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.

 

12

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):

 

 

 

 

15

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):

 

 

 

16

	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)

 

 

17

(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.

18

 

(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

 

 

19

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.

 

20

(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.

 

21

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

 

 

22

	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	—	—

________________________

*gas in MMBtus

 

30

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

 

									Net		Cash
									Unrealized		Collateral(a)
			Non-				Non-		Loss		Included in
	Current		current		Current		current		Included in		Derivative
	Derivative		Derivative		Derivative		Derivative		Regulatory		Assets/
	Assets		Assets		Liabilities		Liabilities		Assets		Liabilities
June 30, 2009	$	5,118 (b)	$	162	$	—	$	159	$	2,163	$	5,792
December 31, 2008	$	4,224	$	—	$	2,924	$	—	$	11,668	$	8,744

__________________________

(a)

FIN 39 permits the netting of receivables and payables when a legally enforceable master netting agreement exists between us and a counterparty. FSP 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 under a master netting agreement. At June 30, 2009 and December 31, 2008, we had the right to reclaim cash collateral of $5.8 million and $8.7 million, respectively.

(b)	Includes option premium of $1.5 million which will be recorded as a regulatory asset upon settlement of the options.

 

Weather Derivatives

 

As approved in the State of Iowa, Iowa Gas uses a weather derivative to mitigate the effect of fluctuations from normal weather, 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. Any gains and losses recorded on the contracts are recorded as regulatory assets or regulatory liabilities and do not have any impact on our financial position. These contracts terminated in the first quarter of 2009.

 

31

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 effectively convert the debt’s variable interest rate to a fixed rate.

 

On June 30, 2009, December 31, 2008 and June 30, 2008, our interest rate swaps and related balances were as follows (in thousands):

 

			Weighted												Pre-tax
			Average				Non-				Non-		Pre-tax		Gain/(Loss)
	Current		Fixed	Maximum	Current		current		Current		current		AOCI		included in
	Notional		Interest	Terms in	Derivative		Derivative		Derivative		Derivative		included in		Income
	Amount		Rate	Years	Assets		Assets		Liabilities		Liabilities		Balance Sheet		Statement
June 30,
2009
Interest rate
swaps	$	150,000	5.04%	7.50	$	—	$	—	$	6,045	$	10,469	$	(16,514)	$	—
Interest rate
swaps*		250,000	5.67%	0.50		—		—		47,971		—		—		46,469
	$	400,000			$	—	$	—	$	54,016	$	10,469	$	(16,514)	$	46,469
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)
June 30,
2008
Interest rate
swaps	$	150,000	5.04%	8.25	$	—	$	—	$	2,760	$	3,641	$	(6,401)	$	—
Interest rate
swaps		250,000	5.67%	0.50		—		—		18,926		—		(18,926)		—
	$	400,000			$	—	$	—	$	21,686	$	3,641	$	(25,327)	$	—

_________________________

*	The $250 million notional amount interest rate swaps represent the interest rate swaps that we de-designated in the fourth quarter of 2008 as disclosed in Note 2 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.

 

Based on June 30, 2009 market interest rates and balances, a loss of approximately $6.0 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. Furthermore, refer to Note 13 for further information related to the $250 million notional swaps that are not designated as hedges for accounting purposes.

 

32

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 $(0.3) million, $(0.2) million and $0.3 million at June 30, 2009, December 31, 2008 and June 30, 2008, respectively, have been recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. For the three and six months ended June 30, 2009, the unrealized foreign exchange gain (loss) was $(0.3) million and less than $0.1 million, respectively, while for the three and six months ended June 30, 2008, the amount of unrealized foreign exchange gain was $0.6 million and $0.9 million, respectively. For the three and six months ended June 30, 2009, the realized foreign currency gain was $1.4 million and $0.7 million, respectively, while for the three and six months ended June 30, 2008, the amount of foreign currency (loss) gain was $(0.2) million and $0.1 million, respectively. Currency transaction gains or losses on transactions executed in Canadian dollars are recorded in Operating revenues on the accompanying Condensed Consolidated Statements of Income as incurred.

 

All forward exchange contracts outstanding at June 30, 2009 will settle by July 24, 2009 and were 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)
(Dollars, in thousands)
Canadian dollars
purchased	$	19,000	1	$	52,000	1	$	47,000	1
Canadian dollars
sold	$	—	—	$	—	—	$	6,000	1

 

 

33

(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 $15.1 million on deposit in margin accounts at June 30, 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 Sheets, 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 June 30, 2009 (in thousands):

 

Fair Value as of June 30, 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	$	7,500	$	3,444
Commodity derivatives	Derivative assets – non-current		3		—
Commodity derivatives	Derivative liabilities – current		55		363
Commodity derivatives	Derivative liabilities – non-current		—		5
Interest rate swaps	Derivative liabilities – current		—		6,045
Interest rate swaps	Derivative liabilities – non-current		—		10,469
Total derivatives designated as hedges under SFAS 133		$	7,558	$	20,326
Derivatives not designated as hedges under SFAS 133:
Commodity derivatives	Derivative assets – current	$	243,199	$	186,714
Commodity derivatives	Derivative assets – non-current		15,875		10,849
Commodity derivatives	Derivative liabilities – current		12,776		27,465
Commodity derivatives	Derivative liabilities – non-current		79		1,703
Interest rate swap	Derivative liabilities – current		—		47,971
Foreign currency derivatives	Derivative liabilities – current		—		334
Total derivatives not designated as hedges under SFAS 133		$	271,929	$	275,036

 

 

34

A description of our derivative activities is discussed in Note 12. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2009.

 

Fair Value Hedges

 

The impact of commodity contracts designated as fair value hedges and the related hedged items on our accompanying Condensed Consolidated Statements of Income for the three and six months ended June 30, 2009 is presented as follows:

 

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
for the Three and Six Months Ended June 30, 2009
Fair Value Hedges
(in thousands)
		Three Months Ended		Six Months Ended
		June 30, 2009		June 30, 2009
	Location of	Amount of		Amount of
Derivatives in SFAS 133	Gain/(Loss) on	Gain/(Loss) on		Gain/(Loss) on
Fair Value	Derivatives Recognized	Derivatives Recognized		Derivatives Recognized
Hedging Relationships	in Income	in Income		in Income
Commodity derivatives	Operating revenue	$	(639)	$	6,881
Fair value adjustment for natural
gas inventory designated as
the hedged item	Operating revenue		1,415		(5,540)
		$	776	$	1,341

 

 

 

35

Cash Flow Hedges

 

The impact of cash flow hedges on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2009 is presented as follows:

 

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
and the Balance Sheet for the Three Months Ended June 30, 2009
Cash Flow Hedges
(in thousands)
			Location			Location of
	Amount of		of Gain/	Amount of		Gain/	Amount of
	Gain/ (Loss)		(Loss)	Gain/(Loss)		(Loss)	Gain/(Loss)
Derivatives	Recognized		Reclassified	Reclassified		Recognized	Recognized in
in SFAS 133	in AOCI		from AOCI	from AOCI		in Income	Income on
Cash Flow	Derivative		into Income	into Income		on Derivative	Derivative
Hedging	(Effective		(Effective	(Effective		(Ineffective	(Ineffective
Relationships	Portion)		Portion)	Portion)		Portion)	Portion)
Interest rate swaps	$	9,606	Interest expense	$	(610)		$	—
Commodity derivatives		(15,663)	Operating revenue		6,546	Operating revenue		(167)
Total	$	(6,057)		$	5,936		$	(167)

 

 

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
and the Balance Sheet for the Six Months Ended June 30, 2009
Cash Flow Hedges
(in thousands)
			Location			Location of
	Amount of		of Gain/	Amount of		Gain/	Amount of
	Gain/ (Loss)		(Loss)	Gain/(Loss)		(Loss)	Gain/(Loss)
Derivatives	Recognized		Reclassified	Reclassified		Recognized	Recognized in
in SFAS 133	in AOCI		from AOCI	from AOCI		in Income	Income on
Cash Flow	Derivative		into Income	into Income		on Derivative	Derivative
Hedging	(Effective		(Effective	(Effective		(Ineffective	(Ineffective
Relationships	Portion)		Portion)	Portion)		Portion)	Portion)
Interest rate swaps	$	11,721	Interest expense	$	(1,958)		$	—
Commodity derivatives		(8,508)	Operating revenue		13,181	Operating revenue		(1,094)
Total	$	3,213		$	11,223		$	(1,094)

 

36

Derivatives Not Designated as Hedge Instruments

 

The impact of derivative instruments that have not been designated as hedges on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2009 is presented below.

 

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
for the Three and Six Months Ended June 30, 2009
Derivatives Not Designated as Hedging Instruments
(in thousands)
		Three Months Ended		Six Months Ended
		June 30, 2009		June 30, 2009
	Location of	Amount of		Amount of
Derivatives Not Designated	Gain/(Loss) on	Gain/(Loss) on		Gain/(Loss) on
as Hedging Instruments	Derivatives Recognized	Derivatives Recognized		Derivatives Recognized
under SFAS 133	in Income	in Income		in Income
Commodity derivatives	Operating revenue	$	(9,239)	$	(17,364)
Interest rate swap	Interest rate swap		31,706		46,469
Foreign currency contracts	Operating revenue		(350)		(107)
		$	22,117	$	28,998

 

 

 

37

(14)	DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

 

Derivative Financial Instruments

 

We adopted SFAS 157 effective January 1, 2008 for all financial assets and liabilities and any other assets and liabilities that are recognized at fair value on a recurring basis. SFAS 157 establishes a new framework for measuring fair value and expands related disclosures. Broadly, SFAS 157 provides a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS 157 establishes a three-tier valuation hierarchy based upon observable and non-observable inputs.

 

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

 

Level 1 – Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities and listed derivatives.

 

Level 2 – Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

 

Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

 

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009, December 31, 2008 and June 30, 2008. As required by SFAS 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

 

 

Recurring Fair Value	At Fair Value as of June 30, 2009
Measures (in thousands)
							Counterparty
							Netting
							and Cash
	Level 1		Level 2		Level 3		Collateral(a)		Total
Assets:
Commodity derivatives	$	—	$	252,368	$	13,189	$	(184,929)	$	80,628
Liabilities:
Commodity derivatives	$	—	$	208,577	$	8,036	$	(199,987)	$	16,626
Foreign currency derivatives		—		334		—		—		334
Interest rate swaps		—		64,486		—		—		64,486
Total	$	—	$	273,397	$	8,036	$	(199,987)	$	81,446

 

 

38

Recurring Fair Value	At Fair Value as of December 31, 2008
Measures (in thousands)
							Counterparty
							Netting
							and Cash
	Level 1		Level 2		Level 3		Collateral(a)		Total
Assets:
Commodity derivatives	$	—	$	267,932	$	28,407	$	(208,952)	$	87,387
Liabilities:
Commodity derivatives	$	—	$	211,672	$	12,009	$	(201,381)	$	22,300
Foreign currency
derivatives		—		227		—		—		227
Interest rate swaps		—		122,675		—		—		122,675
Total	$	—	$	334,574	$	12,009	$	(201,381)	$	145,202

 

 

Recurring Fair Value	At Fair Value as of June 30, 2008
Measures (in thousands)
							Counterparty
							Netting
							and Cash
	Level 1		Level 2		Level 3		Collateral(a)		Total
Assets:
Short - term investments	$	—	$	—	$	7,309	$	—	$	7,309
Commodity derivatives		—		291,848		24,424		(231,461)		84,811
Total	$	—	$	291,848	$	31,733	$	(231,461)	$	92,120
Liabilities:
Commodity derivatives	$	—	$	355,358	$	13,092	$	(280,511)	$	87,939
Interest rate swaps		—		25,327		—		—		25,327
Foreign currency
derivatives		—		318		—		—		318
Total	$	—	$	381,003	$	13,092	$	(280,511)	$	113,584

________________________

(a)

FIN 39 permits the 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 under a master netting agreement. Cash collateral included on deposit in margin accounts at June 30, 2009, December 31, 2008 and June 30, 2008 totaled a net $15.1 million, $(7.6) million and $49.1 million, respectively. 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.

 

39

The following tables present the changes in level 3 recurring fair value for the three and six months ended June 30, 2009 and 2008, respectively (in thousands):

 

	Three Months		Six Months
	Ended		Ended
	June 30, 2009		June 30, 2009
	Commodity		Commodity
	Derivatives		Derivatives
Balance as of beginning of period	$	13,407	$	16,398
Realized and unrealized losses		(1,310)		(1,555)
Purchases, issuance and settlements		(747)		(6,054)
Transfers in and/or out of level 3(a)		(6,197)		(3,636)
Balances as of June 30, 2009	$	5,153	$	5,153
Changes in unrealized losses
relating to instruments still held as of
June 30, 2009	$	(7,013)	$	(10,455)

____________________________

(a)

Transfers into level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable. Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

 

	Three Months Ended
	June 30, 2008
	Commodity		Short-term
	Derivatives		Investments		Total
Balance as of April 1, 2008	$	6,973	$	7,290	$	14,263
Realized and unrealized gains		5,793		19		5,812
Purchases, issuance and settlements		(1,434)		—		(1,434)
Balances as of June 30, 2008	$	11,332	$	7,309	$	18,641
Changes in unrealized gains
relating to instruments still held as of
June 30, 2008	$	727	$	19	$	39

 

 

40

	Six Months Ended
	June 30, 2008
	Commodity		Short-term
	Derivatives		Investments		Total
Balance as of January 1, 2008	$	6,422	$	—	$	6,422
Realized and unrealized gains (losses)		6,830		(166)		6,664
Purchases, issuance and settlements		(1,920)		7,475		5,555
Balances as of June 30, 2008	$	11,332	$	7,309	$	18,641
Changes in unrealized losses
relating to instruments still held as of
June 30, 2008	$	(62)	$	(166)	$	(228)

 

Gains and losses (realized and unrealized) for level 3 commodity derivatives are included in Operating revenues on the accompanying Condensed Consolidated Statements of Income. We believe an analysis of commodity derivatives classified as level 3 needs to be undertaken with the understanding that these items may be economically hedged as part of a total portfolio of instruments that may be classified in level 1 or 2, or with instruments that may not be accounted for at fair value. Accordingly, gains and losses associated with level 3 balances may not necessarily reflect trends occurring in the underlying business. Further, unrealized gains and losses for the period from level 3 items may be offset by unrealized gains and losses in positions classified in level 1 or 2, as well as positions that have been realized during the quarter. Short-term investments included in level 3 represent auction rate securities held at June 30, 2008. The unrealized losses for these investments are recognized in Accumulated other comprehensive income on the accompanying Condensed Consolidated Balance Sheets.

 

Fair Value of Financial Instruments

 

The estimated fair value of our financial instruments at June 30, 2009 is as follows (in thousands):

 

	Carrying Amount		Fair Value
Cash and cash equivalents	$	122,351	$	122,351
Derivative financial instruments – assets	$	80,629	$	80,629
Derivative financial instruments – liabilities	$	81,445	$	81,445
Notes payable	$	270,500	$	270,500
Long-term debt, including current maturities	$	751,329	$	776,616

 

The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

 

Cash and Cash Equivalents and Restricted Cash

 

The carrying amount approximates fair value due to the short maturity of these instruments.

 

Derivative Financial Instruments

 

These instruments are carried at fair value. Descriptions of the various instruments we use and the valuation method employed are included in Notes 12 and 14.

 

41

Notes Payable

 

The carrying amount approximates fair value due to their variable interest rates with short reset periods.

 

Long-Term Debt

 

The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings.

 

(15)	COMMITMENTS AND CONTINGENCIES

 

Legal Proceedings

 

We are subject to various legal proceedings, claims and litigation as described in Note 18 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K. There have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first six months of 2009.

 

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our consolidated financial statements are adequate in light of the probable and estimable contingencies.  However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our consolidated financial statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of June 30, 2009, cannot be reasonably determined and could have a material adverse effect on our results of operations or financial position.

 

FERC Compliance Investigation

 

During 2007, following an internal review of natural gas marketing activities conducted within the Energy Marketing segment, we identified possible instances of noncompliance with regulatory requirements applicable to those activities. We notified the enforcement staff of FERC of our findings and shared information with a purpose to resolve any potential enforcement concerns. We also evaluated public announcements of civil penalties that have been levied against other companies for violations of FERC regulatory requirements. We believe we have adequately reserved for the estimated potential penalty that could be levied on us. Although the outcome of any legal or regulatory proceedings resulting from these matters cannot be predicted with any certainty, and while the final resolution of these matters could have a material impact on the consolidated net income of any particular period, the outcome of this proceeding is not expected to have a material impact upon our overall consolidated financial position.

 

Partial Sale of Wygen I to MEAN

 

During August 2008, we entered into a definitive agreement to sell a 23.5% ownership interest in the Wygen I plant to MEAN. The sale was completed in January 2009 for a price of $51.0 million, which was based on the then-current replacement cost for the coal-fired plant. We realized an after-tax gain of $16.9 million on the sale, and our property, plant and equipment was reduced by $26.2 million. We retain responsibility for operations of the plant, and at closing entered into a site lease, and agreements with MEAN for coal supply and operations. In addition, we terminated a 10-year power purchase contract requiring MEAN to purchase 20 MW of power annually from Wygen I.

 

42

Sale to MDU

 

On April 9, 2009, Black Hills Power sold to MDU a 25% ownership interest in its Wygen III generation facility currently under construction. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received of which $30.2 million was used to pay down a portion of the Acquisition Facility. MDU will continue to reimburse Black Hills Power for its 25% of the total costs paid to complete the project. In conjunction with the sales transaction, we also modified a 2004 power purchase agreement between Black Hills Power and MDU under which Black Hills Power supplied MDU with 74 MW of capacity and energy through 2016.

 

Long-Term Power Sales Agreement

 

In March 2009, our 10-year power sales contract between MEAN and Black Hills Power that originally would have expired in 2013 was re-negotiated and extended until 2023. Under the new contract, MEAN will purchase 20 MW of unit-contingent capacity from the Neil Simpson II and Wygen III plants, with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II plants are as follows:

 

2009-2017	20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

 

Purchase Power Agreement

 

In April 2009, Cheyenne Light entered into an agreement to purchase 30 MW of renewable energy from Duke Energy’s Silver Sage wind site through a 20-year purchase power agreement. Construction is expected to be completed by the end of 2009.

 

43

(16)	ACQUISITION

 

Aquila Transaction

 

On July 14, 2008, we completed the acquisition of a regulated electric utility in Colorado and four regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. See Note 21 of the Notes to our 2008 Annual Report on Form 10-K for additional information.

 

This acquisition has been accounted for under the purchase method of accounting, and accordingly, the purchase price has been allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and liabilities assumed as of the date of acquisition. Adjustments to the purchase price allocation during the six months ended June 30, 2009 included working capital adjustments of $0.2 million. Outstanding adjustments relate to property taxes and inventory, which we finalized subsequent to June 30, 2009. The estimated purchase price allocations are subject to adjustment, generally within one year of the date of acquisition. Adjustments to goodwill subsequent to June 30, 2009 totaled approximately $0.1 million. Allocation of the purchase price as of June 30, 2009 is as follows (in thousands):

 

Current assets	$	113,261
Property, plant and equipment		542,094
Derivative assets		4,695
Goodwill		344,457
Intangible assets		4,884
Deferred assets		70,939
	$	1,080,330
Current liabilities	$	95,257
Deferred credits and other
liabilities		54,550
	$	149,807
Net assets	$	930,523

 

After finalization of the working capital adjustment, the allocation of the purchase price resulted in $344.5 million of goodwill and $4.9 million of intangible assets. Goodwill of $246.5 million was allocated to the Electric Utility and $98.0 million was allocated to the Gas Utilities.

 

The results of operations of the acquired regulated utilities have been included in the accompanying Condensed Consolidated Financial Statements since the acquisition date.

 

44

The following pro-forma consolidated results of operations have been prepared as if the acquisition of the regulated utilities had occurred on January 1, 2008 (in thousands, except per share amounts):

 

	Three Month		Six Month
	Period Ended		Period Ended
	June 30,		June 30,
	2008		2008
Operating revenues	$	338,173	$	826,823
Income from continuing operations		17,603		49,049
Net income available for common stock		26,596		63,017
Earnings per share –
Basic:
Continuing operations	$	0.46	$	1.29
Total	$	0.69	$	1.66
Diluted:
Continuing operations	$	0.46	$	1.28
Total	$	0.69	$	1.64

 

The above pro-forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that would have been achieved had the acquisition been consummated at that time; nor is it intended to be a projection of future results.

 

(17)	INCOME TAXES

 

Our effective tax rate for the six months ended June 30, 2009 was lower than previous periods as a result of a positive adjustment in the first quarter of 2009 for a previously recorded tax position. We recorded a $3.8 million reduction in tax expense in our Oil and Gas segment due to a re-measurement of this position which was recorded in accordance with FIN 48.

 

(18)	DISCONTINUED OPERATIONS

 

We account for our discontinued operations under the provisions of SFAS 144. Accordingly, results of operations and the related charges for discontinued operations have been classified as “Income from discontinued operations, net of taxes” in the accompanying Condensed Consolidated Statements of Income. Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.” For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis.

 

Sale of IPP Assets

 

On April 29, 2008, we entered into a definitive agreement to sell seven of our IPP plants to affiliates of Hastings and IIF for $840 million, subject to certain working capital adjustments. The transaction was completed July 11, 2008. Under the agreement, we received net pre-tax cash proceeds of $756 million, including the effects of estimated working capital adjustments and other costs and the required payoff of approximately $67.5 million of associated project level debt. The after-tax gain recorded on the asset sale, after finalization of the working capital adjustments, was $140.5 million, of which $139.7 million was recorded in 2008 in discontinued operations.

 

45

Revenues and net income from the discontinued operations associated with the divested IPP plants were as follows (in thousands):

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008*		2009		2008*
Operating revenues	$	—	$	27,705	$	—	$	54,065
Pre-tax income from
discontinued operations		—		13,949		1,190		21,853
Income tax expense		—		4,884		424		7,954
Net income from
discontinued operations	$	—	$	9,065	$	766	$	13,899

________________________

*	In accordance with GAAP, during the second quarter of 2008, the Company ceased recording depreciation and amortization expense on the IPP facilities.

 

Allocation of corporate expenses to discontinued operations was made in accordance with SFAS 144 and EITF 87-24. The indirect corporate costs and inter-segment interest expense related to the IPP assets sold and not reclassified to discontinued operations were $4.2 million and $7.7 million after-tax for the three and six months ended June 30, 2008, respectively. These allocated costs remain in the Power Generation segment.

 

Interest expenses included within the operations of the discontinued entities were recorded pursuant to EITF 87-24 and include interest expense on debt which was required to be repaid as a result of the sale transaction. In accordance with EITF 87-24, interest expense was allocated to discontinued operations based on the ratio of the assets sold to total Company net assets, excluding the known debt repayment. For the three and six months ended June 30, 2008, respectively, interest expense allocated to discontinued operations was $2.0 million and $4.7 million.

 

Net assets associated with the divested IPP plants were as follows (in thousands):

	June 30,
	2008
Current assets	$	29,437
Property, plant and equipment, net of
accumulated depreciation		506,609
Goodwill		26,500
Intangible assets (net of accumulated
amortization of $28,958)		20,204
Other non-current assets		15,146
Current liabilities		(9,148)
Long-tem debt		(67,500)
Other non-current liabilities		(86)
Net assets	$	521,162

 

46

 

 

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

 

We are a diversified energy company operating principally in the United States with two major business groups – Utilities and Non-regulated Energy. We report our business groups in the following reportable operating segments:

 

Business Group	Financial Segment
Utilities Group	Electric Utilities
	Gas Utilities
Non-regulated Energy Group	Oil and Gas
	Power Generation
	Coal Mining
	Energy Marketing

 

Our Utilities Group consists of our electric and gas utility segments. Our Electric Utilities generate, transmit and distribute electricity to approximately 202,100 customers in South Dakota, Wyoming, Colorado and Montana. In addition, Cheyenne Light, which is also reported within the Electric Utilities segment, provides natural gas to approximately 33,300 customers in Wyoming. Our Gas Utilities segment serves approximately 524,000 natural gas customers in Colorado, Nebraska, Iowa and Kansas. Our Non-regulated Energy Group engages in the production of coal, natural gas and crude oil primarily in the Rocky Mountain region; the production of electric power through ownership of a portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts; and the marketing of natural gas, crude oil and related services.

 

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 82.

 

Significant Events

 

Wygen III Power Plant Project and Sale to MDU

 

In March 2008, we received final regulatory approval for construction of Wygen III. Construction began immediately and the 110 MW coal-fired base load electric generating facility is expected to be completed by June, 2010. The expected cost of construction is approximately $255 million, which includes estimates for AFUDC. A 2004 Purchase Power Agreement between Black Hills Power and MDU included an option to purchase an ownership interest in Wygen III. MDU exercised this option, and under an agreement entered into in April 2009, we will retain an undivided ownership of 75% of the facility with MDU owning the remaining 25%. At closing, MDU reimbursed us for its 25% of the total costs incurred to date on the ongoing construction of the facility. We received proceeds of $32.8 million, of which $30.2 million was used to pay down a portion of the Acquisition Facility. We will retain responsibility for operations of the facility with a life-of-plant site lease and agreements with MDU for operations and coal supply. In conjunction with the sales transaction, we also modified a 2004 power purchase agreement between Black Hills Power and MDU under which Black Hills Power supplied MDU with 74 MW of capacity and energy through 2016.

47

Partial Sale of Wygen I to MEAN

 

During August 2008, we entered into a definitive agreement to sell a 23.5% ownership interest in the Wygen I plant to MEAN. The sale was completed in January, 2009 for a price of $51.0 million, which was based on the then current replacement cost for the coal-fired plant. We realized an after-tax gain of $16.9 million on the sale, and our property, plant and equipment was reduced by $26.2 million. We retain responsibility for operations of the plant, and at closing entered into a site lease, and agreements with MEAN for coal supply and operations. In addition, we terminated a 10-year power purchase contract requiring MEAN to purchase 20 MW of power annually from Wygen I.

 

Extension of Long-Term Power Sales Agreement with MEAN

 

In March 2009, our 10-year power sales contract between MEAN and Black Hills Power that originally expired in 2013 was re-negotiated and extended until 2023. Under the new contract, MEAN will purchase 20 MW of unit-contingent capacity from the Neil Simpson II and the Wygen III plants with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II plants are as follows:

 

2009-2017	20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

 

Colorado Electric Resource Plan

 

In August 2008, Black Hills Energy filed a long-term Electric Resource Plan with the CPUC proposing to build five natural gas-fired power generation facilities totaling 350 MW to support the customers of Colorado Electric. In the first quarter of 2009, Colorado Electric received approval from the CPUC to build two of the five power generation facilities representing approximately 150 MW. The power generation facilities are part of a plan to replace the purchased power agreement currently with PSCo which expires on December 31, 2011. The initial decision of the CPUC waives the competitive bidding process for the two turbines; the remaining capacity and energy needs of the utility will be acquired from other power producers through a competitive bid process, which is on-going. Our Power Generation segment was allowed to bid in the competitive bidding process. The Company is currently evaluating bids for the remaining capacity and energy requirements and anticipates executing power purchase agreements with the successful bidder(s) prior to year-end.

 

Silver Sage Wind Site

 

In April 2009, Cheyenne Light entered into an agreement to purchase 30 MW of renewable energy from Duke Energy’s Silver Sage wind site through a 20-year purchase power agreement. Construction is expected to be completed by the end of 2009.

 

Purchase Power Agreement with MEAN

 

In July 2009, we entered into a five-year PPA with MEAN. The contract commences the month following the commercial operations of Wygen III. Under this contract, MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.

 

 

48

Results of Operations

 

Executive Summary

 

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008.

Income from continuing operations for the three month period ended June 30, 2009 was $24.6 million, or $0.64 per share, compared to $13.2 million, or $0.34 per share, reported for the same period in 2008. For the three month period ended June 30, 2009, net income available for common stock was $24.6 million or $0.64 per share, compared to $22.2 million, or $0.58 per share, for the same period in 2008.

 

Included in 2009 are the results from the utilities acquired from Aquila on July 14, 2008 and impact of a $20.6 million after-tax non-cash gain, resulting from an unrealized net mark-to-market gain for certain interest rate swaps entered into in 2007.

 

The Utilities Group includes the 2009 results of the electric and gas utilities acquired from Aquila on July 14, 2008. Earnings reflect the impact of lower margins from off-system sales due to lower energy prices, higher interest expense, and higher employee benefit costs.

 

Earnings from the Oil and Gas segment decreased for the quarter due to a decrease in operating revenues resulting from lower oil and gas prices and lower production, partially offset by lower production taxes due to lower oil and gas prices. Average oil prices received, net of hedges, decreased 42% and average gas prices received, net of hedges, decreased 45%.

 

Lower earnings from the Coal Mining segment resulted from lower coal sales volume, increased depreciation and coal taxes, partially offset by revenue increases from higher average sale prices and lower diesel fuel costs.

 

Increased earnings from the Energy Marketing segment reflect higher realized natural gas and crude oil margins received, partially offset by unrealized mark-to-market losses. Realized natural gas margins were primarily impacted by differing market conditions between years.

 

Earnings from the Power Generation segment were impacted by increased interest expense and lower margins due to the net earnings impact of replacing the 20 MW PPA with operating and site lease agreements related to MEAN’s purchase of a 23.5% ownership interest in Wygen I, partially offset by operating fees charged to MEAN. For the three months ended June 30, 2008, results included $6.4 million pre-tax indirect corporate costs and intersegment net interest expense not reclassified to discontinued operations for the IPP Transaction.

 

49

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008.

Income from continuing operations for the six month period ended June 30, 2009 was $50.2 million, or $1.30 per share, compared to $25.0 million, or $0.65 per share, reported for the same period in 2008. For the six month period ended June 30, 2009, net income available for common stock was $51.0 million or $1.32 per share, compared to $39.0 million, or $1.01 per share, for the same period in 2008.

 

Included in the 2009 results are the earnings from the utilities acquired from Aquila on July 14, 2008 and impacts from the following notable items:

 

•     $16.9 million after-tax gain from sale of a 23.5% interest in the Wygen I generation facility on January 22, 2009;

•     $30.2 million after-tax non-cash gain, resulting from an unrealized net mark-to-market gain for certain interest rate swaps entered into in 2007; and

•     Non-cash impairment charge of oil and gas assets totaling $27.8 million after-tax, driven by lower natural gas and crude oil prices at the end of the first quarter of 2009.

 

The Utilities Group includes the 2009 results of the electric and gas utilities acquired from Aquila on July 14, 2008. Earnings reflect the impact of increased retail margins from an approved rate case for transmission rates and the impact of AFUDC related to the Wygen III construction partially offset by lower margins from off-system sales due to lower energy prices and higher interest expense.

 

Earnings from the Oil and Gas segment decreased from 2008 due to a decrease in operating revenues reflecting lower oil and gas prices and lower production and a first quarter of 2009 impairment charge, partially offset by lower production taxes and LOE costs compared to 2008. Average oil prices received, net of hedges, decreased 40% and average gas prices received, net of hedges, decreased 40%.

 

Lower earnings from the Coal Mining segment in 2009 resulted from lower coal sales volumes, increased depreciation and coal taxes, partially offset by revenue increases from higher average sale prices and lower diesel fuel costs.

 

Increased earnings from the Energy Marketing segment in 2009 reflect higher realized natural gas and crude oil margins received, partially offset by unrealized mark-to-market losses. Realized natural gas margins were primarily impacted by differing market conditions between years.

 

Increased earnings from the Power Generation segment in 2009 were impacted by a $16.9 million after-tax gain on the sale of a 23.5% ownership interest in the Wygen I power generation facility to MEAN and increased interest expense, partially offset by lower margins due to the net earnings impact of replacing the 20 MW PPA with operating and site lease agreements related to MEAN’s purchase of the 23.5% ownership interest in Wygen I. In addition, for the six months ended June 30, 2008, results included $11.8 million of pre-tax allocated indirect corporate costs and intersegment net interest expense not classified to discontinued operations for the IPP Transaction.

 

Income from discontinued operations was $0.8 million, or $0.02 per share, for the six month period ended June 30, 2009, compared to $14.1 million, or $0.36 per share, for the same period in 2008. The Income from discontinued operations in 2009 relates to working capital adjustments and the related impact on the gain on sale from the IPP Transaction.

 

50

Consolidated Results

 

The following business group and segment information does not include intercompany eliminations or results of discontinued operations. Amounts are presented on a pre-tax basis unless otherwise indicated.

 

Revenues and Income (loss) from continuing operations provided by each business group were as follows (in thousands):

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Revenues
Utilities	$	211,944	$	93,567	$	605,341	$	192,868
Non - regulated Energy		45,405		59,706		89,951		113,255
	$	257,349	$	153,273	$	695,292	$	306,123
Income (loss) from
continuing operations
Utilities	$	4,983	$	9,553	$	31,566	$	19,720
Non - regulated Energy		2,818		7,547		(3,676)		11,130
Corporate		16,780		(3,897)		22,316		(5,830)
	$	24,581	$	13,203	$	50,206	$	25,020

 

Income from continuing operations increased $11.4 million for the three months ended June 30, 2009 due primarily to the following:

 

•     $0.4 million income from the Gas Utilities segment;

•     A $1.2 million increase in Power Generation earnings;

•     A $1.8 million increase in Energy Marketing earnings; and

•     A $20.7 million increase in corporate income.

The increases in earnings were partially offset by:

•     A $5.0 million decrease in Electric Utilities earnings;

•     A $7.1 million decrease in Oil and Gas earnings; and

•     A $1.0 million decrease in Coal Mining earnings.

 

 

51

Income from continuing operations increased $25.2 million for the six months ended June 30, 2009 due primarily to the following:

 

•     $17.7 million income from the Gas Utilities segment;

•     A $19.3 million increase in Power Generation earnings;

•     A $2.6 million increase in Energy Marketing earnings; and

•     A $28.1 million increase in corporate income.

The increases in earnings were partially offset by:

•     A $5.9 million decrease in Electric Utilities earnings;

•     A $35.3 million decrease in Oil and Gas earnings; and

•     A $1.8 million decrease in Coal Mining earnings.

 

See the following discussion under the captions “Utilities Group” and “Non-regulated Energy Group” for more detail on our results of operations by business segment.

 

52

Utilities Group

 

We acquired from Aquila regulated electric utility assets in Colorado and four regulated gas utilities assets operating in Colorado, Nebraska, Iowa and Kansas. Operations from the acquired utilities have been included in the Utilities Group results from the July 14, 2008 acquisition date.

 

With the completion of the acquisition, we are reporting two segments within the Utilities Group: Electric Utilities and Gas Utilities. The Electric Utilities segment includes the electric operations of Black Hills Power, Colorado Electric and the electric and natural gas operations of Cheyenne Light. The Gas Utilities segment includes the regulated natural gas utility operations of Black Hills Energy in Colorado, Nebraska, Iowa and Kansas.

 

Electric Utilities

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in thousands)
Revenue – electric	$	112,998	$	82,178	$	235,174	$	164,751
Revenue – gas		5,823		11,752		20,922		28,787
Total revenue		118,821		93,930		256,096		193,538
Fuel and purchased power – electric		58,938		37,945		123,836		78,199
Purchased gas		2,705		8,597		12,962		20,457
Total fuel and purchased power		61,643		46,542		136,798		98,656
Gross margin – electric		54,060		44,233		111,338		86,552
Gross margin – gas		3,118		3,155		7,960		8,330
Total gross margin		57,178		47,388		119,298		94,882
Operating expenses		43,338		29,466		86,212		57,093
Operating income	$	13,840	$	17,922	$	33,086	$	37,789
Income from continuing operations
and net income available for
common stock	$	4,541	$	9,553	$	13,858	$	19,720

 

 

 

 

53

The following tables summarize regulated sales revenues, quantities generated and purchased, sales quantities and degree days for our Electric Utilities segment. Included in 2009 reported amounts for the periods are the operations of Colorado Electric, acquired July 14, 2008 as part of the Aquila Transaction:  

 

Sales Revenues	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in thousands)
Residential:
Black Hills Power	$	10,391	$	10,002	$	24,672	$	22,980
Cheyenne Light		7,094		8,093		14,581		18,046
Colorado Electric		15,185		—		31,688		—
Total Residential		32,670		18,095		70,941		41,026
Commercial:
Black Hills Power		14,551		13,063		29,194		26,535
Cheyenne Light		12,565		11,969		24,626		23,390
Colorado Electric		13,943		—		27,171		—
Total Commercial		41,059		25,032		80,991		49,925
Industrial:
Black Hills Power		5,030		5,542		9,780		10,838
Cheyenne Light		2,758		2,179		5,291		4,167
Colorado Electric		6,961		—		15,053		—
Total Industrial		14,749		7,721		30,124		15,005
Municipal:
Black Hills Power		660		639		1,296		1,264
Cheyenne Light		230		240		471		471
Colorado Electric		1,143		—		2,172		—
Total Municipal		2,033		879		3,939		1,735
Contract Wholesale:
Black Hills Power		5,631		6,270		12,184		13,202
Off-system Wholesale:
Black Hills Power		5,765		19,238		14,985		34,335
Cheyenne Light		1,952		1,611		3,932		2,871
Colorado Electric		2,974		—		7,027		—
Total Off - system Wholesale		10,691		20,849		25,944		37,206
Other:
Black Hills Power		4,808		3,224		9,183		6,456
Cheyenne Light		112		108		213		196
Colorado Electric		1,245		—		1,655		—
Total Other		6,165		3,332		11,051		6,652
Total Sales Revenues	$	112,998	$	82,178	$	235,174	$	164,751

 

 

54

Quantities Generated and Purchased	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in MWh)
Generated –
Coal-fired:
Black Hills Power		348,657		384,748		786,208		817,630
Cheyenne Light		185,172		201,685		376,728		389,698
Colorado Electric		56,856		—		123,331		—
Total Coal		590,685		586,433		1,286,267		1,207,328
Gas and Oil-fired:
Black Hills Power		5,750		4,831		6,825		41,831
Cheyenne Light		—		—		—		—
Colorado Electric		199		—		199		—
Total Gas and Oil		5,949		4,831		7,024		41,831
Total Generated:
Black Hills Power		354,407		389,579		793,033		859,461
Cheyenne Light		185,172		201,685		376,728		389,698
Colorado Electric		57,055		—		123,530		—
Total Generated		596,634		591,264		1,293,291		1,249,159
Purchased:
Black Hills Power		451,191		467,284		884,030		851,865
Cheyenne Light		154,286		124,884		312,273		263,547
Colorado Electric		493,319		—		980,845		—
Total Purchased		1,098,796		592,168		2,177,148		1,115,412
Total Generated and Purchased		1,695,430		1,183,432		3,470,439		2,364,571

 

55

 

Quantity Sold	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in MWh)
Residential:
Black Hills Power		119,123		114,106		282,599		277,140
Cheyenne Light		59,100		57,325		130,226		132,667
Colorado Electric		134,557		—		277,230		—
Total Residential		312,780		171,431		690,055		409,807
Commercial:
Black Hills Power		169,955		162,313		345,211		335,772
Cheyenne Light		141,555		141,450		287,100		286,767
Colorado Electric		169,698		—		319,164		—
Total Commercial		481,208		303,763		951,475		622,539
Industrial:
Black Hills Power		93,984		109,028		179,968		211,697
Cheyenne Light		43,425		36,023		86,247		69,771
Colorado Electric		98,603		—		220,417		—
Total Industrial		236,012		145,051		486,632		281,468
Municipal:
Black Hills Power		7,567		7,637		15,662		15,845
Cheyenne Light		682		742		1,707		1,762
Colorado Electric		10,571		—		17,991		—
Total Municipal		18,820		8,379		35,360		17,607
Contract Wholesale:
Black Hills Power		143,248		156,965		311,927		328,585
Off-system Wholesale:
Black Hills Power		230,617		283,770		474,403		511,511
Cheyenne Light		73,947		67,441		144,051		132,413
Colorado Electric		94,865		—		200,808		—
Total Off-system Wholesale		399,429		351,211		819,262		643,924
Total Quantity Sold		1,591,497		1,136,800		3,294,711		2,303,930
Losses and Company Use:
Black Hills Power		41,104		23,044		67,293		30,776
Cheyenne Light		20,749		23,588		39,670		29,865
Colorado Electric		42,080		—		68,765		—
Total Losses and Company
Use		103,933		46,632		175,728		60,641
Total Energy		1,695,430		1,183,432		3,470,439		2,364,571

 

 

56

Degree Days	Three Months Ended
	June 30,
	2009		2008
		Variance		Variance
		from		from
Heating Degree Days:	Actual	Normal	Actual	Normal
Actual –
Black Hills Power	1,273	28%	1,230	23%
Cheyenne Light	1,261	2%	1,306	6%
Colorado Electric	579	(10)%	—	—
Cooling Degree Days:
Actual –
Black Hills Power	51	(50)%	29	(71)%
Cheyenne Light	24	(43)%	27	(36)%
Colorado Electric	184	(15)%	—	—

 

 

Degree Days	Six Months Ended
	June 30,
	2009		2008
		Variance		Variance
		from		from
Heating Degree Days:	Actual	Normal	Actual	Normal
Actual –
Black Hills Power	4,527	5%	4,591	7%
Cheyenne Light	4,085	(7)%	4,542	4%
Colorado Electric	2,949	(10)%	—	—
Cooling Degree Days:
Actual –
Black Hills Power	51	(50)%	29	(71)%
Cheyenne Light	24	(43)%	27	(42)%
Colorado Electric	184	(15)%	—	—

 

 

57

	Electric Utilities Power Plant Availability
	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
Coal-fired plants	81.8%**	89.0%*	89.5%**	91.5%*
Other plants	92.6%	78.8%	96.0%	86.9%
Total availability	86.0%	85.4%	92.0%	89.9%

_________________________

*

Reflects major maintenance outages at our Ben French, Neil Simpson I and Osage coal-fired plants. The Ben French outage was scheduled for 25 days and was subsequently extended to accelerate major maintenance originally scheduled for 2009. The actual outage was 88 days and resulted in the plant’s output being restored to its full rated capacity. The Osage outage was originally scheduled for approximately 10 days and lasted 52 days as a result of additional unplanned required maintenance. All the plants were online by the end of the second quarter of 2008.

**

Reflects major maintenance outages at Neil Simpson I and Neil Simpson II coal-fired plants. The Neil Simpson I outage was scheduled for 31 days and was subsequently extended to 39 days. The Neil Simpson II outage was scheduled for 18 days and was subsequently extended to 27 days. The outages were extended on both units for major rotor damage discovered during the overhauls.

 

Cheyenne Light Natural Gas Distribution

 

Included in the Electric Utilities is Cheyenne Light’s natural gas distribution system. The following table summarizes certain operating information of these natural gas distribution operations:

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Sales Revenues (in thousands):
Residential	$	3,634	$	6,835	$	12,646	$	16,843
Commercial		1,631		3,365		6,060		8,393
Industrial		373		1,355		1,807		3,143
Other		185		197		409		408
Total Sales Revenues	$	5,823	$	11,752	$	20,922	$	28,787
Sales Margins (in thousands):
Residential	$	2,089	$	2,270	$	5,366	$	5,763
Commercial		746		560		1,917		1,838
Industrial		98		127		268		307
Other		185		198		409		422
Total Sales Margins	$	3,118	$	3,155	$	7,960	$	8,330
Volumes Sold (Dth):
Residential		553,518		553,018		1,568,764		1,761,111
Commercial		333,213		309,552		917,636		995,824
Industrial		135,790		138,787		383,115		400,742
Total Volumes Sold		1,022,521		1,001,357		2,869,515		3,157,677

 

 

 

58

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Income from continuing operations for the Electric Utilities decreased $5.0 million from the prior period primarily due to the following:

 

•     A $2.8 million decrease in margins from off-system sales reflecting the lower margins available in the industry’s current low energy price environment;

•     A $1.8 million decrease in retail margins primarily due to outages at Neil Simpson I, Neil Simpson II and Wyodak, partially offset by a full quarter of operations at Ben French which had outages in the second quarter of 2008;

•     A $5.5 million increase in net interest expense due to additional debt associated with the acquisition of Colorado Electric; and

•     A $1.5 million increase in employee benefit costs.

Partially offsetting these were the following:

•     Increased margin of $1.9 million related to an increase in transmission rate effective January 1, 2009 at Black Hills Power; and

•     Increased AFUDC of $1.3 million primarily due to construction of Wygen III and Colorado Electric in 2009.

 

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Income from continuing operations for the Electric Utilities decreased $5.9 million from the prior period primarily due to the following:

 

•     A $3.8 million decrease in margins from off-system sales reflecting the lower margins available in the industry’s current low energy price environment;

•     An $8.7 million increase in net interest expense due to additional debt associated with the acquisition of Colorado Electric; and

•     A $2.3 million increase in employee benefit costs.

Partially offsetting these were the following:

•     Increased gross margins of $3.0 million due to increase in transmission rate effective January 1, 2009 at Black Hills Power; and

•     Increased AFUDC of $2.9 million due to construction of Wygen III and Colorado Electric in 2009.

 

59

Gas Utilities

 

Operating results for the Gas Utilities are as follows:

 

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009		2009
	(in thousands)
Revenue:
Natural gas – regulated	$	86,760	$	335,741
Other – non-regulated services		6,578		13,934
Total sales		93,338		349,675
Cost of sales:
Natural gas – regulated		46,601		227,816
Other – non-regulated services		3,891		8,461
Total cost of sales		50,492		236,277
Gross margin		42,846		113,398
Operating expenses		37,735		78,912
Operating income	$	5,111	$	34,486
Income from continuing
operations and net income
available for common stock	$	442	$	17,708

 

 

 

60

The following table summarizes regulated Gas Utilities’ sales revenues:

 

Sales Revenues	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009		2009
	(in thousands)
Residential:
Colorado	$	10,740	$	38,150
Nebraska		18,864		78,146
Iowa		16,867		71,411
Kansas		11,182		41,888
Total Residential		57,653		229,595
Commercial:
Colorado		2,481		8,313
Nebraska		6,364		28,323
Iowa		6,888		32,375
Kansas		3,150		13,566
Total Commercial		18,883		82,577
Industrial:
Colorado		579		709
Nebraska		577		2,090
Iowa		34		651
Kansas		3,325		4,585
Total Industrial		4,515		8,035
Transportation:
Colorado		186		362
Nebraska		1,969		5,922
Iowa		944		2,044
Kansas		1,190		2,796
Total Transportation		4,289		11,124
Other:
Colorado		29		58
Nebraska		539		1,186
Iowa		267		693
Kansas		585		2,473
Total Other		1,420		4,410
Total Regulated		86,760		335,741
Non-regulated Services		6,578		13,934
Total	$	93,338	$	349,675

 

 

61

The following table summarizes regulated Gas Utilities’ sales margins:

 

Sales Margins	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009		2009
	(in thousands)
Residential:
Colorado	$	3,567	$	8,682
Nebraska		8,995		24,130
Iowa		8,597		24,162
Kansas		6,292		15,348
Total Residential		27,451		72,322
Commercial:
Colorado		649		1,616
Nebraska		2,197		6,941
Iowa		2,194		7,316
Kansas		1,276		3,495
Total Commercial		6,316		19,368
Industrial:
Colorado		149		184
Nebraska		70		212
Iowa		24		90
Kansas		536		750
Total Industrial		779		1,236
Transportation:
Colorado		186		362
Nebraska		1,969		5,921
Iowa		945		2,045
Kansas		1,191		2,797
Total Transportation		4,291		11,125
Other:
Colorado		28		57
Nebraska		539		1,187
Iowa		267		693
Kansas		488		1,937
Total Other		1,322		3,874
Total Regulated		40,159		107,925
Non-regulated Services		2,687		5,473
Total	$	42,846	$	113,398

 

 

62

The following table summarizes regulated Gas Utilities’ volumes sold:

 

Volumes Sold	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009		2009
	(in Dth)
Residential:
Colorado		1,141,526		3,493,140
Nebraska		1,740,296		7,440,074
Iowa		1,487,113		6,952,670
Kansas		1,062,405		4,009,303
Total Residential		5,431,340		21,895,187
Commercial:
Colorado		293,801		803,279
Nebraska		865,365		3,201,025
Iowa		911,543		3,734,480
Kansas		408,154		1,529,081
Total Commercial		2,478,863		9,267,865
Industrial:
Colorado		118,536		130,793
Nebraska		112,284		314,765
Iowa		8,551		90,683
Kansas		811,964		1,001,218
Total Industrial		1,051,335		1,537,459
Transportation:
Colorado		196,826		431,800
Nebraska		5,830,746		13,414,429
Iowa		3,238,495		7,305,769
Kansas		3,524,951		7,017,578
Total Transportation		12,791,018		28,169,576
Other:
Colorado		—		—
Nebraska		245		1,135
Iowa		12,335		48,508
Kansas		17,936		77,518
Total Other		30,516		127,161
Total Regulated		21,783,072		60,997,248

 

 

 

63

	Three Months Ended		Six Months Ended
Degree Days	June 30, 2009		June 30, 2009
		Variance From		Variance From
Heating Degree Days:	Actual	Normal	Actual	Normal
Colorado	987	13%	3,511	(6)%
Nebraska	566	10%	3,545	(3)%
Iowa	772	9%	4,211	1%
Kansas*	496	2%	2,698	(11)%
Combined Gas Utilities
Heating Degree Days	677	(2)%	3,690	(5)%

_________________________

*	Kansas Gas has a 30-year weather normalization adjustment mechanism in place that neutralized the impact of weather on revenues at Kansas Gas.

 

Results from the Gas Utilities for the three and six month periods ended June 30, 2009 reflect the operations from the gas utilities acquired from Aquila on July 14, 2008.

 

The Gas Utilities were acquired on July 14, 2008 and, consequently, information for the three and six month periods ended June 30, 2008 is not available. Our Gas Utilities are highly seasonal and sales volumes depend largely on weather and seasonal heating and industrial loads. Approximately 74% of our Gas Utilities’ revenues are expected in the fourth and first quarters. Therefore, revenues for and certain expenses of, these operations fluctuate significantly among quarters.

 

Depending upon the state jurisdiction, the winter heating season begins around November 1 and ends around March 31. Margins for the Gas Utilities for the quarter ended June 30, 2009 decreased 39% from the quarter ended March 31, 2009. This decrease was driven by a 62% decrease in residential, commercial and industrial volumes.

 

 

64

Regulatory Matters – Utilities Group  

 

The following summarizes our recent rate case activity:

 

	Type of	Date	Date	Amount		Amount
In millions	Service	Requested	Effective	Requested		Approved
Nebraska Gas (1)	Gas	11/2006	9/2007	$	16.3	$	9.2
Iowa Gas (2)	Gas	6/2008	7/27/09	$	13.6	$	10.8
Colorado Gas (3)	Gas	6/2008	4/2009	$	2.8	$	1.4
Black Hills Power (4)	Electric	9/2008	1/2009	$	4.5	$	3.8
Kansas Gas (5)	Gas	5/2009	Pending	$	0.5	$	Pending

 

(1)

In November 2006, Nebraska Gas filed for a $16.3 million rate increase. Interim rates were implemented in February 2007 and, in July 2007, the NPSC granted a $9.2 million increase in annual revenues based on an equity return of 10.4% on a capital structure of 51% equity and 49% debt. Nebraska Gas appealed the decision, and the district court affirmed the NPSC order in February 2008. Because Nebraska Gas collected interim rates subject to refund, it was required to refund to customers the difference between the higher interim rates and the final rates plus interest (approximately $5.6 million). The NPA appealed one aspect of our refund plan worth approximately $0.8 million. On April 15, 2009, the District Court affirmed the NPSC refund plan order, and thereby rejected NPA’s appeal.

 

(2)

On June 3, 2009, Iowa Gas received approval from the IUB to implement new natural gas service rates for its Iowa residential, commercial and industrial customers. The rates went into effect on July 27, 2009. The approved rates allow Iowa Gas to recover capital investments made in its natural gas distribution system and offset increasing operating costs due to inflation since the last rate increase in March 2006. The new rates represent approximately $10.8 million in additional revenue. The increase is based on a return on equity of 10.1%, with a capital structure of 51.4% equity and 48.6% debt.

 

(3)

In June 2008, Colorado Gas filed for a $2.8 million rate increase. The increase was based on a proposed equity return of 11.5% on a capital structure of 50% equity and 50% debt. Interim rates were not available for collection in Colorado. On September 19, 2008, Colorado Gas filed the second phase of its rate request. On January 29, 2009, a settlement agreement was filed with the CPUC and a settlement was approved with new rates effective on April 1, 2009. The new rates included an increase in annual revenues of $1.4 million, which was based on a 10.25% return on equity with a capital structure of 50.48% equity and 49.52% debt.

 

(4)

On February 10, 2009, the FERC approved a formulaic approach to the method used to determine the revenue component of Black Hills Power’s open access transmission tariff, and increased the utility’s annual transmission revenue requirement by approximately $3.8 million. The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt. The new rates had an effective date of January 1, 2009.

 

(5)

Kansas Gas has requested a GSRS in the amount of $0.5 million annually. The KCC staff is recommending approval of all projects submitted, the filed GSRS revenue requirement of $0.5 million, and that Kansas Gas be allowed to continue collecting its current GSRS amount of $0.3 million. The KCC has until September 16, 2009 to issue an order.

 

65

Non-regulated Energy Group

 

An analysis of results from our Non-regulated Energy Group’s operating segments follows:

 

Oil and Gas

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in thousands)
Revenue	$	17,829	$	34,209	$	34,340	$	60,331
Operating expenses*		16,246		21,917		78,508		42,407
Operating income (loss)	$	1,583	$	12,292	$	(44,168)	$	17,924
Income (loss) from continuing
operations and net income
(loss) available for common
stock	$	129	$	7,197	$	(25,591)	$	9,749

__________________________

*	Six months ended June 30, 2009 operating expenses include a $43.3 million pre-tax ceiling test impairment charge.

 

The following tables provide certain operating statistics for our Oil and Gas segment:

 

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009	2008	2009	2008
Fuel production:
Bbls of oil sold	95,900	102,800	195,300	202,800
Mcf of natural gas sold	2,653,600	2,856,800	5,342,500	5,420,000
Mcf equivalent sales	3,229,000	3,473,600	6,514,300	6,636,800

 

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
Average price received: (a)
Gas/Mcf (b)	$	4.39	$	7.92	$	4.65(c)	$	7.71(c)
Oil/Bbl	$	58.32	$	100.31	$	54.30	$	90.05
Depletion expense/Mcfe	$	1.67	$	2.28	$	2.09	$	2.30

________________________

(a)	Net of hedge settlement gains/losses

(b)	Exclusive of gas liquids

(c)	Does not include the negative revenue impacts of a $1.2 million and $2.1 million royalty settlement accrual through June 30, 2009 and 2008, respectively, resulting in a $0.24/Mcf and $0.42/Mcf price impact

 

66

The following are summaries of LOE/Mcfe:

 

	Three Months Ended						Three Months Ended
	June 30, 2009						June 30, 2008
			Gathering,						Gathering,
			Compression						Compression
			and						and
Location	LOE		Processing		Total		LOE		Processing		Total
New Mexico	$	1.18	$	0.28	$	1.46	$	1.37	$	0.18	$	1.55
Colorado		1.25		0.37		1.62		1.05		0.88		1.93
Wyoming		1.52		—		1.52		1.57		—		1.57
All other properties		0.67		0.26		0.93		0.68		0.20		0.88
All locations	$	1.17	$	0.21	$	1.38	$	1.24	$	0.18	$	1.42

 

 

	Six Months Ended						Six Months Ended
	June 30, 2009						June 30, 2008
			Gathering,						Gathering,
			Compression						Compression
			and						and
Location	LOE		Processing		Total		LOE		Processing		Total
New Mexico	$	1.20	$	0.27	$	1.47	$	1.45	$	0.31	$	1.76
Colorado		1.00		0.41		1.41		1.14		0.86		2.00
Wyoming		1.47		—		1.47		1.68		—		1.68
All other properties		0.82		0.34		1.16		0.99		0.10		1.09
All locations	$	1.17	$	0.23	$	1.40	$	1.37	$	0.21	$	1.58

 

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Income from continuing operations decreased $7.1 million for the three months ended June 30, 2009 compared to the same period in 2008 primarily due to:

 

•     Revenue decreased $16.4 million due to a 42% decrease in the average hedged price of oil received, a 45% decrease in average hedged price of gas received, and a 7% decrease in production in both oil and gas. The gas production decrease reflects production shut-ins, impact of normal decline curves, and lower levels of capital deployment.

Partially offsetting these were the following:

•     Decreased depletion and depreciation expense of $2.2 million primarily due to a lower depletion rate reflecting previous ceiling test adjustments and an increase in estimated oil and gas proven reserves as a result of higher commodity prices than those at the end of the first quarter of 2009;

•     A $3.4 million decrease in production taxes due to lower oil and natural gas prices and lower production.

 

 

67

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Income from continuing operations decreased $35.3 million for the six months ended June 30, 2009 compared to the same period in 2008 primarily due to:

 

•     A $27.8 million after-tax non-cash ceiling test impairment charge for the quarter ended March 31, 2009 due to a ceiling test valuation of our natural gas and crude oil properties resulting from low quarter-end natural gas prices. The write-down of gas and oil properties was based on March 31, 2009 period-end NYMEX prices of $3.63 per Mcf, adjusted to $2.23 per Mcf at the wellhead, for natural gas; and $49.66 per barrel, adjusted to $45.32 per barrel at the wellhead, for crude oil; and

•     Revenue decreased $26.0 million due to a 40% decrease in the average hedged price of oil received, a 40% decrease in average hedged price of gas received, a 4% decrease in oil production and a 1% decrease in gas production.

Partially offsetting these were the following:

•     A $1.5 million decrease in LOE as compared to 2008, which was impacted by severe 2008 weather;

•     A $5.0 million decrease in production taxes due to lower oil and natural gas prices and lower production; and

•     A $3.8 million income tax benefit related to an adjustment of a previously recorded tax position.

 

Coal Mining

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in thousands)
Revenue	$	13,493	$	12,647	$	27,895	$	25,894
Operating expenses		14,488		12,729		28,669		24,346
Operating (loss) income	$	(995)	$	(82)	$	(774)	$	1,548
(Loss) income from continuing
operations and net (loss)
income available for
common stock	$	(499)	$	496	$	319	$	2,124

 

 

68

The following table provides certain operating statistics for our Coal Mining segment:

 

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009	2008	2009	2008
	(in thousands)
Tons of coal sold	1,363	1,453	2,870	2,998
Cubic yards of overburden
moved	3,473	2,623	6,635	5,653

 

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008.

Income from continuing operations from our Coal Mining segment for the three months ended June 30, 2009 decreased $1.0 million compared to the same period in the prior year. Results were impacted by the following:

 

•     Operating expenses increased $1.8 million, or 14%, during the three months ended June 30, 2009 primarily due to increased depreciation expense of $1.4 million due to an increased asset base, and increased coal taxes of $0.9 million due to higher coal prices. Cubic yards of overburden moved increased 32%.

Partially offsetting the increased expenses were the following:

•     Revenue increased $0.8 million, or 7%, for the three month period ended June 30, 2009 primarily due to an increase in average price received, partially offset by lower volumes sold. The higher average price received includes the impact of regulated sales prices determined in part by a return on investment base; and

•     Increased operating expenses were offset by lower diesel fuel costs of $0.6 million.

 

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008.

Income from continuing operations from our Coal Mining segment for the six months ended June 30, 2009 decreased $1.8 million compared to the same period in the prior year. Results were impacted by the following:

 

•     Operating expenses increased $4.3 million, or 18%, during the six months ended June 30, 2009 primarily due to increased depreciation expense of $3.7 million due to increased equipment usage and an increased asset base, and increased coal taxes of $1.0 million due to higher coal prices. Cubic yards of overburden moved increased 17%.

Partially offsetting the increased expenses were the following:

•     Revenue increased $2.0 million, or 8%, for the six month period ended June 30, 2009 compared to the same period in 2008 primarily due to an increase in average price received, partially offset by lower volumes sold. The higher average price received includes the impact of regulated sales prices determined in part by a return on investment base; and

•     Increased operating expenses were offset by lower diesel fuel costs of $1.0 million.

69

 

 

Energy Marketing

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in thousands)
Revenue –
Realized gas marketing
gross margin	$	11,384	$	(5,563)	$	22,354	$	7,862
Unrealized gas marketing
gross margin		(5,642)		4,151		(6,978)		(2,472)
Realized oil marketing
gross margin		5,131		2,755		8,108		4,328
Unrealized oil marketing
gross margin		(3,135)		3,807		(8,927)		1,551
		7,738		5,150		14,557		11,269
Operating expenses		4,169		4,544		9,431		10,481
Operating income	$	3,569	$	606	$	5,126	$	788
Income from continuing operations
and net income available for
common stock	$	2,210	$	365	$	3,247	$	664

 

The following is a summary of average daily volumes marketed:

 

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2009	2008	2009		2008
Natural gas physical sales – MMBtus	1,582,900	1,599,300	1,916,000		1,696,700
Crude oil physical sales – Bbls	11,846	6,896	11,456		6,990

 

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Income from continuing operations increased $1.8 million for the three months ended June 30, 2009 compared to the same period in 2008, primarily due to:

 

•     A $19.3 million increase in realized marketing margins primarily due to differing market conditions. In addition, gross margins from crude oil were higher due to the impact of increasing commodity prices and increased volumes marketed.

Partially offsetting these increases was the following:

•     A $16.7 million decrease in unrealized marketing margins.

 

 

70

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Income from continuing operations increased $2.6 million for the six months ended June 30, 2009 compared to the same period in 2008, primarily due to:

 

•     An $18.3 million increase in realized marketing margins primarily due to differing market conditions. In addition, gross margins from crude oil were higher due to the impact of increasing commodity prices and increased volumes marketed.

Partially offsetting these increases were the following:

•     A $15.0 million decrease in unrealized marketing margins; and

•     Lower operating expenses of $1.0 million primarily due to lower bank fees resulting from lower credit facility utilization.

 

Power Generation

 

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2009		2008		2009		2008
	(in thousands)
Revenue	$	7,215	$	8,511	$	14,834	$	17,375
Operating expense (gains)		4,347		7,290		(17,779)		14,539
Operating income	$	2,868	$	1,221	$	32,613	$	2,836
Income (loss) from
continuing operations	$	758	$	(472)	$	17,911	$	(1,368)

 

The following table provides certain operating statistics for our retained plants within the Power Generation segment:

 

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2009	2008	2009	2008
Contracted power plant fleet availability:
Coal-fired plant	92.4%	93.3%	94.0%	94.2%
Other plants	98.5%	89.5%	98.3%	94.7%
Total availability	94.9%	91.8%	95.7%	94.4%

 

 

71

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Income from continuing operations increased $1.2 million for the three months ended June 30, 2009 compared to the same period in 2008, and was primarily impacted by:

 

•     2008 results reflect $6.4 million of allocated indirect corporate costs and inter-segment interest expense related to the IPP assets sold and not reclassified to discontinued operations.

Partially offsetting were the following:

•     A decrease of $1.0 million reflecting the net earnings impact of replacing the 20 MW power purchase agreement with operating and site lease agreements related to MEAN’s purchase of 23.5% ownership interest of Wygen I; and

•     A $4.1 million increase in net interest expense primarily due to a change in inter-segment debt to equity capital structure.

 

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Income from continuing operations increased $19.3 million for the six months ended June 30, 2009 compared to the same period in 2008, and was primarily impacted by:

 

•     A $16.9 million after-tax gain on the sale to MEAN of a 23.5% ownership interest in the Wygen I power generation facility. In conjunction with the sale, MEAN will make payments for costs associated with coal supply, plant operations and administrative services. In addition, a 10-year power purchase contract under which MEAN was obligated to buy from us 20 MW of power annually was terminated; and

•     2008 results reflect $11.8 million of allocated indirect corporate costs and inter-segment interest expense related to the IPP assets sold and not reclassified to discontinued operations.

Partially offsetting were the following:

•     A decrease of $2.0 million reflecting the net earnings impact of replacing the 20 MW power purchase agreement with operating and site lease agreements related to MEAN’s purchase of 23.5% ownership interest of Wygen I; and

•     A $7.8 million increase in net interest expense primarily due to a change in inter-segment debt to equity capital structure.

 

 

72

Corporate

 

Three Months Ended June 30, 2009 Compared to Three Months Ended June 30, 2008. Income increased $20.7 million primarily due to unrealized net, mark-to-market gains for the quarter ended June 30, 2009 of approximately $20.6 million after-tax on certain interest rate swaps, partially offset by a $3.0 million after-tax increase in net interest expense. In addition, 2008 results included approximately $1.7 million after-tax for transition and integration costs related to the Aquila Transaction.

 

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Income increased $28.1 million primarily due to unrealized net, mark-to-market gains for the six months ended June 30, 2009 of approximately $30.2 million after-tax on certain interest rate swaps, partially offset by a $6.1 million after-tax increase in net interest expense. In addition, 2008 results include $4.2 million after-tax for transition and acquisition costs related to the Aquila Transaction.

 

Discontinued Operations

 

Earnings from discontinued operations were $0.8 million for the six month period ended June 30, 2009, compared to $14.1 million for the same period in 2008. The income from discontinued operations in 2009 relates to the final working capital adjustments for the IPP Transaction.

 

Critical Accounting Policies

 

There have been no material changes in our critical accounting policies from those reported in our 2008 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting policies, see Part II, Item 7 of our 2008 Annual Report on Form 10-K.

 

73

Liquidity and Capital Resources

 

Cash Flow Activities

 

During the six month period ended June 30, 2009, we generated sufficient cash flow from operations to meet our operating needs, fund our property, plant and equipment additions and to pay dividends on our common stock. We received proceeds of $51.9 million for the sale of a 23.5% interest in the Wygen I power plant to MEAN and $32.8 million for the sale to MDU of a 25% interest in the 110 MW Wygen III power plant under construction near Gillette, Wyoming. We plan to fund future property and investment additions including our share of the construction costs of the Wygen III power plant and generation for Colorado Electric from internally generated cash resources and external financings.

 

Cash flows from operations of $246.2 million for the six month period ended June 30, 2009 represent a $205.0 million increase compared to the same period in the prior year. The increase in cash provided by operating activities for the current period was due to an increase of $25.2 million in our income from continuing operations and changes in working capital as follows:

 

•     A $136.6 million increase in cash flows from working capital changes. This increase primarily resulted from a $74.4 million increase in cash flows from decreased net purchases of materials, supplies and fuel and a $197.2 million increase from accounts receivable and other current assets partially offset by a $135.0 million decrease from accounts payable and other current liabilities. Changes in materials, supplies and fuel primarily relate to natural gas held in storage by Energy Marketing and the Gas Utilities which fluctuates based on seasonal trends and economic decisions reflecting current market conditions;

and adjusted for non-cash charges and other items as follows:

•     A $14.8 million decrease in cash flows related to changes in deferred income taxes which is primarily a result of the deferred tax benefit associated with a non-cash ceiling test impairment charge applicable to our crude oil and natural gas properties;

•     A $13.3 million increase in cash flows from the net change in derivative assets and liabilities primarily from derivatives associated with normal operations of our oil and gas marketing business and our Oil and Gas segment related to commodity price fluctuations;

•     A $22.5 million increase in depreciation, depletion and amortization expense;

•     A $43.3 million non-cash effect from the ceiling test impairment;

•     A $26.0 million non-cash effect of the gain on sale of operating assets. This gain relates to the sale of the 23.5% interest in the Wygen I power plant to MEAN for which we received $51.9 million included in investing activities;

•     A $46.5 million non-cash effect of unrealized mark-to-market gains on interest rate swaps; and

•     A $64.5 million increase in regulatory assets and liabilities primarily resulting from deferred gas adjustments for our Gas Utilities segment.

 

 

74

During the six months ended June 30, 2009, we had cash outflows from investing activities of

$76.7 million, which were primarily due to the following:

 

•     Cash outflows of $163.6 million for property, plant and equipment additions. These outflows include approximately $47.4 million related to the construction of our Wygen III power plant, approximately $13.0 million in oil and gas property maintenance capital and development drilling, and approximately $50.3 million of distribution, transmission and generation at our Electric Utilities, which includes new transmission at Colorado Electric and a plant air condenser upgrade at Black Hills Power;

•     Cash inflows of $51.9 million of proceeds from the sale of the 23.5% interest in the Wygen I power plant to MEAN;

•     Cash inflows of $32.3 million of proceeds from the sale of the 25% interest in the Wygen III power plant to MDU; and

•     Cash inflows of $7.7 million for working capital adjustments on the purchase price allocation of the Aquila Transaction.

 

During the six months ended June 30, 2009, we had net cash outflows from financing activities of $215.7 million resulting from:

 

•     $433.3 million net payments on the Corporate Credit Facility and the Acquisition Facility;

•     $27.5 million of payments of cash dividends on common stock; and

•     $248.5 million proceeds from issuance of senior unsecured five year notes.

 

Dividends

 

Dividends paid on our common stock totaled $27.5 million during the six months ended June 30, 2009, or $0.71 per share. On July 29, 2009, our Board of Directors declared a quarterly dividend of $0.355 per share payable September 1, 2009, which is equivalent to an annual dividend rate of $1.42 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects.

 

75

Financing Transactions and Short-Term Liquidity

 

Our principal sources of short-term liquidity are our revolving credit facility and cash provided by operations. As of June 30, 2009, we had approximately $122.4 million of cash unrestricted for operations.

 

Corporate Credit Facility

 

Our $525.0 million revolving credit facility expires on May 4, 2010. The cost of borrowings or letters of credit issued under the facility is determined based on our credit ratings. At our current ratings levels, the facility has an annual facility fee of 17.5 basis points, and has a borrowing spread of 70 basis points over LIBOR (which equates to a 1.01% one-month borrowing rate as of June 30, 2009).

 

Our revolving credit facility can be used to fund our working capital needs and for general corporate purposes. At June 30, 2009, we had borrowings of $270.5 million and $43.1 million of letters of credit issued on our revolving credit facility. Available capacity remaining on our revolving credit facility was approximately $211.4 million at June 30, 2009.

 

The credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and maintenance of the following financial covenants:

 

•     A consolidated net worth in an amount of not less than the sum of $625 million and 50% of our aggregate consolidated net income beginning January 1, 2005;

•     A recourse leverage ratio not to exceed 0.70 to 1.00 for the first year after the Aquila Transaction and thereafter, a ratio not to exceed 0.65 to 1.00; and

•     An interest expense coverage ratio of not less than 2.5 to 1.0.

 

If these covenants are violated, it would be considered an event of default entitling the lenders to terminate the remaining commitment and accelerate all principal and interest outstanding.

 

In addition to covenant violations, an event of default under the credit facility may be triggered by other events, such as a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $20 million or more. Subject to applicable cure periods (none of which apply to a failure to timely pay indebtedness), an event of default would permit the lenders to restrict our ability to further access the credit facility for loans or new letters of credit, and could require both the immediate repayment of any principal and interest outstanding and the cash collateralization of outstanding letter of credit obligations.

 

The credit facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result, after giving effect to such action.

 

Our consolidated net worth was $1,080.1 million at June 30, 2009, which was approximately $270.5 million in excess of the net worth we were required to maintain under the credit facility. At June 30, 2009, our long-term debt ratio was 40.0%, our total debt leverage ratio (long-term debt and short-term debt) was 48.6%, and our recourse leverage ratio was approximately 53.3%. Our interest expense coverage ratio for the twelve month period ended June 30, 2009 was 4.2 to 1.0.

 

76

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.

 

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 participating banks: Calyon, Rabobank and RZB Finance. This credit facility expires on May 7, 2010. The facility is a borrowing base line of credit, which allows for the issuance of letters of credit and for borrowings. Maximum borrowings under the facility are subject to a sublimit of $50 million. Borrowings under this facility are available under a base rate option or a Eurodollar option. The base rate option borrowing rate is 2.75% plus the higher of: (i) 0.5% above the Federal Funds Rate, or (ii) the prime rate established by Fortis Bank S.A./N.V. The Eurodollar option borrowing rate is 2.75% plus the higher of the Eurodollar Rate or the reference bank cost of funds. 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 under this facility and there were no cash borrowings outstanding.

 

Acquisition Facility

 

In July 2008, in conjunction with the closing of the Aquila Transaction, we borrowed $382.8 million under our $1 billion bridge acquisition credit facility dated May 7, 2007. The Acquisition Facility was structured as a single-draw term loan facility for the sole purpose of financing the Aquila Transaction.

 

On April 9, 2009, we received proceeds of $30.2 million for the sale of 25% of the Wygen III plant to MDU. The net proceeds were used to pay down a portion of the Acquisition Facility.

 

On May 14, 2009, we received proceeds from a $250 million public debt offering. The net proceeds were used to pay down a portion of the Acquisition Facility.

 

On June 15, 2009, we paid off the remaining $104.6 million balance of the Acquisition Facility by borrowing on our Corporate Credit Facility.

 

77

Future Financing Plans

 

We have an effective shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our finance arrangements and restrictions imposed by federal and state regulatory authorities.

 

We continue to evaluate the debt capital markets and prepare for additional long-term debt issuances to refinance other short-term debt and fund our power generation construction projects. We anticipate issuing a long-term first mortgage bond of approximately $180 million for our electric utility, Black Hills Power, Inc. The offering is expected to be completed in the Fall of 2009; proceeds of the transaction will be used to fund capital expenditures for the utility, including construction costs related to the Wygen III facility, and to fund the approximate $30 million maturity of our Series AC, 8.06% first mortgage bonds due in February 2010.

 

In the unlikely event we are unable to complete debt financing on acceptable terms, we will consider implementing alternative measures to conserve or raise capital. These alternatives could include deferring our planned capital expenditure program, implementing asset sales, issuing equity, reducing or eliminating our dividend payments, or curtailing certain business activities, including our marketing operations.

 

Interest Rate Swaps

 

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations.

 

We have interest rate swaps with a notional amount of $250.0 million that are not designated as hedge instruments in accordance with SFAS 133. Accordingly, mark-to-market changes in value on the swaps are recorded within the income statements. For the three and six months ended June 30, 2009, we recorded a $31.7 million and $46.5 million pre-tax unrealized mark-to-market non-cash gain on the swaps. The mark-to-market value on these swaps was a liability of $48.0 million at June 30, 2009. Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A one basis point move in the interest rate curves over the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of ten and twenty years and have amended mandatory early termination dates ranging from September 30, 2009 to December 29, 2009. We may choose to cash settle these swaps at their fair value prior to their mandatory early termination dates, or unless these dates are extended, we will cash settle these swaps for an amount equal to their fair value on the termination dates.

 

In addition, we have $150.0 million notional amount floating-to-fixed interest rate swaps, having a maximum term of 7.5 years. These swaps have been designated as cash flow hedges in accordance with SFAS 133 and accordingly, their mark-to-market adjustments are recorded in Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $16.5 million at June 30, 2009.

 

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2008 Annual Report on Form 10-K filed with the SEC.

 

78

Credit Ratings

 

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. As of June 30, 2009, our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as follows:

 

Rating Agency	Rating	Outlook
Moody’s	Baa3	Stable
S&P	BBB-	Stable
Fitch	BBB	Stable

 

In addition, the first mortgage bonds issued by Black Hills Power were rated at June 30, 2009 as follows:

 

Rating Agency	Rating	Outlook
Moody’s	Baa1	Stable
S&P	BBB	Stable
Fitch	A-	Stable

 

In August 2009, Moody’s upgraded the senior secured debt rating for Black Hills Power to A3.

79

Capital Requirements

 

During the six months ended June 30, 2009, capital expenditures were approximately $203.7 million for property, plant and equipment additions, which were partially financed through approximately $40.1 million of accrued liabilities. We currently expect total capital expenditures in 2009 to approximate $365.8 million. This sum includes, but is not limited to: $62.1 million for our share of the Wygen III power plant located near Gillette, Wyoming in which we retain 75% ownership interest in the plant; $73.8 million related to maintenance capital for our new utility properties, and $38.6 million within our Oil and Gas segment primarily for maintenance capital and development drilling.

 

Actual and forecasted capital requirements for maintenance capital and development capital are as follows:

 

	Six Months Ended		Total
	June 30, 2009		2009 Planned
	Expenditures		Expenditures
	(in thousands)
Utilities:
Electric Utilities – Wygen III(1)	$	14,612	$	62,100
Electric Utilities (2) (3)		73,256		187,568
Gas Utilities		20,449		42,508
Non-regulated Energy:
Oil and Gas(4)		12,951		38,621
Power Generation		2,696		4,925
Coal Mining		4,963		12,592
Energy Marketing		113		4,135
Corporate		1,769		13,342
	$	130,809	$	365,791

__________________________

(1)	Capital expenditures of the Wygen III coal-fired plant are net of $17.2 million of accrued liabilities and $32.8 million proceeds received from the sale to MDU of a 25% interest in the plant. Forecasted expenditures of the Wygen III coal-fired plant reflect our 75% ownership interest in the plant.

(2)	Electric Utilities capital requirements include approximately $17.6 million for transmission projects in 2009.

(3)

The 2009 total planned expenditures include capital requirements associated with our plans to build gas-fired power generation facilities to serve our Colorado Electric customers. In February 2009, the CPUC authorized Colorado Electric to build two natural gas-fired combustion turbine facilities. We expect to spend capital of $52.3 million in 2009 particularly related to the commitment to purchase the turbine generators from GE. The total construction cost is expected to be approximately $225 million to $275 million to be completed by the end of 2011.

(4)	Development capital for our oil and gas properties is expected to be limited to no more than the cash flows produced by those properties. Continued low commodity prices could further reduce our planned development capital expenditures.

 

As a result of the current global credit crisis we are re-evaluating all of our forecasted capital expenditures, and if determined prudent, may defer some of these expenditures for a period of time. Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.

 

80

Contractual Obligations

 

Unconditional purchase obligations for firm transportation and storage fees for our Energy Marketing segment increased $6.9 million from $93.5 million at December 31, 2008 to $100.4 million at June 30, 2009. Approximately $62.8 million of the firm transportation and storage fee obligations relate to the 2009-2011 period with the remaining occurring thereafter.

 

In June 2009, we entered into a ten and a half year lease obligation to relocate our office located in Golden, Colorado to Denver, Colorado. Total obligations over the ten and a half year lease are $14.7 million. This lease contained certain landlord incentives including rent abatement, relocation and tenant finishes.

 

Guarantees

 

See Note 6 to our Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

 

New Accounting Pronouncements

 

Other than the new pronouncements reported in our 2008 Annual Report on Form 10-K filed with the SEC and those discussed in Notes 2 and 3 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that affect us.

 

81

FORWARD-LOOKING INFORMATION

 

This report contains forward-looking information. All statements, other than statements of historical fact, included in this report that address activities, events, or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. The forward-looking statements include the factors discussed above, the risk factors described in Item 1A. of our 2008 Annual Report on Form 10-K filed with the SEC, and other reports that we file with the SEC from time to time, and the following:

 

•     We are evaluating financing options including first mortgage bonds, term loans, project financing and equity issuance. Some important factors that could cause actual results to differ materially from those anticipated include:

§     Our ability to access the bank loan and debt capital markets depends on market conditions beyond our control. If the credit markets remain tight and do not improve, we may not be able to permanently refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.

§     Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.

•     We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:

§     Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecasted capital expenditure requirements.

§     Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.

 

 

82

 

•     We expect to make contributions to our defined benefit pension plans of approximately $9.5 million and $16.7 million in 2009 and 2010, respectively. Some important factors that could cause actual contributions to differ materially from anticipated amounts include:

§     The actual value of the plans’ invested assets.

§     The discount rate used in determining the funding requirement.

•     We expect the goodwill related to our utility assets to fairly reflect the long-term value of stable, long-lived utility assets. Some important factors that could cause us to revisit the fair value of this goodwill include:

§     A significant, sustainable deterioration of the market value of our common stock.

§     Negative regulatory orders or other events that materially impact our Utilities’ ability to generate stable cash flow over an extended period of time.

•     We expect to make approximately $365.8 million of capital expenditures in 2009. Some important factors that could cause actual costs to differ materially from those anticipated include:

§     The timing of planned generation, transmission or distribution projects for our Utilities is influenced by state and federal regulatory authorities and third parties. The occurrence of events that impact (favorably or unfavorably) our ability to make planned or unplanned capital expenditures could cause our 2009 forecasted capital expenditures to change.

§     Forecasted capital expenditures associated with our Oil and Gas segment are driven, in part, by current market prices. A continued decline in crude oil and natural gas prices may cause us to change our planned 2009 capital expenditures related to our oil and gas operations.

•     The timing, volatility, and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest or foreign exchange rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets.

•     Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

•     The possibility that we may be required to take impairment charges under the SEC’s full cost ceiling test for the accumulated costs of our natural gas and oil reserves.

 

 

83

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

Utilities

 

We produce, purchase and distribute power in four states and purchase and distribute natural gas in five states. All of our gas distribution utilities have PGA provisions that allow them to pass the prudently-incurred cost of gas through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to “true-up” billed amounts to match the actual natural gas cost we incurred. These adjustments are subject to periodic prudence reviews by the state utility commissions. In South Dakota, Colorado, Wyoming and Montana, we have a mechanism for our electric utilities that serves a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer.

 

The fair value of our Utilities derivative contracts are summarized below (in thousands):

 

	June 30,		December 31,
	2009		2008
Net derivative liabilities	$	(670)	$	(7,444)
Cash collateral		5,792		8,744
	$	5,122	$	1,300

 

 

84

Non Regulated Trading Activities

 

The following table provides a reconciliation of activity in our natural gas and crude oil marketing portfolio that has been recorded at fair value including market value adjustments on inventory positions that have been designated as part of a fair value hedge during the six months ended June 30, 2009 (in thousands):

 

Total fair value of energy marketing positions marked-to-market at December 31, 2008	$	28,447 (a)
Net cash settled during the period on positions that existed at December 31, 2008		(25,840)
Unrealized gain on new positions entered during the period and still existing at
June 30, 2009		2,164
Realized loss on positions that existed at December 31, 2008 and were settled during
the period		(3,477)
Change in cash collateral		25,581
Unrealized gain on positions that existed at December 31, 2008 and still exist at
June 30, 2009		10,929
Total fair value of energy marketing positions at June 30, 2009	$	37,804 (a)

_____________________________

(a)

The fair value of energy marketing positions consists of derivative assets/liabilities held at fair value in accordance with SFAS 157 and market value adjustments to natural gas inventory that has been designated as a hedged item as part of a fair value hedge in accordance with SFAS 133, as follows (in thousands):

 

	June 30,		March 31,		December 31,
	2009		2009		2008
Net derivative assets (liabilities)	$	32,352	$	39,843	$	54,117
Cash collateral		9,267		(3,673)		(16,315)
Market adjustment recorded
in material, supplies and fuel		(3,815)		(2,399)		(9,355)
	$	37,804	$	33,771	$	28,447

 

GAAP restricts mark-to-market accounting treatment primarily to only those contracts that meet the definition of a derivative under SFAS 133. Therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities or our expected cash flows from energy trading activities. In our natural gas and crude oil marketing operations, we often employ strategies that include utilizing 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 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 our inventory, transportation or storage positions to market. The result is that while a significant majority of our energy marketing positions are fully 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 should be expected given these accounting requirements.

 

To value the assets and liabilities for our outstanding derivative contracts, we use the fair value methodology outlined in SFAS 157. See Note 3 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K and Note 12, Note 13 and Note 14 of the accompanying Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

 

85

The sources of fair value measurements were as follows (in thousands):

 

Source of Fair Value	Maturities
of Energy Marketing Positions	Less than 1 year		1 – 2 years		Total Fair Value
Cash collateral	$	9,267	$	—	$	9,267
Level 2		25,696		3,749		29,445
Level 3		3,122		(215)		2,907
Market value adjustment for inventory
(see footnote (a) above)		(3,815)		—		(3,815)
Total fair value of our energy
marketing positions	$	34,270	$	3,534	$	37,804

 

The following table presents a reconciliation of our June 30, 2009 energy marketing positions recorded at fair value under GAAP to a non-GAAP measure of the fair value of our energy marketing forward book wherein all forward trading positions are marked-to-market (in thousands):

 

Fair value of our energy marketing positions marked-to-market in accordance with GAAP
(see footnote (a) above)	$	37,804
Market value adjustments for inventory, storage and transportation positions that are
part of our forward trading book, but that are not marked-to-market under GAAP		(6,734)
Fair value of all forward positions (non-GAAP)		31,070
Cash collateral included in GAAP marked-to-market fair value		(9,267)
Fair value of all forward positions excluding cash collateral (non-GAAP)	$	21,803

 

There have been no material changes in market risk compared to those reported in our 2008 Annual Report on Form 10-K filed with the SEC. For more information on market risk, see Part II, Items 7 and 7A. in our 2008 Annual Report on Form 10-K, and Note 12 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

 

86

Activities Other Than Trading

 

We have entered into agreements to hedge a portion of our estimated 2009, 2010 and 2011 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place are as follows:

 

Natural Gas

 

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(MMBtu/day)
San Juan El Paso	07/27/2007	Swap	07/09 – 09/09	5,000	$	7.63
CIG	09/07/2007	Swap	07/09 – 09/09	1,500	$	6.48
AECO	09/07/2007	Swap	04/08 – 10/09	1,000	$	6.89
San Juan El Paso	10/29/2007	Swap	07/09 – 09/09	5,000	$	7.38
San Juan El Paso	10/29/2007	Swap	10/09 – 12/09	5,000	$	7.53
CIG	10/29/2007	Swap	10/09 – 12/09	1,500	$	7.07
NWR	11/16/2007	Swap	01/09 – 12/09	1,500	$	6.87
San Juan El Paso	12/13/2007	Swap	10/09 – 12/09	1,500	$	7.39
San Juan El Paso	12/13/2007	Swap	10/09 – 12/09	1,500	$	7.41
CIG	01/03/2008	Swap	01/10 – 03/10	2,000	$	7.49
NWR	01/03/2008	Swap	01/10 – 03/10	1,500	$	7.50
AECO	01/03/2008	Swap	11/09 – 03/10	1,000	$	8.07
San Juan El Paso	01/23/2008	Swap	01/10 – 03/10	5,000	$	7.50
San Juan El Paso	02/28/2008	Swap	01/10 – 03/10	3,000	$	8.55
San Juan El Paso	04/09/2008	Swap	04/10 – 06/10	5,000	$	7.26
San Juan El Paso	04/30/2008	Swap	04/10 – 06/10	2,500	$	7.65
AECO	08/20/2008	Swap	04/10 – 06/10	1,000	$	7.73
San Juan El Paso	08/20/2008	Swap	07/10 – 09/10	5,000	$	7.74
AECO	08/20/2008	Swap	07/10 – 09/10	1,000	$	7.88
AECO	10/24/2008	Swap	10/10 – 12/10	1,000	$	7.05
San Juan El Paso	12/19/2008	Swap	10/09 – 12/09	1,000	$	5.12
San Juan El Paso	12/19/2008	Swap	04/10 – 06/10	1,500	$	5.39
San Juan El Paso	12/19/2008	Swap	07/10 – 09/10	3,000	$	5.95
San Juan El Paso	12/19/2008	Swap	10/10 – 12/10	5,000	$	5.89
CIG	01/26/2009	Swap	04/10 – 06/10	2,000	$	4.45
CIG	01/26/2009	Swap	07/10 – 09/10	2,000	$	4.47
CIG	01/26/2009	Swap	10/10 – 12/10	2,000	$	4.68
CIG	01/26/2009	Swap	01/11 – 03/11	2,000	$	6.00
NWR	01/26/2009	Swap	01/11 – 03/11	2,000	$	6.05
San Juan El Paso	01/26/2009	Swap	01/11 – 03/11	5,000	$	6.38
San Juan El Paso	02/13/2009	Swap	01/11 – 03/11	2,500	$	6.16
San Juan El Paso	02/13/2009	Swap	10/10 – 12/10	3,000	$	5.35
NWR	02/13/2009	Swap	04/10 – 12/10	1,000	$	4.20
AECO	03/04/2009	Swap	01/11 – 03/11	1,000	$	5.95
NWR	03/04/2009	Swap	07/09 – 09/09	1,000	$	3.07
NWR	03/04/2009	Swap	04/10 – 06/10	1,000	$	4.06
NWR	03/04/2009	Swap	07/10 – 09/10	1,000	$	4.12
NWR	03/04/2009	Swap	10/10 – 12/10	1,000	$	4.55
NWR	03/20/2009	Swap	01/10 – 03/10	500	$	4.58
San Juan El Paso	03/20/2009	Swap	01/10 – 03/10	1,000	$	4.87
San Juan El Paso	06/02/2009	Swap	04/11 – 06/11	5,000	$	5.99
San Juan El Paso	06/02/2009	Swap	10/09 – 12/09	1,500	$	4.14
AECO	06/02/2009	Swap	04/11 – 06/11	800	$	5.89
NWR	06/02/2009	Swap	10/09 – 12/09	500	$	3.95
NWR	06/02/2009	Swap	04/11 – 06/11	1,500	$	5.54
San Juan El Paso	06/25/2009	Swap	04/11 – 06/11	2,500	$	5.55
CIG	06/25/2009	Swap	04/11 – 06/11	1,750	$	5.33

 

 

87

Crude Oil

 

Location	Transaction Date	Hedge Type	Term	Volume	Price
				(Bbls/month)
NYMEX	06/22/2007	Swap	07/09 – 09/09	5,000	$	72.10
NYMEX	07/27/2007	Put	07/09 – 09/09	5,000	$	65.00
NYMEX	09/12/2007	Swap	07/09 – 09/09	5,000	$	71.20
NYMEX	10/29/2007	Put	10/09 – 12/09	5,000	$	75.00
NYMEX	10/29/2007	Swap	10/09 – 12/09	5,000	$	80.75
NYMEX	11/16/2007	Put	07/09 – 09/09	5,000	$	75.00
NYMEX	11/16/2007	Put	10/09 – 12/09	5,000	$	75.00
NYMEX	01/03/2008	Put	01/10 – 03/10	5,000	$	80.00
NYMEX	01/03/2008	Swap	01/10 – 03/10	5,000	$	88.70
NYMEX	01/23/2008	Swap	10/09 – 12/09	5,000	$	83.10
NYMEX	01/23/2008	Swap	01/10 – 03/10	5,000	$	82.90
NYMEX	02/28/2008	Put	01/10 – 03/10	5,000	$	85.00
NYMEX	04/09/2008	Swap	04/10 – 06/10	5,000	$	99.60
NYMEX	04/30/2008	Put	04/10 – 06/10	5,000	$	85.00
NYMEX	05/29/2008	Put	04/10 – 06/10	5,000	$	105.00
NYMEX	07/16/2008	Swap	04/10 – 06/10	5,000	$	135.10
NYMEX	07/16/2008	Swap	07/10 – 09/10	5,000	$	134.90
NYMEX	08/20/2008	Put	07/10 – 09/10	5,000	$	90.00
NYMEX	09/03/2008	Put	07/10 – 09/10	5,000	$	90.00
NYMEX	10/24/2008	Put	07/10 – 09/10	5,000	$	60.00
NYMEX	12/05/2008	Swap	10/10 – 12/10	5,000	$	65.20
NYMEX	01/26/2009	Swap	10/10 – 12/10	5,000	$	60.15
NYMEX	01/26/2009	Swap	01/11 – 03/11	5,000	$	60.90
NYMEX	02/13/2009	Swap	01/11 – 03/11	5,000	$	60.05
NYMEX	03/04/2009	Swap	10/10 – 12/10	5,000	$	55.80
NYMEX	03/04/2009	Swap	01/11 – 03/11	5,000	$	57.00
NYMEX	04/08/2009	Swap	04/11 – 06/11	5,000	$	68.80
NYMEX	04/23/2009	Swap	04/11 – 06/11	5,000	$	65.10
NYMEX	06/02/2009	Swap	10/10 – 12/10	5,000	$	74.30
NYMEX	06/02/2009	Swap	01/11 – 03/11	5,000	$	75.05
NYMEX	06/02/2009	Swap	04/11 – 06/11	5,000	$	75.86
NYMEX	06/04/2009	Put	04/11 – 06/11	5,000	$	67.00

 

 

88

ITEM 4.         CONTROLS AND PROCEDURES

 

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of June 30, 2009. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

 

There have been no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2009 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. On July 14, 2008, we acquired the assets of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa (the “Acquired Businesses”). The internal controls of the Acquired Businesses are an area of focus for us. We are in the process of reviewing the internal controls of the Acquired Businesses and making any necessary changes. As permitted by the guidance set forth by the Securities and Exchange Commission, the Acquired Businesses were not included in management’s assessment of internal control over financial reporting for the year ended December 31, 2008.

 

Our assessment of the effectiveness of our internal controls over financial reporting as of June 30, 2009 excluded the assets and operations acquired on July 14, 2008 in the Aquila Transaction, which are doing business as Black Hills Energy. Such exclusion was in accordance with SEC guidance that an assessment of a recently acquired business may be omitted in management’s report on internal control over financial reporting, provided the acquisition took place within twelve months of management’s evaluation. Collectively, Black Hills Energy comprised 36% of our consolidated assets at June 30, 2009, and for the six months ended June 30, 2009 62% of our consolidated revenues and 25% of our net income. Our disclosure controls and procedures were not materially impacted by the acquisition.

 

89

BLACK HILLS CORPORATION

 

Part II – Other Information

 

Item 1.

Legal Proceedings

 

For information regarding legal proceedings, see Note 18 in Item 8 of our 2008 Annual Report on Form 10-K and Note 15 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 15 is incorporated by reference into this item.

 

Item 1A.

Risk Factors

 

Except to the extent updated or described below, our Risk Factors are documented in Item IA. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2008.

 

Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

 

We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming, Colorado and Idaho. We are constructing another fossil-fuel generating plant in Wyoming. Air emissions of fossil-fuel generating plants are subject to federal, state and tribal regulation. Recent developments under federal and state laws and regulation governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations.

 

On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency, holding that CO2 and other GHG emissions are pollutants subject to regulation under the motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or alternatively, to explain why GHG emissions should not be regulated. On April 17, 2008, the EPA issued its proposed endangerment finding under Section 202 of the Clean Air Act. Although this proposal does not specifically address stationary sources, such as power generation plants, the general endangerment finding relative to GHG’s could support such a proposal by the EPA for stationary sources. On March 10, 2009, the EPA released proposed rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions. Finally, federal legislation is currently under consideration in the U.S. Congress, including H.R. 2454, “the American Clean Energy and Security Act of 2009”, which was approved by the U.S. House of Representatives on June 26, 2009. This legislation would affect electric generation and electric and natural gas distribution companies. H.R. 2454 would establish mandatory GHG reduction targets, utilizing a Federal emissions cap-and-trade program. H.R.2454 also proposes a national renewable electricity standard, which would implement a phased process ultimately mandating that 20% of electricity sold by retail suppliers be met by energy efficiency improvements and renewable energy resources by 2020. The Senate is expected to consider its own version of the legislation later in 2009 or in 2010.

 

90

Due to the uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation upon our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a “cap and trade” structure is implemented, the impact will also be affected by the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the affect of carbon regulation on natural gas and coal prices.

 

More stringent GHG emissions limitations or other energy efficiency requirements, however, could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by our non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.

 

We own electric utilities that serve customers in Colorado, Montana, South Dakota and Wyoming. To varying degrees, Colorado and Montana have each adopted mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If these states increase their renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.

 

91

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

 

Issuer Purchases of Equity Securities

 

					Maximum
				Total	Number (or
				Number	Approximate
				of Shares	Dollar
	Total			Purchased as	Value) of Shares
	Number			Part of Publicly	That May Yet Be
	of	Average		Announced	Purchased Under
	Shares	Price Paid		Plans	the Plans
Period	Purchased	per Share		or Programs	or Programs
April 1, 2009 –
April 30, 2009	415 (1)	$	19.00	—		—
May 1, 2009 –
May 31, 2009	—	$	—	—		—
June 1, 2009 –
June 30, 2009	—	$	—	—		—
Total	415	$	19.00	—		—

__________________________

(1)

Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of Restricted Stock and the distribution of vested restricted stock units.

 

92

Item 4.

Submission of Matters to a Vote of Security Holders

 

(a)

The Annual Meeting of Shareholders was held on May 19, 2009.

 

(b)

Matters Voted Upon at the Meeting

 

1.

Elected three Class III Directors to serve until the Annual Meeting of Shareholders in 2012.

 

David C. Ebertz
Votes For	29,879,847
Votes Withheld	5,267,115
John R. Howard
Votes For	29,783,428
Votes Withheld	5,363,534
Stephen D. Newlin
Votes For	30,106,421
Votes Withheld	5,040,541

 

2.

Ratified the appointment of Deloitte & Touche LLP to serve as Black Hills Corporation’s independent auditors in 2009.

 

Votes For	34,628,264
Votes Against	382,210
Abstain	136,488

 

 

93

Item 6.	Exhibits
	Exhibit 4	Second Supplemental Indenture dated as of May 14, 2009, between the Registrant and Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009).
	Exhibit 10	Joinder Agreements dated May 27, 2009 to the Third Amended and Restated Credit Agreement effective May 7, 2009, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, and Calyon New York Branch, Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A. Rabobank Nederland, New York Branch and RZB Finance LLC (filed as Exhibits 10.1, 10.2 and 10.3 to the Registrant’s Form 8-K filed on May 28, 2009).
	Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
	Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
	Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.
	Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

 

 

94

BLACK HILLS CORPORATION

 

Signatures

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

	BLACK HILLS CORPORATION
	/s/ David R. Emery
	David R. Emery, Chairman, President and
	Chief Executive Officer
	/s/ Anthony S. Cleberg
	Anthony S. Cleberg, Executive Vice President
	and Chief Financial Officer
Dated: August 10, 2009

 

 

95

EXHIBIT INDEX

 

 

Exhibit Number	Description
Exhibit 4	Second Supplemental Indenture dated as of May 14, 2009, between the Registrant and Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009).
Exhibit 10	Joinder Agreements dated May 27, 2009 to the Third Amended and Restated Credit Agreement effective May 7, 2009, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, and Calyon New York Branch, Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A. Rabobank Nederland, New York Branch and RZB Finance LLC (filed as Exhibits 10.1, 10.2 and 10.3 to the Registrant’s Form 8-K filed on May 28, 2009).
Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.
Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

 

 

96