Edgar Filing: BLACK HILLS CORP /SD/

WebFilings | EDGAR view

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, 2010.
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 x		No o

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 x		No o

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 x		Accelerated filer o


	Non-accelerated filer o		Smaller reporting company 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 29, 2010

Common stock, $1.00 par value	39,248,927 shares


TABLE OF CONTENTS
		Page
	Glossary of Terms and Abbreviations and Accounting Standards	3

PART I.	FINANCIAL INFORMATION	5

Item 1.	Financial Statements	5

	Condensed Consolidated Statements of Income - unaudited
	Three and Nine Months Ended September 30, 2010 and 2009	5

	Condensed Consolidated Balance Sheets - unaudited
	September 30, 2010, December 31, 2009 and September 30, 2009	6

	Condensed Consolidated Statements of Cash Flows - unaudited
	Nine Months Ended September 30, 2010 and 2009	8

	Notes to Condensed Consolidated Financial Statements - unaudited	9

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	43

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	83

Item 4.	Controls and Procedures	88

PART II.	OTHER INFORMATION	89

Item 1.	Legal Proceedings	89

Item 1A.	Risk Factors	89

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	93

Item 5.	Other Information	93

Item 6.	Exhibits	95

	Signatures	96

	Exhibit Index	97

GLOSSARY OF TERMS AND ABBREVIATIONS

AND ACCOUNTING STANDARDS

The following terms and abbreviations and accounting standards 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
Annexation Agreement	Agreement with the City of Pueblo, Colorado under which the City of Pueblo annexed the property on which Colorado Electric and Colorado IPP are constructing their generation facilities
AOCI	Accumulated Other Comprehensive Income (Loss)
Aquila	Aquila, Inc.
ASC	Accounting Standards Codification
ASC 310-10-50	ASC 310-10-50, "Disclosures About the Credit Quality of Financing Receivables and the Allowance for Credit Losses"
ASC 810-10-15	ASC 810-10-15, "Consolidation of Variable Interest Entities"
ASC 820	ASC 820, "Fair Value Measurements and Disclosures"
ASC 932-10-S99	ASC 932-10-S99, "Extractive Activities - Oil and Gas, SEC Materials"
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHCRPP	Black Hills Corporation Risk Policies and Procedures
BHEP	Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Blackbox	Blackbox settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
Black Hills Electric Generation	Black Hills Electric Generation, LLC, representing our Power Generation segment, 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
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
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu	British thermal unit
CFTC	Commodities Futures and Trading Commission
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Company
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
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
Colorado IPP	Black Hills Colorado IPP, a direct wholly-owned subsidiary of Black Hills Electric Generation
Corporate Credit Facility	Our $525 million credit facility which was terminated on April 15, 2010
CPUC	Colorado Public Utilities Commission


De-designated interest rate swaps	The $250.0 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but subsequently de-designated in December 2008
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE	U.S. Department of Energy
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
EDF	EDF Trading North America, LLC
Enserco	Enserco Energy Inc., representing our Energy Marketing segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse Gases
GSRS	Gas Safety and Reliability Surcharge
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
IPP	Independent Power Producer
IPP Transaction	Our July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings Fund Management Ltd and IIF BH Investment LLC
IRS	Internal Revenue Service
IUB	Iowa Utilities Board
JPB	Consolidated Wyoming Municipalities Electric Power System Joint Powers 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
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	One thousand standard cubic feet
Mcfe	One thousand standard 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
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
Participation Agreement	Amended and Restated Wygen III Participation Agreement dated July 14, 2010 between BHP, MDU and JPB, which includes JPB as partial owner of Wygen III
PGA	Purchase Gas Adjustment
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordability Care Act
Revolving Credit Facility	Our $500 million three-year revolving credit facility which commenced on April 15, 2010 and expires on April 14, 2013
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
SEC Release No. 33-8995	SEC Release No. 33-8995, "Modernization of Oil and Gas Reporting"
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands, except per share amounts)
Operating revenues	$	264,355		$	225,799		$	977,978		$	921,090

Operating expenses:
Fuel and purchased power	103,250			94,120			468,937			467,309
Operations and maintenance	39,719			35,431			121,861			115,226
Gain on sale of operating assets	(6,238		)	—			(8,921		)	(25,971		)
Administrative and general	38,709			38,344			124,201			117,817
Depreciation, depletion and amortization	30,036			29,824			88,691			92,535
Taxes, other than income taxes	10,937			11,171			34,730			34,680
Impairment of long-lived assets	—			—			—			43,301
Total operating expenses	216,413			208,890			829,499			844,897

Operating income	47,942			16,909			148,479			76,193

Other income (expense):
Interest expense	(24,279		)	(20,691		)	(68,667		)	(62,930		)
Interest rate swap - unrealized (loss) gain	(13,710		)	(8,694		)	(41,663		)	37,775
Interest income	199			327			529			1,184
Allowance for funds used during construction - equity	375			2,598			2,663			5,284
Other income, net	539			2,142			2,225			3,779
Total other income (expenses)	(36,876		)	(24,318		)	(104,913		)	(14,908		)

Income (loss) from continuing operations before equity in earnings (loss) of unconsolidated subsidiaries and income taxes	11,066			(7,409		)	43,566			61,285
Equity in earnings (loss) of unconsolidated subsidiaries	(137		)	119			1,471			1,368
Income tax benefit (expense)	1,461			3,437			(9,872		)	(16,300		)

Income (loss) from continuing operations	12,390			(3,853		)	35,165			46,353
Income from discontinued operations, net of taxes	—			1,673			—			2,439
Net income (loss)	$	12,390		$	(2,180	)	$	35,165		$	48,792

Weighted average common shares outstanding:
Basic	38,933			38,643			38,895			38,584
Diluted	39,133			38,643			39,052			38,646

Earnings (loss) per share:
Basic-
Continuing operations	$	0.32		$	(0.10	)	$	0.90		$	1.20
Discontinued operations	—			0.04			—			0.06
Total earnings (loss) per share - basic	$	0.32		$	(0.06	)	$	0.90		$	1.26

Diluted-
Continuing operations	$	0.32		$	(0.10	)	$	0.90		$	1.20
Discontinued operations	—			0.04			—			0.06
Total earnings (loss) per share - diluted	$	0.32		$	(0.06	)	$	0.90		$	1.26

Dividends paid per share of common stock	$	0.360		$	0.355		$	1.080		$	1.065

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, 2010			December 31, 2009			September 30, 2009
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	58,975		$	112,901		$	137,681
Restricted cash	17,082			17,502			6
Accounts receivables, net	234,480			274,489			208,563
Materials, supplies and fuel	145,251			123,322			99,952
Derivative assets, current	71,688			37,747			56,951
Income tax receivable, net	25,156			2,031			—
Deferred income tax asset, current	15,073			4,523			13,221
Regulatory assets, current	55,941			25,085			12,775
Other current assets	20,932			27,270			31,565
Total current assets	644,578			624,870			560,714

Investments	17,981			18,524			19,462

Property, plant and equipment	3,243,641			2,975,993			2,891,102
Less accumulated depreciation and depletion	(880,938		)	(815,263		)	(795,378		)
Total property, plant and equipment, net	2,362,703			2,160,730			2,095,724

Other assets:
Goodwill	353,734			353,734			353,734
Intangible assets, net	4,129			4,309			4,725
Derivative assets, non-current	12,762			3,777			5,438
Regulatory assets, non-current	124,134			135,578			120,677
Other assets, non-current	20,216			16,176			7,861
Total other assets	514,975			513,574			492,435

TOTAL ASSETS	$	3,540,237		$	3,317,698		$	3,168,335

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

(Continued)

(unaudited)


	September 30, 2010			December 31, 2009			September 30, 2009
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	201,072		$	229,352		$	184,208
Accrued liabilities	166,977			151,504			150,042
Derivative liabilities, current	108,318			57,166			68,634
Accrued income taxes, net	—			—			15,734
Regulatory liabilities, current	12,368			7,092			30,120
Notes payable	145,000			164,500			350,500
Current maturities of long-term debt	5,314			35,245			32,091
Total current liabilities	639,049			644,859			831,329

Long-term debt, net of current maturities	1,188,293			1,015,912			719,215

Deferred credits and other liabilities:
Deferred income tax liability, non-current	279,315			262,034			228,715
Derivative liabilities, non-current	25,892			11,999			27,824
Regulatory liabilities, non-current	79,393			42,458			40,168
Benefit plan liabilities	122,178			140,671			135,027
Other deferred credits and other liabilities	125,710			114,928			123,527
Total deferred credits and other liabilities	632,488			572,090			555,261

Stockholders' equity:
Common stockholders' equity —
Common stock $1 par value; 100,000,000 shares authorized; Issued 39,243,257; 38,977,526 and 38,872,925 shares, respectively	39,243			38,978			38,873
Additional paid-in capital	597,108			591,390			588,556
Retained earnings	466,691			473,857			454,907
Treasury stock at cost – 7,905; 8,834 and 7,605 shares, respectively	(226		)	(224		)	(197		)
Accumulated other comprehensive loss	(22,409		)	(19,164		)	(19,609		)
Total stockholders' equity	1,080,407			1,084,837			1,062,530

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,540,237		$	3,317,698		$	3,168,335

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,
	2010			2009
Operating activities:	(in thousands)

Net income	$	35,165		$	48,792
Income from discontinued operations, net of taxes	—			(2,439		)
Income from continuing operations	35,165			46,353
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	88,691			92,535
Impairment of long-lived assets	—			43,301
Derivative fair value adjustments	(10,690		)	19,647
Gain on sale of operating assets	(8,921		)	(25,971		)
Stock compensation	2,908			1,747
Unrealized mark-to-market loss (gain) on interest rate swaps	41,663			(37,775		)
Deferred income taxes	32,366			5,164
Equity in (earnings) loss of unconsolidated subsidiaries	(1,471		)	(1,368		)
Allowance for funds used during construction - equity	(2,663		)	(5,284		)
Employee benefit plans	12,214			12,807
Other non-cash adjustments	6,663			(126		)
Change in operating assets and liabilities:
Materials, supplies and fuel	(40,344		)	23,210
Accounts receivable and other current assets	8,754			157,118
Accounts payable and other current liabilities	(21,295		)	(101,902		)
Regulatory assets	(2,205		)	31,081
Regulatory liabilities	7,176			23,191
Contributions to defined pension plans	(30,015		)	(16,945		)
Other operating activities	7,765			1,588
Net cash provided by operating activities of continuing operations	125,761			268,371
Net cash provided by operating activities of discontinued operations	—			2,556
Net cash provided by operating activities	125,761			270,927

Investing activities:
Property, plant and equipment additions	(323,883		)	(245,114		)
Proceeds from sale of ownership interest in operating assets	68,105			84,661
Payment for acquisition of business	(2,250		)	—
Working capital adjustment of purchase price allocation on Aquila assets	—			7,098
Other investing activities	4,273			1,933
Net cash used in investing activities	(253,755		)	(151,422		)

Financing activities:
Dividends paid	(42,331		)	(41,338		)
Common stock issued	3,073			2,338
Short-term borrowings - issuances	451,500			484,500
Short-term borrowings - repayments	(471,000		)	(837,800		)
Long-term debt - issuances	200,000			248,500
Long-term debt - repayments	(57,550		)	(2,024		)
Other financing activities	(9,624		)	(4,532		)
Net cash provided by (used in) financing activities	74,068			(150,356		)

Decrease in cash and cash equivalents	(53,926		)	(30,851		)

Cash and cash equivalents:
Beginning of period	112,901			168,532
End of period	$	58,975		$	137,681

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 2009 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," or "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 2009 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying condensed quarterly financial statements reflects all estimates which are, in the opinion of management, necessary for a fair presentation of the September 30, 2010, December 31, 2009 and September 30, 2009 financial information and are of a normal recurring nature. 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, 2010 and September 30, 2009, and our financial condition as of September 30, 2010 and December 31, 2009, 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.

Certain prior year data presented in the financial statements have been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.

(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards

Extractive Activities — Oil and Gas Reserves (SEC Release #33-8995), ASC 932-10-S99

The FASB issued an accounting standards update which aligns the oil and gas reserve estimation and disclosure requirements with the SEC released Final Rule, "Modernization of Oil and Gas Reporting" amending the existing Regulation S-K and Regulation S-X reporting requirements 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 oil and gas prices used to determine reserves from the period-end price to a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months before the end of the reporting period. The amendment was effective for reporting periods ending on or after December 31, 2009. The implementation of this SEC requirement resulted in additional depletion expense of $1.3 million in the fourth quarter of 2009.

Consolidation of Variable Interest Entities, ASC 810-10-15

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 requires 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 with ongoing re-evaluation. The adoption of this standard in January 2010 did not have any impact on our consolidated financial statements, results of operations, and cash flows.

Fair Value Measurements, ASC 820

In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements, disclosure of inputs and techniques used in valuation and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The guidance requires additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 14 of the accompanying Notes to Condensed Consolidated Financial Statements.

Recently Issued Accounting Standards and Legislation

Patient Protection and Affordable Care Act

In March 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the PPACA as amended by the Healthcare and Education Reconciliation Act. The potential impact on the Company, if any, cannot be determined until regulations are promulgated under the PPACA. Included among the provisions of the PPACA is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which affects our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The impact of this change in the tax treatment of the subsidy had an immaterial effect on our financial position, results of operations and cash flows. The Company will continue to assess the accounting implications of the PPACA as related regulations and interpretations become available.

Dodd-Frank Wall Street Reform and Consumer Protection Act

In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated, including swap transactions in the over-the-counter market. Among other things, Dodd-Frank (i) mandates the clearing of some swaps through regulated central clearing organizations and the trading of clearing swaps through regulated exchanges or swap execution facilities, in each case subject to certain key exemptions, and (ii) authorizes regulators to establish collateral and margin requirements for certain swap transactions that are not cleared. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users, and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required over the next several months to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank, and we will continue to evaluate the impact as these rules become available.

Disclosures About the Credit Quality of Financing Receivables and the Allowance for Credit Losses (ASC 310-10-50)

In July 2010, the FASB issued an amendment to ASC 310-10-50, Receivables - Disclosures. The guidance requires additional disclosures that will facilitate financial statement user's evaluation of the nature of credit risk inherent in financing receivables, how that risk is analyzed in arriving at the allowance for credit losses, and the reason for any changes in the allowance for credit losses. These disclosures should be provided on a disaggregated basis but exempts trade receivables that have a contractual maturity of one year or less, receivables measured at lower of cost or fair value, and receivables measured at fair value with the changes in fair value reported in earnings. We are currently evaluating the disclosure requirements of this amendment. It is effective for interim and annual reporting periods ending on or after December 15, 2010.

(3) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION


	Nine Months Ended
	September 30, 2010			September 30, 2009
	(in thousands)
Non-cash investing activities—
Property, plant and equipment acquired with accrued liabilities	$	37,661		$	31,202
Cash (paid) refunded during the period for—
Interest (net of amounts capitalized)	$	(62,740	)	$	(50,311	)
Income taxes	$	(488	)	$	23,311

(4) MATERIALS, SUPPLIES AND FUEL

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


Major Classification	September 30, 2010		December 31, 2009		September 30, 2009
Materials and supplies	$	31,192	$	31,535	$	31,650
Fuel - Electric Utilities	9,056		7,128		7,234
Natural gas in storage — Gas Utilities	36,782		24,053		29,943
Gas and oil held by Energy Marketing*	68,221		60,606		31,125
Total materials, supplies and fuel	$	145,251	$	123,322	$	99,952

_____________

* As of September 30, 2010, December 31, 2009 and September 30, 2009, market adjustments related to natural gas held by Energy Marketing and recorded in inventory were $(18.7) million, $(0.3) million and $(1.3) million, respectively (see Note 13 for further discussion of Energy Marketing trading activities).

(5) ACCOUNTS RECEIVABLE AND 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 primarily due to the seasonality of our regulated Gas Utilities and volumes and commodity prices at our Energy Marketing segment. In addition at September 30, 2010, our trade receivables include $25 million on deposit with a counterparty related to interest rate swaps. During October 2010, this cash collateral posting was replaced with a letter of credit. We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade accounts. We regularly review our trade receivables allowance by considering such factors as historical experience, credit-worthiness, the age of the account balances and current economic conditions that may affect our ability to collect.

Following is a summary of receivables (in thousands):


	September 30, 2010			December 31, 2009			September 30, 2009
Accounts receivable, trade	$	207,707		$	217,723		$	186,123
Unbilled revenues	29,066			61,387			27,942
Total accounts receivable	236,773			279,110			214,065
Less allowance for doubtful accounts	(2,293		)	(4,621		)	(5,502		)
Accounts receivable, net	$	234,480		$	274,489		$	208,563

(6) NOTES PAYABLE

Our credit facilities and debt securities contain certain restrictive covenants including, among others, recourse leverage ratios and consolidated net worth covenants. As of September 30, 2010, we were in compliance with these covenants. None of our facilities or debt securities contain default provisions pertaining to our credit ratings.

Revolving Credit Facility

On April 15, 2010, we terminated our $525 million Corporate Credit Facility and entered into a new $500 million Revolving Credit Facility expiring April 14, 2013. The new facility contains an accordion feature which allows us to increase the capacity of the new facility to $600 million and can be used for the issuance of letters of credit, to fund working capital needs and other corporate purposes. The covenants and events of default are substantially the same as the prior facility, except the minimum interest expense coverage ratio covenant was eliminated. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit are 1.75%, 2.75% and 2.75%, respectively at September 30, 2010. The new facility contains a commitment fee to be charged on the unused amount of the Facility. Based upon current credit ratings, the fee is 0.5%.

Deferred financing costs of $4.7 million are being amortized over the three-year term of the facility and included in Interest expense on the accompanying Condensed Consolidated Income Statement are as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Amortization Expense	$	481	$	148	$	866	$	445

The Revolving Credit Facility includes the following covenants that we must comply with at the end of each quarter (dollars, in thousands). We were in compliance with these covenants as of September 30, 2010.


	Actual			Covenant Requirement
Consolidated Net Worth	$	1,080,407		$	842,506
Recourse leverage ratio	56.1		%	65.0		%

Enserco Credit Facility

In May 2010, Enserco entered into an agreement for a two-year $250 million committed credit facility. The facility contains an accordion feature which allows us, with the consent of the administrative agent, to increase commitments under the facility to $350 million. This facility replaces the $300 million credit facility which expired on May 7, 2010. Maximum borrowings under the facility are subject to a sub-limit of $50 million. Borrowings under this facility are available under a base rate option or a Eurodollar option. Margins for base rate borrowings are 1.75% and for Eurodollar borrowings are 2.50%.

At September 30, 2010, $131.5 million of letters of credit were issued and outstanding under this facility and there were no cash borrowings outstanding.

Deferred financing costs of $2.1 million were recorded for the Enserco Credit Facility and are being amortized over the term of the Enserco Credit Facility. Amortization of deferred financing costs included in Interest expense on the accompanying Condensed Consolidated Statement of Income was as follows (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

Amortization expense	$	263	$	540	$	1,245	$	982

The June 1, 2010 coal marketing acquisition (see Note 20) included certain contractual positions that caused Enserco to temporarily not be in compliance with one of the non-financial covenants to the Enserco Credit Facility as of June 30, 2010. The Enserco Credit Facility limited the net fixed price volume of coal to 1.0 million tons. As of June 30, 2010, Enserco was above that limit. In July, the participating banks waived the non-compliance with this covenant and increased the permitted net fixed price volume of coal allowed to 2.25 million tons for July 2010 and 2.0 million tons thereafter. Enserco was in compliance with this covenant as of September 30, 2010.

In September 2010, the Enserco Credit Facility was amended to allow for trading of electric power, renewable energy credits and emissions credits.

(7) LONG-TERM DEBT

Black Hills Power Series AC Bonds

In February 2010, the Black Hills Power Series AC bonds matured. These were paid in full for $30.0 million of principal plus accrued interest of $1.2 million.

Black Hills Power Series Y Bonds

In March 2010, Black Hills Power completed redemption of its Series Y 9.49% bonds in full. The bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which includes the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Consolidated Balance Sheets and is being amortized over the remaining term of the original bonds.

Black Hills Power Series Z Bonds

In June 2010, Black Hills Power completed redemption of its Series Z 9.35% bonds in full. The bonds were originally due in 2021. A total of $21.8 million was paid on June 1, 2010, which included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Consolidated Balance Sheets and is being amortized over the remaining term of the original bonds.

$200 Million Debt Offering

On July 16, 2010, pursuant to a public offering, we issued $200 million aggregate principal of senior unsecured notes due in 2020. The notes were priced at par and carry a fixed interest rate of 5.875%. We received proceeds of $198.7 million, net of underwriting fees. Deferred financing costs of $1.7 million are being amortized over the 10-year term of the debt. Proceeds were used to pay down a portion of borrowings on our Revolving Credit Facility and to reduce issued letters of credit.

(8) EARNINGS PER SHARE

Basic earnings per share from continuing operations are 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, used to compute earnings per share, is as follows (in thousands, except per share amounts):


Period ended September 30, 2010	Three Months			Nine Months
	Income		Average Shares	Income		Average Shares

Income from continuing operations	$	12,390		$	35,165

Basic earnings	$	12,390	38,933	$	35,165	38,895
Dilutive effect of:
Restricted stock	—		131	—		110
Options	—		12	—		9
Other	—		57	—		39
Diluted earnings	$	12,390	39,133	$	35,165	39,052

Diluted earnings per share from continuing operations	$	0.32		$	0.90


Period ended September 30, 2009	Three Months				Nine Months
	Income			Average Shares	Income		Average 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 (loss) earnings	$	(3,853	)	38,643	$	46,353	38,646

Diluted (loss) earnings per share from continuing operations	$	(0.10	)		$	1.20

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 September 30,		Nine Months Ended September 30,
	2010	2009	2010	2009
Options to purchase common stock	128	374	169	484
Restricted stock	2	1	2	11
Other	1	53	1	56
	131	428	172	551

(9) OTHER COMPREHENSIVE INCOME (LOSS)

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


	Three Months Ended September 30, 2010
Net income			$	12,390
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustments	—
Taxes	—
Minimum pension liability adjustments, net of tax			—

Fair value adjustment on derivatives designated as cash flow hedges	517
Taxes	486
Fair value adjustment on derivatives designated as cash flow hedges, net of tax			1,003

Reclassification adjustments on cash flow hedges settled and included in net income (loss)	(4,730	)
Taxes	1,761
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax			(2,969		)

Comprehensive income			$	10,424


	Three Months Ended September 30, 2009
Net loss			$	(2,180	)
Other comprehensive (loss) income, net of tax:
Minimum pension liability adjustments	5,670
Taxes	(1,999	)
Minimum pension liability adjustments, net of tax			3,671

Fair value adjustment on derivatives designated as cash flow hedges	(15,981	)
Taxes	5,670
Fair value adjustment on derivatives designated as cash flow hedges, net of tax			(10,311		)

Reclassification adjustments on cash flow hedges settled and included in net income (loss)	5,394
Taxes	(1,948	)
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax			3,446

Comprehensive loss			$	(5,374	)


	Nine Months Ended September 30, 2010
Net income			$	35,165
Other comprehensive income, net of tax:
Minimum pension liability adjustments	(8	)
Taxes	(7	)
Minimum pension liability adjustments, net of tax			(15		)

Fair value adjustment on derivatives designated as cash flow hedges	495
Taxes	641
Fair value adjustment on derivatives designated as cash flow hedges, net of tax			1,136

Reclassification adjustments on cash flow hedges settled and included in net income	(6,909	)
Taxes	2,543
Reclassification adjustments on cash flow hedges settled and included in net income, net of tax			(4,366		)

Comprehensive income			$	31,920


	Nine Months Ended September 30, 2009
Net income			$	48,792
Other comprehensive income, net of tax:
Minimum pension liability adjustments	5,670
Taxes	(1,999	)
Minimum pension liability adjustments, net of tax			3,671

Fair value adjustment on derivatives designated as cash flow hedges	(23,704	)
Taxes	8,598
Fair value adjustment on derivatives designated as cash flow hedges, net of tax			(15,106		)

Reclassification adjustments on cash flow hedges settled and included in net income	16,617
Taxes	(6,008	)
Reclassification adjustments on cash flow hedges settled and included in net income, net of tax			10,609

Comprehensive income			$	47,966

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


	September 30, 2010			December 31, 2009			September 30, 2009
Derivatives designated as cash flow hedges	$	(12,741	)	$	(9,462	)	$	(9,037	)
Employee benefit plans	(9,636		)	(9,636		)	(10,456		)
Amount from equity-method investees	(32		)	(66		)	(116		)
Total	$	(22,409	)	$	(19,164	)	$	(19,609	)

(10) COMMON STOCK

Other than the following transactions, we had no material changes in our common stock during the first nine months of 2010 as reported in Note 11 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.

Equity Compensation Plans

•

We granted 77,693 target performance shares to certain officers and business unit leaders for the January 1, 2010 through December 31, 2012 performance period. Actual shares are not issued until the end of the performance plan period (December 31, 2012). 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, the ending stock price must be at least equal to 75% of the beginning stock price for a payout to occur. 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 $24.25 per share.


•	We issued 9,625 shares of common stock under the 2009 short-term incentive compensation plan during the nine months ended September 30, 2010. Pre-tax compensation cost related to the awards was approximately $0.3 million, which was accrued for in 2009.


•	We granted 172,674 restricted common shares during the nine months ended September 30, 2010. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $4.7 million will be recognized over the three-year vesting period.


•	30,000 stock options were exercised during the nine months ended September 30, 2010 at a weighted-average exercise price of $21.875 per share which provided $0.7 million of proceeds.

Total compensation expense recognized for all equity compensation plans for the three months ended September 30, 2010 and 2009 was $1.9 million and $1.1 million, respectively, and for the nine months ended September 30, 2010 and 2009 was $4.7 million and $2.9 million, respectively.

As of September 30, 2010, total unrecognized compensation expense related to non-vested stock awards was $8.2 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 82,875 new shares at a weighted-average price of $29.17 during the nine months ended September 30, 2010. At September 30, 2010, 213,107 shares of unissued common stock were available for future offering under the Plan.

Dividend Restrictions

Our Revolving Credit Facility contains restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The most restrictive financial covenants include the following: a recourse leverage ratio not to exceed 0.65 to 1.00 and a minimum consolidated net worth of $625 million plus 50% of aggregate consolidated net income, if positive, since January 1, 2005. As of September 30, 2010, we were in compliance with the above covenants.

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. The following restrictions on distributions from our subsidiaries existed as of September 30, 2010:


•	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 be subject to further restrictions under the Federal Power Act. As of September 30, 2010, the restricted net assets at our Utilities Group were approximately $245.0 million.

•

Our Enserco credit facility is a borrowing base credit facility, the structure of which requires certain levels of tangible net worth and net working capital to be maintained for a given borrowing base election level. In order to maintain a borrowing base election level, Enserco may be restricted from making dividend payments to its parent company. Enserco's restricted net assets at September 30, 2010 were $104.6 million.


•	Pursuant to a covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted assets of $100.0 million. Black Hills Non-regulated Holdings is the parent of Black Hills Electric Generation which is the parent of Black Hills Wyoming.

(11) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (the "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.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Service cost	$	1,533		$	1,877		$	4,599		$	5,736
Interest cost	3,773			3,679			11,319			11,036
Expected return on plan assets	(3,623		)	(3,638		)	(10,869		)	(10,553		)
Prior service cost	305			25			915			108
Net loss	500			637			1,500			2,140
Curtailment expense	—			320			—			320

Net periodic benefit cost	$	2,488		$	2,900		$	7,464		$	8,787

In September 2010, bargaining unit participants in the Black Hills Corporation Pension Plan (the “Plan”) voted to ratify a partial freeze to the Plan which is effective January 1, 2011. The partial freeze eliminates new bargaining unit employees from participation in the Plan, and freezes the benefits of current participants except for the following group: those participants who both 1) are age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently forgo the additional age- and service points-based employer contribution under the Company's 401(k) retirement savings plan. The assets and obligations for the Black Hills Corporation Pension Plan will be revalued at December 31, 2010 during the year-end valuation process and any pre-tax curtailment effect related to this partial freeze will be recorded by the Company in the fourth quarter of 2010. The adjustment is expected to be less than $0.1 million.

Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor three retiree healthcare plans (the "Healthcare Plans"): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are entitled to postretirement healthcare benefits.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Service cost	$	377		$	260		$	1,131		$	780
Interest cost	611			542			1,833			1,626
Expected return on plan assets	(52		)	(56		)	(156		)	(168		)
Prior service benefit	(77		)	(22		)	(231		)	(66		)
Net transition obligation	—			15			—			45
Net loss (gain)	159			(8		)	477			(24		)

Net periodic benefit cost	$	1,018		$	731		$	3,054		$	2,193

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 $0.2 million and $0.1 million for the three and nine months ended September 30, 2010, respectively, and $0.1 million and $0.3 million for the three and nine months ended September 30, 2009, respectively.

Supplemental Non-qualified Defined Benefit Plans

Additionally, we have various supplemental retirement plans for key executives (the "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 September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Service cost	$	171	$	117	$	513	$	351
Interest cost	321		344		963		1,032
Prior service cost	1		1		3		3
Net loss	71		147		213		441

Net periodic benefit cost	$	564	$	609	$	1,692	$	1,827

Contributions

We anticipate that we will make contributions to each of the benefit plans during 2010 and 2011. Contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):


	Contributions Made		Contributions Made
	Three Months Ended September 30, 2010		Nine Months Ended September 30, 2010		Contributions Remaining for 2010		Contributions Anticipated for 2011
Defined Benefit Pension Plans	$	30,000	$	30,015	$	—	$	5,100
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	950	$	2,850	$	950	$	4,000
Supplemental Non-Qualified Defined Benefit Plans	$	223	$	669	$	223	$	900

(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, 2010, substantially all of our operations and assets were located within the United States.

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. Additionally, in 2009 our Power Generation segment entered into a 20-year PPA to supply Colorado Electric with 200 MW of capacity and energy from power plants under construction in Colorado, 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 coal and related services in the United States and Canada. Additionally, during the third quarter of 2010, Enserco expanded business lines to include power and environmental marketing.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K. In accordance with accounting standards for regulated operations, intercompany fuel and energy sales to the regulated utilities are not eliminated.

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


Three Months Ended September 30, 2010	External Operating Revenues		Inter-segment Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric ^(a)	$	142,587	$	(942	)	$	18,537
Gas	72,323		—			(595		)
Non-regulated Energy:
Oil and Gas	19,354		—			836
Power Generation	7,855		—			575
Coal Mining	7,744		6,533			1,673
Energy Marketing	8,973		—			1,370
Corporate ^(b)	—		—			(10,093		)
Inter-segment eliminations	—		(72		)	87
Total	$	258,836	$	5,519		$	12,390


Three Months Ended September 30, 2009	External Operating Revenues			Inter-segment Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	128,943		$	223		$	10,537
Gas	62,691			—			(3,484		)
Non-regulated Energy:
Oil and Gas	17,887			—			(149		)
Power Generation	7,538			—			575
Coal Mining	8,284			6,903			2,256
Energy Marketing	(5,259		)	—			(4,404		)
Corporate ^(b)	—			—			(9,110		)
Inter-segment eliminations	—			(1,411		)	(74		)
Total	$	220,084		$	5,715		$	(3,853	)


Nine Months Ended September 30, 2010	External Operating Revenues		Inter-segment Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	426,719	$	—		$	35,585
Gas ^(c)	402,608		—			18,017
Non-regulated Energy:
Oil and Gas	57,755		—			3,405
Power Generation	22,602		—			1,239
Coal Mining	22,431		20,875			6,093
Energy Marketing	27,640		—			4,890
Corporate ^(b)	—		—			(34,221		)
Inter-segment eliminations	—		(2,652		)	157
Total	$	959,755	$	18,223		$	35,165


Nine Months Ended September 30, 2009	External Operating Revenues		Inter-segment Operating Revenues			Income (Loss) from Continuing Operations
Utilities:
Electric	$	384,607	$	653		$	24,395
Gas	412,366		—			14,223
Non-regulated Energy:
Oil and Gas ^(d)	52,227		—			(25,740		)
Power Generation ^(e)	22,372		—			18,487
Coal Mining	23,967		19,115			2,575
Energy Marketing	9,299		—			(1,156		)
Corporate ^(b)	—		—			13,205
Inter-segment eliminations	—		(3,516		)	364
Total	$	904,838	$	16,252		$	46,353

____________

(a) Income (loss) from continuing operations includes a $4.1 million after-tax gain on the sale to the City of Gillette of 23% ownership interest in Wygen III power generation facility. (See Note 19)

(b) Income (loss) from continuing operations includes a $8.9 million and a $27.1 million net after-tax mark-to-market loss on interest rate swaps for the three and nine months ended September 30, 2010 and a $5.7 million net after-tax mark-to-market loss and a $24.6 million net after-tax gain on interest rate swaps for the three and nine months ended September 30, 2009, respectively.

(c) Income (loss) from continuing operations includes a $1.7 million after-tax gain on sale of operating assets at Nebraska Gas. (See Note 19)

(d) As a result of lower natural gas prices at March 31, 2009, our Income (loss) from continuing operations reflects a ceiling test impairment of oil and gas assets of $27.8 million after-tax included in the first quarter of 2009. (See Note 18)

(e) Income (loss) from continuing operations includes a $16.9 million after-tax gain on the sale to MEAN of 23.5% ownership interest in Wygen I power generation facility.


Total assets	September 30, 2010		December 31, 2009		September 30, 2009
Utilities:
Electric	$	1,771,014	$	1,659,375	$	1,592,852
Gas	659,801		684,375		619,855
Non-regulated Energy:
Oil and Gas	358,113		338,470		340,046
Power Generation	249,778		161,856		120,426
Coal Mining	94,149		76,209		79,796
Energy Marketing	287,173		321,207		341,720
Corporate	120,209		76,206		73,640
Total	$	3,540,237	$	3,317,698	$	3,168,335

(13) RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sector expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and counterparty risk. We have developed policies, processes, systems, and controls to manage and mitigate these risks.

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks:


•	Commodity price risk associated with our marketing businesses, our natural long position with crude oil, natural gas and coal reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Gas Utilities segment and from commodity price changes;


•	Interest rate risk associated with variable rate credit facilities and changes in forward interest rates used to determine the mark-to-market adjustment on our interest rate swaps; and


•	Foreign currency exchange risk associated with natural gas marketing transacted in Canadian dollars.

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates, currency exchange rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

We actively manage our exposure to certain market risks as described in Note 3 of the Notes to our Consolidated Financial Statements in our 2009 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are detailed in this Note along with Note 14.

Trading Activities

Natural Gas, Crude Oil and Coal Marketing

We have a natural gas, crude oil and coal marketing business specializing in producer services, end-use origination and wholesale marketing that conducts business in the United States and Canada.

Contracts and other activities at our Energy Marketing operations are accounted for under the accounting standards for energy trading contracts. As such, all of the contracts and other activities at our marketing operations that meet the definition of a derivative are accounted for at fair value. The fair values are recorded as either Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The net gains or losses are recorded as Operating revenues in the accompanying Condensed Consolidated Statements of Income. Accounting for energy trading contracts precludes mark-to-market accounting for energy trading contracts that are not defined as derivatives pursuant to accounting standards for derivatives. As part of our 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 limited circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, accounting for derivatives and hedging generally does not allow us to mark inventory, transportation or storage positions to market. The result is that while a significant majority of our natural gas, crude oil and coal marketing positions are 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 results from these accounting requirements.

To effectively manage our portfolios, we enter into forward physical commodity contracts, financial derivative instruments including over-the-counter swaps and options, and storage and transportation agreements. The business activities of our Energy Marketing segment are conducted within the parameters as defined and allowed in the BHCRPP and further delineated in the Risk Management Policies and Procedures as approved by our Executive Risk Committee. Our trading contracts do not include credit risk-related contingent features that require us to maintain a specific credit rating.

We use a number of quantitative tools to measure, monitor and limit our exposure to market risk in our natural gas, crude oil and coal marketing portfolio. We limit and monitor our market risk through established limits on the nominal size of positions based on type of trade, location and duration. Such limits include those on fixed price, basis, index, storage, transportation and foreign exchange positions.

Daily risk management activities include reviewing positions in relation to established position limits, assessing changes in daily mark-to-market and other non-statistical risk management techniques.

The contract or notional amounts and terms of our natural gas, crude oil and coal marketing activities and derivative commodity instruments were as follows:


	Outstanding at September 30, 2010		Outstanding at December 31, 2009		Outstanding at September 30, 2009
	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)
(in thousands of MMBtus)
Natural gas basis swaps purchased	335,805	25	231,703	22	246,175	25
Natural gas basis swaps sold	358,929	25	232,673	22	242,246	25
Natural gas fixed-for-float swaps purchased	84,636	36	60,927	16	89,371	18
Natural gas fixed-for-float swaps sold	97,210	18	72,904	25	94,619	18
Natural gas physical purchases	135,818	18	120,680	27	150,698	18
Natural gas physical sales	136,530	36	124,830	27	179,134	18
Natural gas options purchased	—	—	—	—	1,227	6
Natural gas options sold	—	—	—	—	1,227	6


	Outstanding at September 30, 2010		Outstanding at December 31, 2009		Outstanding at September 30, 2009
	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)
(in thousands of Bbls)
Crude oil physical purchases	5,561	15	5,048	12	3,263	4
Crude oil physical sales	4,759	15	4,998	12	3,126	4
Crude oil swaps/options purchased	135	1	—	—	—	—
Crude oil swaps/options sold	289	3	69	2	64	3


	Outstanding at September 30, 2010 *
	Notional Amounts	Latest Expiration (months)
(in thousands of tons)
Coal fixed-for-float swaps purchased	5,585	39
Coal fixed-for-float swaps sold	4,445	39
Coal physical purchases	24,100	51