Black Hills (BKH) 10-Q 2005 Q3 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 September 30, 2005.

OR

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

For the transition period from __________ to __________.

Commission File Number 001-31303

Black Hills Corporation
Incorporated in South Dakota	IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

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

Yes x No o

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

Yes x No o

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

Yes o No x

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

Class	Outstanding at October 31, 2005
Common stock, $1.00 par value	33,126,894 shares

TABLE OF CONTENTS

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income –
	Three and Nine Months Ended September 30, 2005 and 2004	3
	Condensed Consolidated Balance Sheets –
	September 30, 2005, December 31, 2004 and September 30, 2004	4
	Condensed Consolidated Statements of Cash Flows –
	Nine Months Ended September 30, 2005 and 2004	5
	Notes to Condensed Consolidated Financial Statements	6-25
Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	26-46
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	47-49
Item 4.	Controls and Procedures	49
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	50
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 6.	Exhibits	51
	Signatures	52
	Exhibit Index	53

2

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands, except per share amounts)
Operating revenues	$	373,011	$	270,159	$	978,473	$	804,968
Operating expenses:
Fuel and purchased power		271,377		175,833		667,833		530,839
Operations and maintenance		18,771		17,668		58,890		57,860
Administrative and general		22,867		14,479		63,805		44,886
Depreciation, depletion and amortization		22,333		18,548		63,194		55,438
Taxes, other than income taxes		8,958		5,324		25,778		20,923
Project development cost write-off		8,931		—		9,495		—
Impairment of long-lived assets		50,279		—		50,279		—
		403,516		231,852		939,274		709,946
Operating (loss) income		(30,505)		38,307		39,199		95,022
Other income (expense):
Interest expense		(11,089)		(11,146)		(36,422)		(36,345)
Interest income		365		339		1,393		1,072
Other income, net		139		112		819		514
		(10,585)		(10,695)		(34,210)		(34,759)
(Loss) income from continuing operations before equity in
earnings (losses) of unconsolidated subsidiaries, minority
interest and income taxes		(41,090)		27,612		4,989		60,263
Equity in earnings (losses) of unconsolidated subsidiaries		3,434		285		7,788		(723)
Minority interest		(74)		(48)		(199)		(134)
Income tax benefit (expense)		14,080		(9,245)		(3,436)		(19,303)
(Loss) income from continuing operations		(23,650)		18,604		9,142		40,103
Loss from discontinued operations, net of taxes		(253)		(1,424)		(2,335)		(1,622)
Net (loss) income		(23,903)		17,180		6,807		38,481
Preferred stock dividends		—		(78)		(159)		(244)
Net (loss) income available for common stock	$	(23,903)	$	17,102	$	6,648	$	38,237
Weighted average common shares outstanding:
Basic		32,967		32,420		32,660		32,372
Diluted		32,967		32,913		33,100		32,885
(Loss) earnings per share:
Basic–
Continuing operations	$	(0.72)	$	0.57	$	0.27	$	1.23
Discontinued operations		(0.01)		(0.04)		(0.07)		(0.05)
Total	$	(0.73)	$	0.53	$	0.20	$	1.18
Diluted–
Continuing operations	$	(0.72)	$	0.56	$	0.27	$	1.22
Discontinued operations		(0.01)		(0.04)		(0.07)		(0.05)
Total	$	(0.73)	$	0.52	$	0.20	$	1.17
Dividends paid per share of common stock	$	0.32	$	0.31	$	0.96	$	0.93

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

3

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

	September 30,		December 31,		September 30,
	2005		2004		2004
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	52,970	$	64,506	$	79,939
Restricted cash		700		3,069		—
Receivables (net of allowance for doubtful accounts of $4,317; $4,196 and $6,841, respectively)		318,918		251,945		197,243
Materials, supplies and fuel		184,548		88,475		121,342
Derivative assets		166,668		47,977		36,271
Prepaid income taxes		—		3,978		4,241
Deferred income taxes		6,839		4,237		4,085
Other assets		6,869		7,120		5,500
Assets of discontinued operations		—		117,861		119,941
		737,512		589,168		568,562
Investments		24,906		24,436		23,900
Property, plant and equipment		1,927,324		1,805,768		1,783,274
Less accumulated depreciation and depletion		(514,195)		(468,840)		(448,756)
		1,413,129		1,336,928		1,334,518
Other assets:
Derivative assets		6,454		593		625
Goodwill		30,144		30,144		30,144
Intangible assets (net of accumulated amortization of $22,715; $21,744 and $20,910, respectively)		28,617		36,688		37,521
Other		47,520		38,206		36,265
		112,735		105,631		104,555
	$	2,288,282	$	2,056,163	$	2,031,535
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	269,341	$	196,018	$	172,257
Accrued liabilities		78,048		63,795		53,910
Derivative liabilities		248,425		43,206		57,288
Notes payable		42,000		24,000		—
Current maturities of long-term debt		11,690		16,166		61,016
Accrued income taxes		15,553		7,799		6,839
Liabilities of discontinued operations		—		7,679		7,249
		665,057		358,663		358,559
Long-term debt, net of current maturities		672,770		733,581		736,959
Deferred credits and other liabilities:
Deferred income taxes		131,816		159,623		145,436
Derivative liabilities		7,828		206		1,860
Other		90,870		63,490		62,970
		230,514		223,319		210,266
Minority interest in subsidiaries		5,034		4,835		4,782
Stockholders’ equity:
Preferred stock – no par Series 2000-A; 0; 21,500 and 21,500 shares authorized, respectively; 0; 6,839 and 6,839 issued and outstanding, respectively		—		7,167		7,167
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized; Issued 33,200,699;
32,595,285 and 32,586,929 shares, respectively		33,201		32,595		32,587
Additional paid-in capital		403,822		384,439		383,786
Retained earnings		297,204		322,009		312,661
Treasury stock at cost – 73,805; 117,567 and 117,778 shares, respectively		(1,909)		(2,838)		(2,842)
Accumulated other comprehensive loss		(17,411)		(7,607)		(12,390)
		714,907		728,598		713,802
Total stockholders’ equity		714,907		735,765		720,969
	$	2,288,282	$	2,056,163	$	2,031,535

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

4

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(unaudited)

	Nine Months Ended
	September 30,
	2005		2004
	(in thousands)
Operating activities:
Net income available for common	$	6,648		$	38,237
Adjustments to reconcile net income available for common to net cash provided by operating activities:
Loss from discontinued operations		2,335			1,622
Change in provision for valuation allowances		(1,340)			70
Depreciation, depletion and amortization		63,194			55,438
Impairment of long-lived asset		50,279			—
Write-off of project development costs		5,037			—
Net change in derivative assets and liabilities		2,894			3,250
Deferred income taxes		(17,440)			21,144
Distributed earnings in associated companies		1,954			3,448
Minority interest		199			134
Change in operating assets and liabilities, net of acquisition-
Materials, supplies and fuel		(22,685)			(69,106)
Accounts receivable and other current assets		(48,434)			18,140
Accounts payable and other current liabilities		75,381			2,486
Other operating activities		10,936			3,755
		128,958			78,618
Investing activities:
Property, plant and equipment additions		(88,752)			(59,681)
Proceeds from sale of assets		103,010			—
Payment for acquisition, net of cash acquired		(67,331)			—
Other investing activities		5,615			3,144
		(47,458)			(56,537)
Financing activities:
Dividends paid		(31,453)			(30,143)
Common stock issued		12,822			3,678
Increase in short-term borrowings, net		18,000			—
Long-term debt – repayments		(91,675)			(88,143)
Other financing activities		(730)			(291)
		(93,036)			(114,899)
Decrease in cash and cash equivalents		(11,536)			(92,818)
Cash and cash equivalents:
Beginning of period		64,506			172,757
End of period	$	52,970		$	79,939
Supplemental disclosure of cash flow information:
Cash paid during the period for-
Interest	$	31,551		$	35,461
Net income taxes paid (refunded)	$	2,403		$	(18,637)
Common stock issued in conversion of preferred shares	$	7,167		$	976

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

5

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

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

(1)  MANAGEMENT’S STATEMENT

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

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

(2)  RECLASSIFICATIONS

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

(3)  STOCK-BASED COMPENSATION

At September 30, 2005, the Company had one stock-based employee compensation plan under which it can grant stock options to its employees and three prior plans with stock options outstanding. The Company accounts for these plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees (APB 25),” and related interpretations. No employee compensation cost related to stock options is reflected in net income, as all options granted under these plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

6

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Net (loss) income available for common stock,
as reported	$	(23,903)	$	17,102	$	6,648	$	38,237
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax effects		(126)		(176)		(389)		(496)
Pro forma net (loss) income available for
common stock	$	(24,029)	$	16,926	$	6,259	$	37,741
(Losses) earnings per share:
As reported–
Basic
Continuing operations	$	(0.72)	$	0.57	$	0.27	$	1.23
Discontinued operations		(0.01)		(0.04)		(0.07)		(0.05)
Total	$	(0.73)	$	0.53	$	0.20	$	1.18
Diluted
Continuing operations	$	(0.72)	$	0.56	$	0.27	$	1.22
Discontinued operations		(0.01)		(0.04)		(0.07)		(0.05)
Total	$	(0.73)	$	0.52	$	0.20	$	1.17
Pro forma–
Basic
Continuing operations	$	(0.72)	$	0.57	$	0.26	$	1.22
Discontinued operations		(0.01)		(0.04)		(0.07)		(0.05)
Total	$	(0.73)	$	0.53	$	0.19	$	1.17
Diluted
Continuing operations	$	(0.72)	$	0.55	$	0.26	$	1.21
Discontinued operations		(0.01)		(0.04)		(0.07)		(0.05)
Total	$	(0.73)	$	0.51	$	0.19	$	1.16

7

(4)   RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS No. 123 (Revised 2004)

In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (Revised 2004) “Share Based Payment” (SFAS 123-R). SFAS 123-R 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 SEC adopted a final rule amending the effective date of SFAS 123-R to the beginning of the Company’s next fiscal year 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) for stock options. The effect of adoption of SFAS 123-R will be to recognize compensation expense for the fair value of the stock options granted at the grant date. Had the Company applied the fair value recognition provisions of SFAS 123-R during those periods, 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 September 30, 2005 and 2004, respectively, and $0.4 million and $0.5 million for the nine month periods ending September 30, 2005 and 2004, respectively.

FIN 47

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

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

EITF Issue No. 04-6

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

8

EITF Issue No. 04-13

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

EITF 04-13 is effective for new arrangements entered into in reporting periods beginning after March 16, 2006 and to all inventory transactions that are completed after December 15, 2006, for arrangements entered into prior to March 15, 2006.

The Company’s crude oil marketing contracts are currently 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 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 Company is currently evaluating the impact of EITF 04-13 and, while a net presentation of this issue would reduce both the Company’s revenues and purchases, our net income would not be impacted.

Proposed Accounting Rules for Uncertain Tax Positions

On July 14, 2005, the FASB published an Exposure Draft of a proposed Interpretation, “Accounting for Uncertain Tax Positions”. The Exposure Draft would apply to all tax positions accounted for in accordance with FASB Statement No. 109, “Accounting for Income Taxes” and would establish specific criteria that must be met for benefits of an uncertain tax position to be recognized in the financial statements. Management is currently evaluating the potential impact the proposed Interpretation would have on the Company’s consolidated financial statements and will monitor the FASB’s progress towards finalizing this Exposure Draft. The proposed effective date is the first quarter of 2006, with the impact of adoption to be reported as a cumulative effect of an accounting change.

(5)  IMPAIRMENT OF LONG-LIVED ASSETS AND CAPITALIZED DEVELOPMENT COSTS

Due to a significant increase in the long-term forecasts for natural gas prices during the third quarter of 2005, the operation of the Company’s Las Vegas I gas-fired power plant (Las Vegas I) became uneconomic. Accordingly, the Company assessed the recoverability of the carrying value of Las Vegas I in accordance with the provisions of SFAS No. 144 “Accounting for the Impairment of Long-lived Assets” (SFAS 144).

Las Vegas I is a 53 megawatt, natural gas-fired, combined-cycle turbine operating under a contract as a qualifying facility as defined by the Public Utility Regulatory Policies Act of 1978. Under the contract, which extends through 2024, the Company sells capacity and energy to Nevada Power Company. Fuel requirements for the plant are not externally hedged and have been provided at market index prices under a long-term supply arrangement. While the Company’s oil and gas exploration and production operation produces gas sufficient to cover the plant’s fuel requirements thus providing an internal hedge, SFAS 144 requires the determination of asset impairment at each asset group which has separately identifiable cash flows.

9

The carrying value of the assets tested for impairment was $60.3 million. The assessment resulted in an impairment charge of $50.3 million to write down the related Property, plant and equipment by $44.7 million, net of accumulated depreciation of $11.1 million, and intangible assets by $5.6 million, net of accumulated amortization of $1.5 million. This charge reflects the amount by which the carrying value of the facility exceeded its estimated fair value determined by its estimated future discounted cash flows. This charge is included as a component of “Operating expenses” on the accompanying Condensed Consolidated Statements of Income. Operating results from Las Vegas I are included in the Power Generation Segment.

In addition, during the three-month period ended September 30, 2005, the Company recorded an $8.9 million pre-tax charge for the write-off and expensing of certain capitalized costs for various energy development projects determined less likely to advance, and costs related to unsuccessfully bid projects during the third quarter of 2005. The Company determined these projects were less likely to advance, due to reduced economic feasibility of gas-fired power generation in the expected sustained high-priced natural gas environment, increased expectations of reliance on renewable or coal-fired generation, and a perceived preference of utilities in certain regions to acquire existing merchant generation at significant discounts as an alternative to entering into contracts for capacity and energy from new generation. These costs had been capitalized as management believed it was probable that such costs would ultimately result in acquisition or construction of the projects. This charge is included as a component of “Operating expenses” on the accompanying Condensed Consolidated Statements of Income. For segment reporting the development costs are included in Corporate results.

(6)  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):

	September 30,		December 31,		September 30,
Major Classification	2005		2004		2004
Materials and supplies	$	25,100	$	21,404	$	20,702
Fuel		8,080		2,211		1,290
Gas and oil held by energy marketing*		151,368		64,860		99,350
Total materials, supplies and fuel	$	184,548	$	88,475	$	121,342

___________________________

* As of September 30, 2005, December 31, 2004 and September 30, 2004, market adjustments related to gas and oil held by energy marketing and recorded in inventory were $61.0 million, $(9.0) million and $10.4 million, respectively (see Note 16 for further discussion of natural gas marketing trading activities).

The inventory held by our natural gas marketing company is in the form of storage agreements. The gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future. A substantial majority of the gas was economically hedged at the time of purchase either through a fixed price physical or financial forward sale. Most of this natural gas is currently expected to flow out of inventory in the fourth quarter of 2005 and the first quarter of 2006. If changing market conditions make it economically advantageous to do so, the duration of holding significant amounts of natural gas in inventory could be extended.

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(7)   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		9/30/05
Oil and gas	$	7,942	$	—	$	—	$	414	$	—	$	8,356
Coal mining		15,867		368		(61)		453		—		16,627
Total	$	23,809	$	368	$	(61)	$	867	$	—	$	24,983

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

NET

The Company’s electric and gas subsidiary, Cheyenne Light, Fuel & Power (CLF&P), recovers purchased power and natural gas costs from customers through an electric cost adjustment (ECA) and gas cost adjustment (GCA) mechanism. Each year CLF&P files with the Wyoming Public Service Commission (WPSC) an ECA, effective January 1, and a GCA, effective October 1, to be included in tariff rates for the following year. The ECA and GCA are based on forecasts of the upcoming year’s energy costs and recovery of prior year unrecovered costs. To the extent that energy costs are under recovered or over recovered during the year, they are recorded as a regulatory deferred asset or liability, respectively. These deferred energy balances are interest bearing. As of September 30, 2005, the Company had a deferred energy asset balance of approximately $4.5 million, which is included in “Other” under “Other assets” on the accompanying Condensed Consolidated Balance Sheet.

(9) 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 September 30, 2005	Three Months			Nine Months
			Average			Average
	Loss		Shares	Income		Shares
(Loss) income from continuing operations	$	(23,650)		$	9,142
Less: preferred stock dividends		—			(159)
Basic – available for common shareholders		(23,650)	32,967		8,983	32,660
Dilutive effect of:
Stock options		—	—		—	164
Estimated contingent shares issuable for prior acquisition		—	—		—	158
Others		—	—		—	118
Diluted – available for common shareholders	$	(23,650)	32,967	$	8,983	33,100

11

Period ended September 30, 2004	Three Months			Nine Months
			Average			Average
	Income		Shares	Income		Shares
Income from continuing operations	$	18,604		$	40,103
Less: preferred stock dividends		(78)			(244)
Basic – available for common shareholders		18,526	32,420		39,859	32,372
Dilutive effect of:
Stock options		—	75		—	98
Convertible preferred stock		78	195		244	195
Estimated contingent shares issuable for prior acquisition		—	158		—	158
Others		—	65		—	62
Diluted – available for common shareholders	$	18,604	32,913	$	40,103	32,885

(10)  COMPREHENSIVE INCOME

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

(in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Net (loss) income	$	(23,903)	$	17,180	$	6,807	$	38,481
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives designated
as cash flow hedges		(11,095)		(4,860)		(15,260)		(9,132)
Reclassification adjustments on cash flow hedges
settled and included in net income		3,262		3,376		5,441		7,966
Unrealized gain (loss) on available-for-sale
securities		—		(47)		15		(101)
Comprehensive (loss) income	$	(31,736)	$	15,649	$	(2,997)	$	37,214

(11)  CHANGES IN COMMON AND PREFERRED STOCK

Other than the following transactions, the Company has no other material changes in its common and preferred stock, as reported in Notes 10 and 11 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K.

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

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

Grants under this performance share plan are in addition to grants under two other performance share plans awarded March 1, 2004. Compensation expense recognized for all of the performance share awards for the three and nine months ended September 30, 2005 was $0.6 million and $1.5 million, respectively.

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

•             398,859 stock options were exercised at a weighted-average exercise price of $24.99 per share.

•             The Company acquired 12,588 shares of treasury stock related to forfeiture of unvested restricted stock and the share withholding provisions of the Restricted Stock Plan for the payment of taxes associated with the vesting of shares of restricted stock for certain officers and key employees.

•             The Company granted 44,286 restricted common shares and 2,594 restricted stock units during the first nine months of 2005. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $1.4 million will be recognized over the three-year vesting period.

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

•             6,839 shares of Preferred Stock Series 2000-A were converted into 195,599 shares of common stock at the conversion price of $35.00 per share. No shares of preferred stock remain outstanding after this transaction.

(12)  CHANGES IN LONG-TERM DEBT

In addition to repayments of scheduled maturities, the Company had the following changes in long-term debt.

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

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

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(13)   GUARANTEES

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

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

	Outstanding at	Year
Nature of Guarantee	September 30, 2005	Expiring
Guarantee payments under the Las Vegas Cogen I Power		Upon 5 days
Purchase 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 of interest rate swap transaction with Union Bank
of California	1,240	2006
Guarantee payments of Black Hills Power under various
transactions with Idaho Power Company	250	2006
Guarantee obligations under the Wygen Plant Lease	111,018	2008
Guarantee payment and performance under credit agreements
for two combustion turbines	26,857	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
	$183,115

During the third quarter of 2005, the Company entered into a $1.2 million guarantee for payments related to an interest rate swap transaction between Black Hills Fountain Valley and Union Bank of California. At September 30, 2005, we had a liability included on the Condensed Consolidated Balance Sheet of $0.1 million associated with this swap.

(14)  EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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

14

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Service cost	$	576	$	443	$	1,728	$	1,329
Interest cost		995		909		2,985		2,727
Expected return on plan assets		(1,157)		(1,129)		(3,471)		(3,387)
Amortization of prior service cost		54		58		162		174
Amortization of net loss		296		375		888		1,125
Net periodic benefit cost	$	764	$	656	$	2,292	$	1,968

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

Supplemental Nonqualified Defined Benefit Plans

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Service cost	$	86	$	134	$	258	$	402
Interest cost		252		241		756		723
Amortization of prior service cost		2		2		6		6
Amortization of net loss		157		187		471		561
Net periodic benefit cost	$	497	$	564	$	1,491	$	1,692

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

Non-pension Defined Benefit Postretirement Healthcare Plans

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

15

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Service cost	$	185	$	140	$	555	$	420
Interest cost		232		166		696		498
Amortization of net transition obligation		37		37		111		111
Amortization of prior service cost		(6)		(6)		(18)		(18)
Amortization of net loss		25		47		75		141
Net periodic benefit cost	$	473	$	384	$	1,419	$	1,152

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

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

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of September 30, 2005, substantially all of the Company’s operations and assets are located within the United States. On June 30, 2005, the Company completed the sale of its subsidiary, Black Hills FiberSystems, Inc., which operated as the Company’s Communications segment (see Note 19). The financial information of the Communications segment has been reclassified into Discontinued operations on the accompanying condensed consolidated financial statements.

With the sale of the communications segment, the Company now conducts its operations through the following six reporting segments: Wholesale Energy group, consisting of the following segments: Coal mining, which engages in the mining and sale of coal from its mine near Gillette, Wyoming; Oil and gas, which produces, explores and operates oil and gas interests located in the Rocky Mountain region, Texas, California and other states; Energy marketing and transportation, which markets natural gas, oil and related services to customers in the Midwest, Southwest, Rocky Mountain, West Coast and Northwest regions and transports crude oil in Texas; and Power generation, which produces and sells power and capacity to wholesale customers with plants concentrated in Colorado, Nevada, Wyoming and California; and Retail Services group consisting of the following segments: Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Electric and gas utility, acquired January 21, 2005, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity.

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

16

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

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Three Month Period Ended
September 30, 2005
Wholesale energy:
Coal mining	$	5,537	$	2,945	$	1,643
Oil and gas		22,800		7		5,109
Energy marketing and transportation		227,401		—		(1,072)
Power generation		43,076		—		(24,587)*
Retail services:
Electric utility		48,336		938		1,888
Electric and gas utility		23,501		—		(127)
Corporate		93		—		(6,504)
Intersegment eliminations		—		(1,623)		—
Total	$	370,744	$	2,267	$	(23,650)

__________________________

*Loss from continuing operations includes a $32.7 million after-tax impairment charge for Las Vegas I.

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Three Month Period Ended
September 30, 2004
Wholesale energy:
Coal mining	$	3,776	$	3,256	$	2,537
Oil and gas		13,578		88		2,765
Energy marketing and transportation		159,694		—		670
Power generation		42,980		—		7,192
Retail services:
Electric utility		47,405		516		5,860
Corporate		163		310		(420)
Intersegment eliminations		—		(1,607)		—
Total	$	267,596	$	2,563	$	18,604

17

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Nine Month Period Ended
September 30, 2005
Wholesale energy:
Coal mining	$	15,717	$	9,144	$	4,860
Oil and gas		61,504		7		14,346
Energy marketing and transportation		560,853		—		4,544
Power generation		121,366		—		(14,601)*
Retail services:
Electric utility		133,295		1,387		9,619
Electric and gas utility		78,034		—		1,028
Corporate		647		—		(10,654)
Intersegment eliminations		—		(3,481)		—
Total	$	971,416	$	7,057	$	9,142

__________________________

*Loss from continuing operations includes a $32.7 million after-tax impairment charge for Las Vegas I.

	External		Inter-segment		Income (loss) from
	Operating Revenues		Operating Revenues		Continuing Operations
Nine Month Period Ended
September 30, 2004
Wholesale energy:
Coal mining	$	14,093	$	9,210	$	5,648
Oil and gas		40,776*		260		7,215
Energy marketing and transportation		495,024		—		6,245
Power generation		118,472		—		10,347
Retail services:
Electric utility		128,819		558		12,712
Corporate		630		946		(2,060)
Intersegment eliminations		—		(3,820)		(4)
Total	$	797,814	$	7,154	$	40,103

__________________________

*Includes a $(0.5) million revenue accrual correction.

Other than the impairment of the long-lived assets of Las Vegas I (see Note 5), the acquisition and consolidation of CLF&P into the Company’s Condensed Consolidated Balance Sheet (see Note 18), and the reclassification of its Communications segment to Discontinued operations and subsequent sale completed on June 30, 2005 (see Note 19), the Company had no material changes in the assets of its reporting segments, as reported in Note 23 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

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(16)   RISK MANAGEMENT ACTIVITIES

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

Trading Activities

Natural Gas Marketing

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

(in thousands of MMbtus)	September 30, 2005			December 31, 2004			September 30, 2004
			Latest			Latest			Latest
		Notional	Expiration		Notional	Expiration		Notional	Expiration
		Amounts	(months)		Amounts	(months)		Amounts	(months)
Natural gas basis swaps purchased		51,155	18		24,942	15		28,793	18
Natural gas basis swaps sold		60,522	18		27,145	15		30,548	18
Natural gas fixed-for-float
swaps purchased		19,979	26		27,274	15		22,083	12
Natural gas fixed-for-float
swaps sold		29,576	26		32,206	12		26,090	15
Natural gas physical purchases		62,020	37		64,799	15		64,395	18
Natural gas physical sales		110,341	49		95,996	58		114,031	60
Natural gas options purchased		12,725	24		9,643	33		7,156	36
Natural gas options sold		12,725	24		9,613	33		6,335	36
(thousands of U.S. dollars)
Canadian dollars purchased	$	29,700	1	$	10,800	1	$	—	—
Canadian dollars sold	$	37,600	8	$	38,000	4	$	26,000	6

Derivatives and certain natural gas marketing activities were marked to fair value on September 30, 2005, December 31, 2004 and September 30, 2004, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows (in thousands):

	Current		Non-current		Current		Non-current
	Derivative		Derivative		Derivative		Derivative		Unrealized
	Assets		Assets		Liabilities		Liabilities		Gain (Loss)
September 30, 2005	$	166,596	$	6,454	$	230,699	$	6,273	$	(63,922)
December 31, 2004	$	46,177	$	286	$	38,375	$	6	$	8,082
September 30, 2004	$	36,244	$	625	$	48,569	$	329	$	(12,029)

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 September 30, 2005, December 31, 2004 and September 30, 2004, the market adjustments recorded in inventory were $61.0 million, $(9.0) million and $10.4 million, respectively.

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Activities Other Than Trading

Crude Oil Marketing

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

	September 30, 2005		December 31, 2004		September 30, 2004
		Maximum		Maximum		Maximum
	Notional	Term in	Notional	Term in	Notional	Term in
(in thousands of barrels)	Amounts	Years	Amounts	Years	Amounts	Years
Crude oil purchased	2,365	0.5	1,669	1.0	1,892	0.5
Crude oil sold	2,442	0.5	1,651	1.0	1,880	0.5

The Company’s crude oil marketing contracts are accounted for under the accrual method of accounting. Settled contract amounts are currently 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.

Oil and Gas Exploration and Production

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

											Pre-tax
											Accumulated
		Maximum	Current		Non-current		Current		Non-current		Other
		Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Pre-tax
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
September 30, 2005
Crude oil swaps	300,000	1.00	$	—	$	—	$	4,448	$	1,177	$	(5,607)	$	(18)
Natural gas swaps	2,502,500	0.50		—		—		11,829		378		(12,207)		—
			$	—	$	—	$	16,277	$	1,555	$	(17,814)	$	(18)
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)
September 30, 2004
Crude oil swaps	330,000	1.00	$	—	$	—	$	4,991	$	806	$	(5,748)	$	(49)
Natural gas swaps	2,499,000	0.50		27		—		1,891		74		(1,938)		—
			$	27	$	—	$	6,882	$	880	$	(7,686)	$	(49)

________________________

*crude in barrels, gas in MMbtu’s

Based on September 30, 2005 market prices, a $16.3 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 September 30, 2005 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

20

Electric Utility

On September 30, 2005, the Company had the following swaps and related balances (in thousands):

Pre-tax

Accumulated

Maximum

Current

Non-current

Current

Non-current

Other

Unrealized

Terms in

Derivative

Derivative

Derivative

Derivative

Comprehensive

Gain

Notional*

Years

Assets

Assets

Liabilities

Liabilities

Income (Loss)

(Loss)

September 30, 2005

Natural gas swaps

425,000

0.50

$

—

$

—

$

1,246

$

—

$

(759)

$

(487)

________________________

*gas in MMbtu’s

Based on September 30, 2005 market prices, a $0.8 million loss would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. These estimated realized losses for the next twelve months were calculated using September 30, 2005 market prices. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

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 September 30, 2005, the market adjustments recorded in inventory were $0.5 million.

Financing Activities

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

			Weighted										Pre-tax
			Average										Accumulated
	Current		Fixed	Maximum	Current		Non-current		Current		Non-current		Other		Pre-tax
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Income
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
September 30, 2005
Swaps on project
and other financings	$	113,000	4.22%	1.00	$	72	$	—	$	203	$	—	$	9	$	(140)
December 31, 2004
Swaps on project
financing	$	113,000	4.22%	1.75	$	60	$	—	$	1,226	$	200	$	(1,366)	$	—
September 30, 2004
Swaps on project
financing	$	113,000	4.22%	2.00	$	—	$	—	$	1,837	$	651	$	(2,488)	$	—

Based on September 30, 2005 market interest rates and balances, approximately $0.1 million would be realized and reported in pre-tax earnings as additional interest expense during the next twelve months. Estimated and realized amounts will likely change during the next twelve months as market interest rates change.

21

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

(17)  LEGAL PROCEEDINGS

The Company’s natural gas marketing subsidiary, Enserco Energy, Inc., has been one of several defendants in the class action entitled In re Natural Gas Commodity Litigation, 03 CV 6186 (VM), United States District Court, Southern District of New York. The class action was initiated in 2003 and asserts that defendants manipulated natural gas futures contracts through false reporting of prices and volumes. Specific allegations include claims that former traders at Enserco reported false price and volume information to trade publications. Although the Company believes that the Class Plaintiffs present a flawed theory to recover actual damages, events in the third quarter, including settlements by other defendant companies and mounting joint defense costs, prompted the Company to seek a settlement of claims made against it. Accordingly, during the third quarter of 2005, the Company accrued for a pre-tax charge of approximately $2.5 million, to reflect the tentative settlement.

In addition, the Company is subject to various legal proceedings, claims and litigation as described in Note 21 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K. Other than noted above, 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 nine months of 2005.

(18)  ACQUISITION

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

22

This acquisition has been accounted for under the purchase method of accounting, and accordingly, the purchase price has been allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and liabilities assumed as of the date of acquisition. The estimated purchase price allocations are subject to adjustment, generally within one year of the date of acquisition. Allocation of the purchase price (as revised for the working capital adjustment described above) is as follows (in thousands):

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

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

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				Nine Month Period Ended
	September 30, 2005		September 30, 2004		September 30, 2005		September 30, 2004
Operating revenues	$	373,011	$	289,881	$	987,651	$	873,366
(Loss) income from
continuing operations		(23,650)		18,946		9,321		41,720
Net (loss) income		(23,903)		17,522		6,986		40,098
Earnings per share –
Basic:
Continuing operations	$	(0.72)	$	0.58	$	0.28	$	1.28
Total	$	(0.73)	$	0.54	$	0.21	$	1.23
Diluted:
Continuing operations	$	(0.72)	$	0.58	$	0.28	$	1.27
Total	$	(0.73)	$	0.53	$	0.21	$	1.22

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.

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(19)   DISCONTINUED OPERATIONS

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

Communications Segment

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Operating revenues	$	—	$	9,455	$	21,877	$	29,329
Pre-tax income (loss) from discontinued
operations	$	—	$	(1,932)	$	3,978	$	(4,937)
Pre-tax loss on disposal		(255)		—		(7,490)		—
Income tax (expense) benefit		(14)		676		1,396		1,728
Net loss from discontinued operations	$	(269)	$	(1,256)	$	(2,116)	$	(3,209)

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

	December 31, 2004		September 30, 2004
Current assets	$	5,941	$	6,145
Property, plant and equipment, net		108,804		109,985
Other non-current assets		57		60
Current liabilities		(6,112)		(5,963)
Other non-current liabilities		(916)		(697)
Net assets	$	107,774	$	109,530

24

Sale of Pepperell Plant

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Pre-tax income (loss) from discontinued operations	$	68	$	(248)	$	(261)	$	(717)
Pre-tax loss on disposal		—		—		(39)		—
Income tax (expense) benefit		(52)		94		81		256
Net income (loss) from discontinued operations	$	16	$	(154)	$	(219)	$	(461)

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

	December 31,		September 30,
	2004		2004
Current assets	$	107	$	107
Property, plant and equipment		—		1,064
Non-current deferred tax asset		2,952		2,580
Other current liabilities		(167)		(130)
Non-current liabilities		(484)		(459)
Net assets of discontinued operations	$	2,408	$	3,162

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 (loss) income from the discontinued operations was as follows (in thousands):

	Three Months Ended		Nine Months Ended
	September 30, 2004		September 30, 2004
Pre-tax loss from discontinued operations	$	—	$	(40)
Pre-tax (loss) gain on disposal		(21)		3,208
Income tax benefit (expense)		7		(1,120)
Net (loss) income from discontinued operations	$	(14)	$	2,048

25

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

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

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

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

In June 2005, we sold our subsidiary, Black Hills FiberSystems, Inc., previously reported as our Communications segment. In April 2005, we also sold our Pepperell power plant, our last remaining power plant in the eastern region, which was previously reported in our Power generation segment. Prior period results have been reclassified to present the financial information as Discontinued operations.

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

26

Results of Operations

Consolidated Results

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
Revenues
Wholesale energy	$301,081	$222,591	$766,497	$675,519
Retail services	71,837	47,405	211,329	128,819
Corporate	93	163	647	630
	$373,011	$270,159	$978,473	$804,968
Income/(Loss) from Continuing Operations
Wholesale energy	$(18,907)	$13,164	$ 9,149	$29,455
Retail services	1,761	5,860	10,647	12,708
Corporate	(6,504)	(420)	(10,654)	(2,060)
	$(23,650)	$18,604	$ 9,142	$40,103

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

Discontinued operations for the three and nine months ended September 30, 2005 primarily represent operations and loss on sale of the Communications segment. Operations benefited from discontinuance of depreciation upon entering the definitive agreement to sell, but this reduced depreciation resulted in higher book value than originally anticipated and consequently resulted in a higher after-tax loss on sale than originally estimated. After-tax loss on sale was $4.7 million, or $0.14 per share. See Note 19 of Notes to Condensed Consolidated Financial Statements for further description of our discontinued operations.

On January 21, 2005, we completed the acquisition of Cheyenne Light, Fuel & Power Company (CLF&P), an electric and natural gas utility serving customers in Cheyenne, Wyoming and vicinity. The Company purchased all of the common stock of CLF&P, including the assumption of outstanding debt of approximately $24.6 million, for approximately $90.7 million. The results of operations of CLF&P have been included in the accompanying Condensed Consolidated Financial Statements from the date of acquisition.

Due to a significant increase in the long-term forecasts for natural gas prices during the third quarter of 2005, the operation of our Las Vegas I gas-fired power plant (Las Vegas I) became uneconomic. Accordingly, we assessed the recoverability of the carrying value of Las Vegas I in accordance with the provisions of SFAS No. 144 “Accounting for the Impairment of Long-lived Assets” (SFAS 144).

27

Las Vegas I is a 53 megawatt, natural gas-fired, combined-cycle turbine operating under a contract as a qualifying facility as defined by the Public Utility Regulatory Policies Act of 1978. Under the contract, which extends through 2024, we sell capacity and energy to Nevada Power Company. Fuel requirements for the plant are not externally hedged and have been provided at market index prices under a long-term supply arrangement. While our oil and gas exploration and production operation produces gas sufficient to cover the plant’s fuel requirements thus providing an internal hedge, SFAS 144 requires a determination of asset impairment at each asset group which has separately identifiable cash flows.

The carrying value of the assets tested for impairment was $60.3 million. The assessment resulted in an impairment charge of $50.3 million to write down the related Property, plant and equipment by $44.7 million, net of accumulated depreciation of $11.1 million, and intangible assets by $5.6 million, net of accumulated amortization of $1.5 million. This charge is included as a component of “Operating expenses” on the accompanying Condensed Consolidated Statements of Income. Operating results from Las Vegas I are included in the Power Generation segment.

In addition, we recorded an $8.9 million and $9.5 million pre-tax charge for the three and nine month periods ended September 30, 2005 respectively, for the write-off and expensing of certain capitalized costs for various energy development projects determined less likely to advance, and costs related to unsuccessfully bid projects during the third quarter of 2005. We determined these projects were less likely to advance, due to reduced economic feasibility of gas-fired power generation in the expected sustained high-priced natural gas environment, increased expectations of reliance on renewable or coal-fired generation, and a perceived preference of utilities in certain regions to acquire existing merchant generation at significant discounts as an alternative to entering into contracts for capacity and energy from new generation. These costs had been capitalized as management believed it was probable that such costs would ultimately result in acquisition or construction of the projects. This charge is included as a component of “Operating expenses” on the accompanying Condensed Consolidated Statements of Income. The development costs are included in results for the Corporate segment.

Our natural gas marketing subsidiary, Enserco Energy, Inc., has been a defendant in the class action entitled In re Natural Gas Commodity Litigation. The class action was initiated in 2003 and asserts that defendants manipulated natural gas futures contracts through false reporting of prices and volumes. Specific allegations include claims that former traders at Enserco reported false price and volume information to trade publications. Although we believe that the Class Plaintiffs present a flawed theory to recover actual damages, events in the third quarter, including settlements by other defendant companies and mounting joint defense costs, prompted us to seek a settlement of claims made against us. Accordingly, during the third quarter of 2005, we accrued approximately $2.5 million for purposes of settlement.

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004. Revenues for the three months ended September 30, 2005 increased 38 percent, or $102.9 million, compared to the same period in 2004. Increased revenues were primarily the result of the acquisition and consolidation of CLF&P and higher revenues from oil and gas sales as a result of increased production and higher average prices received and higher revenues from oil marketing primarily as a result of higher average prices received.

Operating expenses increased 74 percent, or $171.7 million, primarily due to the $50.3 million impairment charge from Las Vegas I, cost of operations of CLF&P, higher purchased power costs at our Electric utility, higher cost of oil marketing sales, the write-off and expensing of previously capitalized project development costs, increased administrative and general costs due to the recording of a litigation settlement accrual and higher compensation expense primarily due to increased incentive compensation accruals and increased legal fees.

28

Income from continuing operations decreased $42.3, million due primarily to the following:

•     a $31.8 million decrease in Power generation earnings, which includes the $32.7 million after-tax impairment charge at Las Vegas I;

•     a $1.7 million decrease in Energy marketing and transportation earnings, which includes a $1.6 million after-tax charge accrued for settlement of a class action litigation;

•     a $4.0 million decrease in Electric utility earnings which includes a $1.8 million after-tax charge of additional purchase power costs related to the NS II outage; and

•     a $6.1 million increase in corporate costs, primarily due to the write-off and expensing of various energy development projects; partially offset by

•     a $2.3 million increase in Oil and gas earnings due to stronger product prices and increased production.

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

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004. Revenues for the nine months ended September 30, 2005 increased 22 percent, or $173.5 million, compared to the same period in 2004. Increased revenues are primarily due to the acquisition and consolidation of CLF&P, higher revenues from oil and gas sales as a result of increased production and higher average prices received and higher revenues from oil marketing primarily as a result of higher average prices received.

Operating expenses increased 32 percent, or $229.3 million, primarily due to the $50.3 million impairment charge from Las Vegas I, cost of operations of CLF&P, increased purchased power costs at our Electric utility, higher cost of oil marketing sales, the write-off and expensing of previously capitalized project development costs and increased administrative and general costs. The increase in general and administrative costs was primarily due to the recording of a litigation settlement accrual and increased compensation expense primarily due to increased incentive compensation accruals and increased legal 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.

29

Income from continuing operations decreased 77 percent, or $31.0 million, primarily due to the following:

•     a $24.9 million decrease in Power generation earnings, which includes the $32.7 million after-tax impairment charge at Las Vegas I;

•     a $1.7 million decrease in Energy marketing and transportation earnings, which includes a $1.6 million after-tax charge accrued for settlement of a class action litigation;

•     a $3.1 million decrease in Electric utility earnings, which includes a $1.8 million after-tax charge of additional purchase power costs related to the NS II outage; and

•     an $8.6 million increase in corporate costs, primarily due to the write-off and expensing of various energy development projects; partially offset by

•     a $7.1 million increase in Oil and gas earnings due to stronger product prices and increased production.

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

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

Wholesale Energy Group

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Revenue:
Energy marketing and transportation	$	227,401	$	159,694	$	560,853	$	495,024
Power generation		43,076		42,980		121,366		118,472
Oil and gas		22,807		13,666		61,511		41,036*
Coal mining		8,482		7,032		24,861		23,303
Total revenue		301,766		223,372		768,591		677,835
Operating expenses		329,405**		197,614		742,898**		614,022
Operating (loss) income	$	(27,639)	$	25,758	$	25,693	$	63,813
(Loss) income from continuing
operations	$	(18,907)	$	13,164	$	9,149	$	29,455

___________________________

* Includes a $(0.5) million revenue accrual correction for the nine month period ended September 30, 2004.

** Includes a $50.3 million Las Vegas I power plant impairment charge for the three and nine month periods ended September 30, 2005.

30

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

Energy Marketing and Transportation

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Revenue	$	227,401	$	159,694	$	560,853	$	495,024
Operating (loss) income		(2,048)		1,584		6,613		10,476
(Loss) income from continuing operations		(1,072)		670		4,544		6,245

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
Natural gas physical sales – MMbtus	1,562,200	1,171,300	1,495,000	1,141,700
Natural gas financial sales - MMbtus	844,000	578,000	754,300	493,500
Crude oil – barrels marketed	38,400	41,000	36,550	47,400
Crude oil – barrels transported	37,620	68,350	37,000	50,800

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004. Revenue increases from crude oil marketing were primarily due to a 56 percent increase in average price received, partially offset by increased cost of crude oil sold and decreased volumes. Oil transportation revenues decreased primarily due to the suspension of shipments for routine regulatory required pressure testing of the Millennium pipeline system during July 2005 and power outages caused by Hurricane Rita in September 2005.

Income from continuing operations decreased $1.7 million primarily due to lower oil transportation revenues and a charge for a litigation settlement accrual of $2.5 million relating to a class action lawsuit, initiated in 2003, that alleged false reporting of natural gas price and volume information. These decreases were partially offset by increased oil marketing and gas marketing margins. Gas marketing unrealized mark-to-market losses for the quarter ended September 30, 2005 were $0.1 million lower than unrealized mark-to-market losses for the same period in 2004. (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.) In addition, realized gross margins from gas and crude oil marketing increased $1.2 million.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004. Revenue increases from crude oil marketing were primarily due to a 49 percent increase in average price received, partially offset by increased cost of crude oil sold and decreased volumes. Oil transportation revenues decreased primarily due to suspension of shipments for routine regulatory required pressure testing of the Millennium pipeline system during June and July of 2005 and power outages caused by Hurricane Rita in September 2005.

Income from continuing operations decreased $1.7 million primarily due to lower oil transportation revenues and a charge for a litigation settlement accrual of $2.5 million relating to a class action lawsuit, initiated in 2003, that alleged false reporting of natural gas price and volume information. These decreases were partially offset by increased oil marketing and gas marketing margins. Gas marketing unrealized mark-to-market losses for the nine months ended September 30, 2005 were $0.6 million lower than unrealized mark-to-market losses for the same period in 2004. In addition, realized gross margins from gas and crude oil marketing increased $1.6 million.

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Power Generation

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Revenue	$	43,076	$	42,980	$	121,366	$	118,472
Operating (loss) income		(36,552)		17,351		(10,479)		35,724
(Loss) income from continuing operations		(24,587)		7,192		(14,601)		10,347

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
Contracted fleet plant availability	97.8%	98.9%	98.3%	98.6%

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004. Revenues in the third quarter of 2005 were flat compared to revenues in the third quarter of 2004. Increased revenues from higher megawatts generated at our Gillette Combustion Turbine (CT II) were offset by decreased revenues recognized at our Harbor facility. Revenues earned under the Harbor facility’s new three-year tolling agreement, which commenced April 1, 2005, are recognized on a straight-line basis as opposed to reflecting the higher summer capacity payment.

Operating expenses for the three months ended September 30, 2005 increased $54.0 million, which includes a $50.3 million impairment charge for the Las Vegas I power plant. Operating expenses also increased $3.7 million primarily due to increased fuel expense at the Las Vegas I and CT II plants and increased corporate allocations.

Income from continuing operations decreased $31.8 million due to the after-tax impact of $32.7 million for the Las Vegas I impairment charge. Results from continuing operations prior to the impairment charge increased $0.9 million due to increases in earnings from certain power fund investments, partially offset by increased fuel costs and corporate allocations.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004. Revenues increased 2 percent in the nine months ended September 30, 2005 compared to the same period in 2004. The increased revenues are primarily attributable to increased revenues at our Las Vegas II facility and increased revenues from higher megawatts generated at our CT II. In the first nine months of 2005, our Las Vegas II facility sold capacity and energy to Nevada Power Company under a long-term tolling arrangement, which became effective April 1, 2004, as opposed to selling power into the market on a merchant basis for the first three months of 2004, only when it was economic to do so.

32

Operating expenses for the nine months ended September 30, 2005 increased $49.1 million, due to a $50.3 million impairment charge on the Las Vegas I plant. The increase in operating expenses due to the impairment charge was partially offset by a $1.2 million reduction in operating expenses resulting from decreased fuel expense at the Las Vegas II facility, which incurred fuel costs in the first three months of 2004, before the new, long-term tolling arrangement took effect. The decreased fuel expense at Las Vegas II was partially offset by increased fuel costs at the CT II plant and increased corporate allocations.

Income from continuing operations decreased $24.9 million, primarily due to the $32.7 million after-tax impact of the Las Vegas I impairment charge. Results from continuing operations prior to the impairment charge increased $7.8 million primarily resulting from increased revenue, lower fuel costs and increased earnings from certain power fund investments. These increases were partially offset by increased corporate allocations and increased interest expense related to a $0.7 million charge for the write-off of certain deferred costs associated with the project financing debt repaid during the second quarter of 2005.

Oil and Gas

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Revenue	$	22,807	$	13,666	$	61,511	$	41,036*
Operating income		9,303		4,418		24,099		11,676
Income from continuing operations		5,109		2,765		14,346		7,215

___________________________

* Includes a previously disclosed $(0.5) million revenue accrual correction for the nine-month period ended September 30, 2004.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
Fuel production:
Barrels of oil sold	102,350	99,149	302,784	333,260
Mcf of natural gas sold	2,908,571	2,517,581	8,614,388	7,132,472
Mcf equivalent sales	3,522,671	3,112,475	10,431,092	9,132,032

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004. Revenue from oil and gas increased 67 percent for the three months ended September 30, 2005 compared to the three months ended September 30, 2004. Gas volumes sold increased 16 percent primarily due to increased production from recently completed wells, and oil volumes sold increased 3 percent. Average gas price received, net of hedges and exclusive of gas liquids, for the three months ended September 30, 2005 was $6.22/Mcf compared to $4.54/Mcf in the same period of 2004. Average oil price received, net of hedges, for the three months ended September 30, 2005 was $40.18/bbl compared to $27.32/bbl in the same period of 2004.

33

Total operating expenses increased 46 percent for the three month period ended September 30, 2005 primarily due to generally higher field service costs experienced industry-wide and the increase in number of producing wells as a result of the current drilling program. The lease operating expenses per Mcfe sold (LOE/MCFE) for the three month period decreased 18 percent from $1.05/Mcfe in 2004 to $0.86/Mcfe in 2005 due to higher production rates and efficiencies realized in certain of our fields where significant production increases have been achieved. Depletion expense per Mcfe increased 44 percent over the prior year from $0.98/Mcfe in 2004 to $1.41/Mcfe in 2005. The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The increased rate is a reflection of higher commodity prices which in turn has led to increased demand for drilling services resulting in higher drilling costs and higher estimated future development costs.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004. Revenues from oil and gas increased 50 percent for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. Gas volumes sold increased 21 percent due to increased production from recently completed wells, and oil volumes sold decreased 9 percent primarily due to a normal decline in our mature Wyoming oil field and reduced opportunities for enhanced oil recovery activities. Average gas price received, net of hedges and exclusive of gas liquids, for the nine months ended September 30, 2005 was $5.72/Mcf compared to $4.38/Mcf in the same period of 2004. Average oil price received, net of hedges, for the nine months ended September 31, 2005 was $35.30/bbl compared to $25.31/bbl in the same period of 2004.

Total operating expenses increased 27 percent primarily due to generally higher field service costs experienced industry-wide and the increase in number of producing wells as a result of the current drilling program. The LOE/MCFE for the nine month period decreased 9 percent from $0.99/Mcfe in 2004 to $0.90/Mcfe in 2005 due to higher production rates and efficiencies realized in certain of our fields where significant production increases have been achieved. Depletion expense per Mcfe increased 28 percent over the prior year from $0.93/Mcfe in 2004 to $1.19/Mcfe in 2005. The average depletion rate per Mcfe is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented. The increased rate is a reflection of higher commodity prices which in turn has led to increased demand for drilling services resulting in higher drilling costs and higher estimated future development costs.

Coal Mining

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Revenue	$	8,482	$	7,032	$	24,861	$	23,303
Operating income		1,658		2,405		5,460		5,937
Income from continuing operations		1,643		2,537		4,860		5,648

The following is a summary of coal sales quantities:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2005	2004	2005	2004
Fuel production:
Tons of coal sold	1,172,360	1,235,400	3,474,050	3,510,100

34

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004.

Revenue from our Coal mining segment increased 21 percent for the three month period ended September 30, 2005 compared to the same period in 2004. In September 2004, the Company reached a tax settlement with the Wyoming Department of Revenue which resulted in adjusted coal billings for the period of fourth quarter 2001 through the year 2003. The Company recorded a $1.7 million reduction in revenues and a corresponding reduction in mineral taxes in September, 2004. The Company also recorded an additional $0.4 million decrease to interest expense related to the settlement. Revenues for the three month period ended September 30, 2005 were also impacted by a 5 percent decrease in tons of coal sold primarily due to an unscheduled plant outage at the Neil Simpson II power plant and decreased train loadout sales.

Operating expenses increased 47 percent during the three months ended September 30, 2005 primarily due to the reduction of 2004 mineral tax expense due to the recording of the 2004 tax settlement and increased overburden and compensation expense and corporate allocations, partially offset by lower depletion and depreciation expense.

Income from continuing operations decreased 35 percent due primarily to a decrease in tons of coal sold and increased overburden and compensation expense and corporate allocations, partially offset by lower depletion and depreciation expense. In addition, 2004 results were affected by a $0.4 million benefit from an income tax reserve adjustment and a $0.6 million after-tax benefit from the Wyoming tax settlement.

Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004.

Revenue from our Coal mining segment increased 7 percent for the nine month period ended September 30, 2005 compared to the same period in 2004. In September 2004, the Company reached a tax settlement with the Wyoming Department of Revenue which resulted in adjusted coal billings for the period of fourth quarter 2001 through the year 2003. The Company recorded a $1.7 million reduction in revenues and a corresponding reduction in mineral taxes in September, 2004. The Company also recorded an additional $0.4 million decrease to interest expense related to the settlement. Revenues for the nine months ended September 30, 2005 were also impacted by a 1 percent decrease in tons of coal sold primarily due to unscheduled plant outages at the Neil Simpson II and Wyodak power plants.

Operating expenses increased 12 percent during the nine months ended September 30, 2005 primarily due to the reduction of 2004 mineral tax expense due to the recording of the 2004 tax settlement and increased overburden and compensation expense and corporate allocations, partially offset by decreased depletion expense, due to lower rates.

Income from continuing operations decreased 14 percent primarily due to increased overburden and compensation expense and corporate allocations, partially offset by the decrease in depletion expense. In addition, 2004 results were affected by a $0.4 million benefit from an income tax reserve adjustment and a $0.6 million after-tax benefit from the Wyoming tax settlement.

35

Retail Services Group

Electric Utility

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
	(in thousands)
Revenue	$	49,274	$	47,921	$	134,682		$	129,377
Operating expenses		43,811		35,415		111,603			98,902
Operating income	$	5,463	$	12,506	$	23,079		$	30,475
Income from continuing operations and net income	$	1,888	$	5,860	$	9,619		$	12,712

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

	Electric Revenue
	(in thousands)
	Three Months Ended September 30,			Nine Months Ended September 30,
		Percentage			Percentage
Customer Base	2005	Change	2004	2005	Change	2004
Commercial	$14,127	8%	$13,117	$ 37,179	5%	$ 35,258
Residential	10,441	16	9,019	29,662	8	27,396
Industrial	5,111	(1)	5,175	14,874	(1)	14,963
Municipal sales	693	7	650	1,740	4	1,675
Contract wholesale	5,719	(4)	5,932	17,377	3	16,909
Wholesale off-system	11,766	(7)	12,590	29,050	5	27,592
Total electric sales	47,857	3	46,483	129,882	5	123,793
Other revenue	1,417	(1)	1,438	4,800	(14)	5,584
Total revenue	$49,274	3%	$47,921	$134,682	4%	$129,377

	Megawatt Hours
	Three Months Ended September 30,			Nine Months Ended September 30,
		Percentage			Percentage
Customer Base	2005	Change	2004	2005	Change	2004
Commercial	188,481	7%	175,935	498,643	5%	474,342
Residential	122,400	17	104,468	363,039	8	336,524
Industrial	108,445	(2)	110,611	310,538	1	307,877
Municipal sales	9,622	9	8,799	22,912	5	21,826
Contract wholesale	145,993	(6)	155,991	457,990	1	455,686
Wholesale off-system	198,031	(32)	291,551	598,105	(12)	677,237
Total electric sales	772,972	(9)%	847,355	2,251,227	(1)%	2,273,492

We established a new summer peak load of 401 megawatts in July 2005. We established our winter peak load of 344 megawatts in December 1998.

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	Three Months Ended			Nine Months Ended
	September 30,			September 30,
		Percentage			Percentage
Resources	2005	Change	2004	2005	Change	2004
Megawatt-hours generated:
Coal	397,513	(12)%	452,720	1,259,822	(1)%	1,275,780
Gas	22,065	29	17,121	27,545	8	25,551
	419,578	(11)	469,841	1,287,367	(1)	1,301,331
Megawatt-hours purchased	378,986	(5)	400,123	1,032,091	(1)	1,038,821
Total resources	798,564	(8)%	869,964	2,319,458	(1)%	2,340,152

	Three Months Ended			Nine Months Ended
	September 30,		Percentage	September 30,		Percentage
	2005	2004	Change	2005	2004	Change
Heating and cooling degree days
Actual
Heating degree days	120	198	(39)%	4,043	4,246	(5)%
Cooling degree days	673	463	45%	821	522	57%
Variance from normal
Heating degree days	(47)%	(13)%	—	(11)%	(6)%	—
Cooling degree days	36%	(6)%	—	38%	(12)%	—

Three Months Ended September 30, 2005 Compared to Three Months Ended September 30, 2004. Electric utility revenues increased 3 percent for the three month period ended September 30, 2005, compared to the same period in the prior year. Firm commercial and residential sales increased 8 percent and 16 percent, respectively. Cooling degree days, which is a measure of weather trends, were 45 percent higher than the same period in the prior year. Wholesale off-system sales decreased 7 percent with a 32 percent decrease in megawatt-hours sold, partially offset by a 38 percent increase in average price received. The decrease in wholesale off-system megawatt-hours sold was primarily due to the unscheduled outage of our Neil Simpson II power plant in July and August of 2005, which resulted in fewer megawatt-hours being available for sale.

Electric operating expenses increased 24 percent for the three month period ended September 30, 2005, compared to the same period in the prior year. Higher operating expenses were primarily the result of a $5.3 million increase in fuel and purchased power costs. The increase in fuel and purchased power was due to a $4.8 million increase in purchased power, which includes $2.8 million of additional purchase power costs to cover the outage of NSII, as well as a 40 percent increase in average price per megawatt-hour, partially offset by a 5 percent decrease in megawatt-hours purchased. Fuel costs increased due to a 26 percent increase in average cost partially offset by an 11 percent decrease in megawatt-hours generated. Megawatt-hours produced through coal-fired generation decreased while higher cost gas generation was utilized in the three months ended September 30, 2005. Purchased power and gas generation were utilized for firm load demand and peaking needs due to unscheduled plant outages and warmer weather. The increase in operating expense was also affected by increased power marketing legal expense, compensation costs and corporate allocations.

Income from continuing operations decreased $4.0 million primarily due to increased fuel and purchased power costs, legal expense, compensation costs and corporate allocations, partially offset by increased revenues and lower interest expense, due to the paydown of debt.

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Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004. Electric utility revenues increased 4 percent for the nine month period ended September 30, 2005 compared to the same period in the prior year. Firm commercial, residential and contract wholesale sales increased 5 percent, 8 percent and 3 percent, respectively. Cooling degree days for the nine month period were 57 percent higher than the same period in 2004 and heating degree days were 5 percent lower than the same period in 2004. Wholesale off-system sales increased 5 percent due to a 19 percent increase in average price received partially offset by a 12 percent decrease in megawatt-hours sold.

Electric operating expenses increased 13 percent for the nine month period ended September 30, 2005, compared to the same period in the prior year. Higher operating expenses were primarily the result of an $8.4 million increase in fuel and purchased power costs. The increase in fuel and purchased power was due to an $8.0 million increase in purchased power, which includes $2.8 million of additional purchase power costs to cover the outage of NSII, as well as a 23 percent increase in average price per megawatt-hour, partially offset by a 1 percent decrease in megawatt-hours purchased. Fuel costs increased $0.4 million due to a 5 percent increase in average cost, partially offset by a 1 percent decrease in megawatt-hours generated. Megawatt-hours produced through coal-fired generation decreased while higher cost gas generation was utilized in the nine months ended September 30, 2005. Purchased power and gas generation were utilized for firm load demand and peaking needs due to unscheduled plant outages and warmer weather. The increase in operating expense was also affected by increased power marketing legal expense, compensation costs and corporate allocations, partially offset by lower maintenance costs.

Income from continuing operations decreased $3.1 million primarily due to increased fuel and purchased power costs, legal expense, compensation costs and corporate allocations, partially offset by increased revenues, lower maintenance costs and lower interest expense, due to the pay down of debt.

Electric and Gas Utility

	Three Months Ended		January 21, 2005 to
	September 30,		September 30,
	2005		2005
	(in thousands)
Revenue	$	23,501	$	78,034
Operating expenses		23,540		76,242
Operating (loss) income	$	(39)	$	1,792
(Loss) income from continuing operations and net income	$	(127)	$	1,028

For the three month period ended September 30, 2005, natural gas sales comprised 15 percent or $3.6 million of total revenues, and electric sales comprised 85 percent or $19.9 million of total revenues for this segment.

For the period January 21, 2005 through September 30, 2005, natural gas sales comprised 30 percent, or $23.3 million of total revenues and electric sales comprised 70 percent, or $54.7 million of total revenues.

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The following tables provide certain operating statistics for the Electric and Gas Utility Segment:

	Electric Revenue
	(in thousands)
Customer Base	Three Months Ended September 30, 2005	January 21, 2005 to September 30, 2005
Commercial	$11,007	$ 29,568
Residential	6,462	18,052
Industrial	2,268	6,673
Municipal sales	163	432
Total electric sales	19,900	54,725
Other revenue	17	22
Total revenue	$19,917	$54,747

Resources	Three Months Ended September 30, 2005	January 21, 2005 to September 30, 2005
Megawatt-hours purchased	254,349	667,360

	Gas Revenue
	(in thousands)
Customer Base	Three Months Ended September 30, 2005	January 21, 2005 to September 30, 2005
Commercial	$   702	$ 6,785
Residential	1,784	12,639
Industrial	966	3,336
Total gas sales	3,452	22,760
Other revenue	132	527
Total revenue	$3,584	$23,287

Resources	Three Months Ended September 30, 2005	January 21, 2005 to September 30, 2005
Dekatherms purchased	352,957	2,445,230

	Three Months Ended September 30, 2005	January 21, 2005 to September 30, 2005
Electric sales - MWh	233,737	662,387
Gas sales - Dth	412,977	2,760,711
Gas transport - Dth	2,116,970	6,357,934

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 requested a 3.94 percent and 5.62 percent increase in electric and gas revenues, respectively. On October 3, 2005, the WPSC entered a bench order approving a stipulation and agreement with the Wyoming Office of Consumer Advocate which will result in an annual revenue increase of approximately $4.8 million beginning in 2006. The rates will go into effect on January 1, 2006 and represent increases of 3.65 percent and 5.11 percent in electric and gas revenues, respectively. In addition, we expect additional costs in 2006 related to allocated corporate costs to total approximately $2.7 million.

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We are progressing with the construction of Wygen II, a 90 megawatt, coal-fired power plant to be sited at our Wyodak energy complex near Gillette, Wyoming. Wygen II will be a regulated asset of CLF&P. We have obtained all necessary permits and have commenced construction. The cost of construction is estimated to be approximately $169 million. Wygen II is expected to commence commercial operations in early 2008.

Corporate

Losses from corporate activities primarily represent unallocated corporate costs. Higher losses are primarily the result of the write-off and expensing of certain capitalized project development costs of approximately $8.9 million and $9.5 million for the three and nine month periods ended September 30, 2005, which projects have been determined less likely to advance and costs related to unsuccessfully bid projects during the third quarter of 2005. These costs were partially offset by allocating increased compensation and debt retirement costs down to the subsidiary level.

Critical Accounting Policies

During the third quarter of 2005, in accordance with our accounting policies, we evaluated for impairment the long-lived asset carrying values of our Las Vegas I power plant. In measuring the fair value of the Las Vegas I power plant and the resulting impairment charge, we considered a number of possible cash flow models associated with the various probable operating assumptions and pricing for the capacity and energy of the facility. We then made our best determination of the relative likelihood of the various models in computing a weighted average expected cash flow for the facility. Inclusion of other possible cash flow scenarios and/or different weighting of those that were included could have led to different conclusions about the fair value of the plant. Further, the weighted average cash flow method is sensitive to the discount rate assumption. If we had used a discount rate that was 1 percent higher, the resulting impairment charge would have been approximately $0.3 million higher. If the discount rate would have been 1 percent lower, the impairment charge would have been approximately $0.3 million lower.

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

Cash flows from operations increased $50.3 million for the nine month period ended September 30, 2005 compared to the same period in the prior year primarily as a result of the following:

• A $63.1 million increase related to non-cash charges for the impairment of our Las Vegas I power plant, higher depreciation, depletion and amortization, and the write-off of capitalized project development costs.

• A $52.7 million increase from working capital changes. This is primarily driven by $46.4 million less being spent on material, supplies and fuel during the period. Fluctuations in our material, supplies and fuel balances are largely the result of natural gas inventory held by our natural gas marketing company in the form of storage agreements.

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The above increases were partially offset by the following operating cash flow decreases:

• A $31.6 million decrease in net income.

• $38.6 million from changes in deferred income taxes, largely the result of higher book depreciation and impairment charges during 2005.

During the nine months ended September 30, 2005, we had cash outflows from investing activities of $47.5 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, partially offset by a $103.0 million cash payment received for the sale of Black Hills FiberSystems.

During the nine months ended September 30, 2005, we had cash outflows from financing activities of $93.0 million, primarily due to the repayment of $81.5 million of project level debt at our Fountain Valley facility and due to the payment of quarterly cash dividends on common stock, which were partially offset by an increase in short term borrowings.

Dividends

Dividends paid on our common stock totaled $31.5 million during the nine months ended September 30, 2005, or $0.32 per share, per quarter in the first, second and third quarters of 2005. This reflects a 3.2 percent increase, as approved by our board of directors in January 2005, from the 2004 quarterly dividend level. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under PUHCA, restrictions under our credit facilities and our future business prospects.

Short-Term Liquidity and Financing Transactions

Our principal sources of short-term liquidity are our revolving bank facility and cash provided by operations. Our liquidity position remained strong during the first nine months of 2005. As of September 30, 2005, we had approximately $53.0 million of cash unrestricted for operations and $400 million of credit through our revolving bank facility. Approximately $8.5 million of the cash balance at September 30, 2005 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company.

Our revolving credit facility can be used to fund our working capital needs, for general corporate purposes, and to provide liquidity for a commercial paper program if implemented. At September 30, 2005, we had $42.0 million of borrowings outstanding under the facility. After inclusion of applicable letters of credit, the remaining borrowing capacity under the facility was $293.9 million at September 30, 2005.

On May 5, 2005, we entered into a new $400 million revolving bank facility with ABN AMRO as Administrative Agent, Union Bank of California and US Bank as Co-Syndication Agents, Bank of America and Harris Nesbitt as Co-Documentation Agents, and other syndication participants. The new facility has a five year term, expiring May 4, 2010. The facility contains a provision which allows the facility size to be increased by up to an additional $100 million through the addition of new lenders, or through increased commitments from existing lenders, but only with the consent of such lenders. The cost of borrowings or letters of credit issued under the new facility is determined based on our credit ratings; at our current ratings levels, the facility has an annual facility fee of 17.5 basis points, and has a borrowing spread of 70.0 basis points over the LIBOR (which equates to a 4.56 percent one-month borrowing rate as of September 30, 2005). In conjunction with entering into the new revolving bank facility, we terminated our $125 million revolving bank facility due May 12, 2005 and our $225 million facility due August 20, 2006.

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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 $714.9 million at September 30, 2005, which was approximately $86.6 million in excess of the net worth we were required to maintain under the bank facility in place at September 30, 2005. The long-term debt component of our capital structure at September 30, 2005 was 48.5 percent, our total debt leverage (long-term debt and short-term debt) was 50.4 percent, and our recourse leverage ratio was approximately 49.3 percent.

In addition, Enserco Energy Inc., our gas marketing unit, has an uncommitted, discretionary line of credit to provide support for the purchase of natural gas. In the third quarter of 2005, the facility was increased to $200 million and the expiration date extended to November 30, 2005. As of September 30, 2005, we had a $3.0 million guarantee to the lender under this facility. At September 30, 2005, there were outstanding letters of credit issued under the facility of $163.3 million, with no borrowing balances outstanding on the facility.

Similarly, Black Hills Energy Resources, Inc. (BHER), our oil marketing unit, has an uncommitted, discretionary credit facility. The facility allows BHER to elect from $25.0 million up to $50.0 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 September 30, 2005, BHER had elected to have $50.0 million of available credit and had letters of credit outstanding of $36.5 million. In the third quarter of 2005, the expiration date of the facility was extended to November 30, 2005.

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

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

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

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Guarantees

During the first quarter of 2005, a $0.5 million guarantee related to payments under various transactions with Idaho Power Company was reduced to $0.3 million. During the second quarter of 2005, a $0.8 million guarantee related to payments under various transactions with Southern California Edison Company expired and was not renewed.

During the third quarter of 2005, we entered into a guarantee for the payments related to an interest rate swap transaction between our Black Hills Fountain Valley subsidiary and Union Bank of California. The notional amount of the swap was $25 million and the swap expires in the third quarter of 2006. At September 30, 2005, the fair value of the swap was a liability of $0.1 million. At September 30, 2005, the maximum potential amount which could be due with respect to the swap transaction and corresponding guarantee, is approximately $1.2 million. At September 30, 2005, we had guarantees totaling $183.1 million in place. On October 12, 2005, the Wyoming Department of Environmental Quality approved our Self-Bonding Agreement in the amount of $17.9 million related to reclamation on our Wyodak coal mine. In conjunction, we signed an Indemnification Agreement, and bonds previously posted with private insurers were released from liability.

Capital Requirements

During the nine months ended September 30, 2005, capital expenditures were approximately $88.8 million for property, plant and equipment additions and $67.3 million for the acquisition of CLF&P (exclusive of debt assumed in the acquisition). We currently expect capital expenditures for the entire year 2005 to approximate $200 million, as detailed in Item 7 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission excluding debt assumed in the CLF&P acquisition and the elimination of capital expenditures related to the discontinued Communications segment.

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

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RISK FACTORS

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

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

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

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.

REGULATORY ISSUES

Energy Policy Act of 2005

In July 2005, Congress passed the Energy Policy Act of 2005 (the Act) and on August 8, 2005, the President signed the Act into law. The Act includes numerous provisions meant to increase domestic gas and oil supplies, improve energy system reliability, build new nuclear power plants and expand renewable energy sources. The Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking on September 16, 2005 proposing rules implementing the repeal of the Public Utility Holding Company Act of 1935 (PUHCA 1935) and the enactment of the Public Utility Holding Company Act of 2005 (PUHCA 2005). We are currently evaluating the impact the Act may have on our results of operations and financial condition.

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SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

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

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

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

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

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

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

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

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

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

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

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•             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 and events;

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

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

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

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

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

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Trading Activities

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

Total fair value of natural gas marketing positions marked-to-market at December 31, 2004	$	(930) (a)
Net cash settled during the period on positions that existed at December 31, 2004		762
Change in fair value due to change in techniques and assumptions		—
Unrealized loss on new positions entered during the period and still existing at September 30, 2005		(3,434)
Realized gain on positions that existed at December 31, 2004 and were settled during the period		39
Unrealized gain on positions that existed at December 31, 2004 and still exist at September 30, 2005		687
Total fair value of natural gas marketing positions at September 30, 2005	$	(2,876)(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):

	September 30, 2005		June 30, 2005		March 31, 2005		December 31, 2004
Net derivative assets/(liabilities)	$	(63,922)	$	(2,973)	$	(9,360)	$	8,082
Fair value adjustment recorded in
material, supplies and fuel		61,046		2,876		4,762		(9,012)
	$	(2,876)	$	(97)	$	(4,598)	$	(930)

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

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

	Maturities
Source of Fair Value	Less than 1 year		1 – 2 years		Total Fair Value
Actively quoted (i.e., exchange-traded) prices	$	(23,547)	$	3,387	$	(20,160)
Prices provided by other external sources		20,490		(3,206)		17,284
Modeled		—		—		—
Total	$	(3,057)	$	181	$	(2,876)

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

Fair value of our natural gas marketing positions marked-to-market in accordance with
GAAP see footnote (a) above)	$	(2,876)
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		15,544
Fair value of all forward positions (Non-GAAP)		12,668
“Liquidity Reserve” included in GAAP marked-to-market fair value (b)		2,146
Fair value of all forward positions excluding the “Liquidity Reserve” (Non-GAAP)	$	14,814

_____________________________

(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 16 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

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Activities Other Than Trading

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

Natural Gas

Location	Transaction Date	Term	Volume	Price
			(Mmbtu/day)
San Juan El Paso	08/01/2004	04/05 – 10/05	2,500	$	5.30
San Juan El Paso	09/22/2004	04/05 – 10/05	2,500	$	5.40
San Juan El Paso	10/20/2004	04/05 – 10/05	2,500	$	6.04
San Juan El Paso	12/29/2004	04/05 – 10/05	2,500	$	5.40
San Juan El Paso	11/04/2004	11/05 – 03/06	2,500	$	7.08
San Juan El Paso	04/04/2005	11/05 – 03/06	2,500	$	7.77
San Juan El Paso	07/12/2005	11/05 – 03/06	5,000	$	8.03
San Juan El Paso	08/10/2005	11/05 – 03/06	2,500	$	8.90
San Juan El Paso	07/12/2005	04/06 – 10/06	5,000	$	7.00

Crude Oil

Location	Transaction Date	Term	Volume	Price
			(barrels/month)
NYMEX	01/08/2004	Calendar 2005	10,000	$	27.90
NYMEX	05/12/2004	Calendar 2005	10,000	$	34.08
NYMEX	10/06/2004	Calendar 2006	10,000	$	41.00
NYMEX	07/29/2005	Calendar 2007	5,000	$	61.00
NYMEX	08/04/2005	Calendar 2007	5,000	$	62.00

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of September 30, 2005. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.

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

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

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

49

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 17 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 17 is incorporated by reference into this item.

Item 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
	(a) Total			Purchased as	That May Yet Be
	Number of	(b) Average		Part of Publicly	Purchased Under
	Shares	Price Paid		Announced Plans	the Plans
Period	Purchased	per Share		or Programs	or Programs
July 1, 2005 – July 31, 2005	—	$	—	—		—
August 1, 2005 – August 31, 2005	124(1)	$	39.30	—		—
September 1, 2005 – September 30, 2005	724(2)	$	32.48	—		—
Total	848	$	33.47	—		—

___________________________

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

(2) Includes 500 shares acquired by forfeiture of Restricted Stock and 224 shares acquired by a Rabbi Trust for the Outside Directors Stock Based Compensation Plan.

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Item 6. Exhibits

(a) Exhibits–

Exhibit 10.1	Second Amendment to the Amended and Restated Credit Agreement made as of the 5th day of April, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party hereto.
Exhibit 10.2	Third Amendment to the Amended and Restated Credit Agreement made as of the 20th day of July, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party hereto.
Exhibit 10.3	Fourth Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party hereto.
Exhibit 10.4	Form of Stock Option Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 10.5	Form of Restricted Stock Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 10.6	Form of Restricted Stock Unit Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 10.7	Form of Performance Share Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 31.1	Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
Exhibit 31.2	Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
Exhibit 32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.
Exhibit 32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

51

BLACK HILLS CORPORATION

Signatures

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

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

52

EXHIBIT INDEX

Exhibit Number	Description
Exhibit 10.1	Second Amendment to the Amended and Restated Credit Agreement made as of the 5th day of April, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party hereto.
Exhibit 10.2	Third Amendment to the Amended and Restated Credit Agreement made as of the 20th day of July, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party hereto.
Exhibit 10.3	Fourth Amendment to the Amended and Restated Credit Agreement made as of the 30th day of September, 2005, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, BNP Paribas, U.S. Bank National Association and Societe Generale, and each other financial institution which became a party hereto.
Exhibit 10.4	Form of Stock Option Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 10.5	Form of Restricted Stock Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 10.6	Form of Restricted Stock Unit Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 10.7	Form of Performance Share Award Agreement for 2005 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 11, 2005).
Exhibit 31.1	Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
Exhibit 31.2	Certification pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
Exhibit 32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.
Exhibit 32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

53