UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

 

 

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.

 

 

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).

 

 

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).

 

 

 

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

 

 

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

 

 

TABLE OF CONTENTS

 

 

2

GLOSSARY OF TERMS AND ABBREVIATIONS

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

 

 

3

 

 

 

4

 

 

 

5

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

 

 

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

 

6

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

 

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

7

BLACK HILLS CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

 

_________________________

 

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

 

8

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)

 

 

 

The condensed consolidated financial statements included herein have been prepared by Black Hills Corporation (the “Company,” “us,” “we,” “our”) without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These condensed quarterly financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2008 Annual Report on Form 10-K filed with the SEC. These financial statements include consideration of events through August 10, 2009.

 

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying condensed quarterly financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the June 30, 2009, December 31, 2008 and June 30, 2008 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2009, and our financial condition as of June 30, 2009 and December 31, 2008, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

 

On July 11, 2008, we completed the sale of seven of our IPP plants. Amounts associated with the IPP plants divested in the IPP Transaction have been reclassified as discontinued operations for the quarter ended June 30, 2008. See Note 18 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 16 for additional information.

 

 

9

 

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 were settled for an amount other than as previously recorded prior to the adoption of SFAS 141(R), the reversal of any remaining liability would have affected 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 and the resolution of certain tax contingencies.

 

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 14.

 

SFAS 160

 

In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest, and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. SFAS 160 also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. This statement was effective for us beginning January 1, 2009.

 

We applied the provisions of SFAS 160 on January 1, 2009. Non-controlling interest in the accompanying Condensed Consolidated Statements of Income and Balance Sheets represents the non-affiliated equity investors’ interest in Wygen Funding LP, a Variable Interest Entity as defined by 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 overall effect.

 

10

SFAS 161

 

In March 2008, the FASB issued SFAS 161, which requires enhanced disclosures about derivative and hedging activities and their affect on 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 adopted the provisions of SFAS 161 on January 1, 2009. The additional disclosures are provided in Note 12 and Note 13.

 

SFAS 165

 

In May 2009, the FASB issued SFAS 165, which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. We adopted and applied the provisions of SFAS 165 for our financial statements issued after June 15, 2009.

 

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 requires public companies to provide more frequent disclosures about the fair value of their financial instruments. These disclosures are included in Note 14.

 

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 required include interim disclosure of valuation techniques. The adopted FSP FAS 157-4 had no overall effect on our financial statements and any additional disclosures are included in Note 14.

 

FSP EITF 03-6-1

 

In June 2008, the FASB issued FSP EITF 03-6-1 which states that unvested share-based payment awards that contain non-forfeitable rights to dividends are “participating securities” as defined under EITF 03-6 and therefore should be included in computing EPS using the two-class method. The two-class method is an earnings allocation method for computing EPS and determines EPS based on dividends declared on common stock and participating securities in any undistributed earnings. We adopted FSP EITF 03-6-1 on January 1, 2009. We prepared our current and prior period EPS computation in accordance with FSP EITF 03-6-1, and there was no impact on our EPS as a result of the adoption.

 

11

 

SEC Release No. 33-8995

 

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

 

SFAS 167

 

In June 2009, the FASB issued SFAS 167, a revision to FASB Interpretation No. 46(R). This Statement amends the analysis performed by a Company in determining whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It will require additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This Statement is effective for annual periods that begin after November 15, 2009. We are currently assessing the impact that the adoption of this Statement will have on our financial condition, results of operations, and cash flows.

 

SFAS 168

 

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

 

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

 

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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:

 

 

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

 

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

 

___________________________

* As of June 30, 2009, December 31, 2008 and June 30, 2008, market adjustments related to natural gas held by Energy Marketing and recorded in inventory were $(3.8) million, $(9.4) million and $6.3 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 subsequent sales date in the future.

 

13

 

Public Debt Offering

 

On May 14, 2009, we issued a $250 million aggregate principal amount of senior unsecured notes due in 2014 pursuant to a public offering. The notes were priced at par and carry a fixed interest rate of 9%. We received proceeds of $248.5 million, net of underwriting fees. Proceeds were used to pay down the Acquisition Facility. Estimated deferred financing costs related to the offering of $2.2 million were capitalized and will be amortized over the life of the debt. Amortization expense for the three months ended June 30, 2009 was approximately $0.1 million.

 

Acquisition Facility

 

In May 2007, we entered into a senior unsecured $1 billion Acquisition Facility with ABN AMRO Bank N.V., as administrative agent, and other banks to fund the Aquila Transaction. On July 14, 2008, in conjunction with the completion of the purchase of the Aquila properties, we executed a single draw of $382.8 million under the Acquisition Facility. The loan was originally scheduled to mature on February 5, 2009. However, on December 18, 2008, we amended the facility to extend the maturity date to December 29, 2009. The Acquisition Facility was repaid in the second quarter of 2009 using: (1) net proceeds from the sale of a 25% ownership interest in the Wygen III plant of $30.2 million; (2) proceeds from the $250 million public debt offering; and (3) $104.6 million from borrowings under the Corporate Credit Facility. Amortization expense for the three and six months ended June 30, 2009 was $0.7 million and $1.9 million, respectively. The remaining balance of $2.9 million of deferred financing costs was written off as Interest expense on the accompanying Condensed Consolidated Statements of Income as the loan was repaid.

 

Enserco Credit Facility

 

On May 8, 2009, Enserco entered into an agreement for a $240 million committed credit facility. Societe Generale, Fortis Capital Corp., and BNP Paribas were co-lead arranger banks. On May 27, 2009, Enserco entered into an agreement for an additional $60 million of Commitments under the credit facility with three new participating banks: Calyon, Rabobank and RZB Finance. This credit facility expires on May 7, 2010. The facility is a borrowing rate line of credit, which allows for the issuance of letters of credit and for borrowings. Maximum borrowings under the facility are subject to a sublimit of $50 million. Borrowings under this facility are available under a base rate option or a Eurodollar option. The base rate option borrowing rate is 2.75% plus the higher of: (i) 0.5% above the Federal Funds Rate, or (ii) the prime rate established by Fortis Bank S.A./N.V. The Eurodollar option borrowing rate is 2.75% plus the higher of the Eurodollar Rate or the reference bank cost of funds. 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, we may be restricted from making dividends from Enserco to the parent company of Enserco. At June 30, 2009, $73.6 million of letters of credit were issued and outstanding under this facility and there were no cash borrowings outstanding. Deferred financing costs of $1.9 million were capitalized and will be amortized over the life of the facility.

 

14

 

Guarantees with GE

 

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

 

Guarantees to MEAN

 

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

 

 

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):

 

 

 

 

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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):

 

 

 

 

The following table presents the components of our other comprehensive income

(in thousands):

 

 

 

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	Six Months Ended
	June 30,
	2009		2008
Net income	$	50,972	$	39,118
Other comprehensive income (loss),
net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges
(net of tax of $2,928 and $20,462,
respectively)		(4,795)		(37,792)
Reclassification adjustments on cash
flow hedges settled and included in
net income (net of tax of $(4,060)
and $(2,413), respectively)		7,163		4,310
Unrealized loss on available for sale
securities (net of tax of $58)		—		(108)
Total comprehensive income		53,340		5,528
Comprehensive loss attributable to
non-controlling interest		—		(130)
Comprehensive income attributable to
Black Hills Corporation	$	53,340	$	5,398

 

Other comprehensive income from fair value adjustments on derivatives designated as cash flow hedges in the six months ended June 30, 2008 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 in 2008, 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 June 30, 2009	$	(2,191)	$	(14,127)	$	(97)	$	—	$	(16,415)
As of December 31, 2008	$	(4,522)	$	(14,127)	$	(134)	$	—	$	(18,783)
As of June 30, 2008	$	(51,709)	$	(6,115)	$	(166)	$	(108)	$	(58,098)

 

 

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(9)	COMMON STOCK

 

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

 

Equity Compensation Plans

 

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

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

•    We granted 81,877 restricted common shares during the six months ended June 30, 2009. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $2.2 million will be recognized over the three-year vesting period.

 

Total compensation expense recognized for all equity compensation plans for the three months ended June 30, 2009 and 2008 was $1.4 million and $0.5 million, respectively, and for the six months ended June 30, 2009 and 2008 was $1.8 million and $0.7 million, respectively.

 

As of June 30, 2009, total unrecognized compensation expense related to non-vested stock awards was $6.8 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 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 80,746 new shares at a weighted-average price of $19.23 during the six months ended June 30, 2009. At June 30, 2009, 358,569 shares of unissued common stock were available for future offering under the Plan.

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(10)	EMPLOYEE BENEFIT PLANS

 

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

 

Defined Benefit Pension Plans

 

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

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Service cost	$	1,929	$	754	$	3,858	$	1,508
Interest cost		3,679		1,230		7,358		2,460
Expected return on plan assets		(3,458)		(1,573)		(6,916)		(3,146)
Prior service cost		41		41		82		82
Net loss		752		—		1,504		—
Net periodic benefit cost	$	2,943	$	452	$	5,886	$	904

 

We made a $1.4 million contribution to the Cheyenne Light Pension Plan and a $2.5 million contribution to the Black Hills Energy Pension Plan in the second quarter of 2009; no contributions were made to the Black Hills Corporation Pension Plan during the second quarter of 2009. Additional contributions anticipated to be made to the Plans for 2009 and 2010 are expected to total approximately $9.5 million and $16.7 million, respectively.

 

Non-pension Defined Benefit Postretirement Healthcare Plans

 

Employees who are participants in our 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				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Service cost	$	260	$	125	$	520	$	250
Interest cost		542		217		1,084		434
Expected return on asset		(56)		—		(112)		—
Prior service (benefit)		(22)		—		(44)		—
Net transition obligation		15		15		30		30
Net gain		(8)		(20)		(16)		(40)
Net periodic benefit cost	$	731	$	337	$	1,462	$	674

 

 

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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 and $0.2 million for the three and six month periods ended June 30, 2009 and 2008, respectively.

 

Supplemental Non-qualified Defined Benefit Plans

 

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

 

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

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Service cost	$	117	$	112	$	234	$	224
Interest cost		344		311		688		622
Prior service cost		1		3		2		6
Net loss		147		142		294		284
Net periodic benefit cost	$	609	$	568	$	1,218	$	1,136

 

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.

 

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(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 June 30, 2009, substantially all of our operations and assets are located within the United States.

 

The Utilities Group includes two reportable segments: Electric Utilities and Gas Utilities. We manage our electric and gas utility businesses predominantly by state; however, because our electric utilities and our gas utilities have similar economic characteristics, we aggregate our electric (and combination) utility businesses in the Electric Utilities reporting segment and our gas utility businesses in the Gas Utilities reporting segment. Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric, and the regulated electric and natural gas utility operations of Cheyenne Light. The natural gas operations within our combination utility, Cheyenne Light, 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.

 

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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
June 30, 2009
Utilities:
Electric Utilities	$	118,606	$	215	$	4,541
Gas Utilities		93,338		—		442
Non-regulated Energy:
Oil and Gas		17,829		—		129
Power Generation		7,215		—		758
Coal Mining		7,746		5,747		(499)
Energy Marketing		7,738		—		2,210
Corporate		—		—		16,780
Inter-segment eliminations		—		(1,085)		220
Total	$	252,472	$	4,877	$	24,581

 

 

 

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Three Month Period Ended
June 30, 2008
Utilities:
Electric Utilities	$	93,567	$	363	$	9,553
Gas Utilities		—		—		—
Non-regulated Energy:
Oil and Gas		34,209		—		7,197
Power Generation		2,135		6,376		(472)
Coal Mining		7,987		4,660		496
Energy Marketing		5,150		—		365
Corporate		—		—		(3,897)
Inter-segment eliminations		—		(1,174)		(39)
Total	$	143,048	$	10,225	$	13,203

 

 

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	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Six Month Period Ended
June 30, 2009
Utilities:
Electric Utilities	$	255,665	$	430	$	13,858
Gas Utilities		349,676		—		17,708
Non-regulated Energy:
Oil and Gas		34,340		—		(25,591)(a)
Power Generation		14,834		—		17,911
Coal Mining		15,683		12,212		319
Energy Marketing		14,557		—		3,247
Corporate		—		—		22,316
Inter-segment eliminations		—		(2,105)		438
Total	$	684,755	$	10,537	$	50,206

________________________

(a)

As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment in the first quarter of 2009. The lower prices at March 31, 2009 resulted in a $43.3 million pre-tax decrease in the full cost accounting method’s ceiling limit for capitalized oil and gas property costs. The write-down in the net carrying value of our natural gas and crude oil properties was recorded as Impairment of long-lived assets and was based on the March 31, 2009 NYMEX price of $3.63 per Mcf, adjusted to $2.23 per Mcf at the wellhead, for natural gas; and NYMEX price of $49.66 per barrel, adjusted to $45.32 per barrel at the wellhead, for crude oil.

 

 

	External		Inter-segment		Income (Loss) from
	Operating		Operating		Continuing
	Revenues		Revenues		Operations
Six Month Period Ended
June 30, 2008
Utilities:
Electric Utilities	$	192,868	$	670	$	19,720
Gas Utilities		—		—		—
Non-regulated Energy:
Oil and Gas		60,331		—		9,749
Power Generation		4,449		12,926		(1,368)
Coal Mining		15,876		10,018		2,124
Energy Marketing		11,269		—		664
Corporate		—		—		(5,830)
Inter-segment eliminations		—		(2,284)		(39)
Total	$	284,793	$	21,330	$	25,020

 

 

23

	Three		Three		Six		Six
	Months		Months		Months		Months
	Ended		Ended		Ended		Ended
	June 30,		June 30,		June 30,		June 30,
	2009		2008		2009		2008
Depreciation, depletion and amortization
Utilities:
Electric Utilities	$	10,967	$	7,892	$	21,925	$	15,639
Gas Utilities		7,499		—		15,680		—
Non-regulated Energy:
Oil and Gas		6,197		8,446		15,138		16,360
Power Generation		945		1,216		1,851		2,394
Coal Mining		3,588		2,186		7,574		3,852
Energy Marketing		129		185		262		368
Corporate		61		863		282		1,561
Total	$	29,386	$	20,788	$	62,712	$	40,174

 

 

 

	June 30,		December 31,		June 30,
	2009		2008		2008
Total assets
Utilities:
Electric Utilities	$	1,558,525	$	1,485,040	$	908,112
Gas Utilities		628,152		733,377		—
Non-regulated Energy:
Oil and Gas		347,198		403,583		454,433
Power Generation		119,876		155,819		148,262
Coal Mining		75,647		75,872		66,012
Energy Marketing		299,374		339,543		435,612
Corporate		82,968		186,409		51,509
Discontinued operations		—		246		598,294
Total	$	3,111,740	$	3,379,889	$	2,662,234

 

 

24

(12)	RISK MANAGEMENT ACTIVITIES

 

Our activities in the regulated and unregulated 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 and natural gas reserves and production, and fuel procurement for certain of our gas-fired generation assets;

•     Interest rate risk associated with variable rate credit facilities;

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

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

 

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

 

We actively manage our exposure to certain market risks as described in Note 2 of the Notes to Consolidated Financial Statements in our 2008 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 and Note 13 and Note 14.

 

25

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.

 

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. Our contracts do not include credit risk-related contingent features.

 

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.

 

26

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
	June 30, 2009			December 31, 2008			June 30, 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		289,140	28		187,368	34		209,344	40
Natural gas basis
swaps sold		302,324	28		186,710	34		212,498	40
Natural gas fixed - for - float
swaps purchased		90,974	21		85,412	24		50,707	24
Natural gas fixed - for - float
swaps sold		100,088	18		90,171	24		65,093	24
Natural gas physical
purchases		168,381	18		131,937	16		130,253	22
Natural gas physical sales		184,873	21		145,706	21		168,938	22
Natural gas options
purchased		—	—		1,440	3		7,650	9
Natural gas options sold		—	—		1,440	3		7,650	9

 

 

	Outstanding at			Outstanding at			Outstanding at
	June 30, 2009			December 31, 2008			June 30, 2008
			Latest			Latest			Latest
	Notional		Expiration	Notional		Expiration	Notional		Expiration
	Amounts		(months)	Amounts		(months)	Amounts		(months)
(in thousands of Bbls)
Crude oil physical
purchases		5,595	6		7,446	12		6,713	18
Crude oil physical sales		4,925	6		6,251	12		5,084	18
Crude oil swaps/options
purchased		42	3		435	24		515	6
Crude oil swaps/options
sold		111	3		502	24		565	6

 

 

27

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on June 30, 2009, December 31, 2008 and June 30, 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
June 30, 2009	$	52,870	$	1,802	$	14,970	$	(1,917)	$	(9,267)	$	32,352
December 31, 2008	$	52,723	$	(145)	$	15,553	$	(777)	$	16,315	$	54,117
June 30, 2008	$	69,723	$	14,010	$	33,809	$	2,480	$	(49,050)	$	(1,606)

____________________________

(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 June 30, 2009 and June 30, 2008, we had the right to reclaim cash collateral of $9.3 million and $49.1 million, respectively. At December 31, 2008, we had an obligation to return cash collateral of $16.3 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 June 30, 2009, December 31, 2008 and June 30, 2008, the market adjustments recorded in inventory were $(3.8) million, $(9.4) million and $6.3 million, respectively.

 

28

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 June 30, 2009, December 31, 2008 and June 30, 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 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 was reported in other comprehensive income and the ineffective portion was reported in earnings.

 

On June 30, 2009, December 31, 2008 and June 30, 2008, we had the following derivatives and related balances (in thousands):

 

											Pre-tax
		Maximum			Non-				Non-		AOCI
		Terms	Current		current		Current		current		included
		in	Derivative		Derivative		Derivative		Derivative		in
	Notional*	Years**	Assets		Assets		Liabilities		Liabilities		Balance Sheet		Earnings
June 30,
2009
Crude oil
swaps/options	480,000	0.25	$	3,600	$	1,453	$	—	$	1,995	$	2,543	$	515
Natural gas
swaps	9,862,050	0.75		14,012		1,612		361		1,392		13,871		—
			$	17,612	$	3,065	$	361	$	3,387	$	16,414	$	515
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
June 30,
2008
Crude oil
swaps/options	465,000	0.50	$	389	$	—	$	8,931	$	5,996	$	(14,927)	$	389
Natural gas
swaps	10,474,000	1.34		702		26		25,363		11,040		(35,675)		—
			$	1,091	$	26	$	34,294	$	17,036	$	(50,602)	$	389

___________________________

*	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.

 

29

Based on June 30, 2009 market prices, a $14.7 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.

 

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, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivative transactions under SFAS 133, are marked-to-market, are 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 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 are as follows:

 

	Outstanding at		Outstanding at
	June 30, 2009		December 31, 2008
		Latest		Latest
	Notional	Expiration	Notional	Expiration
	Amounts*	(months)	Amounts*	(months)
Natural gas futures purchased	8,920,000	21	1,290,000	3
Natural gas options purchased	2,650,000	9	3,990,000	3
Natural gas options sold	—	—	820,000	3
Natural gas basis swaps
purchased	377,500	9