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 March 31, 2011.
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 as of	April 29, 2011

Common stock, $1.00 par value	39,409,489	shares



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

PART I.	FINANCIAL INFORMATION	5

Item 1.	Financial Statements	4

	Condensed Consolidated Statements of Income - unaudited
	Three Months Ended March 31, 2011 and 2010	5

	Condensed Consolidated Balance Sheets - unaudited
	March 31, 2011, December 31, 2010 and March 31, 2010	6

	Condensed Consolidated Statements of Cash Flows - unaudited
	Three Months Ended March 31, 2011 and 2010	8

	Notes to Condensed Consolidated Financial Statements - unaudited	9

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	60

Item 4.	Controls and Procedures	64

PART II.	OTHER INFORMATION	64

Item 1.	Legal Proceedings	64

Item 1A.	Risk Factors	64

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64

Item 5.	Other Information	64

Item 6.	Exhibits	66

	Signatures	67

	Exhibit Index	68

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:



AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
Aquila	Aquila, Inc.
ASC	Accounting Standards Codification
ASC 820	ASC 820, "Fair Value Measurements and Disclosures"
Bbl	Barrel
Bcf	Billion cubic feet
Bcfe	Billion cubic feet equivalent
BHC	Black Hills Corporation
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
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
CPCN	Certificate of Public Convenience and Necessity
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



Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
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
Forward Agreement	Equity Forward Agreement with J. P. Morgan connected to a public offering of 4,000,000 million shares of Black Hills Corporation common stock
GAAP	Generally Accepted Accounting Principles
Global Settlement	Global 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
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
IRS	Internal Revenue Service
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
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
MSHA	Mine Safety and Health Administration
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
PGA	Purchase Gas Adjustment
PPA	Power Purchase Agreement
PPACA	Patient Protection and Affordability Care Act
PSCo	Public Service Company of Colorado
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
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 March 31,
	2011			2010
	(in thousands, except per share amounts)
Operating revenues:
Utilities	$	374,696		$	388,666
Non-regulated energy	28,604			37,834
Total operating revenues	403,300			426,500

Operating expenses:
Utilities -
Fuel, purchased power and cost of gas sold	210,511			236,314
Operations and maintenance	67,409			65,034
Gain on sale of operating assets	—			(2,683		)
Non-regulated energy operations and maintenance	29,211			22,960
Depreciation, depletion and amortization	31,987			28,395
Taxes - property, production and severance	8,218			6,477
Other operating expenses	251			301
Total operating expenses	347,587			356,798

Operating income	55,713			69,702

Other income (expense):
Interest charges -
Interest expense (including amortization of debt issuance costs, premium and discount, realized settlements on interest rate swaps)	(29,735		)	(25,120		)
Allowance for funds used during construction - borrowed	3,363			3,148
Capitalized interest	2,434			206
Interest rate swaps - unrealized (loss) gain	5,465			(3,035		)
Interest income	560			246
Allowance for funds used during construction - equity	295			2,028
Other income, net	731			418
Total other income (expense)	(16,887		)	(22,109		)

Income (loss) from continuing operations before equity in earnings (loss) of unconsolidated subsidiaries and income taxes	38,826			47,593
Equity in earnings (loss) of unconsolidated subsidiaries	993			317
Income tax benefit (expense)	(12,909		)	(16,476		)

Net income (loss)	$	26,910		$	31,434

Weighted average common shares outstanding:
Basic	39,059			38,848
Diluted	39,761			39,009

Total earnings (loss) per share - basic	$	0.69		$	0.81

Total earnings (loss) per share - diluted	$	0.68		$	0.81

Dividends paid per share of common stock	$	0.365		$	0.360

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)



	March 31, 2011			December 31, 2010			March 31, 2010
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	44,016		$	32,438		$	136,023
Restricted cash	3,406			4,260			27,215
Accounts receivable, net	306,070			328,811			242,189
Materials, supplies and fuel	69,341			139,677			91,111
Derivative assets, current	49,295			56,572			54,773
Income tax receivable, net	23,665			—			—
Deferred income tax assets, current	18,362			17,113			5,610
Regulatory assets, current	36,834			66,429			42,876
Other current assets	60,804			25,571			26,189
Total current assets	611,793			670,871			625,986

Investments	17,088			17,780			18,466

Property, plant and equipment	3,461,559			3,359,762			3,045,126
Less accumulated depreciation and depletion	(889,031		)	(864,329		)	(830,423		)
Total property, plant and equipment, net	2,572,528			2,495,433			2,214,703

Other assets:
Goodwill	354,831			354,831			353,734
Intangible assets, net	4,011			4,069			4,248
Derivative assets, non-current	5,135			9,260			5,877
Regulatory assets, non-current	140,735			138,405			117,561
Other assets, non-current	20,907			20,860			18,064
Total other assets	525,619			527,425			499,484

TOTAL ASSETS	$	3,727,028		$	3,711,509		$	3,358,639

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)



	March 31, 2011			December 31, 2010			March 31, 2010
	(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	217,559		$	279,069		$	194,342
Accrued liabilities	141,184			170,301			140,939
Derivative liabilities, current	91,139			79,167			68,834
Accrued income taxes, net	—			779			10,568
Regulatory liabilities, current	15,004			3,943			9,850
Notes payable	287,000			249,000			223,000
Current maturities of long-term debt	4,254			5,181			24,426
Total current liabilities	756,140			787,440			671,959

Long-term debt, net of current maturities	1,184,830			1,186,050			993,514

Deferred credits and other liabilities:
Deferred income tax liability, non-current	303,647			277,136			270,079
Derivative liabilities, non-current	15,554			21,361			12,081
Regulatory liabilities, non-current	90,923			84,611			44,788
Benefit plan liabilities	128,170			124,709			144,199
Other deferred credits and other liabilities	134,617			129,932			114,021
Total deferred credits and other liabilities	672,911			637,749			585,168

Stockholders' equity:
Common stockholders' equity —
Common stock $1 par value; 100,000,000 shares authorized; Issued 39,434,304; 39,280,048 and 39,178,067 shares, respectively	39,434			39,280			39,178
Additional paid-in capital	601,021			598,805			593,589
Retained earnings	498,614			486,075			491,202
Treasury stock at cost – 26,075; 10,962 and 4,284 shares, respectively	(762		)	(309		)	(112		)
Accumulated other comprehensive loss	(25,160		)	(23,581		)	(15,859		)
Total stockholders' equity	1,113,147			1,100,270			1,107,998

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$	3,727,028		$	3,711,509		$	3,358,639

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)



	Three Months Ended March 31,
	2011			2010
Operating activities:	(in thousands)

Net income (loss)	$	26,910		$	31,434
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	31,987			28,395
Derivative fair value adjustments	9,662			(1,579		)
Gain on sale of operating assets	—			(2,683		)
Stock compensation	2,370			989
Unrealized mark-to-market loss (gain) on interest rate swaps	(5,465		)	3,035
Deferred income taxes	25,679			3,492
Equity in (earnings) loss of unconsolidated subsidiaries	(993		)	(317		)
Allowance for funds used during construction - equity	(295		)	(2,028		)
Employee benefit plans	3,642			3,940
Other adjustments	(1,599		)	2,382

Change in operating assets and liabilities:
Materials, supplies and fuel	79,717			21,755
Accounts receivable and other current assets	(35,605		)	24,044
Accounts payable and other current liabilities	(73,302		)	(24,716		)
Regulatory assets	33,966			3,277
Regulatory liabilities	9,984			2,834

Other operating activities	4,613			(5,335		)
Net cash provided by operating activities	111,271			88,919

Investing activities:
Property, plant and equipment additions	(122,544		)	(81,290		)
Proceeds from sale of ownership interest in operating assets	—			6,105
Other investing activities	786			(2,865		)
Net cash used in investing activities	(121,758		)	(78,050		)

Financing activities:
Dividends paid	(14,371		)	(14,089		)
Common stock issued	605			1,522
Short-term borrowings - issuances	210,000			108,500
Short-term borrowings - repayments	(172,000		)	(50,000		)
Long-term debt - repayments	(2,155		)	(33,217		)
Other financing activities	(14		)	(463		)
Net cash provided by (used in) financing activities	22,065			12,253

Net change in cash and cash equivalents	11,578			23,122

Cash and cash equivalents beginning of period	32,438			112,901
Cash and cash equivalents end of period	$	44,016		$	136,023

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 2010 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 2010 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 adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2011, December 31, 2010 and March 31, 2010 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 months ended March 31, 2011 and our financial condition as of March 31, 2011, December 31, 2010, and March 31, 2010 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. Specifically, (a) the Company has reclassified revenue into two categories: utilities revenue and non-regulated revenues, (b) the categories of Fuel, purchased power and cost of gas sales and Operations and maintenance included in our Operating expenses have also been reclassified into utilities and non-regulated, and (c) the Taxes - property, production and severance line has been reclassified to show only those taxes. Any taxes other than income are now included in the respective utility or non-regulated operations and maintenance lines. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.

Restatement - Subsequent to the issuance of the Company's 2010 financial statements, the Company's management determined that certain intercompany transactions with our rate regulated operations had not been properly eliminated in consolidation, resulting in an overstatement of Utility and Non-regulated revenue and Fuel, purchased power and cost of gas sold of $15.8 million, in aggregate for the three months ended March 31, 2010, respectively. As such, the condensed consolidated financial statements have been restated for the correction of this error. The error did not have an impact on our gross margin, net income, total assets or cash flows.

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

Recently Adopted Accounting Standards

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 were 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 13.

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, potentially including utilities, 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.

(3) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION



	Three Months Ended
	March 31, 2011			March 31, 2010
	(in thousands)
Non-cash investing activities—
Property, plant and equipment acquired with accrued liabilities	$	32,419		$	23,473
Cash (paid) refunded during the period for—
Interest (net of amounts capitalized)	$	(11,817	)	$	(10,182	)
Income taxes, net	$	(24	)	$	44

(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):



	March 31, 2011		December 31, 2010		March 31, 2010
Materials and supplies	$	34,341	$	31,749	$	32,200
Fuel - Electric Utilities	9,307		9,687		9,028
Natural gas in storage — Gas Utilities	2,199		21,691		4,868
Gas and oil held by Energy Marketing*	23,494		76,550		45,015
Total materials, supplies and fuel	$	69,341	$	139,677	$	91,111

_____________

* As of March 31, 2011, December 31, 2010 and March 31, 2010, market adjustments related to natural gas held by Energy Marketing and recorded in inventory as part of fair value hedge transactions were $0.3 million, $(9.1) million and $(11.0) million, respectively (see Note 12 for further discussion of Energy Marketing trading activities).

(5) ACCOUNTS RECEIVABLE

Trade Accounts Receivable

Our Accounts receivable represents primarily customer trade accounts at our Electric Utilities, Gas Utilities and counterparty trade accounts at our Energy Marketing segment. This balance fluctuates primarily due to the seasonality of our 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 accounts receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit-worthiness, the age of the accounts receivable balances and current economic conditions that may affect our ability to collect.

Following is a summary of receivables (in thousands):



March 31, 2011	Accounts Receivable, Trade		Unbilled Revenues		Total Accounts Receivable		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric	$	46,077	$	16,196	$	62,273	$	(728	)	$	61,545
Gas	58,665		21,620		80,285		(1,763		)	78,522
Oil and Gas	7,503		—		7,503		(161		)	7,342
Coal Mining	982		—		982		—			982
Energy Marketing	154,660		—		154,660		(114		)	154,546
Power Generation	2,050		—		2,050		—			2,050
Corporate	1,083		—		1,083		—			1,083
Total	$	271,020	$	37,816	$	308,836	$	(2,766	)	$	306,070



December 31, 2010	Accounts Receivable, Trade		Unbilled Revenues		Total Accounts Receivable		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric	$	51,005	$	19,572	$	70,577	$	(708	)	$	69,869
Gas	41,970		40,376		82,346		(1,425		)	80,921
Oil and Gas	6,213		—		6,213		(161		)	6,052
Coal Mining	2,420		—		2,420		—			2,420
Energy Marketing	157,064		—		157,064		(69		)	156,995
Power Generation	307		—		307		—			307
Corporate	12,247		—		12,247		—			12,247
Total	$	271,226	$	59,948	$	331,174	$	(2,363	)	$	328,811



March 31, 2010	Accounts Receivable, Trade		Unbilled Revenues		Total Accounts Receivable		Less Allowance for Doubtful Accounts			Accounts Receivable, net
Electric	$	45,466	$	13,415	$	58,881	$	(1,346	)	$	57,535
Gas	60,076		19,977		80,053		(2,877		)	77,176
Oil and Gas	6,144		—		6,144		—			6,144
Coal Mining	1,698		—		1,698		—			1,698
Energy Marketing	99,738		—		99,738		(1,008		)	98,730
Power Generation	569		—		569		—			569
Corporate	337		—		337		—			337
Total	$	214,028	$	33,392	$	247,420	$	(5,231	)	$	242,189

Income Tax Receivable

Income tax receivable is primarily comprised of the refund (including an estimate of after-tax interest income) to be received as a result of the settlement reached with IRS in mid-2010 and finalized in early 2011 and estimated payments made at the federal, state, and foreign levels. With respect to the estimated payments, they relate to multiple prior tax years and were included in taxes payable at both March 31, 2010 and December 31, 2010.

(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 March 31, 2011, 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

In April 2010, we entered into a new $500.0 million Revolving Credit Facility expiring April 14, 2013. The facility contains an accordion feature which allows us to, with the consent of the administrative agent, increase the capacity of the facility to $600.0 million. This facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. 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 March 31, 2011. The 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 term of the facility and the amortization expense is included in Interest expense on the accompanying Condensed Consolidated Statements of Income as follows (in thousands):



	Three Months Ended March 31,
	2011		2010
Amortization Expense	$	473	$	—

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 March 31, 2011.



	Actual			Covenant Requirement
Consolidated Net Worth	$	1,113		$	873
Recourse leverage ratio	57.8		%	65.0		%

Enserco Credit Facility

In May 2010, Enserco entered into an agreement for a two-year $250.0 million committed credit facility. The facility contains an accordion feature which allows Enserco, with the consent of the administrative agent, to increase commitments under the facility to $350.0 million. 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%. The facility covenants include tangible net worth, net working capital and realized net working capital requirements. Enserco was in compliance with the covenants of this facility as of March 31, 2011.

At March 31, 2011, $147.1 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 facility. Amortization of deferred financing costs included in Interest expense on the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):



	Three Months Ended March 31,
	2011		2010
Amortization expense	$	268	$	533

Corporate Term Loan

In December 2010, we entered into a one-year $100.0 million term loan (the "Loan") with J.P. Morgan and Union Bank due in December 2011. The cost of borrowing under the Loan was based on a spread of 137.5 basis points over LIBOR (1.69% at March 31, 2011). The covenants are substantially the same as those which are included in the Revolving Credit Facility. We were in compliance with these covenants as of March 31, 2011.

(7) EARNINGS PER SHARE

Basic earnings per share are computed by dividing net income by the weighted-average number of common shares outstanding during the period. Diluted earnings per share are computed by using all dilutive common shares potentially outstanding during a period. A reconciliation of Net income and basic and diluted share amounts, used to compute earnings per share, is as follows (in thousands, except per share amounts):



Period Ended March 31, 2011	Three Months
	Income		Average Shares
Net income	$	26,910	39,059
Dilutive effect of:
Restricted stock	—		132
Options	—		17
Forward Equity Issuance	—		460
Other	—		93
Diluted earnings	$	26,910	39,761

Diluted earnings per share	$	0.68



Period Ended March 31, 2010	Three Months
	Income		Average Shares
Net income	$	31,434	38,848
Dilutive effect of:
Restricted stock	—		89
Options	—		—
Other	—		72
Diluted earnings	$	31,434	39,009

Diluted earnings per share	$	0.81

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 March 31,
	2011	2010
Options to purchase common stock	83	264
Restricted stock	7	—
	90	264

(8) COMPREHENSIVE INCOME (LOSS)

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



	Three Months Ended March 31, 2011
Net income				$	26,910
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives designated as cash flow hedges	$	(3,785	)
Taxes	1,637
Fair value adjustment on derivatives designated as cash flow hedges, net of tax				(2,148		)

Reclassification adjustments on cash flow hedges settled and included in net income (loss)	$	861
Taxes	(292		)
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax				569

Comprehensive income				$	25,331



	Three Months Ended March 31, 2010
Net income				$	31,434
Other comprehensive income (loss), net of tax:
Minimum pension liability adjustments	$	19
Taxes	(7		)
Minimum pension liability adjustments, net of tax				12

Fair value adjustment on derivatives designated as cash flow hedges	$	2,007
Taxes	(591		)
Fair value adjustment on derivatives designated as cash flow hedges, net of tax				1,416

Reclassification adjustments on cash flow hedges settled and included in net income (loss)	$	2,938
Taxes	(1,061		)
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax				1,877

Comprehensive income				$	34,739

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



	March 31, 2011			December 31, 2010			March 31, 2010
Derivatives designated as cash flow hedges	$	(14,016	)	$	(12,437	)	$	(6,182	)
Employee benefit plans	(11,142		)	(11,142		)	(9,624		)
Amount from equity-method investees	(2		)	(2		)	(53		)
Total	$	(25,160	)	$	(23,581	)	$	(15,859	)

(9) COMMON STOCK

Other than the following transactions, we had no material changes in our common stock during the first three months of 2011 from the amount reported in Note 11 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

Equity Compensation Plans

•

We granted 67,389 target performance shares to certain officers and business unit leaders for the January 1, 2011 through December 31, 2013 performance period. Actual shares are not issued until the end of the performance plan period (December 31, 2013). 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, certain stock price performance must be achieved 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 $25.91 per share.


•	We issued 14,111 shares of common stock under the 2010 short-term incentive compensation plan during the three months ended March 31, 2011. Pre-tax compensation cost related to the awards was approximately $0.4 million, which was accrued for in 2010.


•	We granted 125,963 restricted common shares during the three months ended March 31, 2011. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $3.8 million will be recognized over the three-year vesting period.


•	2,500 stock options were exercised during the three months ended March 31, 2011 at a weighted-average exercise price of $30.81 per share which provided $0.1 million of proceeds.

Total compensation expense recognized for all equity compensation plans for the three months ended March 31, 2011 and 2010 was $2.4 million and $1.8 million, respectively.

As of March 31, 2011, total unrecognized compensation expense related to non-vested stock awards was $11.0 million and is expected to be recognized over a weighted-average period of 2.2 years.

Dividend Reinvestment and Stock Purchase Plan

We have a Dividend Reinvestment and Stock Purchase Plan ("DRIP") 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 25,026 new shares at a weighted-average price of $31.07 during the three months ended March 31, 2011. At March 31, 2011, 164,667 shares of unissued common stock were available for future offering under the DRIP 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 March 31, 2011, 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 March 31, 2011:


•	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 March 31, 2011, the restricted net assets at our Utilities Group were approximately $193.7 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 March 31, 2011 were $86.2 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.

Forward Equity Issuance

In November 2010, we entered into a Forward Agreement with J.P. Morgan in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. Under the Forward Agreement on November 10, 2010, we agreed to issue to J.P. Morgan 4,000,000 shares of our common stock at an initial forward price of $28.70875 per share. On December 7, 2010, the underwriters exercised the over-allotment option to purchase an additional 413,519 shares under the same terms as the original Forward Agreement (together with the Forward Agreement, the "Forward Agreements").

Based on the closing Black Hills Corporation common stock price of $33.44 on March 31, 2011, and the forward price on the date for the initial equity forward of $27.95 and over-allotment shares of $27.95, the fair value net cash settlement of the 4,000,000 equity forward instrument and 413,519 over-allotment shares was approximately $24.2 million. The Forward Agreements require a 60-day notice prior to settlement for cash or net share settlements. Forward prices and volume-weighted average market prices for the period between when notice is provided and settlement are used to calculate cash and net share settlement amounts.

We may settle the equity forward instrument at any time up to the maturity date of November 10, 2011. We may also unilaterally elect to cash or net share settle on any date up to maturity, for all or a portion of the equity forward shares. It is our intent to settle the equity forward with the physical delivery of shares in the fourth quarter of 2011.

At March 31, 2011, the equity forward instrument could have been settled with physical delivery of 4,413,519 shares to J.P. Morgan in exchange for cash of $123.4 million. Assuming required notices were given and actions taken, the forward instruments could have also been net settled at March 31, 2011 with delivery of cash of approximately $23.5 million or approximately 706,000 shares of common stock to J.P. Morgan.

(10) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (the "Pension Plans"). One Pension Plan covers certain eligible employees of the following subsidiaries: Black Hills Service Company, Black Hills Power, WRDC and BHEP; one Pension Plan covers certain eligible employees of our subsidiary, Cheyenne Light, and the remaining Pension Plan covers certain eligible employees of Black Hills Energy. The Pension Plan benefits are based on years of service and compensation levels.

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



	Three Months Ended March 31,
	2011			2010
Service cost	$	1,355		$	1,533
Interest cost	3,732			3,773
Expected return on plan assets	(4,239		)	(3,623		)
Prior service cost	25			305
Net loss	1,135			500

Net periodic benefit cost	$	2,008		$	2,488

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 were as follows (in thousands):



	Three Months Ended March 31,
	2011			2010
Service cost	$	375		$	377
Interest cost	542			611
Expected return on plan assets	(41		)	(52		)
Prior service cost (benefit)	(120		)	(77		)
Net loss (gain)	169			159

Net periodic benefit cost	$	925		$	1,018

It has been determined that our post-65 retiree drug prescription plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

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 were as follows (in thousands):



	Three Months Ended March 31,
	2011		2010
Service cost	$	257	$	171
Interest cost	324		321
Prior service cost	1		1
Net loss	127		71

Net periodic benefit cost	$	709	$	564

Contributions

We anticipate that we will make contributions to each of the benefit plans during 2011 and 2012. 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		Anticipated		Anticipated
	Three Months Ended March 31, 2011		Contributions Remaining for 2011		Contributions for 2012
Defined Benefit Pension Plans	$	—	$	550	$	13,431
Non-Pension Defined Benefit Postretirement Healthcare Plans	$	882	$	2,647	$	3,765
Supplemental Non-Qualified Defined Benefit Plans	$	235	$	707	$	896

(11) 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 March 31, 2011, 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 supply 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 supply 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. 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. In January 2011, we sold our ownership interest in the partnership which owned the Idaho facilities;


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


•	Energy Marketing, which provides natural gas, crude oil, coal, power and environmental marketing and related services in the United States and Canada.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

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



Three Months Ended March 31, 2011	External Operating Revenues		Intercompany Operating Revenues			Net Income (Loss)
Utilities:
Electric	$	144,430	$	3,839		$	10,249
Gas	230,266		—			19,263
Non-regulated Energy:
Oil and Gas	17,906		—			(715		)
Power Generation	687		6,933			1,186
Coal Mining	7,614		7,881			(1,298		)
Energy Marketing	2,397		68			(2,641		)
Corporate ^(a)	—		—			934
Intercompany eliminations	—		(18,721		)	(68		)
Total	$	403,300	$	—		$	26,910



Three Months Ended March 31, 2010	External Operating Revenues		Intercompany Operating Revenues^(b)			Net Income (Loss)
Utilities:
Electric	$	144,387	$	4,422		$	9,852
Gas ^(c)	243,170		—			19,498
Non-regulated Energy:
Oil and Gas	19,743		—			2,348
Power Generation	1,334		6,734			1,080
Coal Mining	6,882		7,098			1,346
Energy Marketing	9,856		(84		)	2,193
Corporate ^(a)	—		—			(4,967		)
Intercompany eliminations	—		(17,042		)	84
Total	$	425,372	$	1,128		$	31,434

____________

(a) Net income (loss) includes a $3.6 million net after-tax mark-to-market gain on interest rate swaps for the three months ended March 31, 2011 and a $2.0 million net after-tax mark-to-market loss on these same interest rate swaps for the three months ended March 31, 2010.

(b) Total Revenues have been restated to reflect elimination of intercompany activities previously not eliminated. See Note 1 for further discussion.

(c) Net income (loss) includes a $1.7 million after-tax gain on the sale of operating assets as a result of annexation proceedings by the City of Omaha, Nebraska.



Total assets	March 31, 2011		December 31, 2010		March 31, 2010
Utilities:
Electric	$	1,868,600	$	1,834,019	$	1,701,329
Gas	683,927		722,287		644,734
Non-regulated Energy:
Oil and Gas	355,357		349,991		348,156
Power Generation	336,827		293,334		185,856
Coal Mining	94,416		96,962		82,776
Energy Marketing	293,544		314,930		324,478
Corporate	94,357		99,986		71,310
Total	$	3,727,028	$	3,711,509	$	3,358,639

(12) 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 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 marketing transactions 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 2010 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 13.

Trading Activities

Energy Marketing

We have a natural gas, crude oil, coal, power and environmental 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 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 Energy Marketing 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 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 marketing activities and derivative commodity instruments were as follows:



	Outstanding at		Outstanding at		Outstanding at
	March 31, 2011		December 31, 2010		March 31, 2010
	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)
(in thousands of MMBtus)
Natural gas basis swaps purchased	649,523	19	399,128	22	240,400	19
Natural gas basis swaps sold	671,468	19	426,903	22	245,790	19
Natural gas fixed-for-float swaps purchased	199,897	30	135,005	33	87,161	20
Natural gas fixed-for-float swaps sold	196,305	19	150,803	22	99,233	22
Natural gas physical purchases	147,699	33	144,948	36	125,570	24
Natural gas physical sales	134,202	33	143,021	36	123,620	24
Natural gas futures purchased	13,570	13	—	—	—	—
Natural gas futures sold	12,050	2	—	—	—	—



	Outstanding at		Outstanding at		Outstanding at
	March 31, 2011		December 31, 2010		March 31, 2010
	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)
(in thousands of Bbls)
Crude oil physical purchases	6,779	13	5,628	16	5,296	9
Crude oil physical sales	6,783	13	6,921	16	5,647	9
Crude oil swaps purchased	65	4	20	3	—	—
Crude oil swaps sold	275	4	240	4	94	2



	Outstanding at		Outstanding at
	March 31, 2011		December 31, 2010
	Notional Amounts	Latest Expiration (months)	Notional Amounts	Latest Expiration (months)
(in thousands of tons)
Coal fixed-for-float swaps purchased	5,330	33	4,060	36
Coal fixed-for-float swaps sold	6,140	33	3,720	36
Coal physical purchases	25,575	45	24,634	48
Coal physical sales	11,065	33	9,046	36
Coal options purchased	2,970	45	2,835	48
Coal options sold	552	9	270	12



	Outstanding at		Outstanding at
	March 31, 2011		December 31, 2010
	Notional Amounts	Latest expiration (months)	Notional Amounts	Latest expiration (months)
(in thousands of MWh):
Power fixed-for-float swaps purchased	3,009	33	902	11
Power fixed-for-float swaps sold	3,008	33	902	11

Derivatives and certain other marketing activities were marked to fair value and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Condensed Statements of Income were as follows (in thousands):



	March 31, 2011			December 31, 2010		March 31, 2010
Derivative assets, current	$	41,482		$	43,862	$	40,541
Derivative assets, non-current	$	3,951		$	6,635	$	2,409
Derivative liabilities, current	$	31,167		$	14,550	$	17,733
Derivative liabilities, non-current	$	(236	)	$	3,464	$	(588	)
Cash collateral receivable (payable) included in derivative assets/liabilities	$	2,984		$	3,958	$	171
Unrealized gain	$	11,518		$	28,525	$	25,634

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in fair value hedge transactions. These volumes include market adjustments based on published industry quotations. Market adjustments are recorded in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets and the related unrealized gain/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of March 31, 2011, December 31, 2010 and March 31, 2010, the market adjustments recorded in Materials, supplies and fuel were $0.3 million, $(9.1) million and $(11.0) million, respectively.

Activities Other Than Trading

Oil and Gas Exploration and Production

We produce natural gas and crude oil through our exploration and production activities. Our natural "long" positions, or unhedged open positions, result in commodity price risk and variability to our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve our cash flows and we have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Executive Risk Committee, and are routinely reviewed by our Board of Directors.

We held a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those over-the-counter swaps and options. These transactions were designated at inception as cash flow hedges, documented under accounting for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives is reported in Accumulated other comprehensive income (loss) and the ineffective portion is reported in earnings.

We held the following derivatives and related balances (dollars in thousands):



	March 31, 2011					December 31, 2010					March 31, 2010
	Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps		Crude Oil Swaps/ Options			Natural Gas Swaps
Notional*	487,500			5,974,800		424,500			6,821,800		565,500			10,142,050
Maximum terms in years **	1			0.25		0.25			0.25		0.25			0.75
Derivative assets, current	$	108		$	6,649	$	248		$	7,675	$	2,816		$	9,151
Derivative assets, non-current	$	—		$	975	$	19		$	2,606	$	220		$	3,248
Derivative liabilities, current	$	4,688		$	—	$	3,814		$	—	$	2,655		$	53
Derivative liabilities, non-current	$	2,678		$	157	$	1,301		$	—	$	1,428		$	—
Pre-tax accumulated other comprehensive income (loss) included in balance sheets	$	(7,613	)	$	7,467	$	(5,313	)	$	10,281	$	(1,908	)	$	12,346
Earnings	$	355		$	—	$	465		$	—	$	861		$	—

____________

* Crude oil in Bbls, gas in MMBtu.

** Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.

Based on March 31, 2011 market prices, a $1.6 million gain would be realized and reported in pre-tax earnings during the next 12 months related to hedges of production. Estimated and actual realized gains will likely change during the next 12 months as market prices change.

Gas Utilities - Gas Hedges

Our Gas Utilities segment purchases and distributes natural gas in four states. During the winter heating season, our gas customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain exchange traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives in accordance with accounting standards for derivatives and mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums upon settlement, on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated operations. Accordingly, the earnings impact is recognized in the Consolidated Income Statements as a component of PGA costs when the related costs are recovered through our rates as part of PGA costs in operating revenue.

The contract or notional amounts and terms of our natural gas derivative commodity instruments held at our Gas Utilities were as follows:



	Outstanding at		Outstanding at		Outstanding at
	March 31, 2011		December 31, 2010		March 31, 2010
	Notional Amounts (MMBtus)	Latest Expiration (months)	Notional Amounts (MMBtus)	Latest Expiration (months)	Notional Amounts (MMBtus)	Latest Expiration (months)
Natural gas futures purchased	4,680,000	24	6,670,000	15	4,740,000	24
Natural gas options purchased	—	—	1,730,000	3	—	—

We had the following derivative balances related to the hedges in our Gas Utilities (in thousands):



	March 31, 2011			December 31, 2010			March 31, 2010
Derivative assets, current	$	1,056		$	4,787		$	1,943
Derivative assets, non-current	$	209		$	—		$	—
Derivative liabilities, non-current	$	—		$	1,620		$	324
Net unrealized gain (loss) included in regulatory assets	$	(2,455	)	$	(8,030	)	$	(6,475	)
Cash collateral receivable (payable) included in derivative assets/liabilities	$	3,720		$	10,355		$	8,094

Option premium included in Derivative assets, current	$	—		$	842		$	—

Financing Activities

We are exposed to interest rate risk associated with fluctuations in the interest rate on our variable interest rate debt. To manage this risk, we have entered into floating-to-fixed interest rate swap agreements with the intention to convert the debt's variable interest rate to a fixed rate.

Our interest rate swaps and related balances were as follows (dollars in thousands):



	March 31, 2011						December 31, 2010						March 31, 2010
	Designated Interest Rate Swaps			Dedesignated Interest Rate Swaps*			Designated Interest Rate Swaps			Dedesignated Interest Rate Swaps*			Designated Interest Rate Swaps			Dedesignated Interest Rate Swaps*
Current notional amount	$	150,000		$	250,000		$	150,000		$	250,000		$	150,000		$	250,000
Weighted average fixed interest rate	5.04		%	5.67		%	5.04		%	5.67		%	5.04		%	5.67		%
Maximum terms in years	5.75			0.75			6.00			1.00			6.75			0.75
Derivative liabilities, current	$	6,769		$	48,515		$	6,823		$	53,980		$	6,571		$	41,822
Derivative liabilities, non-current	$	12,955		$	—		$	14,976		$	—		$	10,917		$	—
Pre-tax accumulated other comprehensive gain (loss) included in Condensed Consolidated Balance Sheets	$	(19,724	)	$	—