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 is a large accelerated filer, an accelerated filer or a non-accelerated filer (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

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

 

 

3

 

 

 

4

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.

 

5

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.

6

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.

 

7

BLACK HILLS CORPORATION

 

Notes to Condensed Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2006 Annual Report on Form 10-K)

 

 

The financial statements included herein have been prepared by Black Hills Corporation (the Company) 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, the Company believes that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in the Company’s 2006 Annual Report on Form 10-K filed with the SEC.

 

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the March 31, 2007, December 31, 2006 and March 31, 2006 financial information and are of a normal recurring nature. Some of the Company’s operations are highly seasonal and revenues from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as changes in market price. The results of operations for the three months ended March 31, 2007, are not necessarily indicative of the results to be expected for the full year. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

 

 

FIN 48

 

The Company adopted FIN 48 on January 1, 2007 (see Note 8). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

 

8

SAB 108  

 

During September 2006, the staff of the SEC released SAB 108. SAB 108 provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement. Prior practice allowed the evaluation of materiality on the basis of (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method). Reliance on either method in prior years could have resulted in misstatement of the financial statements. The guidance provided in SAB 108 requires both methods to be used in evaluating materiality. Immaterial prior year errors may be corrected with the first filing of prior year financial statements after adoption. The cumulative effect of the correction can either be reported in the carrying amounts of assets and liabilities as of the beginning of that fiscal year, and the offsetting adjustment made to the opening balance of retained earnings for that year, or by restating prior periods. Disclosure requirements include the nature and amount of each individual error being corrected in the cumulative adjustment, as well as a disclosure of when and how each error being corrected arose and the fact that the errors had previously been considered immaterial. SAB 108 was effective January 1, 2007. SAB 108 did not have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

 

 

SFAS 157

 

During September 2006, the FASB issued SFAS 157 and applies under other accounting pronouncements that require or permit fair value measurements. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Management is currently evaluating the impact SFAS 157 will have on the Company’s consolidated financial statements.

 

SFAS 159

 

During February 2007, the FASB issued SFAS 159, which establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. Management is currently evaluating the impact SFAS 159 will have on the Company’s consolidated financial statements.

 

9

 

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 March 31, 2007, December 31, 2006 and March 31, 2006, market adjustments related to natural gas held by Energy marketing and recorded in inventory were $2.4 million, $(31.5) million and $(5.4) million, respectively (see Note 12 for further discussion of Energy marketing trading activities).

 

The gas inventory held by the Company’s Energy marketing subsidiary primarily consists of gas held in storage and gas imbalances held on account with pipelines. Such gas is being held in inventory to capture the price differential between the time at which it was purchased and a sales date in the future. A substantial majority of the gas was economically hedged at the time of purchase either through a fixed price physical or financial forward sale.

 

 

Note Payable

 

During the first quarter of 2007, the Company repaid the $145.5 million borrowing balance outstanding on its revolving credit facility with proceeds from the Company’s February 22, 2007 equity issuance (see Note 9).

 

Long-term Debt

 

On April 30, 2007, the Company prepaid the outstanding balance of the GECC Financing. Accordingly, the December 31, 2006 long-term balance of $22.2 million has been classified as a current liability on the accompanying March 31, 2007 Condensed Consolidated Balance Sheet.

 

Amendments to Revolver

 

On March 13, 2007, the Company entered into a second amendment to its revolving bank facility. The second amendment (i) increased the limit for borrowings or other credit accommodations for the separate credit facility for the Company’s energy marketing subsidiary from $260 million to $300 million, (ii) increased the allowed total commitments under the facility without requiring amendment of the facility from $500 million to $600 million, (iii) effective with the acquisition of certain electric and gas utility assets from Aquila, will increase the recourse leverage ratio limit from 0.65 to 1.00 to 0.70 to 1.00 for the first year after completion of the Aquila asset acquisition, reverting to 0.65 to 1.00 thereafter, and (iv) allowed for other modifications to enable the Company to complete the Aquila asset acquisition.

 

10

 

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):

 

 

 

 

 

 

11

 

The following table presents the components of the Company’s comprehensive income

(in thousands):

 

 

 

The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation of FIN 48, the Company recognized an approximate $0.7 million benefit from a decrease in the liability for unrecognized tax benefits. This benefit was accounted for as an adjustment to the January 1, 2007 balance of retained earnings.

 

The total gross amount of unrecognized tax benefits at January 1, 2007 was approximately $72.6 million. The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $2.0 million (net of the federal benefit on state issues and interest) at the date of adoption.

 

It is the Company’s continuing practice to recognize penalties and/or interest related to income tax matters in income tax expense. The Company had no penalties accrued and approximately $0.4 million for the accrual of interest income at the date of adoption of FIN 48.

 

The Company files income tax returns in the U.S. federal jurisdiction, various state jurisdictions and a foreign jurisdiction. The Company is no longer subject to U.S. federal examination for tax years before 2004. However, the Company is under examination by a state taxing authority for tax years 2001 through 2003 and remains subject to examination by foreign income tax authorities for tax years as early as 1999.

 

The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2008.

 

12

 

Other than the following transactions, the Company had no other material changes in its common stock, as reported in Note 9 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

 

Private Placement of Common Stock

 

On February 22, 2007, the Company completed the issuance and sale of approximately 4.17 million shares of common stock at a price of $36.00 per share in a private placement offering. The Company used the approximate $145.6 million of net proceeds from this offering for debt reduction.

 

These shares were not initially registered under the Securities Act of 1933, therefore restricting the purchasers’ ability to offer or sell the shares. The offering agreements required the Company to register the related securities with the SEC within a specified period of time, and the Company has performed this obligation. In addition, the Company must maintain an effective shelf registration statement with the SEC, allowing resale of the restricted shares, until all related shares have been resold or cease to be restricted. If the Company fails to maintain an effective shelf registration statement in accordance with the terms of the offering agreements, it may be required to pay damages to the purchasers at a per thirty-day rate of 1.0 percent of the related share purchase price until the default is cured. The total damage payments under the agreements are limited to 10.0 percent of the related share purchase price. The Company believes the likelihood of making any payments under the damage provisions is remote and accordingly has not recognized any liability within its consolidated financial statements.

 

Equity Compensation Plans

 

 

 

13

 

Defined Benefit Pension Plan

 

The Company has two non-contributory defined benefit pension plans (Plans). One Plan covers employees of the Company and the following subsidiaries who meet certain eligibility requirements: Black Hills Service Company, Black Hills Power, WRDC and BHEP. The other Plan covers employees of the Company’s subsidiary, Cheyenne Light, who meet certain eligibility requirements.

 

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

 

 

The Company made a $0.5 million contribution to the Cheyenne Light Pension Plan in the first quarter of 2007; no additional contributions are anticipated to be made to the Plans during the 2007 fiscal year.

 

Supplemental Non-qualified Defined Benefit Plans

 

The Company has various supplemental retirement plans for key executives of the Company (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):

 

 

The Company anticipates that it will need to make contributions to the Supplemental Plans for the 2007 fiscal year of approximately $0.7 million. The contributions are expected to be made in the form of benefit payments.

 

14

Non-pension Defined Benefit Postretirement Healthcare Plans

 

Employees who are participants in the Company’s Postretirement Healthcare Plans (Healthcare Plans) and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.

 

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

 

 

The Company anticipates that it will make contributions to the Healthcare Plans for the 2007 fiscal year of approximately $0.3 million. The contributions are expected to be made in the form of benefits payments.

 

It has been determined that the Company’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was approximately $0.1 million for each of the three month periods ended March 31, 2007 and 2006.

 

 

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of March 31, 2007, substantially all of the Company’s operations and assets are located within the United States.

 

The Company conducts its operations through the following six reporting segments: Retail Services group consisting of the following segments: Electric utility, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Electric and gas utility, which supplies electric and gas utility service to Cheyenne, Wyoming and vicinity; and Wholesale Energy group, consisting of the following segments: Oil and gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region, Texas, California and other states; Power generation, which produces and sells power and capacity to wholesale customers with plants concentrated in Colorado, Nevada, Wyoming and California; Coal mining, which engages in the mining and sale of coal from its 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.

 

15

Segment information follows the same accounting policies as described in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K. In accordance with the provisions of SFAS 71, intercompany fuel sales to the electric utility are not eliminated.

 

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

 

 

 

 

The Company had no material changes in the assets of its reporting segments, as reported in Note 20 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K, beyond changes resulting from normal operating activities.

 

16

 

The Company actively manages its exposure to certain market risks as described in Note 2 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form

10-K. Details of derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are as follows:

 

Trading Activities

 

Natural Gas and Crude Oil Marketing

 

The contract or notional amounts and terms of the Company’s natural gas and crude oil marketing activities and derivative commodity instruments are as follows:

 

 

 

17

_________________________

 

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on March 31, 2007, December 31, 2006 and March 31, 2006, 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):

 

 

In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a “fair value” hedge transaction. These volumes are stated at market value using published spot industry quotations. Market adjustments are recorded in inventory on the Condensed Consolidated Balance Sheets and the related unrealized gain/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of March 31, 2007, December 31, 2006 and March 31, 2006, the market adjustments recorded in inventory were $2.4 million, $(31.5) million and $(5.4) million, respectively.

 

18

Activities Other Than Trading

 

Oil and Gas Exploration and Production

 

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company had the following derivatives and related balances (in thousands):

 

________________________

*crude in Bbls, gas in MMBtus

 

Based on March 31, 2007 market prices, a $2.0 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.

 

19

Fuel in Storage

 

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company had the following swaps and related balances (in thousands):

 

________________________

*gas in MMBtus

 

Based on March 31, 2007 market prices, a loss of $(0.2) million would be realized and reported in pre-tax earnings during the next twelve months related to the cash flow hedge. Estimated and actual realized losses will likely change during the next twelve months as market prices change.

 

20

Financing Activities

 

On March 31, 2007, December 31, 2006 and March 31, 2006, the Company’s interest rate swaps and related balances were as follows (in thousands):

 

 

Based on March 31, 2007 market interest rates and balances, a gain of less than $0.1 million would be realized and reported in pre-tax earnings during the next twelve months. Estimated and realized gains will likely change during the next twelve months as market interest rates change.

 

 

The Company is subject to various legal proceedings, claims and litigation as described in Note 18 of the Notes to Consolidated Financial Statements in the Company’s 2006 Annual Report on Form 10-K.

 

Earn-Out Litigation

 

As disclosed in previous filings with the SEC, the Company has ongoing litigation with the former Indeck stockholders. On March 12, 2007, the Court granted, in part, the Company’s Motion to Dismiss the Amended Complaint. The Court dismissed Counts 1 and 5 of the Amended Complaint. Count 1 included all claims of fraud against individual defendants. Those individuals were not named in other counts of the Amended Complaint, so they were dismissed as parties to the lawsuit. Count 5 asserted a claim for breach of the covenant of good faith and fair dealing relating to the alleged destruction of evidence. The Court approved the amendment of the complaint on other theories. The Company expects to file Motions for Summary Judgment on these remaining claims. A status hearing is set for late June 2007, at which time we expect the Court to set a trial date if Motions for Summary Judgment are denied in whole or in part.

 

The outcome of this matter is uncertain, as is the amount of contingent merger consideration that could be awarded following arbitration and/or litigation. If any additional merger consideration is awarded, it would be recorded as additional goodwill. If an adverse outcome was to occur and punitive damages were awarded, the punitive damages would be recorded as an expense.

 

21

Las Vegas Cogeneration/Nevada Power Company Arbitration

 

On March 16, 2007, Nevada Power filed a Demand for Arbitration pursuant to a Power Purchase Agreement dated May 27, 1992, between Nevada Power and LVC for Las Vegas I. Nevada Power asserts that LVC is in breach of its obligation under the Agreement to maintain a reliable fuel supply throughout the term of the Agreement. Nevada Power also asserts that LVC failed to deliver the amounts of energy and capacity required by the Agreement. The relief Nevada Power requests include: (1) Determination and Order requiring LVC to provide reasonable assurance of its ability to supply fuel to the facility for the full remaining term of the Agreement; (2) Determination that LVC has breached the Agreement relating to fuel supply requirements, and therefore finding that Nevada Power is relieved of its obligation to purchase power under the Agreement; (3) Determination concerning the energy and capacity delivery requirements of the Agreement; and (4) Determination that LVC breached the performance requirements of the Agreement during the winter season of 2005-2006, and providing an award of damages incurred by Nevada Power by reason of the alleged breach.

 

LVC denies all these claims and filed its response to the Demand for Arbitration, asserting the following defenses: (1) That Nevada Power failed to honor its contractual obligation to properly negotiate in good faith before filing the demand for arbitration; (2) That LVC has complied with its obligations relating to fuel supply and transportation; (3) That LVC has fulfilled its obligations to deliver energy and capacity to Nevada Power, and did not breach the Agreement during the winter season of 2005-2006, when substantial mechanical problems required an extended outage to perform redesign and repair of generation equipment; and (4) That numerous other affirmative defenses preclude Nevada Power from receiving the relief requested.

 

The arbitration demand was filed with the American Arbitration Association, pursuant to its Commercial Arbitration Rules. The parties are in the process of selecting an arbitrator, who will establish the process and schedule for determination of this dispute. While the Company cannot predict the final timing or outcome of this action, it is not expected to have a material adverse impact on the Company’s consolidated financial position or results of operations.  

 

Except as described above, 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 three months of 2007.

 

22

 

On February 7, 2007, the Company entered into a definitive agreement with Aquila for the asset acquisition of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The purchase price of the assets is $940.0 million, subject to closing adjustments. In conjunction with this agreement, the Company has entered into a binding agreement with a group of lenders for a committed acquisition credit facility (see Note 16).

 

The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the regulated utilities to the Company. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Service Commission, the Nebraska Public Service Commission, the Iowa Utilities Board and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions.

 

This transaction would add approximately 93,000 electric utility customers and 523,000 gas utility customers to the Company’s utility operations.

 

The Company is capitalizing certain incremental acquisition costs incurred in the current period related to this pending acquisition. Amounts capitalized in the three months ended March 31, 2007 were approximately $2.0 million.

 

 

The Company accounts for its discontinued operations under the provisions of SFAS 144. Accordingly, results of operations and the related charges for discontinued operations have been classified as “(Loss) 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 Crude Oil Marketing and Transportation Assets

 

On March 1, 2006, the Company sold the operating assets of BHER and related subsidiaries, its crude oil marketing and transportation business for approximately $41 million. Assets sold include the 200-mile Millennium and the 190-mile Kilgore Pipelines, oil marketing contracts and certain other ancillary assets. Following the sale, the Company closed the operations of the Houston, Texas based business. For business segment reporting purposes, BHER was included in the Energy marketing and transportation segment.

 

23

Revenues and net (loss) income from the discontinued operations were as follows (in thousands):

 

 

Losses incurred subsequent to the asset sale resulted from the settlement of certain contract disputes with the purchaser and other costs incurred in closing down the business operations.

 

Assets and liabilities of the crude oil marketing and transportation business were as follows (in thousands):

 

 

 

24

 

Power Plant Project and Power Purchase Agreement

 

In April 2007, the Company entered into a power purchase agreement to provide electric power to Public Service Company of New Mexico, a regulated electric and natural gas utility subsidiary of PNM.

 

Under the terms of the agreement, the Company will provide the capacity and energy of a 149 MW, simple-cycle gas turbine generation facility to be located near Albuquerque, New Mexico. The project is expected to cost approximately $101 million, and has a commercial operation in-service date of June 1, 2008. The agreement is a customary tolling agreement, where the Company receives variable and fixed fees for the plant’s availability and operation, and Public Service Company of New Mexico will be responsible for providing fuel for the operation. In addition, the PPA affords us favorable “change of law” and “government impositions” pass throughs to Public Service Company of New Mexico. The duration of the power purchase agreement is 20 years. The agreement also allows Public Service Company of New Mexico the option to acquire an equity interest of up to 50 percent in this project.

>

 

Acquisition Credit Facility

 

On May 7, 2007, the Company entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and various other banks to provide for funding for the Company’s pending acquisition of Aquila assets. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount of up to $1.0 billion. The commitment to fund the acquisition term loan terminates on August 5, 2008. Upon funding of the loan, the loan termination date is the earlier of the date which is 364 days from the loan funding date or February 5, 2009. The facility also includes certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.

 

GECC

 

On April 30, 2007, the Company called its outstanding debt with GE Capital in the amount of $23.5 million. In conjunction with this, the Company expensed less than $0.1 million in unamortized deferred finance costs. The associated payment guarantees provided by the Company were also terminated.

 

 

25

 

We are a diversified energy company operating principally in the United States with two major business groups – retail services and wholesale energy. We report our business groups in the following segments:

 

 

Our retail services group consists of our electric and gas utilities segments. Our electric utility, Black Hills Power, generates, transmits and distributes electricity to an average of approximately 64,200 customers in South Dakota, Wyoming and Montana. Our electric and gas utility, Cheyenne Light, serves approximately 38,900 electric and 32,600 natural gas customers in Cheyenne, Wyoming and vicinity. Our wholesale 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 diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts; and the marketing of fuel products.

 

Pending Acquisition of Assets from Aquila

 

On February 7, 2007 the Company entered into a definitive agreement with Aquila for the asset acquisition of Aquila’s regulated electric utility in Colorado and its regulated gas utilities in Colorado, Kansas, Nebraska and Iowa. The purchase price of the assets is $940 million, subject to closing adjustments. In conjunction with this agreement, the Company has entered into a binding agreement with a group of lenders for a committed acquisition credit facility as a bridge financing for the transaction. The Acquisition Credit Facility was completed on May 7, 2007.

 

The purchase is conditioned on the completion of the acquisition of the outstanding shares of Aquila by Great Plains immediately following the sale of the regulated utilities to us. The purchase is also subject to regulatory approvals from the Missouri Public Service Commission, the Kansas Corporation Commission, the Colorado Public Service Commission, the Nebraska Public Service Commission, the Iowa Utilities Board and FERC; Hart-Scott-Rodino antitrust review; as well as other customary conditions.

 

This transaction would add approximately 93,000 electric utility customers and 523,000 gas utility customers to our utility operations.

 

Disposition of Crude Oil Marketing and Transportation Business

 

In March 2006, we sold the operating assets of BHER and related subsidiaries, our crude oil marketing and pipeline transportation business headquartered in Houston, Texas. These activities were previously reported in our Energy marketing and transportation segment.

 

26

Results of Operations

 

Executive Summary

 

Results for the three months ended March 31, 2007 reflect solid utility performance, strong energy marketing results and improved power generation performance. Results also reflect the impacts of lower gas production and higher operating costs for the Oil and gas segment.

 

Increased retail services earnings resulted from overall steady operations at both of our utilities. Black Hills Power earnings benefited from a South Dakota rate increase. Cheyenne Light earnings were impacted by the effects of earnings from the AFUDC related to the construction of Wygen II. We also received additional permits on the Wygen III power plant project and expect to complete the permitting process and begin construction in late 2007 or early 2008.

 

Earnings from the oil and gas operations decreased due to lower production on an equivalent basis, driven by drilling permit delays in core operating areas, lower well performance in the Denver-Julesburg Basin and the effects of winter weather. Higher overall industry costs also affected results. Earnings were positively impacted by increased hedged natural gas and oil prices received compared to the prior year.

 

Increased earnings from power generation reflect plant availability of 96.1 percent compared to 85.7 percent in the three months ended March 31, 2006, primarily due to the return to service of the Las Vegas facilities after scheduled and unscheduled maintenance in the first quarter of 2006.

 

Strong earnings from energy marketing benefited from higher margins received and increased volumes. Lower overall market prices helped serve increased demand, and our storage, transportation and other marketing strategies were able to take advantage of natural gas price volatility and basis differentials in the Rocky Mountain and other regions.

 

On February 22, 2007 the Company completed the issuance and sale of approximately 4.17 million shares of common stock at a price of $36.00 per share in a private placement to institutional investors pursuant to a Securities Purchase Agreement dated as of February 14, 2007. We used the net proceeds from this offering for debt reduction. As a result of the use of a weighted average methodology to calculate the number of shares outstanding, the dilutive effect of the stock issuance will increase as the year progresses.

 

27

Consolidated Results

 

Revenues and Income (Loss) from Continuing Operations provided by each business group were as follows (in thousands):

 

 

Discontinued operations in 2007 and 2006 represent the operations of our crude oil marketing and transportation business. The assets of this business were sold in March 2006.

 

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Revenues for the three months ended March 31, 2007 increased 9 percent, or $14.6 million, compared to the same period in 2006. Increased revenues were primarily driven by higher margins from our energy marketing activities, higher retail rates at Black Hills Power, and improved revenues from Power generation.

 

Operating expenses decreased 1 percent, or $1.9 million, primarily due to lower fuel and purchased power costs at the electric and gas utility, and lower operating and maintenance cost at Power generation due to the 2006 outages at the Las Vegas facility, partially offset by increased depreciation and depletion expense.

 

Income from continuing operations increased $13.9 million due primarily to the following:

 

 

 

28

See the following discussion of our business segments under the captions “Retail Services Group” and “Wholesale Energy Group” for more detail on our results of operations.

 

The following business group and segment information does not include intercompany eliminations or discontinued operations.

 

Retail Services Group

 

Electric Utility

 

 

 

The following tables provide certain operating statistics for the Electric utility segment:

 

 

 

29

 

 

 

 

 

30

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $1.8 million primarily due to increased revenues, partially offset by increased fuel and purchased power costs and operating expenses. In addition, wholesale off-system gross margins were flat with the 2006 period.

 

Electric utility revenues increased 9 percent for the three month period ended March 31, 2007, compared to the same period in the prior year. Higher retail revenues were primarily due to increased rates in South Dakota that became effective January 1, 2007. Total retail MWh sales increased 4 percent compared to the three months ended March 31, 2006 due to colder weather conditions and customer growth. Heating degree days, which is a measure of weather trends, were 4 percent higher than the same period in the prior year. Wholesale off-system sales decreased 20 percent due to a 26 percent decrease in MWhs sold partially offset by an 8 percent increase in average price received. MWhs available for wholesale off-system sales decreased from the prior period due to scheduled plant outages and power transmission constraints to the east of our AC-DC transmission tie, and increased native load.

 

Electric operating expenses increased 4 percent for the three month period ended March 31, 2007, compared to the same period in the prior year. Fuel and purchased power costs increased 6 percent due to a 5 percent increase in purchased power at average prices that were 11 percent higher than the same period in the prior year and increased fuel production costs, primarily due to higher average coal prices. MWhs generated and purchased decreased 2 percent and 6 percent, respectively, for the three months ended March 31, 2007 compared to the same period in 2006. Operating expense for the three months ended March 31, 2007 was also affected by increased maintenance costs for scheduled outages and increased depreciation expense.

 

Electric and Gas Utility

 

 

 

31

The following tables provide certain operating statistics for the Electric and gas utility segment:

 

 

 

 

 

 

 

 

 

32

 

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $1.7 million for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. The increase in income from continuing operations was impacted by income related to AFUDC attributable to the construction of Wygen II, a 90 MW, coal-fired power plant sited at our Wyodak energy complex near Gillette, Wyoming.

 

Gross margin increased 3 percent primarily due to an increase in sales volumes. We consider gross margin to be a more useful performance measure when looking at our fluctuating financial and statistical figures related to revenue. These fluctuations are a direct result of cost recovery adjustments for electricity and natural gas due to volatile market prices and timing of revenue and expense recognition. Historically, Cheyenne Light has filed an annual adjustment for electricity and more frequent filings for natural gas to manage volatile market price impacts.

 

Operating expenses decreased 5 percent primarily due to decreased depreciation expense and benefit costs.

 

Rate Increase Requested. During March 2007, Cheyenne Light filed a rate request with the WPSC. The filing requests general rate increases of $8.4 million for electric rates and $4.6 million for gas rates, based upon rates in place at December 31, 2006. The requested increases also include placing into rate base Wygen II and other capital investments necessary for the expansion and maintenance of both electric and gas distribution systems to accommodate population and energy growth.

 

Wholesale Energy Group

 

A discussion of results from our Wholesale Energy group’s operating segments follows:

 

Oil and Gas

 

 

 

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The following tables provide certain operating statistics for our oil and gas segment:

 

 

Production for the three months ended March 31, 2007 was affected by winter weather impacts and lower well performance in the Denver Julesburg Basin. We expect to increase production coming out of the winter season and through additional drilling activity. Drilling activity will be contingent on the issuance of drilling permits and our evaluation of rising costs. We still expect to increase annual production 4-6 percent over the previous year, which is a decrease from our December 31, 2006 estimated growth of 10 percent.

 

________________________

 

The following is a summary of LOE/Mcfe at March 31:

 

 

(a)

Reflects the expenses associated with Colorado acquisitions completed in 2006 which included underutilized gathering, processing and compression assets. It is anticipated that future development of these properties will increase the capacity utilization rate of these gathering and processing assets and the per unit cost will decrease.

 

 

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Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations decreased 33 percent in the three months ended March 31, 2007 compared to the same period in 2006 due to increased production expenses, depletion expense and increased interest expense due to higher borrowings to fund acquisitions and development costs, partially offset by increased revenues.

 

Revenue increased 3 percent for the three months ended March 31, 2007 compared to the three months ended March 31, 2006. Gas production decreased 9 percent and the average hedged gas price received increased 3 percent. Oil production increased 14 percent and average hedged oil price received increased 16 percent.

 

Total operating expenses increased 16 percent for the three month period ended March 31, 2007 primarily due to increased field service costs and depletion expense. The LOE per Mcfe sold (LOE/Mcfe) increased 22 percent primarily due to changing property mix with the 2006 acquisitions and increased repair and weather-related costs incurred in 2007. Depletion expense per Mcfe increased 26 percent. The average depletion rate per Mcfe is a function of capitalized costs, projected future development costs and the related underlying reserves in the periods presented. The increased depletion rate is due to increases in current year finding costs and higher estimated future development costs as well as the higher average cost of reserves acquired in March 2006 and their future development costs.

 

Power Generation

 

 

The following table provides certain operating statistics for our power generation segment:

 

 

 

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Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $2.9 million. Revenues in the first quarter of 2007 increased

18 percent compared to revenues in the first quarter of 2006 primarily due to the return of the Las Vegas facilities to full operations. In the first three months of 2006 the Las Vegas plants experienced scheduled and unscheduled repair outages.

 

Operating expenses for the three months ended March 31, 2007, increased $1.1 million from the same period in the prior year. The increase in operating expenses primarily resulted from increased variable operating costs and increased fuel costs at the Las Vegas I plant partially offset by lower maintenance costs compared to costs incurred for repairs of the Las Vegas facilities in 2006.

 

Coal Mining

 

 

The following table provides certain operating statistics for our coal mining segment:

 

 

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006.

Income from continuing operations from our Coal mining segment increased 14 percent. Revenue increased 5 percent for the three month period ended March 31, 2007 compared to the same period in 2006 due to an increase in average price received partially offset by lower tons of coal sold. Operating expenses increased 6 percent during the three months ended March 31, 2007 primarily due to increased overburden removal expense, increased depreciation expense and increased general and administrative expense partially offset by lower mineral taxes.

 

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Energy Marketing

 

 

The following is a summary of average daily energy marketing volumes:

 

____________________

^(a) Daily oil volumes are calculated beginning May 1, 2006 to reflect the start of crude oil marketing by Enserco out of our Golden, Colorado offices.

 

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006. Income from continuing operations increased $6.4 million due to increased realized marketing margins and increased unrealized marketing gains.

 

Realized gas marketing margins increased approximately $6.3 million over the prior year due to a 49 percent increase in natural gas volumes marketed, partially offset by a lower margin per MMBtu sold. Unrealized mark-to-market gains increased $5.1 million over unrealized mark-to-market gains for the same period in 2006. Opportunities generated by existing market conditions allowed for the marketing of additional natural gas volumes, compared to the three months ended in March 2006. Colder winter weather increased demand from utility customers and we were able to purchase additional volumes within our credit limits, due to lower overall market prices. In addition, due to the volatility of natural gas markets, we were able to take advantage of seasonal price spreads and price differentials between the Rocky Mountain and other regions. (For discussion of potential volatility in energy marketing earnings related to accounting treatment of certain hedging activities at our natural gas and oil marketing operations, see “Trading Activities” in Part 1, Item 3 of this Form 10-Q.) Results also reflect earnings from the addition of crude oil marketing to our Rocky Mountain region producer services. Operating expenses increased primarily due to increased compensation cost related to higher realized margins partially offset by a decrease in the bad debt provision.

 

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Corporate

 

Decreased costs in the three months ended March 31, 2007, compared to the same period in 2006, are primarily the result of increased allocation of interest costs and the capitalization of approximately $2.0 million of certain acquisition costs in the current period related to the pending purchase of certain Aquila assets, and the expensing of development costs in the same period ended March 31, 2006 associated with our activities related to Northwestern Corporation.

 

Critical Accounting Policies

 

There have been no other material changes in our critical accounting policies from those reported in our 2006 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 2006 Annual Report on Form 10-K.

 

Liquidity and Capital Resources

 

Cash Flow Activities

 

During the three month period ended March 31, 2007, we generated sufficient cash flow from operations to meet our operating needs, to pay dividends on our common stock, to pay our scheduled long-term debt maturities and to fund our property, plant and equipment additions. We plan to fund future property and investment additions including our pending acquisition of certain electric and gas utility assets of Aquila and the construction costs of the 149 MW, simple-cycle gas turbine generation facility to be located near Albuquerque, New Mexico through a combination of new equity, mandatory convertible securities, unsecured debt at the holding company level and internally generated cash resources.

 

Cash flows from operations increased $19.3 million for the three month period ended March 31, 2007 compared to the same period in the prior year as a $13.9 million increase in income from continuing operations was affected by the following:

 

 

 

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During the three months ended March 31, 2007, we had cash outflows from investing activities of $37.7 million, which was primarily due to the following:

 

 

During the three months ended March 31, 2007, we had net outflows of cash used for financing activities of $14.3 million, primarily due to a $145.5 million payment on our credit facility, the payment of cash dividends on common stock, as well as payment of long-term debt maturities, partially offset by cash proceeds of $146.6 million from the issuance of common stock.

 

Dividends

 

Dividends paid on our common stock totaled $11.4 million during the three months ended March 31, 2007, or $0.34 per share. This reflects a 3 percent increase, as approved by our board of directors in January 2007, from the 2006 dividend level. 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 facility and our future business prospects.

 

Financing Transactions and Short-Term Liquidity

 

On February 22, 2007, we completed the issuance and sale of approximately 4.17 million shares of our common stock, par value $1.00 per share, at a sale price of $36.00 per share, in a private placement to institutional investors. Net proceeds of approximately $145.6 million were used for the pay down of our revolving bank facility.

 

Our principal sources of short-term liquidity are our revolving bank facility and cash provided by operations. Our liquidity position remained strong during the first three months of 2007. As of March 31, 2007, we had approximately $77.8 million of cash unrestricted for operations. Approximately $3.0 million of the cash balance at March 31, 2007 was restricted by subsidiary debt agreements that limit our subsidiaries’ ability to dividend cash to the parent company.

 

Our $400 million revolving bank facility has a five year term, expiring May 4, 2010. The cost of borrowings or letters of credit issued under the new 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 0.70 basis points over LIBOR (which equates to a 6.02 percent one-month borrowing rate as of March 31, 2007).

 

On March 13, 2007, we entered into a second amendment of our revolving bank facility. The second amendment (i) increased the limit for borrowings or other credit accommodations for the separate credit facility for our energy marketing subsidiary from $260 million to $300 million, (ii) increased the allowed total commitments under the facility without requiring amendment of the facility from $500 million to $600 million, (iii) effective with the acquisition of certain electric and gas utility assets from Aquila, will increase the recourse leverage ratio limit from 0.65 to 1.00 to 0.70 to 1.00 for the first year after completion of the Aquila asset acquisition, reverting to 0.65 to 1.00 thereafter, and (iv) allowed for other modifications to enable us to complete the Aquila asset acquisition.

 

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Our revolving credit facility can be used to fund our working capital needs and for general corporate purposes. At March 31, 2007, we had no borrowings and $50.2 million of letters of credit issued on our revolving credit facility with a remaining available capacity of $349.8 million.

 

The bank 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:

 

 

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.

 

A default under the bank facility may be triggered by events such as a failure to comply with financial covenants or certain other covenants under the bank facility, 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. A default under the bank facility would permit the participating banks to restrict our ability to further access the credit facility for loans or new letters of credit, require the immediate repayment of any outstanding loans with interest and require the cash collateralization of outstanding letter of credit obligations.

 

The bank facility prohibits us from paying cash dividends unless no default or no event of default exists prior to, or would result, after giving effect to such action.

 

Our consolidated net worth was $949.8 million at March 31, 2007, which was approximately $251.4 million in excess of the net worth we were required to maintain under the bank facility. Our long-term debt ratio at March 31, 2007 was 38.8 percent, our total debt leverage (long-term debt and short-term debt) was 40.3 percent, our recourse leverage ratio was approximately 41.1 percent and our interest expense coverage ratio was 5.61 to 1.0.

 

In addition, Enserco, our energy marketing segment, has a $260 million uncommitted, discretionary line of credit to provide support for the purchase and sale of natural gas and crude oil. The line of credit is secured by all of Enserco’s assets and expires on May 11, 2007. At March 31, 2007, there were outstanding letters of credit issued under the facility of $161.7 million, with no borrowing balances outstanding on the facility. We expect to renew the facility prior to expiration with an increased total commitment level of $300.0 million.

 

Our corporate credit rating by Moody’s was “Baa3”during the first three months of 2007; the outlook is negative. Our corporate credit rating by S&P was “BBB-;” the outlook is stable.

 

On April 30, 2007, we called our outstanding debt with GE Capital in the amount of $23.5 million. In conjunction with this, we expensed less than $0.1 million in unamortized deferred finance costs. The associated payment guarantees provided by us were also terminated.

 

 

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On May 7, 2007, the Company entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and various other banks to provide for funding for the Company’s pending acquisition of Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount of up to $1.0 billion. The commitment to fund the acquisition term loan terminates on August 5, 2008. Upon funding of the loan, the loan termination date is the earlier of the date which is 364 days from the loan funding date or February 5, 2009.

 

The Acquisition Facility includes conditions precedent to funding which include consummation of the Aquila acquisition substantially in accordance with the existing asset purchase agreement. Borrowings under the term loan can be made under a base rate option, which is based on the then-current prime rate, or under a LIBOR option, which is based on the then-current LIBOR plus an applicable margin. The applicable margin for LIBOR borrowings is 55 basis points during the period from the initial funding under the term loan to six months thereafter, 67.5 basis points during the period from six months and one day after the initial funding to nine months thereafter, and 92.5 basis points during the period from nine months and one day after the initial funding until the loan maturity. The facility also includes certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.

 

Permanent financing to replace the Acquisition Facility for funding the $940.0 million purchase price and for related other costs of the acquisition of the Aquila assets is expected to be provided through a combination of new equity, mandatory convertible securities, unsecured debt at the holding company level and internally generated cash resources.

 

Our ability to obtain additional financing, if necessary, will depend upon a number of factors, including our future performance and financial results, and capital market conditions. We can provide no assurance that we will be able to raise additional capital on reasonable terms or at all.

 

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2006 Annual Report on Form 10-K filed with the SEC.

 

Capital Requirements

 

During the three months ended March 31, 2007, capital expenditures were approximately $64.5 million for property, plant and equipment additions, which includes approximately $25.9 million of accrued liabilities. We currently expect capital expenditures for the entire year 2007 to approximate $168.0 million, excluding the (a) $940.0 million purchase price and related other costs for the pending acquisition of Aquila utility assets; and (b) the $101.0 million total cost of the 149 MW, simple-cycle gas turbine generating facility to be located near Albuquerque, New Mexico, to be completed by June 2008.

 

We continue to actively evaluate potential future acquisitions and other growth opportunities in accordance with our disclosed business strategy. We are not obligated to a project until a definitive agreement is entered into and cannot guarantee we will be successful on any potential projects. Future projects are dependent upon the availability of economic opportunities and, as a result, actual expenditures may vary significantly from forecasted estimates.

 

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New Accounting Pronouncements

 

Other than the new pronouncements reported in our 2006 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 issued that when implemented would require us to either retroactively restate prior period financial statements or record a cumulative catch-up adjustment.

 

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SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

 

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q 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. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Item 1A. of Part I of our 2006 Annual Report on Form 10-K and in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:

 

 

 

43

 

 

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

 

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Trading Activities

 

The following table provides a reconciliation of our activity in energy trading contracts that meet the definition of a derivative under SFAS 133 and that were marked-to-market during the three months ended March 31, 2007 (in thousands):

 

_____________________________

 

 

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 and our expected cash flows from energy trading activities. At 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.

 

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

 

 

The following table presents a reconciliation of our March 31, 2007 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). In accordance with GAAP and industry practice, the Company includes a “Liquidity Reserve” in its GAAP marked-to-market fair value. This “Liquidity Reserve” accounts for the estimated impact of the bid/ask spread in a liquidation scenario under which the Company is forced to liquidate its forward book on the balance sheet date.

 

 

There have been no material changes in market risk faced by us from those reported in our 2006 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 2006 Annual Report on Form 10-K, and Note 12 of our Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

 

46

Activities Other Than Trading

 

The Company has entered into agreements to hedge a portion of its estimated 2007, 2008 and 2009 natural gas and crude oil production. The hedge agreements in place are as follows:

 

Natural Gas

 

 

Crude Oil

 

 

 

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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 (Exchange Act)) as of March 31, 2007. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the required time periods.

 

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2007 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

48

BLACK HILLS CORPORATION

 

Part II – Other Information

 

 

For information regarding legal proceedings, see Note 18 in Item 8 of the Company’s 2006 Annual Report on Form 10-K and Note 13 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 13 is incorporated by reference into this item.

 

 

There have been no material changes in our Risk Factors from those reported in Item 1A. of Part I of our 2006 Annual Report on Form 10-K filed with the SEC.

 

 

Unregistered Sales of Equity Securities

 

Sales as previously reported on Form 8-K filed February 22, 2007.

 

Issuer Purchases of Equity Securities

 

___________________________

 

 

49

 

On May 7, 2007, the Company entered into a senior unsecured $1.0 billion Acquisition Facility with ABN AMRO Bank N.V. as administrative agent and various other banks to provide for funding for the Company’s pending acquisition of Aquila’s electric utility in Colorado and its gas utilities in Colorado, Kansas, Nebraska and Iowa. The Acquisition Facility is a committed facility to fund an acquisition term loan in a single draw in an amount of up to $1.0 billion. The commitment to fund the acquisition term loan terminates on August 5, 2008. Upon funding of the loan, the loan termination date is the earlier of the date which is 364 days from the loan funding date or February 5, 2009.

 

The Acquisition Facility includes conditions precedent to funding which include consummation of the Aquila acquisition substantially in accordance with the existing asset purchase agreement. Borrowings under the term loan can be made under a base rate option, which is based on the then-current prime rate, or under a LIBOR option, which is based on the then-current LIBOR plus an applicable margin. The applicable margin for LIBOR borrowings is 55 basis points during the period from the initial funding under the term loan to six months thereafter, 67.5 basis points during the period from six months and one day after the initial funding to nine months thereafter, and 92.5 basis points during the period from nine months and one day after the initial funding until the loan maturity. The facility also includes certain customary affirmative and negative covenants which largely replicate the covenants under our existing revolving credit facility.

 

Permanent financing to replace the Acquisition Facility for funding the $940.0 million purchase price and for related other costs of the acquisition of the Aquila assets is expected to be provided through a combination of new equity, mandatory convertible securities, unsecured debt at the holding company level and internally generated cash resources.

 

50

 

__________________________

 

51

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.

 

 

 

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EXHIBIT INDEX

 

 

__________________________

 

 

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