Edgar Filing: BLACK HILLS CORP /SD/

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

	Commission File Number 001-31303

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

Registrant’s telephone number (605) 721-1700

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

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

Yes

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

Yes

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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

Yes

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

Class	Outstanding at April 30, 2009

Common stock, $1.00 par value	38,798,483 shares

TABLE OF CONTENTS

		Page

	Glossary of Terms and Abbreviations	3-5

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income –
	Three Months Ended March 31, 2009 and 2008	6

	Condensed Consolidated Balance Sheets –
	March 31, 2009, December 31, 2008 and March 31, 2008	7

	Condensed Consolidated Statements of Cash Flows –
	Three Months Ended March 31, 2009 and 2008	8

	Notes to Condensed Consolidated Financial Statements	9-39

Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	40-67

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	67-71

Item 4.	Controls and Procedures	72

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	73

Item 1A.	Risk Factors	73

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	73

Item 5.	Other Information	74

Item 6.	Exhibits	74

	Signatures	75

	Exhibit Index	76

GLOSSARY OF TERMS AND ABBREVIATIONS

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

Acquisition Facility	Our $1.0 billion single-draw, senior unsecured facility from which a
	$383 million draw was used to provide part of the funding for our
	Aquila Transaction
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
ARB	Accounting Research Bulletin
ARB 51	ARB 51 “Consolidated Financial Statements”
Aquila	Aquila, Inc.
Aquila Transaction	Our July 14, 2008 acquisition of Aquila’s regulated electric utility in
	Colorado and its regulated gas utilities in Colorado, Kansas,
	Nebraska and Iowa
Bbl	Barrel
BHCRPP	Black Hills Corporation Risk Policies and Procedures
BHEP	Black Hills Exploration and Production, Inc., a direct, wholly-owned
	subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct wholly-owned
	subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy	The name used to conduct the business activities of Black Hills Utility
	Holdings, including the gas and electric utility properties acquired
	from Aquila
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned
	subsidiary of the Company that was formerly known as Black Hills
	Energy, Inc.
Black Hills Power	Black Hills Power, Inc., a direct, wholly-owned subsidiary of the
	Company
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of
	the Company formed to acquire and own the utility properties
	acquired from Aquila, all which are now doing business as
	Black Hills Energy
Black Hills Wyoming	Black Hills Wyoming, Inc., a direct, wholly-owned subsidiary of Black
	Hills Electric Generation
Btu	British thermal unit
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned
	subsidiary of the Company
Cheyenne Light Pension Plan	The Cheyenne Light, Fuel and Power Company Pension Plan
Colorado Electric	Black Hills Colorado Electric Utility Company, LP, (doing business as
	Black Hills Energy), an indirect, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Colorado electric
	utility properties acquired from Aquila
Colorado Gas	Black Hills Colorado Gas Utility Company, LP, (doing business as
	Black Hills Energy), an indirect, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Colorado gas
	utility properties acquired from Aquila
CPUC	Colorado Public Utilities Commission
Dth	Dekatherm. A unit of energy equal to 10 therms or one million
	British thermal units (MMBtu)
EITF	Emerging Issues Task Force

EITF 02-3	EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative
	Contracts Held for Trading Purposes and Contracts Involved in
	Energy Trading and Risk Management Activities”
EITF 87-24	EITF Issue No. 87-24, “Allocation of Interest to Discontinued
	Operations”
EITF 99-2	EITF Issue No. 99-2, “Accounting for Weather Derivatives”
Enserco	Enserco Energy Inc., a direct, wholly-owned subsidiary of Black Hills
	Non-regulated Holdings
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretations
FIN 39	FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain
	Contracts – an Interpretation of APB Opinion No. 10 and FASB
	Statement No. 105”
FIN 46(R)	FIN 46-(R), “Consolidation of Variable Interest Entities (Revised
	December 2003) – an interpretation of ARB No. 51”
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income
	Taxes – an interpretation of FASB Statement No. 109”
FSP	FASB Staff Position
FSP FAS 107-1	FSP FAS 107-1, “Interim Disclosure About Fair Value of Financial
	Instruments”
FSP FAS 132(R)-1	FSP FAS 132(R)-1, “Employer’s Disclosures about Pensions and Other
	Postretirement Benefits” (Revised)
FSP FAS 157-2	FSP FAS 157-2, “Effective Date of FASB Statement No. 157”
FSP FAS 157-4	FSP FAS 157-4, “Determining Whether a Market is Not Active and a
	Transaction is Not Distressed”
FSP FIN 39-1	FSP FIN 39-1, “Amendment of FASB Interpretation No. 39”
GAAP	Generally Accepted Accounting Principles
GE	GE Packaged Power, Inc.
Hastings	Hastings Funds Management Ltd
IIF	IIF BH Investment LLC, a subsidiary of an investment entity advised by
	JPMorgan Asset Management
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, (doing business as
	Black Hills Energy), a direct, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Iowa gas
	utility properties acquired from Aquila
IPP	Independent Power Production
IPP Transaction	Our July 11, 2008 sale of seven of our IPP plants to affiliates of
	Hastings and IIF
IUB	Iowa Utilities Board
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, (doing business as
	Black Hills Energy), a direct, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Kansas gas
	utility properties acquired from Aquila
KCC	Kansas Corporation Commission
LIBOR	London Interbank Offered Rate
LOE	Lease Operating Expense
Mcf	One thousand cubic feet
Mcfe	One thousand cubic feet equivalent
MDU	MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska

MMBtu	One million British thermal units
MW	Megawatt
MWh	Megawatt-hour
Nebraska Gas	Black Hills Nebraska Gas Utility Company, LLC, (doing business as
	Black Hills Energy), a direct, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Nebraska gas
	utility properties acquired from Aquila
NPA	Nebraska Public Advocate
NPSC	Nebraska Public Service Commission
NYMEX	New York Mercantile Exchange
OCA	Office of Consumer Advocate
PGA	Purchase Gas Adjustment
SEC	United States Securities and Exchange Commission
SEC Release No. 33-8995	SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting”
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 133	SFAS 133, “Accounting for Derivative Instruments and Hedging
	Activities”
SFAS 141(R)	SFAS 141(R), “Business Combinations”
SFAS 142	SFAS 142, “Goodwill and Other Intangible Assets”
SFAS 144	SFAS 144, “Accounting for the Impairment or Disposal of Long-lived
	Assets”
SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS 160	SFAS 160, “Non-controlling Interest in Consolidated Financial
	Statements – an amendment of ARB No. 51”
SFAS 161	SFAS 161, “Disclosure about Derivative Instruments and Hedging
	Activities – an amendment of FASB Statement No. 133”
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned
	subsidiary of Black Hills Non-regulated Holdings, LLC

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended
	March 31,
	2009		2008
	(in thousands, except per share amounts)

Operating revenues	$	437,943	$	152,850

Operating expenses:
Fuel and purchased power		261,020		52,395
Operations and maintenance		39,335		21,966
Gain on sale of assets		(25,971)		—
Administrative and general		41,766		24,059
Depreciation, depletion and amortization		33,325		19,386
Taxes, other than income taxes		11,698		9,508
Impairment of long-lived assets		43,301		—
		404,474		127,314

Operating income		33,469		25,536

Other income (expense):
Interest expense		(18,901)		(9,194)
Interest rate swap – unrealized gain		14,763		—
Interest income		528		426
Allowance for funds used during
construction – equity		1,372		281
Other income, net		744		336
		(1,494)		(8,151)

Income from continuing operations
before equity in (loss) earnings of
unconsolidated subsidiaries and income
taxes		31,975		17,385
Equity in (loss) earnings of unconsolidated
subsidiaries		(327)		232
Income tax expense		(6,023)		(5,801)

Income from continuing operations		25,625		11,816
Income from discontinued operations,
net of taxes		766		5,052

Net income		26,391		16,868
Net loss attributable to non-controlling
interest		—		(77)

Net income available for common stock	$	26,391	$	16,791

Weighted average common shares
outstanding:
Basic		38,511		37,826
Diluted		38,563		38,399

Earnings per share:
Basic–
Continuing operations	$	0.67	$	0.31
Discontinued operations		0.02		0.13
Total	$	0.69	$	0.44

Diluted–
Continuing operations	$	0.66	$	0.31
Discontinued operations		0.02		0.13
Total	$	0.68	$	0.44

Dividends paid per share of common stock	$	0.355	$	0.35

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

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

	March 31,		December 31,		March 31,
	2009		2008		2008
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	121,562	$	168,491	$	71,027
Restricted cash		—		—		5,484
Short-term investments		—		—		7,290
Receivables (net of allowance for doubtful accounts of $7,832;
$6,751 and $4,213, respectively)		233,921		357,404		254,178
Materials, supplies and fuel		59,139		118,021		80,533
Derivative assets		79,443		73,068		46,337
Income tax receivable		—		20,269		—
Deferred income taxes		11,788		10,244		14,011
Regulatory assets		19,053		35,390		2,659
Other current assets		11,517		16,380		11,779
Assets of discontinued operations		—		246		590,687
		536,423		799,513		1,083,985

Investments		19,956		22,764		16,745

Property, plant and equipment		2,750,760		2,705,492		1,903,096
Less accumulated depreciation and depletion		(750,748)		(683,332)		(526,729)
		2,000,012		2,022,160		1,376,367
Other assets:
Goodwill		359,093		359,290		14,000
Intangible assets, net		4,870		4,884		3
Derivative assets		11,606		9,799		1,360
Regulatory assets		137,108		143,705		18,553
Other		12,041		17,774		14,054
		524,718		535,452		47,970
	$	3,081,109	$	3,379,889	$	2,525,067
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	191,817	$	288,907	$	238,955
Accrued liabilities		129,405		134,940		84,597
Derivative liabilities		105,883		118,657		72,526
Accrued income taxes		19,794		—		303
Regulatory liabilities		14,939		5,203		4,804
Notes payable		479,800		703,800		73,000
Current maturities of long-term debt		32,082		2,078		130,330
Liabilities of discontinued operations		—		88		90,001
		973,720		1,253,673		694,516

Long-term debt, net of current maturities		471,226		501,252		503,279

Deferred credits and other liabilities:
Deferred income taxes		222,157		223,607		209,272
Derivative liabilities		20,656		22,025		16,516
Regulatory liabilities		39,514		38,456		29,379
Benefit plan liabilities		160,397		159,034		42,244
Other		121,842		131,306		59,379
		564,566		574,428		356,790

Stockholders’ equity:
Common stock equity –
Common stock $1 par value; 100,000,000 shares authorized;
Issued 38,796,005; 38,676,054 and 38,425,006 shares,
respectively		38,796		38,676		38,425
Additional paid-in capital		585,244		584,582		578,742
Retained earnings		460,091		447,453		400,909
Treasury stock at cost – 4,725; 40,183 and 29,400
shares, respectively		(119)		(1,392)		(1,050)
Accumulated other comprehensive loss		(12,415)		(18,783)		(51,788)
Total common stockholders’ equity		1,071,597		1,050,536		965,238
Non-controlling interest in subsidiaries		—		—		5,244
Total equity		1,071,597		1,050,536		970,482

	$	3,081,109	$	3,379,889	$	2,525,067

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,
	2009		2008
	(in thousands)
Operating activities:
Net income	$	26,391	$	16,868
Income from discontinued operations, net of taxes		(766)		(5,052)
Income from continuing operations		25,625		11,816
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization		33,325		19,386
Impairment of long-lived assets		43,301		—
Net change in derivative assets and liabilities		6,154		7,745
Gain on sale of operating assets		(25,971)		—
Unrealized mark-to-market gain on interest rate swaps		(14,763)		—
Deferred income taxes		(5,427)		8,830
Distributed earnings in associated companies		2,687		1,241
Allowance for funds used during construction – equity		(1,372)		(281)
Change in operating assets and liabilities:
Materials, supplies and fuel		65,838		22,390
Accounts receivable and other current assets		123,993		(22,430)
Accounts payable and other current liabilities		(83,994)		(8,742)
Regulatory assets and liabilities		33,027		(266)
Other operating activities		(2,971)		(1,937)
Net cash provided by operating activities of continuing operations		199,452		37,752
Net cash provided by operating activities of discontinued operations		883		15,929
Net cash provided by operating activities		200,335		53,681

Investing activities:
Property, plant and equipment additions		(71,272)		(56,547)
Proceeds from sale of business operations		51,878		—
Working capital adjustment of purchase price allocation on acquisition		7,900		—
Increase in short-term investments		—		(7,290)
Other investing activities		135		951
Net cash used in investing activities of continuing operations		(11,359)		(62,886)
Net cash used in investing activities of discontinued operations		—		(17,742)
Net cash used in investing activities		(11,359)		(80,628)

Financing activities:
Dividends paid		(13,753)		(13,275)
Common stock issued		764		1,998
Increase (decrease) in short-term borrowings, net		(224,000)		36,000
Long-term debt – repayments		(22)		(18)
Other financing activities		1,065		297
Net cash (used in) provided by financing activities of continuing operations		(235,946)		25,002
Net cash used in financing activities of discontinued operations		—		(3,214)
Net cash (used in) provided by financing activities		(235,946)		21,788

Decrease in cash and cash equivalents		(46,970)		(5,159)

Cash and cash equivalents:
Beginning of period		168,532^(a)		81,255^(b)
End of period	$	121,562	$	76,096^(c)

Supplemental disclosure of cash flow information:
Non-cash investing and financing activities-
Property, plant and equipment acquired with accrued liabilities	$	28,947	$	18,939
Cash paid during the period for-
Interest (net of amounts capitalized)	$	10,177	$	7,333
Income taxes paid (net of amounts refunded)	$	(24,495)	$	1,500

_________________________

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

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

(c)	Includes approximately $5.1 million of cash included in the assets of discontinued operations.

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

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

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

(1)	MANAGEMENT’S STATEMENT

The condensed consolidated financial statements included herein have been prepared by Black Hills Corporation (the Company, “us”, “we”, “our”) without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2008 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the March 31, 2009, December 31, 2008 and March 31, 2008 financial information and are of a normal recurring nature. Some of our operations 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. The results of operations for the three months ended March 31, 2009, are not necessarily indicative of the results to be expected for the full year. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On July 11, 2008, we completed the sale of seven of our IPP plants. Amounts associated with the IPP plants divested in the IPP Transaction have been reclassified as discontinued operations for the quarter ended March 31, 2008. See Note 20 for additional information.

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

(2)	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

SFAS 157

During September 2006, the FASB issued SFAS 157. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 does not expand the application of fair value accounting to any new circumstances, but applies the framework to other accounting pronouncements that require or permit fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives within our Energy Marketing and Oil and Gas segments, interest rate swap instruments, and other miscellaneous derivatives.

As a result of the adoption of SFAS 157 on January 1, 2008, we discontinued our use of a “liquidity reserve” in valuing the total forward positions within our energy marketing portfolio. This impact was accounted for prospectively as a change in accounting estimate and resulted in a $1.2 million after-tax benefit that was recorded within our unrealized marketing margins. Unrealized margins are presented as a component of Operating revenues on the accompanying Condensed Consolidated Statements of Income. SFAS 157 also required new disclosures regarding the level of pricing observability associated with instruments carried at fair value. These disclosures are provided in Note 13.

FSP FAS 157-2

In February 2008, the FASB issued FSP FAS 157-2, which permits a one-year deferral of the application of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). We adopted FSP FAS 157-2 effective January 1, 2008. Accordingly, the provisions of SFAS 157 were not applied to non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, until January 1, 2009. We adopted the provisions of SFAS 157 for non-financial assets and non-financial liabilities upon the expiration of FSP FAS 157-2 and it did not have an impact on our consolidated financial statements.

SFAS 141(R)

In December 2007, the FASB issued SFAS 141(R). SFAS 141(R) requires an acquiring entity to recognize the assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at the acquisition date to be measured at their fair values as of the acquisition date, with limited exceptions specified in the statement. Acquisition-related costs will be expensed in the periods in which the costs are incurred or services are rendered. If income tax liabilities are settled for an amount other than as previously recorded prior to the adoption of SFAS 141(R), the reversal of any remaining liability will affect goodwill. If such liabilities reverse subsequent to the adoption of SFAS 141(R), such reversals will affect expense including income tax expense in the period of reversal. Costs to issue debt or equity securities shall be accounted for under other applicable GAAP. SFAS 141(R) applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. We adopted SFAS 141(R) on January 1, 2009. Any impact that SFAS 141(R) will have on our consolidated financial statements will depend on the nature and magnitude of any future acquisitions we consummate.

SFAS 160

In December 2007, the FASB issued SFAS 160. SFAS 160 amends ARB 51 and requires:

• Ownership interests in subsidiaries held by parties other than the parent be clearly identified on the consolidated statement of financial position within equity, but separate from the parent’s equity;

• Consolidated net income attributable to the parent and to the non-controlling interest be clearly identified on the face of the consolidated statement of income;

• Changes in a parent’s ownership interest while the parent retains a controlling financial interest be accounted for consistently as equity transactions;

• When a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary be initially measured at fair value; and

• Sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.

We applied the provisions of SFAS 160 on January 1, 2009. Non-controlling interest in the accompanying Condensed Consolidated Statement of Income and Balance Sheet represents the non-affiliated equity investors’ interest in Wygen Funding LP, a Variable Interest Entity as defined by FIN 46(R). In June 2008, we purchased the non-controlling share. Presentation of a non-controlling interest that we held until June 2008 was retrospectively applied as required, and had an immaterial effect overall.

SFAS 161

In March 2008, the FASB issued SFAS 161, which requires enhanced disclosures about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. SFAS 161 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption. SFAS 161 requires comparative disclosures only for periods subsequent to its initial adoption. We evaluated and applied the provisions of SFAS 161 on January 1, 2009. Our contracts do not include credit risk-related contingent features. The additional disclosures are provided in Note 12 and Note 14.

(3)	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SEC Release No. 33-8995

On December 29, 2008, the SEC issued Release No. 33-8995, amending the existing Regulation S-K and Regulation S-X requirements for reporting the quantity and value of oil and gas reserves to align with current industry practices and technology advances. Key revisions include the ability to include non-traditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the pricing used to determine reserves. Companies must use a 12-month average price. The average is calculated using unweighted average of the first-day-of-the-month price for each of the 12 months that make up the reporting period. The amendment is effective for annual reporting periods ending on December 31, 2009, and early adoption is not permitted. We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

FSP FAS 132(R)-1

During December 2008, the FASB issued FSP FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets in a defined benefit pension or other postretirement plan to provide users of financial statements with an understanding of:

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

• The major categories of plan assets;

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

• The effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and

• Significant concentrations of risk within plan assets.

FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009 and we will adopt as of January 1, 2010. We do not expect the adoption of FSP FAS 132(R)-1 to have a significant effect on our consolidated financial statements.

FSP FAS 157-4

In April 2009, the FASB approved FSP FAS 157-4 effective for interim and annual periods ending after June 15, 2009. This FSP amends FAS 157 which addresses inactive markets. This FSP includes a two step model with the first step determining whether factors exist that indicate a market for an asset is not active. If step one results in the conclusion that there is not an active market, step two evaluates whether the quoted price is not associated with a distressed transaction. Additional disclosures will be required.

We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

FSP FAS 107-1

In April 2009, the FASB approved FSP FAS 107-1 effective for interim and annual periods ending after June 15, 2009. This FSP will require public companies to provide more frequent disclosures about the fair value of their financial instruments. We are currently assessing the impact that the adoption will have on our disclosures.

(4)	MATERIALS, SUPPLIES AND FUEL

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

	March 31,		December 31,		March 31,
Major Classification	2009		2008		2008

Materials and supplies	$	34,574	$	32,580	$	28,384
Fuel – Electric Utilities		7,270		10,058		1,749
Natural gas in storage – Gas Utilities		7,590		59,529		—
Gas and oil held by Energy
Marketing*		9,705		15,854		50,400

Total materials, supplies and fuel	$	59,139	$	118,021	$	80,533

___________________________

* As of March 31, 2009, December 31, 2008 and March 31, 2008, market adjustments related to natural gas held by Energy Marketing and recorded in inventory were $(2.4) million, $(9.4) million and $4.6 million, respectively (see Note 12 for further discussion of Energy Marketing trading activities).

Gas and oil inventory held by Energy Marketing primarily consists of gas held in storage. Such gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future.

(5)	NOTES PAYABLE AND LONG-TERM DEBT

Acquisition Credit Facility

In May 2007, we entered into a senior unsecured $1 billion Acquisition Facility with ABN AMRO Bank N.V., as administrative agent, and other banks to fund the Aquila Transaction. On July 14, 2008, in conjunction with the completion of the purchase of the Aquila properties, we executed a single draw of $382.8 million under the Acquisition Facility. The loan was originally scheduled to mature on February 5, 2009. However, on December 18, 2008, we amended the facility to extend the maturity date to December 29, 2009. The March 31, 2009 outstanding balance of $382.8 million, is included in Notes payable in the accompanying Condensed Consolidated Balance Sheets. In April 2009, we received proceeds of $30.2 million for the partial sale of the Wygen III plant. These proceeds were used to pay down a portion of the Acquisition Facility (see Note 21).

(6)	GUARANTEES

On January 19, 2009, we issued a guarantee for up to $37.9 million to GE for payment obligations arising from a contract to purchase one LMS100 natural gas turbine generator by Colorado Electric, which is expected to be used in meeting the needs of our Colorado Electric customers. It is a continuing guarantee which terminates upon payment in full of the purchase price to GE. Payments are scheduled based upon estimated milestone dates with the final payment due September 29, 2010. The purchase contract also gives us a short-term option for the purchase of two additional LMS100 turbine generators at the same pricing as the first generator.

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

(7)	EARNINGS PER SHARE

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

Period ended March 31, 2009	Three Months
			Average
	Income		Shares

Income from continuing operations	$	25,625

Basic earnings		25,625	38,511
Dilutive effect of:
Restricted stock		—	52
Diluted earnings	$	25,625	38,563

Period ended March 31, 2008	Three Months
			Average
	Income		Shares

Income from continuing operations	$	11,816

Basic earnings		11,816	37,826
Dilutive effect of:
Stock options		—	80
Estimated contingent shares issuable
for prior acquisition		—	397
Restricted stock		—	78
Others		—	18
Diluted earnings	$	11,816	38,399

(8)	OTHER COMPREHENSIVE INCOME

The following table presents the components of our other comprehensive income

(in thousands):

	Three Months Ended
	March 31,
	2009		2008

Net income	$	26,391	$	16,868
Other comprehensive income (loss),
net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges
(net of tax of $(1,144) and $14,951,
respectively)		2,998		(27,433)
Reclassification adjustments on cash
flow hedges settled and included in
net income (net of tax of $(1,917)
and $(152), respectively)		3,370		273
Unrealized loss on available for sale
securities (net of tax of $65)		—		(120)

Total comprehensive income (loss)		32,759		(10,412)

Less comprehensive income attributable
to non-controlling interest		—		(77)

Comprehensive income attributable to
Black Hills Corporation	$	32,759	$	(10,489)

Other comprehensive income from fair value adjustments on derivatives designated as cash flow hedges in the three months ended March 31, 2009 is primarily attributable to fluctuating oil and gas prices affecting the fair value of natural gas and crude oil swaps held in the Oil and Gas segment and a decrease in interest rates affecting the fair value of interest rate swaps on variable rate debt.

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

	Derivatives						Unrealized
	Designated as		Employee		Amount from		Loss on
	Cash Flow		Benefit		Equity-method		Available-for-
	Hedges		Plans		Investees		Sale Securities		Total

As of March 31, 2009	$	1,818	$	(14,127)	$	(106)	$	—	$	(12,415)

As of December 31, 2008	$	(4,522)	$	(14,127)	$	(134)	$	—	$	(18,783)

As of March 31, 2008	$	(45,379)	$	(6,115)	$	(174)	$	(120)	$	(51,788)

(9)	COMMON STOCK

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

Equity Compensation Plans

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

• We issued 47,202 shares of common stock under the 2008 short-term incentive compensation plan during the three months ended March 31, 2009. Pre-tax compensation cost related to the award was approximately $1.6 million, which was accrued for in 2008.

• We granted 78,877 restricted common shares during the three months ended March 31, 2009. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $2.1 million will be recognized over the three-year vesting period.

• No stock options were exercised during the three months ended March 31, 2009.

• Total compensation expense recognized for all equity compensation plans for the three months ended March 31, 2009 and 2008 was $0.4 million and $0.2 million, respectively.

• As of March 31, 2009, total unrecognized compensation expense related to non-vested stock awards was $7.7 million and is expected to be recognized over a weighted-average period of 2.4 years.

Dividend Reinvestment and Stock Purchase Plan

We have a Dividend Reinvestment and Stock Purchase Plan under which shareholders 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 39,833 open market shares at a weighted-average price of $17.07 during the three months ended March 31, 2009. At March 31, 2009, 399,482 shares of unissued common stock were available for future offering under the Plan.

(10)	EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (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
	March 31,
	2009		2008

Service cost	$	1,929	$	754
Interest cost		3,679		1,230
Expected return on plan assets		(3,458)		(1,573)
Prior service cost		41		41
Net loss		752		—

Net periodic benefit cost	$	2,943	$	452

We made a $0.1 million contribution to the Cheyenne Light Pension Plan and a $0.4 million contribution to the Black Hills Corporation Pension Plan in the first quarter of 2009; no contributions were made to the Black Hills Energy Plan during the first three months of 2009. Additional contributions anticipated to be made to the Plans for 2009 and 2010 are expected to be approximately $14.4 million and $16.7 million, respectively.

Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

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

	Three Months Ended
	March 31,
	2009		2008

Service cost	$	117	$	112
Interest cost		344		311
Prior service cost		1		3
Net loss		147		142

Net periodic benefit cost	$	609	$	568

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

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in our Postretirement Healthcare Plans (Healthcare Plans) and who meet 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
	March 31,
	2009		2008

Service cost	$	260	$	125
Interest cost		542		217
Expected return on asset		(56)		—
Prior service cost		(22)		—
Net transition obligation		15		15
Net gain		(8)		(20)

Net periodic benefit cost	$	731	$	337

We anticipate that we will make contributions to the Healthcare Plans for the 2009 fiscal year of approximately $3.3 million. The contributions are expected to be made in the form of benefits payments.

It has been determined that our post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was approximately $0.1 million for each of the three month periods ended March 31, 2009 and 2008.

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

Our reportable segments are those that 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, 2009, substantially all of our operations and assets are located within the United States.

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

We conduct our operations through the following six reportable segments:

Utilities Group –

• Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Montana and Colorado 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;

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

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

Segment information follows the same accounting policies as described in Note 1 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K. In accordance with the provisions of SFAS 71, intercompany fuel sales to the regulated utilities are not eliminated.

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

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
March 31, 2009

Utilities:
Electric Utilities	$	137,060	$	215	$	9,317
Gas Utilities		256,337		—		17,265
Non-regulated Energy:
Oil and Gas		16,511		—		(25,720)
Power Generation		7,619		—		17,153
Coal Mining		7,937		6,465		819
Energy Marketing		6,820		—		1,037
Corporate		—		—		5,536
Inter-segment eliminations		—		(1,021)		218

Total	$	432,284	$	5,659	$	25,625

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
March 31, 2008

Utilities:
Electric Utilities	$	99,302	$	306	$	10,167
Non-regulated Energy:
Oil and Gas		26,122		—		2,551
Power Generation		2,313		6,551		(896)
Coal Mining		7,889		5,358		1,629
Energy Marketing		6,119		—		299
Corporate		—		—		(1,934)
Inter-segment eliminations		—		(1,110)		—

Total	$	141,745	$	11,105	$	11,816

	March 31,		December 31,		March 31,
	2009		2008		2008
Total assets
Utilities:
Electric Utilities	$	1,522,885	$	1,485,040	$	872,074
Gas Utilities		653,860		733,377		—
Non-regulated Energy:
Oil and Gas		357,233		403,583		436,716
Power Generation		121,489		155,819		148,885
Coal Mining		75,092		75,872		61,994
Energy Marketing		262,441		339,543		357,483
Corporate		88,109		186,409		57,228
Discontinued operations		—		246		590,687
Total	$	3,081,109	$	3,379,889	$	2,525,067

(12)	RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and unregulated energy sector expose us to a number of risks in the normal operations 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 and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets, and gas usage at our Gas Utilities segment;

• Interest rate risk associated with variable rate credit facilities; 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 2 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K. Details of derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are as follows:

Trading Activities

Natural Gas and Crude Oil Marketing

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

Contracts and other activities at our natural gas and crude oil marketing operations are accounted for under the provisions of EITF 02-3 and SFAS 133. As such, all of the contracts and other activities at our natural gas and crude oil marketing operations that meet the definition of a derivative under SFAS 133 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. EITF 02-3 precludes mark-to-market accounting for energy trading contracts that are not derivatives pursuant to SFAS 133. As part of our natural gas and crude oil 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, SFAS 133 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 and crude oil 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 result from these accounting requirements.

FSP FIN 39-1 permits a reporting entity to offset fair value amounts recognized for the right to reclaim or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. Each Condensed Consolidated Balance Sheet herein reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of offset exists.

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 gas marketing Risk Management Policies and Procedures as approved by our Executive Risk Committee.

We use a number of quantitative tools to measure, monitor and limit our exposure to market risk in our natural gas and oil 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 and crude oil marketing activities and derivative commodity instruments are as follows:

	Outstanding at			Outstanding at			Outstanding at
	March 31, 2009			December 31, 2008			March 31, 2008
			Latest			Latest			Latest
	Notional		Expiration	Notional		Expiration	Notional		Expiration
	Amounts		(months)	Amounts		(months)	Amounts		(months)
(in thousands of MMBtus)
Natural gas basis
swaps purchased		273,496	31		187,368	34		187,068	33
Natural gas basis
swaps sold		280,478	31		186,710	34		191,738	33
Natural gas fixed - for - float
swaps purchased		101,094	21		85,412	24		53,738	24
Natural gas fixed - for - float
swaps sold		107,705	21		90,171	24		67,910	24
Natural gas physical
purchases		143,642	19		131,937	16		132,559	12
Natural gas physical sales		136,504	19		145,706	21		136,687	24
Natural gas options
purchased		—	—		1,440	3		11,311	12
Natural gas options sold		—	—		1,440	3		11,311	12

	Outstanding at			Outstanding at			Outstanding at
	March 31, 2009			December 31, 2008			March 31, 2008
			Latest			Latest			Latest
	Notional		Expiration	Notional		Expiration	Notional		Expiration
	Amounts		(months)	Amounts		(months)	Amounts		(months)

(in thousands of Bbls)
Crude oil physical
purchases		5,070	9		7,446	12		3,737	9
Crude oil physical sales		4,301	9		6,251	12		2,903	9
Crude oil swaps/options
purchased		67	1		435	24		495	9
Crude oil swaps/options
sold		119	4		502	24		545	9

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on March 31, 2009, December 31, 2008 and March 31, 2008, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows (in thousands):

									Cash
									Collateral
									Included in
	Current		Non-current		Current		Non-current		Derivative
	Derivative		Derivative		Derivative		Derivative		Assets/		Unrealized
	Assets		Assets		Liabilities		Liabilities		Liabilities^(a)		(Loss)/Gain


March 31, 2009	$	53,741	$	2,317	$	20,422	$	(534)	$	3,673	$	39,843


December 31, 2008	$	52,723	$	(145)	$	15,553	$	(777)	$	16,315	$	54,117


March 31, 2008	$	45,542	$	1,246	$	21,393	$	994	$	(32,876)	$	(8,475)

____________________________

(a)

FIN 39 permits netting of receivables and payables when a legally enforceable master netting agreement exists between us and a counterparty. FIN 39-1 permits offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract. At March 31, 2009 and December 31, 2008, we had an obligation to return cash collateral of $3.7 million and $16.3 million, respectively. At March 31, 2008, we had the right to reclaim cash collateral of $32.9 million.

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. 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, 2009, December 31, 2008 and March 31, 2008, the market adjustments recorded in inventory were $(2.4) million, $(9.4) million and $4.6 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, introduce commodity price risk and variability in 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.

Over-the-counter swaps and options are used to mitigate commodity price risk and preserve cash flows. These derivative instruments fall under the purview of SFAS 133 and we elect to utilize hedge accounting as allowed under this Statement.

At March 31, 2009, December 31, 2008 and March 31, 2008, we had a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. These transactions were designated at inception as cash flow hedges, properly documented and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives are 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 was reported in other comprehensive income and the ineffective portion was reported in earnings.

On March 31, 2009, December 31, 2008 and March 31, 2008, we had the following derivatives and related balances (in thousands):

											Pre-tax
		Maximum			Non-				Non-		Accumulated
		Terms	Current		current		Current		current		Other
		in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Earnings
	Notional*	Years**	Assets		Assets		Liabilities		Liabilities		Income (Loss)		(Loss)
March 31,
2009

Crude oil
swaps/options	450,000	0.25	$	5,189	$	4,523	$	—	$	524	$	8,629	$	559
Natural gas
swaps	9,946,500	0.75		18,932		4,764		4		244		23,448		—
			$	24,121	$	9,287	$	4	$	768	$	32,077	$	559
December 31,
2008

Crude oil
swaps/options	435,000	0.25	$	7,674	$	3,464	$	—	$	10	$	9,642	$	1,486
Natural gas
swaps	8,523,500	1.00		11,828		3,749		—		297		15,280		—
			$	19,502	$	7,213	$	—	$	307	$	24,922	$	1,486
March 31,
2008

Crude oil
swaps/options	495,000	0.75	$	484	$	—	$	4,078	$	2,187	$	(6,265)	$	484
Natural gas
swaps	11,657,000	1.59		66		114		12,653		3,328		(15,801)		—
			$	550	$	114	$	16,731	$	5,515	$	(22,066)	$	484

___________________________

*	Crude 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, 2009 market prices, a $20.9 million gain would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production. Estimated and actual realized gains will likely change during the next twelve months as market prices change.

Fuel in Storage

On March 31, 2008, we had the following swaps and related balances (in thousands):

Pre-tax

Non-

Accumulated

Maximum

Current

current

Current

current

Other

Terms in

Derivative

Comprehensive

Unrealized

Notional*

Months

Assets

Liabilities

Income (Loss)

Gain

March 31,

2008

Natural gas

swaps

300,000

245

—

245

—

________________________

*gas in MMBtus

Regulated 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 and option transactions to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivative transactions under SFAS 133, are marked-to-market, not designated as hedges under SFAS 133 and, are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums, on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with SFAS 71. Accordingly, the earnings impact is recognized in the Consolidated Income Statement 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 are as follows:

	Outstanding at		Outstanding at
	March 31, 2009		December 31, 2008
		Latest		Latest
	Notional	Expiration	Notional	Expiration
	Amounts*	(months)	Amounts*	(months)

Natural gas futures purchased	2,110,000	24	1,290,000	3
Natural gas options purchased	—	—	3,990,000	3
Natural gas options sold	—	—	820,000	3

________________________

*gas in MMBtus

On March 31, 2009 and December 31, 2008, we had the following derivatives and related balances (in thousands):

									Net		Cash
									Unrealized		Collateral
			Non-				Non-		Loss		Included in
	Current		current		Current		current		Included in		Derivative
	Derivative		Derivative		Derivative		Derivative		Regulatory		Assets/
	Assets		Assets		Liabilities		Liabilities		Assets		Liabilities

March 31, 2009	$	1,581	$	2	$	—	$	82	$	543	$	2,044

December 31, 2008	$	4,224	$	—	$	2,924	$	—	$	11,668	$	8,744

Weather Derivatives

As approved in the State of Iowa, Iowa Gas uses a weather derivative to offset inherent risks, but not for trading or speculative purposes. EITF 99-2 requires that these weather derivatives are accounted for by recording an asset or liability for the difference between the actual and contracted threshold cooling or heating degree days in the period, multiplied by the contract price. The amount of realized gains included in Regulatory liabilities was $0.5 million for the three months ended March 31, 2009. The liability amount included in Current liabilities, other was $1.0 million at March 31, 2009; the receivable amount included in Current liabilities, other was $1.8 million at December 31, 2008.

Financing Activities

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

On March 31, 2009, December 31, 2008 and March 31, 2008, our interest rate swaps and related balances were as follows (in thousands):

			Weighted										Pre-tax
			Average				Non-				Non-		Accumulated
	Current		Fixed	Maximum	Current		current		Current		current		Other
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Pre-tax
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		(Loss)/Income		Gain/(Loss)
March 31,
2009

Interest rate
swaps	$	150,000	5.04%	7.75	$	—	$	—	$	5,780	$	20,340	$	(26,120)	$	—
Interest rate
swaps		250,000	5.67%	0.75		—		—		79,677		—		—		14,763
	$	400,000			$	—	$	—	$	85,457	$	20,340	$	(26,120)	$	14,763

December 31,
2008

Interest rate
swaps	$	150,000	5.04%	8.00	$	—	$	—	$	5,740	$	22,495	$	(28,235)	$	—
Interest rate
swaps		250,000	5.67%	1.00		—		—		94,440		—		—		(94,440)
	$	400,000			$	—	$	—	$	100,180	$	22,495	$	(28,235)	$	(94,440)

March 31,
2008

Interest rate
swaps	$	150,000	5.04%	8.50	$	—	$	—	$	3,534	$	10,007	$	(13,541)	$	—
Interest rate
swaps		250,000	5.54%	0.25		—		—		30,621		—		(30,621)		—
	$	400,000			$	—	$	—	$	34,155	$	10,007	$	(44,162)	$	—

Based on March 31, 2009 market interest rates and balances, a loss of approximately $5.8 million would be realized and reported in pre-tax earnings during the next twelve months. Estimated and realized losses will likely change during the next twelve months as market interest rates change.

Foreign Exchange Contracts

Our Energy Marketing Segment conducts its gas marketing in the United States and Canada. Transactions in Canada are generally transacted in Canadian dollars and create exchange risk for us. To mitigate this risk, we enter into forward currency exchange contracts to offset earnings volatility from changes in exchange rates between the Canadian and United States dollar.

The outstanding forward exchange contracts, which had a fair value of less than $0.1 million, $(0.2) million and $(0.4) million at March 31, 2009, December 31, 2008 and March 31, 2008, respectively, have been recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The impact of foreign currency exchange transactions did not have a material effect on our Condensed Consolidated Statements of Income. All forward exchange contracts outstanding at March 31, 2009 will settle by May 25, 2009 and were as follows:

	Outstanding at			Outstanding at			Outstanding at
	March 31, 2009			December 31, 2008			March 31, 2008
			Latest			Latest			Latest
	Notional		Expiration	Notional		Expiration	Notional		Expiration
	Amounts		(months)	Amounts		(months)	Amounts		(months)

(Dollars, in thousands)
Canadian dollars
purchased	$	20,000	2	$	52,000	1	$	27,000	1

(13)	QUANTITATIVE DISCLOSURES RELATED TO DERIVATIVES

As required by SFAS 161, fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions permitted in accordance with FIN 39 and under terms of our master netting agreements. Further, the amounts do not include net cash collateral of $1.6 million on deposit in margin accounts at March 31, 2009 to collateralize certain financial instruments, which is included in Derivative assets – current. Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheet, nor will they agree to the fair value measurements presented in Note 12 and Note 14. The following table presents the fair value and balance sheet classification of our derivative instruments as of March 31, 2009 (in thousands):

Fair Value as of March 31, 2009

		Fair Value		Fair Value
		of Asset		of Liability
	Balance Sheet Location	Derivatives		Derivatives

Derivatives designated as hedges under SFAS 133:
Commodity derivatives	Derivative assets – current	$	7,339	$	4,717
Interest rate swaps	Derivative liabilities – current		—		5,780
Interest rate swaps	Derivative liabilities – non-current		—		20,340
Total derivatives designated as hedges under SFAS 133		$	7,339	$	30,837

Derivatives not designated as hedges under SFAS 133:
Commodity derivatives	Derivative assets – current	$	343,372	$	265,003
Commodity derivatives	Derivative assets – non-current		19,120		7,514
Commodity derivatives	Derivative liabilities – current		11,959		32,320
Commodity derivatives	Derivative liabilities – non-current		170		486
Interest rate swap	Derivative liabilities – current		—		79,677
Foreign currency derivatives	Derivative assets – current		107		26
Foreign currency derivatives	Derivative liabilities – current		—		65
Total derivatives not designated as hedges under SFAS 133		$	374,728	$	385,091

A description of our derivative activities is discussed in Note 12. The following tables present the impact that derivatives had on our Condensed Consolidated Statement of Income for the three months ended March 31, 2009.

Fair Value Hedges

The impact of commodity contracts designated as fair value hedges and the related hedged items on our accompanying Condensed Consolidated Statement of Income for the three months ended March 31, 2009 is presented as follows:

The Effect of Derivative Instruments on the Condensed Consolidated Statement of Income
for the Quarter Ended March 31, 2009

Fair Value Hedges
(in thousands)


Derivatives in SFAS 133	Location of Gain/(Loss)	Amount of Gain/(Loss)
Fair Value	on Derivatives	on Derivatives
Hedging Relationships	Recognized in Income	Recognized in Income

Commodity derivatives	Operating revenue	$	7,520
Fair value adjustment for natural
gas inventory designated as
the hedged item	Operating revenue		(6,955)
		$	565

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statement of Income for the three months ended March 31, 2009 is presented as follows:

The Effect of Derivative Instruments on the Condensed Consolidated Statement of Income
and the Balance Sheet for the Quarter Ended March 31, 2009

Cash Flow Hedges
(in thousands)

		Location	Location of
	Amount of