.

Income from continuing operations decreased 15 percent due to the decrease in revenues partially offset by lower taxes and production-related costs.

Retail Services Group

Electric Utility

	Three Months Ended
	March 31
	2005		2004
	(in thousands)

Revenue	$	43,147	$	41,647
Operating expenses		33,652		30,239
Operating income	$	9,495	$	11,408

Income from continuing operations and net income	$	4,322	$	5,037

The following table provides certain operating statistics:

	Three Months Ended
	March 31
	2005	2004

Firm (system) sales – MWh	517,962	513,234
Off-system sales – MWh	231,314	202,294

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004. Electric utility revenues increased 4 percent for the three-month period ended March 31, 2005, compared to the same period in the prior year. The increase in revenue was primarily due to a 14 percent increase in off-system electric megawatt-hour sales at an 8 percent increase in average prices received. Firm residential, commercial and wholesale sales increased 1 percent, 2 percent and 1 percent, respectively, and industrial sales declined 1 percent. Degree days, which is a measure of weather trends, were 4 percent below last year.

Electric operating expenses increased 11 percent for the three-month period ended March 31, 2005, compared to the same period in the prior year. Purchased power increased $2.7 million due to a 14 percent increase in megawatt-hours purchased, at a 13 percent increase in the average cost per megawatt-hour. The increase in purchased power costs was primarily due to the increased off-system sales and 18 days of unscheduled plant outages at the Wyodak plant and was partially offset by a $0.3 million decrease in fuel costs as prevailing gas prices made it more economical for us to purchase power for our peaking needs and increased off-system sales, rather than generate energy utilizing our gas turbines. The Wyodak plant has postponed a planned 2005 maintenance outage and rescheduled the maintenance outage for 2006. The increase in operating expense was also affected by increased legal expense and health insurance costs, partially offset by lower maintenance costs.

Income from continuing operations decreased $0.7 million primarily due to the increase in purchased power expense, legal expense and health insurance expense, partially offset by an increase in electric sales and a decrease in interest expense primarily due to the pay down of debt.

Electric and Gas Utility

	January 21, 2005 to
	March 31
	2005
	(in thousands)

Revenue	$	27,075
Operating expenses		26,177
Operating income	$	898

Income from continuing opeations and net income	$	512

Natural gas sales comprised 41 percent or $11.0 million of total revenues, and electric sales comprised 59 percent or $16.1 million of total revenues for this segment.

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

Communications

	Three Months Ended
	March 31
	2005		2004
	(in thousands)

Revenue	$	9,666	$	8,455
Operating expenses		10,172		10,294
Operating loss	$	(506)	$	(1,839)

Net loss	$	(887)	$	(1,784)

The following table provides certain operating statistics:

	March 31	December 31	March 31
	2005	2004	2004

Business customers	3,376	3,317	3,156
Residential customers	23,838	23,663	23,478
Revenue generating units	57,542	56,835	55,395

Three Months Ended March 31, 2005 Compared to Three Months Ended March 31, 2004. The communications business group’s net loss was $0.9 million for the three-month period ended March 31, 2005 compared to a net loss of $1.8 million for the same period in 2004. Revenues increased 14 percent as a result of a 2 percent increase in customers and the expiration of a sales incentive marketing campaign initiated in response to a local competitor’s aggressive pricing pressure in 2004. Revenue was also impacted by a 4 percent increase in residential revenue generating units over the same period in the prior year. The increase in revenues was partially offset by an increase in the cost of sales related to the increase in customers.

In April 2005, we entered into a definitive agreement to sell our communications business. Under the purchase and sale agreement, we will receive a cash payment of approximately $103 million. The transaction is subject to certain state and federal regulatory approvals and is expected to be completed prior to June 30, 2005. We expect to record a loss of approximately $0.09 per share on the sale.

Critical Accounting Policies

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

Liquidity and Capital Resources

Cash Flow Activities

During the three-month period ended March 31, 2005, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on common and preferred stock, to pay our long-term debt maturities, and to fund our property, plant and equipment additions and the CLF&P acquisition (exclusive of debt assumed). We plan to fund future property and investment additions primarily through a combination of operating cash flow and increased short-term and long-term debt.

Cash flows from operations increased $24.3 million for the three-month period ended March 31, 2005 compared to the same period in the prior year primarily due to a $6.0 million increase in net income, an $18.7 million increase in our cash flows from net derivative assets and liabilities and a $4.8 million increase in cash flows from distributions from equity investments partially offset by a $7.3 million decrease in operating assets and liabilities.

During the three months ended March 31, 2005, we had cash outflows from investing activities of $97.0 million, which was primarily related to property, plant and equipment additions in the normal course of business and the $67.3 million cash payment related to the acquisition of CLF&P.

During the three months ended March 31, 2005, we had cash outflows from financing activities of $10.3 million, primarily due to the payment of quarterly cash dividends on common stock.

Dividends

Dividends paid on our common stock totaled $10.4 million, or $0.32 per share in the first quarter of 2005. This reflects a 3.2 percent increase, as approved by our board of directors in January 2005, from the 2004 quarterly dividend level. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under PUHCA, restrictions under our credit facilities and our future business prospects.

Short-Term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are revolving bank facilities and cash provided by operations. Our liquidity position remained strong during the first quarter of 2005. As of March 31, 2005, we had approximately $67.6 million of cash unrestricted for operations and $350 million of credit through revolving bank facilities. Approximately $41.1 million of the cash balance at March 31, 2005 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company. The bank facilities consisted of a $225 million facility due August 20, 2006 and a $125 million facility due May 12, 2005.

These bank facilities can be used to fund our working capital needs, for general corporate purposes, and to provide liquidity for a commercial paper program if implemented. At March 31, 2005, we had $25.0 million of borrowings outstanding under these facilities. After inclusion of applicable letters of credit, the remaining borrowing capacity under the bank facilities was $277.4 million at March 31, 2005.

On May 5, 2005, the Company entered into a new $400 million revolving bank facility with ABN AMRO as Administrative Agent, Union Bank of California and US Bank as Co-Syndication Agents, Bank of America and Harris Nesbitt as Co-Documentation Agents, and other syndication participants. The new facility has a five year term, expiring May 4, 2010. The facility contains a provision which allows the facility size to be increased by up to an additional $100 million through the addition of new lenders, or through increased commitments from existing lenders, but only with the consent of such lenders. The cost of borrowings or letters of credit issued under the new facility is determined based on the Company’s credit ratings; at the Company’s current ratings levels, the facility has an annual facility fee of 17.5 basis points, and a borrowing spread of 70.0 basis points over the one month LIBOR (which equates to a 3.57 percent borrowing rate as of March 31, 2005). In conjunction with entering into the new revolving bank facility, the Company terminated its $125 million revolving bank facility due May 12, 2005 and its $225 million facility due August 20, 2006.

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

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

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

• an interest coverage ratio of not less than 2.5 to 1.0.

If these covenants are violated, it would be considered an event of default entitling the lender to terminate the remaining commitment and accelerate all principal and interest outstanding.

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

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

Our consolidated net worth was $737.7 million at March 31, 2005, which was approximately $155.7 million in excess of the net worth we were required to maintain under the bank facilities in place at March 31, 2005. The long-term debt component of our capital structure at March 31, 2005 was 50.6 percent, our total debt leverage (long-term debt and short-term debt) was 52.0 percent, and our recourse leverage ratio was approximately 47.4 percent.

In addition, Enserco Energy Inc., our gas marketing unit, has a $150 million uncommitted, discretionary line of credit to provide support for the purchase of natural gas. As of March 31, 2005, we had a $3.0 million guarantee to the lender under this facility. At March 31, 2005, there were outstanding letters of credit issued under the facility of $99.8 million, with no borrowing balances outstanding on the facility.

Similarly, Black Hills Energy Resources, Inc., (BHER), our oil marketing unit, has a $25 million uncommitted, discretionary credit facility. The facility allows BHER to elect up to $40 million of available credit via notification to the bank at the beginning of each calendar quarter. This line of credit provides credit support for the purchases of crude oil by BHER. We provided no guarantee to the lender under this facility. At March 31, 2005, BHER had letters of credit outstanding of $17.7 million.

There were no changes in our corporate credit ratings during the first quarter of 2005.

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.

Upon closing of the agreement to sell our communications subsidiary, Black Hills FiberSystems, Inc., we expect to receive a cash payment of approximately $103 million. The transaction is expected to be completed on or before June 30, 2005. Proceeds from the transaction are expected to be used to reduce debt, to fund our capital expenditures or a combination of both.

There have been no other material changes in our forecasted changes in liquidity requirements from those reported in Item 7 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

Guarantees

During the first quarter of 2005, a $0.5 million guarantee related to payments under various transactions with Idaho Power Company was reduced to $0.3 million. At March 31, 2005, we had guarantees totaling $183.5 million in place.

Capital Requirements

During the three months ended March 31, 2005, capital expenditures were approximately $28.3 million for property, plant and equipment additions and $67.3 million for the acquisition of CLF&P (exclusive of debt assumed). We currently expect capital expenditures for the entire year 2005 to approximate $245 million, as detailed in Item 7 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

RISK FACTORS

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

Our sale of Black Hills FiberSystems, Inc. is subject to the receipt of approvals and consents from governmental authorities and third parties. If we do not complete the acquisition, we may continue to incur losses in our Communications segment.

On April 20, 2005, we entered into an agreement with PrairieWave Communications, Inc. for PrairieWave to acquire all the outstanding common stock of Black Hills FiberSystems, Inc. for approximately $103.0 million in cash. Completion of the sale is conditioned, among other things, upon the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, consent by the SDPUC and the receipt of consents, orders, approvals or clearance of certain other regulatory authorities and third parties. A failure to obtain satisfactory approvals, a substantial delay thereof or the imposition of unfavorable terms or conditions in the approvals could prevent us from consummating the sale and could cause us to continue to incur losses from our Communications segment, and could have other adverse effects on our business, financial condition or results of operation.

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

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

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

NEW ACCOUNTING PRONOUNCEMENTS

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

SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

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

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

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

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

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

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

• Our compliance with orders of the SEC under PUHCA related to our financing and investment authority, and related to transactions and cost allocation among our affiliated companies;

• Our ability to complete the sale of Black Hills FiberSystems, Inc., including the receipt of required approvals and consents and the timing thereof;

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

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

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

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

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

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

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

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

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

• Weather and other natural phenomena;

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

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

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

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

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

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

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

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

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Trading Activities

The following table is a required disclosure and provides a reconciliation of the activity in energy trading contracts that meet the definition of a derivative under SFAS 133 and that were marked-to-market during the three months ended March 31, 2005 (in thousands):

Total fair value of natural gas marketing positions marked-to-market at December 31, 2004	$	(930)^(a)
Net cash settled during the quarter on positions that existed at December 31, 2004		541
Change in fair value due to change in techniques and assumptions		—
Unrealized loss on new positions entered during the quarter and still existing at March 31, 2005		(4,535)
Realized gain on positions that existed at December 31, 2004 and were settled during the quarter		355
Unrealized loss on positions that existed at December 31, 2004 and still exist at March 31, 2005		(29)

Total fair value of natural gas marketing positions net assets at March 31, 2005	$	(4,598)^(a)

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

	March 31, 2005			December 31, 2004
Net derivative assets/(liabilities)	$	(9,360	)	$	8,082
Fair value adjustment recorded in material,
supplies and fuel		4,762			(9,012	)

	$	(4,598	)	$	(930	)

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

At March 31, 2005, we had a mark to fair value unrealized loss of $(4.6) million for our natural gas marketing activities, with $(4.3) million of this amount current. The sources of fair value measurements were as follows (in thousands):

	Maturities
Source of Fair Value	Less than 1 year		1 – 2 years		Total Fair Value

Actively quoted (i.e., exchange-traded) prices	$	2,067	$	157	$	2,224
Prices provided by other external sources		(6,391)		(431)		(6,822)
Modeled		—		—		—

Total	$	(4,324)	$	(274)	$	(4,598)

The following table presents a reconciliation of our March 31, 2005 natural gas marketing positions recorded at fair value under generally accepted accounting principles (GAAP) to a non-GAAP measure of the fair value of our natural gas forward book wherein all forward trading positions are marked-to-market (in thousands). The approach used in determining the non-GAAP measure is consistent with our previous accounting methods under EITF 98-10. As part of our GAAP fair value calculations we include a “Liquidity Reserve” to reflect a liquidation scenario on the balance sheet date. We have added back this liquidity reserve in the non-GAAP presentation below as we anticipate holding our natural gas contracts until their settlement and therefore not incur the impact of the bid/ask spread in our realized gross margin.

Fair value of our natural gas marketing positions marked-to-market in accordance with GAAP
(see footnote (a) above)	$	(4,598)
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		4,359

Fair value of all forward positions (Non-GAAP)		(239)

“Liquidity Reserve” included in GAAP marked-to-market fair value (b)		2,723

Fair value of all forward positions excluding the “Liquidity Reserve” (Non-GAAP)	$	2,484

(b)

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

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

Activities Other Than Trading

The Company has entered into agreements to hedge a portion of its estimated 2005 and 2006 natural gas and crude oil production. The hedge agreements in place at March 31, 2005 are as follows:

Natural Gas

Location	Term	Volume (Mmbtu/day)	Price

San Juan El Paso	04/05 – 10/05	2,500	$	5.30
San Juan El Paso	04/05 – 10/05	5,000	$	5.40
San Juan El Paso	04/05 – 10/05	2,500	$	6.04
San Juan El Paso	11/05 – 03/06	2,500	$	7.08

Crude Oil

Location	Term	Volume (barrels/month)	Price

NYMEX	Calendar 2005	10,000	$	27.90
NYMEX	Calendar 2005	10,000	$	34.08
NYMEX	Calendar 2006	10,000	$	41.00

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, 2005. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.

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

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

Other than changes resulting from our acquisition of CLF&P, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

BLACK HILLS CORPORATION

Part II – Other Information

Item 1.

Legal Proceedings

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

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities

None

Share Repurchases

					(d) Maximum
					Number (or
				(c) Total Number	Approximate Dollar
				of Shares	Value) of Shares
				Purchased as	That May Yet Be
	(a) Total	(b) Average		Part of Publicly	Purchased Under
	Number of	Price Paid		Announced Plans	the Plans
Period	Shares Purchased	per Share		or Programs	or Programs

January 1, 2005 – January 31, 2005	—	$	—	—		—

February 1, 2005 – February 28, 2005	—	$	—	—		—

March 1, 2005 – March 31, 2005	287⁽¹⁾	$	32.03	—		—

Total	287	$	32.03	—		—

___________________________

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

Item 6.

Exhibits

(a)

Exhibits–

Exhibit 10.1	Credit Agreement, dated as of May 5, 2005 among Black Hills Corporation, a South Dakota corporation ("Borrower"), the financial institutions from time to time party hereto (each a "Bank," and collectively the "Banks"), U.S. Bank, National Association, in its capacity as a co-syndication agent for the Banks (in such capacity, a "Co-Syndication Agent"), Union Bank of California, N.A., in its capacity as a Co-Syndication Agent, BANK OF AMERICA, N.A., in its capacity as a co-documentation agent for the Banks (in such capacity, a "Co-Documentation Agent"), BANK OF MONTREAL dba HARRIS NESBITT, as Co-Documentation Agent, and ABN AMRO Bank N.V. in its capacity as agent for the Banks hereunder (in such capacity, the "Administrative Agent").
Exhibit 31.1	Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 31.2	Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

BLACK HILLS CORPORATION

Signatures

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

	BLACK HILLS CORPORATION


	/s/ David R. Emery
	David R. Emery, President and
	Chief Executive Officer


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

Dated: May 10, 2005

EXHIBIT INDEX

Exhibit Number	Description
Exhibit 10.1	Credit Agreement, dated as of May 5, 2005 among Black Hills Corporation, a South Dakota corporation ("Borrower"), the financial institutions from time to time party hereto (each a "Bank," and collectively the "Banks"), U.S. Bank, National Association, in its capacity as a co-syndication agent for the Banks (in such capacity, a "Co-Syndication Agent"), Union Bank of California, N.A., in its capacity as a Co-Syndication Agent, BANK OF AMERICA, N.A., in its capacity as a co-documentation agent for the Banks (in such capacity, a "Co-Documentation Agent"), BANK OF MONTREAL dba HARRIS NESBITT, as Co-Documentation Agent, and ABN AMRO Bank N.V. in its capacity as agent for the Banks hereunder (in such capacity, the "Administrative Agent").

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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Black Hills (BKH) 10-Q2005 Q1 Quarterly report

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