Edgar Filing: BLACK HILLS CORP /SD/

form10q_3rdqtr-2009.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2009.
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the transition period from __________ to __________.

	Commission File Number 001-31303

Black Hills Corporation
Incorporated in South Dakota	IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701

Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report
NONE

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

Yes

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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

Yes

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

Class	Outstanding at October 30, 2009

Common stock, $1.00 par value	38,866,236 shares

TABLE OF CONTENTS

		Page

	Glossary of Terms and Abbreviations	3-5

	Accounting Standards	6

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income –
	Three and Nine Months Ended September 30, 2009 and 2008	7

	Condensed Consolidated Balance Sheets –
	September 30, 2009, December 31, 2008 and September 30, 2008	8

	Condensed Consolidated Statements of Cash Flows –
	Nine Months Ended September 30, 2009 and 2008	9

	Notes to Condensed Consolidated Financial Statements	10-52

Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	53-91

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	91-97

Item 4.	Controls and Procedures	98

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	99

Item 1A.	Risk Factors	99-100

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	101

Item 6.	Exhibits	102

	Signatures	103

	Exhibit Index	104

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

Acquisition Facility	Our $1.0 billion single-draw, senior unsecured facility from which a
	$383 million draw was used to provide part of the funding for the
	Aquila Transaction
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
Aquila	Aquila, Inc.
Aquila Transaction	Our July 14, 2008 acquisition of Aquila’s regulated electric utility in
	Colorado and its regulated gas utilities in Colorado, Kansas,
	Nebraska and Iowa
Bbl	Barrel
Bcf	Billions cubic feet
Bcfe	Billion cubic feet equivalents
BHCRPP	Black Hills Corporation Risk Policies and Procedures
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned
	subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned
	subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business activities of Black Hills Utility
	Holdings, including the gas and electric utility properties acquired
	from Aquila
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned
	subsidiary of the Company that was formerly known as Black Hills
	Energy, Inc.
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the
	Company
Black Hills Service Company	Black Hills Service Company, a direct wholly-owned subsidiary of
	the Company
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of
	the Company formed to acquire and own the utility properties
	acquired from Aquila, all which are now doing business as
	Black Hills Energy
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black
	Hills Electric Generation
Btu	British thermal unit
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned
	subsidiary of the Company
Cheyenne Light Pension Plan	The Cheyenne Light, Fuel and Power Company Pension Plan
Colorado Electric	Black Hills Colorado Electric Utility Company, LP, (doing business as
	Black Hills Energy), an indirect, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Colorado electric
	utility properties acquired from Aquila

Colorado Gas	Black Hills Colorado Gas Utility Company, LP, (doing business as
	Black Hills Energy), an indirect, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Colorado gas
	utility properties acquired from Aquila
Corporate Credit Facility	Our unsecured $525 million revolving line of credit
CPUC	Colorado Public Utilities Commission
Dth	Dekatherm. A unit of energy equal to 10 therms or one million
	British thermal units (MMBtu)
Enserco	Enserco Energy Inc., a direct, wholly-owned subsidiary of Black Hills
	Non-regulated Holdings
EPA	Environmental Protection Agency
EPS	Earnings per share
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GE	GE Packaged Power, Inc.
GHG	Greenhouse gases
GSRS	Gas Safety and Reliability Surcharge
Hastings	Hastings Funds Management Ltd
IIF	IIF BH Investment LLC, a subsidiary of an investment entity advised by
	JPMorgan Asset Management
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, (doing business as
	Black Hills Energy), a direct, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Iowa gas
	utility properties acquired from Aquila
IPP	Independent Power Production
IPP Transaction	Our July 11, 2008 sale of seven of our IPP plants to affiliates of
	Hastings and IIF
IUB	Iowa Utilities Board
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, (doing business as
	Black Hills Energy), a direct, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Kansas gas
	utility properties acquired from Aquila
KCC	Kansas Corporation Commission
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	One thousand cubic feet
Mcfe	One thousand cubic feet equivalent
MDU	MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
MMBtu	One million British thermal units
MW	Megawatt
MWh	Megawatt-hour

Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC, (doing business as
	Black Hills Energy), a direct, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Nebraska gas
	utility properties acquired from Aquila
NPA	Nebraska Public Advocate
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
PGA	Purchase Gas Adjustment
PPA	Power Purchase Agreement
PSCo	Public Service Company of Colorado
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Silver Sage	Silver Sage Windpower LLC, a subsidiary of Duke Energy Corporation
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned
	subsidiary of Black Hills Non-regulated Holdings

ACCOUNTING STANDARDS

ASC	Accounting Standards Codification
ASC 105	ASC 105, “FASB Accounting Standards Codification and the Hierarchy
	of Generally Accepted Accounting Principles – a replacement of
	FASB Standard No. 162
ASC 260	ASC 260, “Earnings Per Share”
ASC 715	ASC 715, “Compensation – Retirement Benefits”
ASC 805	ASC 805, “Business Combinations”
ASC 810	ASC 810, “Consolidations”
ASC 810-10-15	ASC 810-10-15, “Consolidation of Variable Interest Entities”
ASC 815	ASC 815, “Derivatives and Hedging”
ASC 820	ASC 820, “Fair Value Measurements and Disclosures”
ASC 825	ASC 825, “Financial Instruments”
ASC 855	ASC 855, “Subsequent Events”
ASC 940-325-S99	ASC 940-325-S99, “SEC Materials”
EITF	Emerging Issues Task Force
FASB	Financial Accounting Standards Board
FSP	FASB Staff Position
FSP EITF 03-6-1	FSP EITF 03-6-1, “Determining Whether Instruments Granted in
	Share-Based Payment Transactions are Participating Securities”
FSP FAS 107-1	FSP FAS 107-1, “Interim Disclosure About Fair Value of Financial
	Instruments”
FSP FAS 132(R)-1	FSP FAS 132(R)-1, “Employer’s Disclosures about Pensions and Other
	Postretirement Benefits” (Revised)
FSP FAS 157-4	FSP FAS 157-4, “Determining Whether a Market is Not Active and a
	Transaction is Not Distressed”
SEC Release No. 33-8995	SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting”
SFAS	Statement of Financial Accounting Standards
SFAS 141(R)	SFAS 141(R), “Business Combinations”
SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS 160	SFAS 160, “Non-controlling Interest in Consolidated Financial
	Statements – an amendment of ARB No. 51”
SFAS 161	SFAS 161, “Disclosure about Derivative Instruments and Hedging
	Activities – an amendment of FASB Statement No. 133”
SFAS 165	SFAS 165, “Subsequent Events”
SFAS 167	SFAS 167, “Amendment to FASB Interpretation No. 46(R)”
SFAS 168	SFAS 168, “FASB Accounting Standards Codification and the
	Hierarchy of Generally Accepted Accounting Principles – a
	replacement of FASB Standard No. 162”

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended								Nine Months Ended
	September 30,								September 30,
	2009			2008			2009				2008
	(in thousands, except per share amounts)

Operating revenues	$	225,799		$	291,892			$	921,090		$	598,015

Operating expenses:
Fuel and purchased power		94,120			131,300				467,309			230,643
Operations and maintenance		35,431			34,477				115,226			80,762
Gain on sale of assets		—			—				(25,971	)		—
Administrative and general		38,344			40,993				117,817			90,273
Depreciation, depletion and amortization		29,824			30,825				92,535			70,999
Taxes, other than income taxes		11,171			11,609				34,680			31,590
Impairment of long-lived assets		—			—				43,301			—
		208,890			249,204				844,897			504,267

Operating income		16,909			42,688				76,193			93,748

Other income (expense):
Interest expense		(20,691	)		(16,402	)			(62,930	)		(35,160	)
Interest rate swap – unrealized (loss) gain		(8,694	)		—				37,775			—
Interest income		327			628				1,184			1,427
Allowance for funds used during
construction – equity		2,598			1,390				5,284			2,287
Other income, net		2,142			171				3,779			573
		(24,318	)		(14,213	)			(14,908	)		(30,873	)

(Loss) income from continuing operations
before equity in earnings of
unconsolidated subsidiaries and income
taxes		(7,409	)		28,475				61,285			62,875
Equity in earnings of unconsolidated
subsidiaries		119			1,359				1,368			3,656
Income tax benefit (expense)		3,437			(10,312	)			(16,300	)		(21,989	)

(Loss) income from continuing operations		(3,853	)		19,522				46,353			44,542
Income from discontinued operations,
net of taxes		1,673			145,389				2,439			159,486

Net (loss) income		(2,180	)		164,911				48,792			204,028
Net loss attributable to non-controlling
interest		—			—				—			(130	)

Net (loss) income available for
common stock	$	(2,180	)	$	164,911			$	48,792		$	203,898

Weighted average common shares
outstanding:
Basic		38,643			38,307				38,584			38,145
Diluted		38,643			38,425				38,646			38,430

Earnings (loss) per share:
Basic–
Continuing operations	$	(0.10	)	$	0.51			$	1.20		$	1.16
Discontinued operations		0.04			3.79				0.06			4.18
Total	$	(0.06	)	$	4.30			$	1.26		$	5.34

Diluted–
Continuing operations	$	(0.10	)	$	0.51			$	1.20		$	1.16
Discontinued operations		0.04			3.78				0.06			4.15
Total	$	(0.06	)	$	4.29			$	1.26		$	5.31

Dividends declared per share of common stock	$	0.355		$	0.350			$	1.065		$	1.050

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

	September 30,			December 31,			September 30,
	2009			2008			2008
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	137,681		$	168,491		$	152,457
Restricted cash		6			—			5,514
Short-term investments		—			—			6,310
Receivables, net		208,563			357,404			227,862
Materials, supplies and fuel		99,952			118,021			173,734
Derivative assets		56,951			73,068			84,758
Income tax receivable, net		—			20,269			—
Deferred income taxes		13,221			10,244			—
Regulatory assets		12,775			35,390			17,360
Other current assets		31,565			16,380			15,064
Assets of discontinued operations		—			246			322
		560,714			799,513			683,381

Investments		19,462			22,764			21,911

Property, plant and equipment		2,891,102			2,705,492			2,615,627
Less accumulated depreciation and depletion		(795,378	)		(683,332	)		(566,191	)
		2,095,724			2,022,160			2,049,436
Other assets:
Goodwill		353,734			359,290			400,959
Intangible assets, net		4,725			4,884			—
Derivative assets		5,438			9,799			1,500
Regulatory assets		120,677			143,705			51,122
Other		7,861			17,774			18,390
		492,435			535,452			471,971
	$	3,168,335		$	3,379,889		$	3,226,699
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	184,208		$	288,907		$	234,647
Accrued liabilities		150,042			134,940			140,981
Derivative liabilities		68,634			118,657			62,409
Deferred income taxes		—			—			592
Accrued income taxes, net		15,734			—			48,360
Regulatory liabilities		30,120			5,203			3,787
Notes payable		350,500			703,800			627,800
Current maturities of long-term debt		32,091			2,078			2,074
Liabilities of discontinued operations		—			88			124
		831,329			1,253,673			1,120,774

Long-term debt, net of current maturities		719,215			501,252			501,277

Deferred credits and other liabilities:
Deferred income taxes		228,715			223,607			240,654
Derivative liabilities		27,824			22,025			6,792
Regulatory liabilities		40,168			38,456			37,824
Benefit plan liabilities		135,027			159,034			44,465
Other		123,527			131,306			125,552
		555,261			574,428			455,287

Stockholders’ equity:
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized;
Issued 38,872,925; 38,676,054 and 38,490,315 shares,
respectively		38,873			38,676			38,490
Additional paid-in capital		588,556			584,582			580,601
Retained earnings		454,907			447,453			561,102
Treasury stock at cost – 7,605; 40,183 and 40,059
shares, respectively		(197	)		(1,392	)		(1,419	)
Accumulated other comprehensive loss		(19,609	)		(18,783	)		(29,545	)
Total common stockholders’ equity		1,062,530			1,050,536			1,149,229
Non-controlling interest in subsidiaries		—			—			132
Total equity		1,062,530			1,050,536			1,149,361

	$	3,168,335		$	3,379,889		$	3,226,699

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended
	September 30,
	2009			2008
	(in thousands)
Operating activities:
Net income	$	48,792		$	204,028
Income from discontinued operations, net of taxes		(2,439	)		(159,486	)
Income from continuing operations		46,353			44,542
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization		92,535			70,999
Impairment of long-lived assets		43,301			—
Derivative fair value adjustments		19,647			(26,853	)
Gain on sale of operating assets		(25,971	)		—
Unrealized mark-to-market gain on interest rate swaps		(37,775	)		—
Deferred income taxes		5,164			76,546
Distributed (undistributed) earnings of associated companies		3,424			(1,988	)
Allowance for funds used during construction – equity		(5,284	)		(2,287	)
Other non-cash adjustments		(4,782	)		(4,295	)
Change in operating assets and liabilities:
Materials, supplies and fuel, net of market adjustments		23,210			(47,382	)
Accounts receivable and other current assets		157,118			111,595
Accounts payable and other current liabilities		(101,902	)		(118,369	)
Regulatory assets and liabilities		54,272			(30,204	)
Other operating activities		(939	)		(10,403	)
Net cash provided by operating activities of continuing operations		268,371			61,901
Net cash provided by operating activities of discontinued operations		2,556			18,184
Net cash provided by operating activities		270,927			80,085

Investing activities:
Property, plant and equipment additions		(245,114	)		(219,350	)
Proceeds from sale of business operations		—			835,316
Proceeds from sale of ownership interest in plants		84,661			—
Payment for acquisition of net assets, net of cash acquired		—			(937,606	)
Working capital adjustment of purchase price allocation on Aquila assets		7,098			—
Purchase of short-term investments		—			(6,525	)
Other investing activities		1,933			(698	)
Net cash used in investing activities of continuing operations		(151,422	)		(328,863	)
Net cash used in investing activities of discontinued operations		—			(28,966	)
Net cash used in investing activities		(151,422	)		(357,829	)

Financing activities:
Dividends paid		(41,338	)		(40,189	)
Common stock issued		2,338			2,611
(Decrease) increase in short-term borrowings, net		(353,300	)		590,800
Long-term debt – issuances		248,500			—
Long-term debt – repayments		(2,024	)		(130,276	)
Other financing activities		(4,532	)		(72	)
Net cash (used in) provided by financing activities of continuing operations		(150,356	)		422,874
Net cash used in financing activities of discontinued operations		—			(73,928	)
Net cash (used in) provided by financing activities		(150,356	)		348,946

(Decrease) increase in cash and cash equivalents		(30,851	)		71,202

Cash and cash equivalents:
Beginning of period		168,532	(a)		81,255	(b)
End of period	$	137,681		$	152,457

Supplemental disclosure of cash flow information:
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities	$	31,202		$	25,549
Cash paid during the period for-
Interest (net of amounts capitalized)	$	50,311		$	29,748
Income taxes (refunded) paid	$	(23,311	)	$	2,984

_________________________

(a)	Includes less than $0.1 million of cash included in the assets of discontinued operations.

(b)	Includes approximately $4.4 million of cash included in the assets of discontinued operations.

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

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2008 Annual Report on Form 10-K)

(1)	MANAGEMENT’S STATEMENT

The condensed consolidated financial statements included herein have been prepared by Black Hills Corporation (the “Company,” “us,” “we,” “our”) without audit, pursuant to the rules and regulations of the SEC. 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, we believe that the footnotes adequately disclose the information presented. These condensed quarterly financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2008 Annual Report on Form 10-K filed with the SEC. These financial statements include consideration of events through November 6, 2009.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying condensed quarterly financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the September 30, 2009, December 31, 2008 and September 30, 2008 financial information and are of a normal recurring nature. Certain reclassifications have been made to prior period presentations to conform to the current year presentation but have no affect over the results of the prior period numbers. Certain industries in which we operate are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2009, and our financial condition as of September 30, 2009 and December 31, 2008, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On July 11, 2008, we completed the sale of seven of our IPP plants. Amounts associated with the IPP plants divested in the IPP Transaction have been reclassified as discontinued operations for the quarter ended September 30, 2008. See Note 19 for additional information.

On July 14, 2008, we completed the acquisition of a regulated electric utility in Colorado and regulated gas utilities in Colorado, Kansas, Nebraska and Iowa from Aquila. Effective as of that date, the assets and liabilities, results of operations, and cash flows of the acquired utilities are included in our Condensed Consolidated Financial Statements. See Note 17 for additional information.

(2)	RECENTLY ADOPTED ACCOUNTING STANDARDS

FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Standard No. 162, ASC 105 (SFAS 168)

On July 1, 2009, the FASB Accounting Standards CodificationTM became the source of authoritative GAAP recognized by the FASB to be applied by non-governmental entities. On the effective date of this Statement, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-SEC accounting literature not included or grandfathered in the Codification became non-authoritative. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Task Force Abstracts. Instead, it will issue Accounting Standards Updates. The FASB will not consider Accounting Standards Updates as authoritative in their own right. Accounting Standards Updates will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.

Business Combinations, ASC 805 (SFAS 141(R))

The ASC for Business Combinations requires an acquiring entity to recognize the assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at the acquisition date be measured at their fair values as of the acquisition date, with limited exceptions. Acquisition-related costs will be expensed in the periods in which the costs are incurred or services are rendered. If income tax liabilities are settled for an amount other than as previously recorded, the adjustment of any remaining liability would affect goodwill. If such liabilities are adjusted subsequent to December 31, 2008, such adjustments will affect expense including income tax expense in the period of adjustment. Costs to issue debt or equity securities shall be accounted for under other applicable GAAP. These requirements apply prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. Effective January 1, 2009, any impact a business combination will have on our consolidated financial statements will depend on the nature and magnitude of any future acquisitions we consummate and the resolution of certain tax contingencies.

Fair Value Measurements and Disclosures, ASC 820 (SFAS 157 and FSP FAS 157-4)

The ASC for Fair Value Measurements and Disclosures defines fair value, establish a framework for measuring fair value in GAAP and expand disclosures about fair value measurements. This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives within our Energy Marketing and Oil and Gas segments, interest rate swap instruments, and other miscellaneous derivatives.

On January 1, 2008, we discontinued our use of a “liquidity reserve” in valuing the total forward positions within our energy marketing portfolio. This impact was accounted for prospectively as a change in accounting estimate and resulted in a $1.2 million after-tax benefit that was recorded within our unrealized marketing margins. Unrealized margins are presented as a component of Operating revenues on the accompanying Condensed Consolidated Statements of Income. Disclosures regarding the level of pricing observability associated with instruments carried at fair value are provided in Note 15.

Consolidation of Non-Controlling Interest, ASC 810 (SFAS 160)

The ASC for Consolidation of Non-Controlling Interest establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest, and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. The ASC establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. These standards and disclosure requirements were effective January 1, 2009.

Non-controlling interest in the accompanying Condensed Consolidated Statements of Income and Balance Sheets represents the non-affiliated equity investors’ interest in Wygen Funding LP, a Variable Interest Entity as defined by ASC 810. In June 2008, we purchased the non-controlling share. Presentation of a non-controlling interest that we held until June 2008 was retrospectively applied as required, and had an immaterial overall effect.

Derivative and Hedging Disclosures, ASC 815 (SFAS 161)

The ASC for Derivative and Hedging Disclosures requires enhanced disclosures about derivative and hedging activities and their affect on an entity’s financial position, financial performance and cash flows. ASC 815 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption. Required disclosures for periods subsequent to January 1, 2009 are provided in Note 13 and Note 14.

Subsequent Events, ASC 855 (SFAS 165)

The ASC for Subsequent Events establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. These standards and disclosures were applied to our financial statements issued after June 15, 2009.

Financial Instruments, ASC 825 (FSP FAS 107-1)

The ASC for Financial Instruments requires public companies to provide more frequent disclosures about the fair value of their financial instruments for interim and annual periods ending after June 15, 2009. These disclosures are included in Note 15.

Earnings Per Share, ASC 260 (FSP EITF 03-6-1)

The ASC for Earnings per share states that unvested share-based payment awards that contain non-forfeitable rights to dividends are “participating securities” as defined and should be included in computing EPS using the two-class method. The two-class method is an earnings allocation method for computing EPS and determines EPS based on dividends declared on common stock and participating securities in any undistributed earnings. As of January 1, 2009, we prepared our current and prior period EPS computation in accordance with the guidance in ASC 260 and there was no impact on our EPS.

(3)	RECENTLY ISSUED ACCOUNTING STANDARDS

SEC Release No. 33-8995

On December 29, 2008, the SEC issued Release No. 33-8995, amending the existing Regulation S-K and Regulation S-X requirements for reporting the quantity and value of oil and gas reserves to align with current industry practices and technology advances. Key revisions include the ability to include non-traditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves. Companies must use a 12-month average price. The average is calculated using unweighted average of the first-day-of-the-month price for each of the 12 months that make up the reporting period. The amendment is effective for annual reporting periods ending on December 31, 2009, and early adoption is prohibited. We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

Consolidation of Variable Interest Entities, ASC 810-10-15 (SFAS 167)

In June 2009, the FASB issued a revision regarding consolidations. The amendment requires a Company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It will require additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard is effective for annual periods that begin after November 15, 2009. We are currently assessing the impact that the adoption of this standard will have on our financial condition, results of operations, and cash flows.

Compensation – Retirement Benefits, ASC 715 (FSP FAS 132(R)-1)

The ASC for Compensation – Retirement Benefits provides guidance on an employer’s disclosures about plan assets in a defined benefit pension or other postretirement plan to provide users of financial statements with an understanding of:

· How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies;

· The major categories of plan assets;

· The input and valuation techniques used to measure the fair value of plan assets;

· The effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and

· Significant concentrations of risk within plan assets.

These disclosures are effective for fiscal years ending after December 15, 2009.

(4)	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	2009		2008		2008

Materials and supplies	$	31,650	$	32,580	$	32,565
Fuel – Electric Utilities		7,234		10,058		11,497
Natural gas in storage – Gas Utilities		29,943		59,529		74,407
Gas and oil held by Energy
Marketing*		31,125		15,854		55,265

Total materials, supplies and fuel	$	99,952	$	118,021	$	173,734

___________________________

* As of September 30, 2009, December 31, 2008 and September 30, 2008, market adjustments related to natural gas held by Energy Marketing and recorded in inventory were $(1.3) million, $(9.4) million and $(15.1) million, respectively (see Note 13 for further discussion of Energy Marketing trading activities).

Gas and oil inventory held by Energy Marketing primarily consists of gas held in storage. Such gas is being held in inventory to capture the price differential between the time at which it was purchased and a subsequent sales date in the future. Natural gas volumes held as of September 30, 2009, December 31, 2008 and September 30, 2008 include 8.2 Bcf, 3.6 Bcf, and 7.9 Bcf. Crude oil volumes held as of September 30, 2009, December 31, 2008 and September 30, 2008 include 71,000 Bbl, 54,000 Bbl, and 64,000 Bbl, respectively.

Natural gas in storage at our Gas Utilities represents primarily gas purchased for use by our customers. The natural gas in storage fluctuates with the seasonality of our business and the commodity price of natural gas. Although volumes held in storage by us have varied due to season, there has been a notable price decrease during 2009 and 2008. Volumes held as of September 30, 2009, December 31, 2008 and September 30, 2009 include 8.6 Bcf, 7.3 Bcf and 8.6 Bcf, respectively.

(5)	ALLOWANCE FOR DOUBTFUL ACCOUNTS

Our Accounts receivable represents primarily customer trade accounts at our Electric Utilities and Gas Utilities and counterparty trade accounts at our Energy Marketing segment. This balance fluctuates due to the seasonality of our regulated Gas Utilities and volumes and commodity prices at our Energy Marketing segment. We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivables allowances by considering such factors as historical experience, credit-worthiness, the age of the receivable balances and current economic conditions that may affect the ability to pay.

Following is a summary of receivables (in thousands):

	September 30,		December 31,		September 30,
	2009		2008		2008

Accounts receivable	$	214,065	$	364,155	$	233,939
Less allowance for doubtful accounts		5,502		6,751		6,077
Net accounts receivable	$	208,563	$	357,404	$	227,862

(6)	NOTES PAYABLE AND LONG-TERM DEBT

Debt Offering

On May 14, 2009, we issued a $250 million aggregate principal amount of senior unsecured notes due in 2014 pursuant to a public offering. The notes were priced at par and carry a fixed interest rate of 9%. We received proceeds of $248.5 million, net of underwriting fees. Proceeds were used to pay down the Acquisition Facility. Deferred financing costs related to the offering of $2.3 million were capitalized and will be amortized over the life of the debt. Amortization of these deferred financing costs is included in interest expense and for the three and nine months ended September 30, 2009 was approximately $0.1 million and $0.2 million, respectively.

Acquisition Facility

In May 2007, we entered into a senior unsecured $1 billion Acquisition Facility with ABN AMRO Bank N.V., as administrative agent, and other banks to fund the Aquila Transaction. On July 14, 2008, in conjunction with the completion of the purchase of the Aquila properties, we executed a single draw of $382.8 million under the Acquisition Facility. The loan was originally scheduled to mature on February 5, 2009. However, on December 18, 2008, we amended the facility to extend the maturity date to December 29, 2009. The Acquisition Facility was repaid in the second quarter of 2009 using: (1) net proceeds from the sale of a 25% ownership interest in the Wygen III plant of $30.2 million; (2) net proceeds from the $250 million public debt offering; and (3) $104.6 million from borrowings under the Corporate Credit Facility. Approximately $3.6 million of unamortized deferred financing costs were fully expensed in the second quarter of 2009 in conjunction with the repayment of this facility. Therefore, amortization of the deferred financing costs associated with this facility is included in Interest expense on the accompanying Condensed Consolidated Statements of Income and for the nine months ended September 30, 2009 was $4.8 million.

Corporate Credit Facility

Our consolidated net worth was $1,062.5 million at September 30, 2009, which was approximately $254.0 million in excess of the net worth we are required to maintain under the Corporate Credit Facility. At September 30, 2009, our long-term debt ratio was 40.4%, our total debt coverage leverage ratio (long-term debt and short-term debt) was 50.9%, and our recourse leverage ratio was approximately 55.2%. Our interest expense coverage ratio for the twelve month period ended September 30, 2009 was 3.7 to 1.0. We were in compliance with our covenants as of September 30, 2009.

Enserco Credit Facility

On May 8, 2009, Enserco entered into an agreement for a $240 million committed credit facility. Societe Generale, Fortis Capital Corp., and BNP Paribas were co-lead arranger banks. On May 27, 2009, Enserco entered into an agreement for an additional $60 million of commitments under the credit facility with three new participating banks: Calyon, Rabobank and RZB Finance. This credit facility expires on May 7, 2010 and is a borrowing base line of credit, which allows for the issuance of letters of credit and for borrowings. Maximum borrowings under the facility are subject to a sublimit of $50 million. Borrowings under this facility are available under a base rate option or a Eurodollar option. The base rate option borrowing rate is 2.75% plus the higher of: (i) 0.5% above the Federal Funds Rate, or (ii) the prime rate established by Fortis Bank S.A./N.V. The Eurodollar option borrowing rate is 2.75% plus the higher of the Eurodollar Rate or the reference bank cost of funds.

At September 30, 2009, $71.7 million of letters of credit were issued and outstanding under this facility and there were no cash borrowings outstanding. Deferred financing costs of $1.9 million were capitalized and are amortized over the life of the facility. Amortization of these deferred financing costs is included in interest expense and for the three and nine months ended September 30, 2009 was approximately $0.1 million and $0.9 million, respectively.

Industrial Development Revenue Bonds

Cheyenne Light completed a $17 million weekly variable rate refunding bond issuance on September 3, 2009. The new issue replaces existing debt and the bond credit support structure from an AMBAC Financial Group insurance policy to a direct-pay letter of credit issued by Wells Fargo Bank. Laramie County, Wyoming was the tax-exempt conduit issuer for this transaction. The bonds were issued in two series: a $10.0 million series maturing March 1, 2027 and a $7.0 million series maturing September 1, 2021. The principal amounts and maturity dates did not change from the original financing. The initial variable weekly rate was set at 0.4%. Excluding the letter of credit fees and other issuance costs, the current all-in rate is approximately 2.65%.

(7)	GUARANTEES

Guarantees to GE

We issued two guarantees for up to $37.9 million each to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers. These are continuing guarantees which terminate upon payment in full of the purchase price to GE. Payments are scheduled based upon estimated construction milestone dates with the final payment due October 27, 2010.

Surety Bonds Issued to MEAN

On January 20, 2009, we issued a surety bond for $9.2 million to MEAN to secure operating performance obligations related to the Wygen I ownership agreement. Black Hills Wyoming and MEAN entered into the ownership agreement when MEAN acquired a 23.5% ownership interest in the Wygen I plant. The surety bond and guarantees expire on December 31, 2009.

Enserco

We have guaranteed up to $7.0 million of the obligations of Enserco under an agency agreement whereby Enserco provides services to structure certain transactions involving the buying, selling, transportation and storage of natural gas on behalf of another energy company. The guarantee expires in July 2010.

(8)	EARNINGS PER SHARE

Basic earnings per share from continuing operations is computed by dividing income from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted earnings per share from continuing operations are computed by using 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, 2009	Three Months					Nine Months
				Average				Average
	Income			Shares		Income		Shares

(Loss) income from continuing
operations	$	(3,853	)			$	46,353

Basic earnings		(3,853	)		38,643		46,353		38,584
Dilutive effect of:
Restricted stock		—			—		—		60
Other		—			—		—		2
Diluted earnings	$	(3,853	)		38,643	$	46,353		38,646

Period ended September 30, 2008	Three Months				Nine Months
			Average				Average
	Income		Shares		Income		Shares

Income from continuing operations	$	19,522			$	44,542

Basic earnings		19,522		38,307		44,542		38,145
Dilutive effect of:
Stock options		—		42		—		62
Estimated contingent shares issuable
for prior acquisition		—		—		—		132
Restricted stock		—		72		—		70
Other		—		4		—		21
Diluted earnings	$	19,522		38,425	$	44,542		38,430

The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008

Options to purchase common stock		374		151		484		99

(9)	OTHER COMPREHENSIVE INCOME

The following table presents the components of our other comprehensive (loss) income

(in thousands):

	Three Months Ended
	September 30,
	2009			2008

Net (loss) income	$	(2,180	)	$	164,911
Other comprehensive income (loss),
net of tax:
Minimum pension liability adjustments (net of
tax of $(1,999))		3,671			—
Fair value adjustment on derivatives
designated as cash flow hedges
(net of tax of $5,670 and $(14,030),
respectively)		(10,311	)		25,824
Reclassification adjustments on cash
flow hedges settled and included in
net income (net of tax of $(1,948)
and $(1,539), respectively)		3,446			2,761
Unrealized gain on available for sale
securities (net of tax of $17 in 2008)		—			(32	)

Comprehensive (loss) income attributable to
Black Hills Corporation	$	(5,374	)	$	193,464

	Nine Months Ended
	September 30,
	2009			2008

Net income	$	48,792		$	204,028
Other comprehensive income (loss),
net of tax:
Minimum pension liability adjustment
(net of tax of $(1,999))		3,671			—
Fair value adjustment on derivatives
designated as cash flow hedges
(net of tax of $8,598 and $6,449,
respectively)		(15,106	)		(11,951	)
Reclassification adjustments on cash
flow hedges settled and included in
net income (net of tax of $(6,008)
and $(3,952), respectively)		10,609			7,071
Unrealized loss on available for sale
securities (net of tax of $58)		—			(157	)

Total comprehensive income		47,966			198,991

Comprehensive loss attributable to
non-controlling interest		—			(130	)

Comprehensive income attributable to
Black Hills Corporation	$	47,966		$	198,861

Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):

	September 30,			December 31,			September 30,
	2009			2008			2008

Derivatives designated as cash flow hedges	$	(9,037	)	$	(4,522	)	$	(23,168	)
Employee benefit plans		(10,456	)		(14,127	)		(6,115	)
Amount from equity-method investees		(116	)		(134	)		(122	)
Unrealized loss on available-for-sale
securities		—			—			(140	)
Total	$	(19,609	)	$	(18,783	)	$	(29,545	)

(10)	COMMON STOCK

Other than the following transactions, we had no material changes in our common stock, as reported in Note 10 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.

Equity Compensation Plans

· We granted 78,136 target performance shares to certain officers and business unit leaders for the January 1, 2009 through December 31, 2011 performance period. Actual shares are not issued until the end of the Performance Plan period (December 31, 2011). Performance shares are awarded based on our total stockholder return over the designated performance period as measured against a selected peer group and can range from 0 to 175% of target. In addition, our stock price must also increase during the performance period. 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% in the form of cash and 50% in shares of common stock. The grant date fair value was $29.20 per share.

· We issued 47,331 shares of common stock under the 2008 short-term incentive compensation plan during the nine months ended September 30, 2009. Pre-tax compensation cost related to the award was approximately $1.6 million, which was accrued for in 2008.

· We granted 84,376 restricted common shares during the nine months ended September 30, 2009. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $2.3 million will be recognized over the three-year vesting period.

· 5,000 stock options were exercised during the nine months ended September 30, 2009 at a weighted-average exercise price of $24.06 per share providing $0.1 million of proceeds to the Company.

Total compensation expense recognized for all equity compensation plans for the three months ended September 30, 2009 and 2008 was $1.1 million and $0.3 million, respectively, and for the nine months ended September 30, 2009 and 2008 was $2.9 million and $1.0 million, respectively.

As of September 30, 2009, total unrecognized compensation expense related to non-vested stock awards was $5.8 million and is expected to be recognized over a weighted-average period of 2.0 years.

Dividend Reinvestment and Stock Purchase Plan

We have a Dividend Reinvestment and Stock Purchase Plan under which stockholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued 111,753 new shares at a weighted-average price of $20.91 during the nine months ended September 30, 2009. At September 30, 2009, 327,562 shares of unissued common stock were available for future offering under the Plan.

Dividend Restrictions

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.

Our utility subsidiaries are generally limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As of September 30, 2009, the restricted net assets at our Electric and Gas Utilities were approximately $79.2 million.

In August 2009, one of the covenants to the Enserco Credit Facility was amended to temporarily increase the allowable rolling twelve month Net Cumulative Loss as calculated on a Non-GAAP basis and temporarily restrict all dividends or loans to the Company. In addition to the borrowing base structure which requires Enserco to maintain certain levels of tangible net worth and net working capital, 100% of Enserco’s net assets are now restricted. The Company expects this to be the case through November 30, 2009. Therefore, upon review of these covenants at September 30, 2009, restricted net assets at Enserco total $214.3 million for this stand-alone Enserco Credit Facility.

(11)	EMPLOYEE BENEFIT PLANS

We have three non-contributory defined benefit pension plans (“Plans”) and three Postretirement Healthcare Plans (“Healthcare Plans”). One Plan covers employees of the following subsidiaries who meet certain eligibility requirements: Black Hills Service Company, Black Hills Power, WRDC and BHEP. The second Plan covers employees of our subsidiary, Cheyenne Light, who meet certain eligibility requirements. The third Plan covers employees of the Black Hills Energy utilities who meet certain eligibility requirements.

Defined Benefit Pension Plans

In July 2009, the Board of Directors approved a resolution to freeze two of our Defined Benefit Pension Plans to new participants and to transfer certain existing participants to an age and service based defined contribution plan, effective January 1, 2010. The first plan covers employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP and the second plan covers employees of Black Hills Energy. Plan assets and obligations were revalued July 31, 2009 in conjunction with the curtailment of these plans and we recognized a pre-tax curtailment expense of approximately $0.3 million in the three months ended September 30, 2009.

The following table sets forth the projected benefit obligation as of December 31, 2008 and July 31, 2009. The July 31, 2009 projected benefit obligation reflects the curtailment of the two plans and includes the Cheyenne Light pension plan projected benefit obligation as of its December 31, 2008 measurement date:

	Defined Benefit
	Pension Plans
	at July 31, 2009
	(in thousands)

Change in benefit obligation:

Projected benefit obligation at
December 31, 2008	$	242,545

Service cost		4,743
Interest cost		8,713
Actuarial loss		453
Amendments		20
Benefits paid		(5,159	)
Benefits curtailed		(8,033	)
Change in discount rate		(1,613	)
Net increase (decrease)		(876	)
Projected benefit obligation at
July 31, 2009	$	241,669

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

Service cost	$	1,877		$	1,547		$	5,736		$	3,055
Interest cost		3,679			3,165			11,036			5,625
Expected return on plan assets		(3,638	)		(3,644	)		(10,553	)		(6,790	)
Prior service cost		25			41			108			123
Net loss		637			—			2,140			—
Curtailment expense		320			—			320			—

Net periodic benefit cost	$	2,900		$	1,109		$	8,787		$	2,013

We made a $0.5 million contribution to the Plans in the first quarter of 2009, a $3.9 million contribution to the Plans in the second quarter of 2009, and a $12.5 million contribution to the Plans during the third quarter of 2009. There are no additional contributions anticipated to be made to the Plans for 2009. We anticipate additional contributions totaling approximately $7.7 million in 2010.

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in our Healthcare Plans and who meet certain eligibility requirements are entitled to certain postretirement healthcare benefits.

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,
	2009			2008			2009			2008

Service cost	$	260		$	226		$	780		$	476
Interest cost		542			503			1,626			937
Expected return on plan assets		(56	)		(43	)		(168	)		(43	)
Prior service benefit		(22	)		—			(66	)		—
Net transition obligation		15			15			45			45
Net gain		(8	)		(20	)		(24	)		(60	)

Net periodic benefit cost	$	731		$	681		$	2,193		$	1,355

We anticipate that we will make aggregate contributions to the Healthcare Plans for the 2009 and 2010 fiscal years of approximately $2.8 million and $3.0 million, respectively. The contributions are expected to be made in the form of benefits payments.

It has been determined that our post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was approximately $0.1 million and $0.3 million for the three and nine month periods ended September 30, 2009.

Supplemental Non-qualified Defined Benefit Plans

Additionally, we have various supplemental retirement plans for key executives (“Supplemental Plans”). The Supplemental Plans are non-qualified defined benefit plans.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008

Service cost	$	117	$	112	$	351	$	336
Interest cost		344		311		1,032		933
Prior service cost		1		3		3		9
Net loss		147		142		441		426

Net periodic benefit cost	$	609	$	568	$	1,827	$	1,704

We anticipate that we will make aggregate contributions to the Supplemental Plans for the 2009 fiscal year of approximately $1.0 million. The contributions are expected to be made in the form of benefit payments.

(12)	SUMMARY OF INFORMATION RELATING TO SEGMENTS OF OUR BUSINESS

Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of September 30, 2009, substantially all of our operations and assets are located within the United States.

The Utilities Group includes two reportable segments: Electric Utilities and Gas Utilities. We manage our electric and gas utility businesses predominantly by state; however, because our electric utilities and our gas utilities have similar economic characteristics, we aggregate our electric (and combination) utility businesses in the Electric Utilities reporting segment and our gas utility businesses in the Gas Utilities reporting segment. Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric, and the regulated electric and natural gas utility operations of Cheyenne Light. The natural gas operations within our combination utility, Cheyenne Light, have historically provided relatively stable gross margins and overall financial results. Periodic variances are therefore rarely expected to significantly impact the operating results for the Electric Utilities segment. Presentation of prior periods has been adjusted to reflect the combination of Black Hills Power and Cheyenne Light within the Electric Utilities segment. Gas Utilities, acquired on July 14, 2008, consists of the operating results of the regulated natural gas utility operations of Colorado Gas, Iowa Gas, Kansas Gas, and Nebraska Gas.

We conduct our operations through the following six reportable segments:

Utilities Group –

· Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyoming and vicinity; and

· Gas Utilities, which supplies natural gas utility service in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group –

· Oil and Gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region and other states;

· Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming and Idaho. Our Power Generation segment has also entered into a 20-year PPA to supply Colorado Electric with 200 MW of capacity and energy from power plants to be constructed in Colorado and which are expected to be placed into service by December 31, 2011;

· Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyoming; and

· Energy Marketing, which markets natural gas, crude oil and related services primarily in the western and central regions of the United States and Canada.

Segment information follows the same accounting policies as described in Note 1 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K. In accordance with accounting standards for regulated operations, intercompany fuel sales to the regulated utilities are not eliminated.

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

	Three Months Ended
	September 30, 2009						September 30, 2008
	External			Inter-segment			External		Inter-segment
	Operating			Operating			Operating		Operating
	Revenues			Revenues			Revenues		Revenues

Utilities:
Electric Utilities	$	128,943		$	223		$	136,644	$	334
Gas Utilities		62,691			—			83,937		—
Non-regulated Energy:
Oil and Gas		17,887			—			25,438		—
Power Generation		7,538			—			11,704		—
Coal Mining		8,284			6,903			8,103		7,928
Energy Marketing		(5,259	)		—			19,196		—
Inter-segment eliminations		—			(1,411	)		—		(1,392	)

Total	$	220,084		$	5,715		$	285,022	$	6,870

	Nine Months Ended
	September 30, 2009					September 30, 2008
	External		Inter-segment			External		Inter-segment
	Operating		Operating			Operating		Operating
	Revenues		Revenues			Revenues		Revenues

Utilities:
Electric Utilities	$	384,607	$	653		$	329,512	$	1,004
Gas Utilities		412,366		—			83,937		—
Non-regulated Energy:
Oil and Gas		52,227		—			85,770		—
Power Generation		22,372		—			29,079		—
Coal Mining		23,967		19,115			23,979		17,946
Energy Marketing		9,299		—			30,465		—
Inter-segment eliminations		—		(3,516	)		—		(3,677	)

Total	$	904,838	$	16,252		$	582,742	$	15,273

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

Income (loss) from continuing
operations
Utilities:
Electric Utilities	$	10,537		$	10,765		$	24,395		$	30,485
Gas Utilities		(3,484	)		(1,854	)		14,223			(1,854	)
Non-regulated Energy:
Oil and Gas		(149	)		1,517			(25,740	)(a)		11,266
Power Generation		575			3,197			18,487	(b)		1,828
Coal Mining		2,256			1,092			2,575			3,217
Energy Marketing		(4,404	)		6,902			(1,156	)		7,565
Corporate		(9,110	)(c)		(2,061	)		13,205	(c)		(7,889	)
Inter-segment eliminations		(74	)		(36	)		364			(76	)

Total	$	(3,853	)	$	19,522		$	46,353		$	44,542

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(a)

As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment in the first quarter of 2009. The lower prices at March 31, 2009 resulted in a $27.8 million after-tax decrease in the full cost accounting method’s ceiling limit for capitalized oil and gas property costs. The write-down in the net carrying value of our natural gas and crude oil properties was recorded as Impairment of long-lived assets and was based on the March 31, 2009 NYMEX price of $3.63 per Mcf, adjusted to $2.23 per Mcf at the wellhead, for natural gas; and NYMEX price of $49.66 per barrel, adjusted to $45.32 per barrel at the wellhead, for crude oil.

(b)	Includes $16.9 million after-tax gain on sale to MEAN of 23.5% ownership interest in Wygen I power generation facility.

(c)	Includes $8.7 million net mark-to-market loss for the three months ended September 30, 2009 and a $37.8 million net mark-to-market gain for the nine months ended September 30, 2009.

Three Months Ended

Nine Months Ended

September 30,

2009