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Table of Contents

 

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

Form 10-Q

 

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2004

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM                                TO                                 

 

Commission file number: 001-14837

 


 

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)

 

Delaware   75-2756163
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

 

777 West Rosedale, Suite 300, Fort Worth, Texas 76104

(Address of principal executive offices) (Zip Code)

 

(817) 665-5000

(Registrant’s telephone number, including area code)

 

None

(Former name, former address and former fiscal year, if changed since last report)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x No  ¨

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes  x No  ¨

 

As of July 31, 2004, the registrant had 49,718,544 outstanding shares of its common stock, $0.01 par value.

 



Table of Contents

QUICKSILVER RESOURCES INC.

INDEX TO FORM 10-Q

For the Period Ending June 30, 2004

 

     Page

PART I. FINANCIAL INFORMATION     

Item 1. Financial Statements (Unaudited)

    

Report of Independent Registered Public Accounting Firm

   3

Condensed Consolidated Balance Sheets at June 30, 2004 and December 31, 2003

   4

Condensed Consolidated Statements of Income and Comprehensive Income for the Three and Six Months Ended June 30, 2004 and 2003

   5

Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003

   6

Notes to Condensed Consolidated Interim Financial Statements

   7

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

   13

Item 3. Quantitative and Qualitative Disclosures About Market Risk

   21

Item 4. Controls and Procedures

   23
PART II. OTHER INFORMATION     

Item 4. Submission of Matters to a Vote of Security Holders

   24

Item 6. Exhibits and Reports on Form 8-K

   25

Signatures

   26

 

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Table of Contents

PART I. FINANCIAL INFORMATION

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors and Stockholders of

Quicksilver Resources Inc.

Fort Worth, Texas

 

We have reviewed the accompanying condensed consolidated balance sheet of Quicksilver Resources Inc. (the Company) as of June 30, 2004, and the related condensed consolidated statements of income and comprehensive income for the three and six month periods ended June 30, 2004 and 2003 and of cash flows for the six-month periods ended June 30, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.

 

We conducted our reviews in accordance with standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

 

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

 

We have previously audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of the Company as of December 31, 2003, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated March 15, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

 

As discussed in Note 2 to the condensed consolidated interim financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations.

 

/s/ DELOITTE & TOUCHE LLP

 

Fort Worth, Texas

August 5, 2004

 

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

 

     June 30,
2004 (a)


    December 31,
2003 (a)


 
ASSETS                 

Current assets

                

Cash and cash equivalents

   $ 5,946     $ 4,116  

Accounts receivable

     20,939       26,247  

Current deferred income taxes

     12,575       11,760  

Inventories and other current assets

     7,152       7,588  
    


 


Total current assets

     46,612       49,711  

Investments in and advances to equity affiliates

     8,982       9,173  

Properties, plant and equipment – net (“full cost”)

     672,057       604,576  

Other assets

     2,357       3,474  
    


 


     $ 730,008     $ 666,934  
    


 


LIABILITIES AND STOCKHOLDERS’ EQUITY                 

Current liabilities

                

Current portion of long-term debt

   $ 319     $ 339  

Accounts payable

     18,791       17,954  

Accrued derivative obligations

     36,649       34,577  

Accrued liabilities

     24,948       27,644  
    


 


Total current liabilities

     80,707       80,514  

Long-term debt

     296,190       249,097  

Derivative obligations

     —         9,662  

Asset retirement obligations

     18,712       15,135  

Deferred income taxes

     77,910       70,710  

Stockholders’ equity

                

Preferred stock, $0.01 par value, 10,000,000 shares authorized, 1 share issued and outstanding

             —    

Common stock, $0.01 par value, 100,000,000 and 80,000,000 shares authorized, and 52,277,859 and 52,045,726 shares issued, respectively

     523       520  

Paid in capital in excess of par value

     195,498       194,246  

Treasury stock of 2,568,611 and 2,578,904 shares, respectively

     (10,258 )     (10,299 )

Accumulated other comprehensive loss

     (17,743 )     (17,683 )

Retained earnings

     88,469       75,032  
    


 


Total stockholders’ equity

     256,489       241,816  
    


 


     $ 730,008     $ 666,934  
    


 


 

a) Share and per share amounts have been adjusted to reflect a two-for-one stock split during June 2004. Treasury shares were not affected by this split.

 

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

 

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

In thousands, except for per share data – Unaudited

 

     For the Three Months
Ended June 30, (a)


    For the Six Months
Ended June 30, (a)


 
          2004     

         2003     

    2004

    2003

 

Revenues

                                

Oil, gas and related product sales

   $ 41,600     $ 32,457     $ 80,724     $ 69,544  

Other revenue

     380       638       1,033       1,067  
    


 


 


 


Total revenues

     41,980       33,095       81,757       70,611  

Expenses

                                

Oil and gas production costs

     15,658       13,444       31,663       26,077  

Other operating costs

     372       343       662       781  

Depletion, depreciation and accretion

     9,714       7,381       18,819       15,182  

General and administrative

     3,353       2,172       6,009       4,206  
    


 


 


 


Total expenses

     29,097       23,340       57,153       46,246  
    


 


 


 


Income from equity affiliates

     289       347       580       653  
    


 


 


 


Operating income

     13,172       10,102       25,184       25,018  

Other (income) expense-net

     (23 )     (59 )     (93 )     (34 )

Interest expense

     3,630       8,235       7,042       13,127  
    


 


 


 


Income before income taxes and cumulative effect of change in accounting principle

     9,565       1,926       18,235       11,925  

Income tax expense

     2,065       817       4,798       4,404  
    


 


 


 


Net income before cumulative effect of change in accounting principle

     7,500       1,109       13,437       7,521  

Cumulative effect of change in accounting principle, net of tax

     —         —         —         2,297  
    


 


 


 


Net income

   $ 7,500     $ 1,109     $ 13,437     $ 5,224  
    


 


 


 


Other comprehensive income – net of taxes

                                

Reclassification adjustments – hedge settlements

     7,536       6,387       14,148       16,503  

Change in derivative fair value

     (2,627 )     (8,299 )     (10,107 )     (22,176 )

Change in foreign currency translation adjustment

     (3,064 )     4,187       (4,101 )     6,610  
    


 


 


 


Comprehensive income

   $ 9,345     $ 3,384     $ 13,377     $ 6,161  
    


 


 


 


Basic net income per common share:

                                

Net income before cumulative effect of accounting change

   $ 0.15     $ 0.03     $ 0.27     $ 0.18  

Cumulative effect of accounting change, net of tax

     —         —         —         (0.06 )
    


 


 


 


Net income

   $ 0.15     $ 0.03     $ 0.27     $ 0.12  
    


 


 


 


Diluted net income per common share:

                                

Net income before cumulative effect of accounting change

   $ 0.15     $ 0.03     $ 0.27     $ 0.17  

Cumulative effect of accounting change, net of tax

     —         —         —         (0.05 )
    


 


 


 


Net income

   $ 0.15     $ 0.03     $ 0.27     $ 0.12  
    


 


 


 


Weighted average common shares outstanding

                                

Basic

     49,700       42,327       49,650       42,267  

Diluted

     50,737       43,243       50,635       43,210  

 

a) Share and per share amounts have been adjusted to reflect a two-for-one stock split during June 2004. Treasury shares were not affected by this split.

 

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

 

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited

 

     For the Six Months
Ended June 30,


 
     2004

    2003

 

Operating activities:

                

Net income

   $ 13,437     $ 5,224  

Charges and credits to net income not affecting cash

                

Cumulative effect of accounting change, net of tax

     —         2,297  

Depletion, depreciation and accretion

     18,819       15,182  

Deferred income taxes

     4,608       4,294  

Recognition of unearned revenues

     —         507  

Income from equity affiliates

     (580 )     (653 )

Non-cash gain from hedging activities

     (355 )     (1,189 )

Amortization of deferred loan costs

     616       2,022  

Other

     (2 )     (38 )

Changes in assets and liabilities, net of acquisition

                

Accounts receivable

     5,016       (700 )

Inventory, prepaid expenses and other

     533       (1,157 )

Accounts payable

     837       (4,260 )

Accrued liabilities and other

     (2,397 )     2,179  
    


 


Net cash from operating activities

     40,532       23,708  
    


 


Investing activities:

                

Development and exploration costs and other property additions

     (87,333 )     (54,002 )

Purchase of Voyager Compression Services assets

     —         (684 )

Distributions and advances from equity affiliates – net

     771       860  

Proceeds from sale of assets

     82       71  
    


 


Net cash used for investing activities

     (86,480 )     (53,755 )
    


 


Financing activities:

                

Notes payable, bank proceeds

     47,000       97,000  

Principal payments on long-term debt

     (154 )     (53,804 )

Deferred financing costs

     —         (1,360 )

Issuance of common stock, net of issuance costs

     932       543  
    


 


Net cash from financing activities

     47,778       42,379  
    


 


Net increase in cash and cash equivalents

     1,830       12,332  

Cash and cash equivalents at beginning of period

     4,116       9,116  
    


 


Cash and cash equivalents at end of period

   $ 5,946     $ 21,448  
    


 


SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:

                

Interest paid

   $ 6,823     $ 11,781  
    


 


Income taxes paid

   $ 58     $ 36  
    


 


Distribution of equity to Mercury Exploration Company

   $ —       $ (505 )
    


 


 

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

 

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QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

 

1. ACCOUNTING POLICIES AND DISCLOSURES

 

The accompanying condensed consolidated interim financial statements of Quicksilver Resources Inc. (“Quicksilver” or the “Company”) have not been audited by independent public accountants. In the opinion of Company management, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to present fairly the financial position of the Company as of June 30, 2004, its income and comprehensive income for the three and six month periods ended June 30, 2004 and 2003 and its cash flows for the six month periods ended June 30, 2004 and 2003. All such adjustments are of a normal recurring nature. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates.

 

Certain 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. Accordingly, these financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2003.

 

Stock Split

 

On June 1, 2004, the Company announced that its Board of Directors declared a two-for-one split of the Company’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2004, to stockholders of record at the close of business on June 15, 2004. Treasury shares were not affected by the split.

 

All share and per-share information included in the accompanying consolidated condensed financial statements for all periods presented have been adjusted to retroactively reflect the stock split.

 

Net Income per Common Share

 

Basic net income per common share is computed by dividing the net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact on net income and common shares of the potential dilution from stock options, stock warrants, and any other convertible securities outstanding. For the three and six month periods ended June 30, 2004 and 2003 there were no adjustments to net income for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three and six month periods ended June 30, 2004 and 2003.

 

     Three Months Ended
June 30,


  

Six Months Ended

June 30,


         2004    

       2003    

   2004

   2003

     (in thousands)    (in thousands)

Weighted average common shares-basic

   49,700    42,327    49,650    42,267

Potentially dilutive securities

                   

Stock options

   1,037    916    985    943
    
  
  
  

Weighted average common shares-diluted

   50,737    43,243    50,635    43,210
    
  
  
  

 

No outstanding options were excluded from the diluted net income per share calculation for any of the 2004 periods presented. For the three and six months ended June 30, 2003, options covering 40,420 shares of common stock were excluded from the diluted net income per share calculation because the exercise price exceeded the average market price of the Company’s common stock.

 

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2. ASSET RETIREMENT OBLIGATIONS

 

The FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which is effective for fiscal years beginning after June 15, 2002. This statement, adopted by the Company as of January 1, 2003, establishes accounting and reporting standards for the legal obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction or development and the normal operation of long-lived assets. It requires that the fair value of the liability for asset retirement obligations be recognized in the period in which it is incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the long-lived asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is allocated to expense using a systematic method over the asset’s useful life. Changes in the liability for the asset retirement obligation are recognized for (a) the passage of time and (b) revisions to either the timing or the amount of the original estimate of undiscounted cash flows.

 

In connection with adoption of SFAS No. 143, all asset retirement obligations of the Company were identified and the fair value of the retirement costs were estimated as of the date the long-lived assets were placed into service. The asset retirement obligations’ fair values were then estimated as of January 1, 2003. At January 1, 2003, the Company recognized asset retirement costs of $10.8 million and asset retirement obligations of $13.3 million, of which $0.9 million was classified as current. The cumulative-effect adjustment of $2.3 million included $1.3 million for additional depletion and depreciation of the asset retirement costs, $2.2 million for accretion of the fair value of the asset retirement obligations and $1.2 million for deferred tax benefits.

 

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the six months ended June 30, 2004 and 2003.

 

     Six Months Ended
June 30,


     2004

    2003

     (in thousands)

Beginning asset retirement obligation

   $ 15,189     $ 13,326

Change in estimated retirement costs

     2,494       —  

Additional liability incurred

     774       307

Accretion expense

     448       395

Asset retirement costs incurred

     (86 )     —  

Currency translation adjustment

     (53 )     128
    


 

Ending asset retirement obligation

   $ 18,766     $ 14,156
    


 

 

During the six months ended June 30, 2004 and 2003, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the statement of income for the period. Asset retirement obligations at June 30, 2004 are $18.8 million, of which $54,000 has been classified as current.

 

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3. HEDGING

 

The estimated fair values of all hedge derivatives and the associated fixed price firm sale and purchase commitments as of June 30, 2004 and December 31, 2003 are provided below. The associated carrying values of these financial instruments and firm commitments are equal to the estimated fair values for each period presented.

 

     June 30,
2004


   December 31,
2003


     (in thousands)

Derivative assets:

             

Floating price natural gas financial swaps

   $ 143    $ 463

Fixed price natural gas financial swaps

     —        336

Natural gas financial collars

     —        330

Fixed price sale commitments

     —        43

Fixed to floating interest rate swap

     —        50
    

  

     $ 143    $ 1,222
    

  

Derivative liabilities:

             

Fixed price natural gas financial swaps

   $ 34,984    $ 41,363

Crude oil financial collars

     585      448

Fixed price sale commitments

     147      356

Floating price natural gas financial swaps

     —        42

Floating to fixed interest rate swap

     933      2,030
    

  

     $ 36,649    $ 44,239
    

  

 

The fair values of all natural gas and crude oil financial instruments and firm sale commitments as of June 30, 2004 and December 31, 2003 were estimated based on market prices of natural gas and crude oil for the periods covered by the hedge derivatives. The net differential between the contractual prices in each hedge derivative and commitment and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the fair value of the Company’s hedge derivatives and commitments does not necessarily represent the value a third party would pay to assume the Company’s contract positions nor does it necessarily reflect the final settlement to be realized by the Company . The fair value of the interest rate swap was based upon third-party estimates of the fair value of the swap.

 

At June 30, 2004, all derivative assets and liabilities have been classified as current based on the maturity of the derivative instruments. The Company estimates $23.3 million of after-tax losses to be reclassified from other comprehensive income over the next twelve months.

 

In July, the Company hedged 20,000 Mcfd of MGV’s Canadian natural gas production from its wholly-owned subsidiary, MGV Energy Inc, for the five months from November 2004 through March 2005 using price collars with an average price floor of $5.50 and an average price ceiling of $9.69. A price collar was also entered into to hedge 15,000 Mcfd of MGV’s Canadian natural gas production at a price floor of $5.50 and a price ceiling of $6.75 from April through October 2005. A final price collar was entered into that hedges 15,000 Mcfd of Quicksilver’s U.S. natural gas production from May through October 2005 with a price floor of $5.50 and a price ceiling of $7.15.

 

4. LONG-TERM DEBT

 

Long-term debt consists as follows:

 

     June 30,
2004


    December 31,
2003


 
     (in thousands)  

Notes payable to banks

   $ 225,000     $ 178,000  

Second mortgage notes payable

     70,000       70,000  

Other loans

     1,232       1,386  

Fair value interest hedge

     277       50  
    


 


       296,509       249,436  

Less current maturities

     (319 )     (339 )
    


 


     $ 296,190     $ 249,097  
    


 


 

As of June 30, 2004, the Company’s borrowing base under its senior credit facility was $250 million of which $24.4 million was available. The loan agreements for the senior credit facility prohibited the declaration or payment of

 

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dividends by the Company and contained certain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio and an earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. Additionally, the Second Mortgage Notes contain restrictive covenants, which, among other things, require maintenance of a minimum current ratio, a minimum collateral coverage ratio and a minimum earnings (before interest, taxes, depreciation, depletion, accretion and amortization, non-cash income and expense and exploration costs) to fixed charges ratio. As of June 30, 2004, the Company was in compliance with all such restrictions.

 

The Company refinanced its prior senior bank debt on July 28, 2004 upon entering into a new five-year $300 million senior revolving credit facility, which the Company has the option to increase to $600 million with the consent of the senior lenders. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds being available for borrowing by the Company and Canadian funds being available for borrowing by the Company’s Canadian subsidiary, MGV Energy Inc. The Company’s initial borrowing capacity under the facility is $300 million (of which amount approximately $238 million was drawn immediately to refinance all amounts outstanding under the Company’s prior credit facility). The Company’s interest rate options under the facility include LIBOR, U.S. prime, and Canadian prime. As borrowings increase, LIBOR margins increase in specified increments from 1.125% to a maximum of 1.75%. The facility is secured by Quicksilver’s oil and gas properties, and the lenders annually re-determine the global borrowing base under the facility in accordance with their customary practices for oil and gas loans based upon the estimated value of the Company’s year-end proved reserves. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio.

 

On June 27, 2003, the Company redeemed $53 million in principal amount of subordinated notes payable through the issuance of $70 million in principal amount of second mortgage notes. As a result of the redemption, the Company recognized additional interest expense of $3.8 million, consisting of a prepayment premium of $3.2 million and remaining deferred financing costs of $1.5 million partially offset by an associated deferred hedging gain of $0.9 million.

 

5. COMMITMENTS AND CONTINGENCIES

 

Quicksilver currently has employment agreements in place for three executives of MGV. These agreements contain a formula for calculating bonuses with a determination date of December 31, 2005. The formula requires actual data with respect to, among other things, capital spending and proved reserve value for MGV from the last six months of 2005. The Company is in discussions with the MGV executives to clarify, amend or replace certain provisions contained in the existing employment agreements. Among the incentive provisions being discussed, it is contemplated that if the parties can agree on terms for revised employment agreements, the revised agreements will provide for incentives that could include stock options and cash, which would be tied, in part, to meeting certain reserve growth targets. The Company will continue to monitor its potential liability in respect of these matters, and will record accruals in respect of such liabilities when payment thereof becomes probable and the amounts thereof become reasonably estimable.

 

The Company is subject to various possible contingencies, which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, production rates, marketing and environmental matters are subject to regulation by various federal and state agencies.

 

6. STOCK-BASED COMPENSATION

 

Quicksilver has two stock-based compensation plans, the 1999 Stock Option and Stock Retention Plan and the newly adopted 2004 Non-Employee Director Stock Option Plan. The Company accounts for the plans under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

 

On January 7, 2004, the Company granted stock options covering 575,930 shares of common stock to the Company’s officers and employees. These options were granted at an exercise price of $16.515. Stock options

 

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covering 15,384 shares of common stock were granted to the Company’s non-employee directors on May 18, 2004 at an exercise price of $23.75.

 

The following table reflects pro forma income before the cumulative effect of an accounting change and the associated earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-based Compensation, to stock-based employee compensation.

 

     Three Months Ended
June 30,


    Six Months Ended
June 30,


 
         2004    

        2003    

    2004

    2003

 
     (in thousands, except for per share amounts)  

Net income before cumulative effect of change in accounting principle

   $ 7,500     $ 1,109     $ 13,437     $ 7,521  

Deduct: Total stock – based compensation expense determined under fair value based method for all awards, net of related tax effect

     (342 )     (121 )     (640 )     (232 )
    


 


 


 


Pro forma net income before cumulative effect of change in accounting principle

   $ 7,158     $ 988     $ 12,797     $ 7,289  
    


 


 


 


Net income before accounting change per common share as reported

                                

Basic

   $ 0.15     $ 0.03     $ 0.27     $ 0.18  

Diluted

     0.15       0.03       0.27       0.17  

Pro forma net income before accounting change per common share

                                

Basic

   $ 0.14     $ 0.02     $ 0.26     $ 0.17  

Diluted

     0.14       0.02       0.25       0.17  

 

7. RELATED PARTY TRANSACTIONS

 

The Darden family and associated entities, including Mercury Exploration Company (“Mercury”), Quicksilver Energy L.P., The Discovery Fund, Thomas Darden, Glenn Darden, Anne Darden Self, Lucy Darden and eight Darden family trusts beneficially own approximately 37% of Quicksilver’s shares outstanding. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

 

Quicksilver and its subsidiaries paid $0.4 million during each of the six-month periods ended June 30, 2004 and 2003 for rent on buildings owned by a Mercury affiliate. Rental rates were determined based on comparable rates charged by third parties.

 

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8. GEOGRAPHIC INFORMATION

 

The Company operates in two geographic segments, the United States and Canada. Both areas are engaged in the exploration and production segment of the oil and gas industry. The Company evaluates performance based on operating income.

 

     For the Three Months
Ended June 30,


    For the Six Months
Ended June 30,


 
     2004

    2003

    2004

    2003

 
     (in, thousands)     (in thousands)  

Revenues

                

United States

   $ 33,006     $ 31,021     $ 65,091     $ 66,734  

Canada

     8,974       2,074       16,666       3,877  
    


 


 


 


Total

   $ 41,980     $ 33,095     $ 81,757     $ 70,611  

Depletion, depreciation and accretion

                                

United States

   $ 7,786     $ 6,896     $ 15,118     $ 14,251  

Canada

     1,860       376       3,515       674  

Corporate

     68       109       186       257  
    


 


 


 


Total

   $ 9,714     $ 7,381     $ 18,819     $ 15,182  

Operating income

                                

United States

   $ 11,838     $ 11,630     $ 22,663     $ 27,845  

Canada

     4,755       753       8,716       1,636  

Corporate

     (3,421 )     (2,281 )     (6,195 )     (4,463 )
    


 


 


 


Total

   $ 13,172     $ 10,102     $ 25,184     $ 25,018  

Expenditures for assets

                                

United States

   $ 23,231     $ 19,899     $ 43,741     $ 32,791  

Canada

     24,140       12,509       43,517       20,987  

Corporate

     45       180       75       224  
    


 


 


 


Total

   $ 47,416     $ 32,588     $ 87,333     $ 54,002  

Fixed assets – net as of June 30, 2004 and 2003

                                

United States

   $ 524,642     $ 464,033     $ 524,642     $ 464,033  

Canada

     146,016       58,619       146,016       58,619  

Corporate

     1,399       1,910       1,399       1,910  
    


 


 


 


Total

   $ 672,057     $ 524,562     $ 672,057     $ 524,562  

 

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Certain statements contained in this quarterly report and other materials we file with the SEC, as well as information included in oral statements or other written statements made or to be made by us, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may relate to a variety of matters not currently ascertainable, such as future capital expenditures, drilling activity, acquisitions and dispositions, development or exploratory activities, cost savings efforts, production activities and volumes, hydrocarbon reserves, hydrocarbon prices, hedging activities and the results thereof, financing plans, liquidity, competition and our ability to realize efficiencies related to certain transactions or organizational changes. Forward-looking statements generally are accompanied by words such as “may,” “will,” “could,” “should,” “anticipate,” “believe,” “budgeted,” “expect,” “intend,” “plan,” “project,” “potential,” “estimate,” “continue,” or “future” or the negative, other variations thereof or other or similar statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include:

 

  changes in general economic conditions;

 

  fluctuations in crude oil and natural gas prices;

 

  failure or delays in achieving expected production from oil and gas development projects;

 

  uncertainties inherent in estimates of oil and gas reserves and predicting oil and gas reservoir performance;

 

  competitive conditions in our industry;

 

  actions taken by third-party operators, processors and transporters;

 

  changes in the availability and cost of capital;

 

  operating hazards, natural disasters, casualty losses and other matters beyond our control;

 

  the effects of existing and future laws and governmental regulations;

 

  the effects of existing or future litigation; and

 

  factors discussed in our Form 10-K for the year ended December 31, 2003.

 

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. In addition to the foregoing and any risks and uncertainties specifically identified in the text surrounding forward-looking statements, any statements in the reports and other documents filed by us with the Commission that warn of risks or uncertainties associated with future results, events or circumstances identify important factors that could cause actual results, events and circumstances to differ materially from those reflected in the forward-looking statements.

 

The following discussion and analysis should be read in conjunction with our condensed consolidated interim financial statements contained herein and our annual report for the year ended December 31, 2003, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such annual report.

 

Unless otherwise noted, discussions relating to our shares of common stock reflect the effects of the two-for-one split of the Company’s common stock effected in the form of a stock dividend payable to stockholders of record as of the close of business on June 15, 2004.

 

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Table of Contents

RESULTS OF OPERATIONS

 

Three Months Ended June 30, 2004 Compared with Three Months Ended June 30, 2003

 

     Three Months Ended
June 30,


     2004

   2003

     (in thousands)

Total operating revenues

   $ 41,980    $ 33,095

Total operating expenses

     29,097      23,340

Operating income

     13,172      10,102

Net income

     7,500      1,109

 

We recorded net income of approximately $7.5 million ($0.15 per diluted share) for the three months ended June 30, 2004, compared to net income of approximately $1.1 million ($0.03 per diluted share) for the second quarter of 2003. In the second quarter of 2004, we recorded a Canadian tax credit for scientific research and experimental development granted by Revenue Canada on certain 2001 capital expenditures. Recognition of the tax credit increased net income $1.3 million. Included in the 2003 results was $3.8 million of additional interest expense associated with our early redemption of $53 million in principal amount of our subordinated notes payable.

 

Operating Revenues

 

Revenues for the second quarter of 2004 were $42.0 million; an $8.9 million increase from the $33.1 million reported for the three months ended June 30, 2003. Production revenue increased $9.1 million as a result of a 14% increase in realized sales prices and a 13% increase in sales volumes.

 

Gas, Oil and Related Product Sales

 

Sales volumes, revenues and average prices for the three months ended June 30, 2004 and 2003 are as follows:

 

     Three Months Ended
June 30,


     2004

   2003

Natural gas, oil and NGL sales (in thousands)

             

United States

   $ 32,629    $ 30,383

Canada

     8,971      2,074
    

  

Total natural gas, oil and NGL sales

   $ 41,600    $ 32,457
    

  

Product sale revenues (in thousands)

             

Natural gas sales

   $ 34,812    $ 26,606

Crude oil sales

     6,030      5,093

NGL sales

     758      758
    

  

Total oil, gas and NGL sales

   $ 41,600    $ 32,457
    

  

Average daily sales volume

             

Natural gas – Mcfd

             

United States

     83,046      83,409

Canada

     20,165      5,322
    

  

Total

     103,211      88,731

Crude oil – Bbld

             

United States

     2,032      2,330

Canada

     —        1
    

  

Total

     2,032      2,331

NGL – Bbld

             

United States

     363      290

Canada

     1      2
    

  

Total

     364      292

Total sales – Mcfed

             

United States

     97,409      99,127

Canada

     20,177      5,340
    

  

Total

     117,586      104,467

 

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Table of Contents
     Three Months Ended
June 30,


         2004    

       2003    

Unit prices – including impact of hedges

             

Natural gas – per Mcf

             

United States

   $ 3.42    $ 3.23

Canada

     4.88      4.27

Consolidated

     3.71      3.30

Crude oil – per Bbl

             

United States

   $ 32.62    $ 24.01

Canada

     —        24.61

Consolidated

     32.62      24.01

NGL – per Bbl

             

United States

   $ 22.71    $ 28.64

Canada

     55.38      21.57

Consolidated

     22.85      28.57

 

Natural gas sales of $34.8 million for the second quarter of 2004 were 31% higher than the $26.6 million for the comparable 2003 period. Revenue increased $3.3 million from the second quarter of 2003 as a result of a $0.41 increase in realized average natural gas prices. Additional sales volumes increased revenue $4.9 million compared to the second quarter of 2003. Additional natural gas volumes included 220,000 Mcf and 32,000 Mcf from Michigan Antrim and PdC wells, respectively, and 375,000 Mcf from New Albany Shale wells drilled in Indiana and Kentucky during 2003 and 2004. Production from our coal bed methane projects in Canada increased 1,320,000 Mcf from the second quarter of 2003 as a result of additional wells drilled in our coal bed methane (“CBM”) projects. Production increases were partially offset by natural production declines.

 

Crude oil sales were $6.0 million for the three months ended June 30, 2004 compared to $5.1 million in the second quarter of 2003. The second quarter average crude oil sales price for 2004 increased to $32.62 from $24.01 in the second quarter of 2003 and increased revenue $1.8 million. This increase was partially offset by an approximate 27,000 Bbl decrease in 2004 sales volumes that resulted from natural production declines that reduced revenue $0.9 million from the prior year quarter.

 

Operating Expenses

 

Second quarter operating expenses for 2004 were $29.1 million; an increase of $5.8 million over the $23.3 million of expenses incurred in the second quarter of 2003.

 

Oil and Gas Production Costs

 

     Three Months Ended
June 30,


     2004

   2003

     (in thousands, except
per unit amounts)

Production expenses

             

United States

   $ 13,299    $ 12,498

Canada

     2,359      946
    

  

     $ 15,658    $ 13,444
    

  

Production expenses – per Mcfe

             

United States

   $ 1.51    $ 1.39

Canada

     1.29      1.95

Consolidated

     1.46      1.41

 

Oil and gas production costs were $15.7 million. A $2.1 million increase in lease operating expenses included approximately $1.3 million of additional Canadian operating and overhead costs incurred in conjunction with additional producing wells and increased production from CBM properties currently under development. The increase in production volumes resulted in a decrease in production expense on a Mcfe basis by $0.66 to $1.29 per Mcfe as a result of the improving economies of scale.

 

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Table of Contents

U.S. lease operating expenses for the second quarter of 2004 were $0.8 million higher than the 2003 period. Initial operating expenses associated with new Indiana and Kentucky wells and production increased production expenses approximately $0.9 million. That increase includes approximately $0.2 million for salt water disposal and equipment rentals. These expenses were the result of inadequate salt water disposal capacity and delays in completing electricity connections at each well. During the first half of 2004, 36 new wells and 24 non-producing wells acquired in 2003 began production in addition to 47 wells that began production in the fourth quarter of 2003. Operating costs have begun to decrease as natural gas production increases after initial production that contained high concentrations of water as well as decrease in the use of equipment rentals. Production overhead in Indiana increased approximately $0.3 million as a result of personnel added to operate and maintain these properties. These increases were partially offset by lower lease operating expenses in our Michigan operating area. The net increase in operating expenses raised U.S. production expense on a Mcfe-basis by $0.08 per Mcfe for the second quarter of 2004.

 

Depletion, Depreciation and Accretion

 

     Three Months Ended
June 30,


         2004    

       2003    

     (in thousands, except
per unit amounts)

Depletion

   $ 8,232    $ 6,302

Depreciation of other fixed assets

     1,252      879

Accretion

     230      200
    

  

Total depletion, depreciation and accretion

   $ 9,714    $ 7,381
    

  

Average depletion cost per Mcfe

   $ 0.77    $ 0.66

 

Second quarter 2004 depletion of $8.2 million was $1.9 million higher than depletion for the second quarter of 2003. A $0.11 increase in our consolidated depletion rate resulted in additional depletion expense of approximately $1.0 million. The higher depletion rate is the result of additional capital expenditures and future development costs anticipated in the June 2004 proved reserve report as compared to the increase in proved reserves. Additional production volumes resulted in the remaining increase. Depreciation expense increased approximately $0.2 million due to depreciation taken on a new pipeline and compression facilities that began operations in the fall of 2003. These assets gather and deliver Indiana and Kentucky natural gas production to an interstate pipeline in Kentucky.

 

General and Administrative Expenses

 

General and administrative costs incurred during the three months ended June 30, 2004 were $3.4 million. The $1.2 million increase over second quarter of 2003 expense was primarily the result of a $0.6 million increase in personnel costs for the 2004 quarter. Increased payroll and benefit costs are primarily the result of additional management and administrative personnel hired during the fourth quarter of 2003 and the first quarter of 2004. Costs incurred for the two-for-one stock split and additional compliance requirements were approximately of $0.3 million in total. Directors’ fees payable in cash of approximately $0.1 million were accrued in the second quarter of 2004.

 

Interest Expense

 

Interest expense for the second quarter of 2004 was $3.6 million, a decrease of $4.6 million compared to the second quarter of 2003. During the second quarter of 2003, we redeemed the $53 million in principal amount of our subordinated notes payable through the issuance of $70 million in principal amount of second lien notes. As a result of the early redemption, we recognized additional interest expense of $3.8 million, consisting of a prepayment premium of $3.2 million and remaining deferred financing costs of $1.5 million partially offset by an associated deferred hedging gain of $0.9 million. Ongoing interest expense decreased $0.8 million as a result of lower effective interest rates that was partially offset by an increase due to additional amounts of total debt outstanding.

 

Income Tax Expense

 

Income tax expense increased $1.2 million over the prior year period as a result of higher pretax income for the second quarter of 2004. Our income tax provision of $2.1 million was established using an effective U.S. federal tax rate of 35%. The effective Canadian tax rate of 7% includes a tax credit of $1.3 million. The tax credit was granted by Revenue Canada for certain capital expenditures made by MGV in 2001 that qualified for a scientific research and experimental development tax credit. Without the tax credit, the effective Canadian tax rate would have been 31%, which reflects adjustments for temporary differences between the accounting and tax basis of assets and liabilities with consideration of enacted tax rate reductions in future years.

 

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Table of Contents

Six Months Ended June 30, 2004 Compared with Six Months Ended June 30, 2003

 

     Six Months Ended
June 30,


     2004

   2003

     (in thousands)

Total operating revenues

   $ 81,757    $ 70,611

Total operating expenses

     57,153      46,246

Operating income

     25,184      25,018

Net income before accounting change

     13,437      7,521

Net income after accounting change

     13,437      5,224

 

We recorded net income of approximately $13.4 million ($0.27 per diluted share) in the six months ended June 30, 2004, compared to net income of approximately $5.2 million ($0.12 per diluted share) for the first six months of 2003. In the second quarter of 2004, we recorded a Canadian tax credit for scientific research and experimental development. Recognition of the tax credit increased net income $1.3 million. Included in the 2003 period was a $2.3 million charge ($0.05 per diluted share), net of tax, for the adoption of Statement of Financial Accounting Standard (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003. The 2003 period also included a $3.8 million pre-tax charge to interest expense as a result of our early redemption of $53 million in principal amounts of our subordinated notes payable.

 

Operating Revenues

 

Revenues for the six months ended June 30, 2004 were $81.8 million; an $11.2 million increase from the $70.6 million reported for the six months ended June 30, 2003. Higher realized prices increased product sales revenue $5.8 million while additional sales volumes further increased revenue $5.4 million. Volume increases were primarily the result of natural gas production from new wells drilled in our Canadian CBM, Michigan Antrim and Indiana New Albany Shale projects.

 

Gas, Oil and Related Product Sales

 

Sales volumes, revenues and average prices for the six months ended June 30, 2004 and 2003 are as follows:

 

     Six Months Ended
June 30,


     2004

   2003

Natural gas, oil and NGL sales (in thousands)

             

United States

   $ 64,066    $ 65,669

Canada

     16,658      3,875
    

  

Total natural gas, oil and NGL sales

   $ 80,724    $ 69,544
    

  

Product sale revenues (in thousands)

             

Natural gas sales

   $ 67,845    $ 57,565

Crude oil sales

     11,229      10,506

NGL sales

     1,650      1,473
    

  

Total oil, gas and NGL sales

   $ 80,724    $ 69,544
    

  

Average daily sales volume

             

Natural gas – Mcfd

             

United States

     82,878      87,508

Canada

     19,403      4,918
    

  

Total

     102,281      92,426

Crude oil – Bbld

             

United States

     2,038      2,360

Canada

     —        1
    

  

Total

     2,038      2,361

NGL – Bbld

             

United States

     379      335

Canada

     1      4
    

  

Total

     380      339
    

  

Total

     116,793      108,625
    

  

 

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Table of Contents
     Six Months Ended
June 30,


     2004

   2003

Total sales – Mcfed

             

United States

     97,373      103,673

Canada

     19,420      4,952
    

  

Total

     116,793      108,625
    

  

Unit prices – including impact of hedges

             

Natural gas – per Mcf

             

United States

   $ 3.39    $ 3.39

Canada

     4.71      4.32

Consolidated

     3.64      3.44

Crude oil – per Bbl

             

United States

   $ 30.27    $ 24.59

Canada

     —        24.72

Consolidated

     30.27      24.59

NGL – per Bbl

             

United States

   $ 23.72    $ 24.00

Canada

     41.76      24.96

Consolidated

     23.83      24.00

 

Natural gas sales of $67.8 million for the six months ended June 30, 2004 were 18% higher than the $57.6 million of revenue for the comparable 2003 period. Revenue increased $3.4 million from the 2003 period as a result of a $0.20 increase in realized average natural gas prices. Additional sales volumes increased revenue $6.9 million compared to the first six months of 2003. Additional natural gas volumes for the 2004 period included 505,000 Mcf and 32,000 Mcf from Antrim and PdC wells, respectively, drilled in Michigan during 2003 and 2004 as well as 720,000 Mcf from New Albany wells drilled in Indiana and Kentucky. Production from in Canada increased 2,744,000 Mcf during the first half of 2004 as a result wells drilled in our CBM projects. New production was partially offset by decreases due to natural production declines.

 

Crude oil sales were $11.2 million for the six months ended June 30, 2004 compared to $10.5 million in the first six months of 2003. The average crude oil sales price for the first six months of 2004 increased to $30.27 from $24.59 and improved revenue $2.4 million from the first six months of 2003. Decreased production was due to natural production declines and reduced revenue $1.7 million from the prior year period.

 

Other Revenue

 

Other revenue was unchanged from the prior year period. The first quarter of 2003 included a $0.5 million reduction in other revenue that resulted from the completion of our repurchase of Section 29 tax credit properties. Gas marketing, processing and transportation revenue for the first quarter of 2004 decreased $0.6 million primarily as a result of the cessation of business of our marketing subsidiary, Cinnabar Energy Services & Trading, LLC, as of December 31, 2003.

 

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Table of Contents

Operating Expenses

 

Operating expenses for the first six months of 2004 were $57.1 million, an increase of $10.9 million over expenses of $46.2 million incurred in the first six months of 2003.

 

Oil and Gas Production Costs

 

     Six Months Ended June 30,

     2004

   2003

     (in thousands, except
per unit amounts)

Production expenses

             

United States

   $ 27,228    $ 24,509

Canada

     4,435      1,568
    

  

     $ 31,663    $ 26,077
    

  

Production expenses – per Mcfe

             

United States

   $ 1.54    $ 1.31

Canada

     1.25      1.75

Consolidated

     1.49      1.33

 

Oil and gas production costs were $31.7 million. The $5.6 million increase as compared to the six-month period ended June 30, 2003 was the result of increased lease operating expenses. Canadian lease operating expenses were $2.5 million higher as a result of additional Canadian operating expense as a result of new wells drilled on our CBM properties and the associated production volumes. The increase in production volumes resulted in a decrease in production expense on a Mcfe basis by $0.50 to $1.25 per Mcfe as a result of the improving economies of scale.

 

U.S. lease operating expenses were $3.1 million higher than the 2003 period. Initial operating expenses associated with new Indiana and Kentucky wells and production increased production expenses approximately $1.8 million. The increase included approximately $0.7 million for salt water disposal and equipment rentals. These expenses were the result of inadequate salt water disposal capacity and delays in completing electricity connections at each well. During the first half of 2004, 36 new wells and 24 non-producing wells acquired in 2003 began production in addition to 47 wells that began production in the fourth quarter of 2003. Operating costs have begun to decrease as natural gas production increases after initial production that contained high concentrations of water. Production overhead in Indiana increased approximately $0.6 million as a result of personnel added to operate and maintain these properties. Michigan operating expenses increased approximately $0.8 million as a result of the routine overhaul of several compressors. Similar overhaul expenses were not incurred in the 2003 period. These items increased U.S. production expenses by $0.18 per Mcfe for the first six months of 2004.

 

Depletion, Depreciation and Accretion

 

     Six Months Ended June 30,

     2004

   2003

     (In thousands, except
per unit amounts)

Depletion

   $ 15,935    $ 13,011

Depreciation of other fixed assets

     2,436      1,776

Accretion

     448      395
    

  

Total depletion, depreciation and accretion

   $ 18,819    $ 15,182
    

  

Average depletion cost per Mcfe

   $ 0.75    $ 0.66

 

Depletion for the first six months of 2003 of $2.9 million was higher than first six months of 2003. Depletion expense was higher due to an increase in both the depletion rate and sales volumes. The $0.09 increase in consolidated depletion rate was primarily the result of additional capital expenditures and future development costs anticipated in the June 2004 proved reserve report when compared to the increase in proved reserves. The $0.7 million increase in depreciation expense included approximately $0.5 million of depreciation taken on a new pipeline and compression facilities that began operations in the fall of 2003. These assets gather and deliver Indiana and Kentucky natural gas production.

 

General and Administrative Expenses

 

General and administrative costs incurred during the six months ended June 30, 2004 were $6.0 million; $1.8 higher than the expense incurred in the six months ended June 30, 2003. The increase in general and administrative expenses was primarily due to a $1.2 million increase in personnel costs for the 2004 period. Increased payroll and benefit costs are primarily the result of additional management and administrative personnel hired during the fourth quarter of 2003 and the first half of 2004. Costs incurred for the two-for-one stock split and additional compliance requirements were approximately of $0.3 million in total. Directors’ fees payable in cash of approximately $0.1 million were accrued in the second quarter of 2004.

 

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Table of Contents

Interest Expense

 

Interest expense for the first six months of 2004 was $7.0 million, a decrease of $6.1 million compared to the first six months of 2003. During the second quarter of 2003, we redeemed the $53 million in principal amount of our subordinated notes payable through the issuance of $70 million in principal amount of second lien notes. As a result of the early redemption, we recognized additional interest of expense of $3.8 million, which consisted of a prepayment premium of $3.2 million and remaining deferred financing costs of $1.5 million partially offset by an associated deferred hedging gain of $0.9 million. Ongoing interest expense decreased $1.1 million as a result of lower effective interest rates and was partially offset by additional interest expense associated with higher debt outstanding.

 

Income Tax Expense

 

Income tax expense increased $0.4 million over the prior year period as a result of additional pretax income for the first six months of 2004. Our income tax provision of $4.8 million was established using an effective U.S. federal tax rate of 35% and an effective Canadian tax rate of 16%. The effective Canadian tax rate of 16% includes a tax credit of $1.3 million. The tax credit was granted by Revenue Canada for certain capital expenditures made by MGV in 2001 that qualified for a scientific research and experimental development tax credit. Without the tax credit, the effective Canadian tax rate would have been 31%, which reflects adjustments for temporary differences between the accounting and tax basis of assets and liabilities with consideration of enacted tax rate reductions in future years.

 

CAPITAL RESOURCES AND LIQUIDITY

 

Net cash from operations of $40.5 million for the six months ended June 30, 2004 was $16.8 million more than the same period in 2003. Operating income before noncash items increased $8.9 million that was primarily the result of additional sales volumes and higher prices. Cash from operations was reduced by $3.2 million in 2003 as a result of the prepayment premium for the early redemption of $53 million in principal amount of our subordinated notes payable. The remaining increase was primarily the result of decreases in accounts receivable and inventory and increases in accounts payable, as partially offset by decreases in accrued liabilities.

 

Our principal operating sources of cash include sales of natural gas and crude oil and revenues from gas marketing, transportation and processing. During the first half of 2004, we sold approximately 28% of our natural gas production under long-term contracts with an average floor price of $2.48 and an additional 51% of our natural gas production was sold under fixed-price swap agreements. Additionally, price collars covered 2% and 49% of our natural gas and crude oil production, respectively. As a result of our hedging activities, we benefit from significant predictability of our natural gas and crude oil revenues. However, when natural gas and crude oil market prices exceed our financial hedge swap prices, we are required to make payment for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payment from our customers until 25 to 60 days after the month of production. Additionally, in the event of a significant production curtailment, we are required contractually to fulfill our commitments under our long-term sales contracts by purchasing natural gas volumes at market prices.

 

Net cash used in investing activities for the six months ended June 30, 2004 was $86.5 million. Investing activities were comprised of $82.5 million expended for exploration and development activities and $4.8 million for construction and acquisition of gathering and processing facilities and other fixed assets. Of the $82.5 million expended for exploration and development, $23.1 million was incurred in leasehold acquisitions. Those acquisitions included $9.4 million in Canada, $3.0 million in Indiana and Kentucky and $8.3 million in Texas.

 

Capital expenditures

 

     Six Months Ended
June 30, 2004


     (in thousands)

Exploration and development

      

United States

   $ 39,521

Canada

     43,004
    

Total exploration and development

     82,525

Gas processing/transportation and other

     4,808
    

Total capital expenditures

   $ 87,333
    

 

Net cash provided by financing activities for the six months ended June 30, 2004 was $47.8 million. We borrowed $47.0 million under our credit facility during the first six months of 2004. Expenditures for capital additions exceeded operating cash flow by approximately $46.0 million for the first half of 2004.

 

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We refinanced our prior senior bank debt on July 28, 2004 upon entering into a new five-year $300 million senior revolving credit facility, which we have the option to increase to $600 million with the consent of the senior lenders. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds being available to us for borrowing by the Company and Canadian funds being available for borrowing by the our Canadian subsidiary, MGV Energy Inc. Our initial borrowing capacity under the facility is $300 million (of which amount approximately $238 million was drawn immediately to refinance all amounts outstanding under our prior credit facility). Our interest rate options under the facility include LIBOR, U.S. prime, and Canadian prime. As borrowings increase, LIBOR margins increase in specified increments from 1.125% to a maximum of 1.75%. The facility is secured by our oil and gas properties, and the lenders annually re-determine the global borrowing base under the facility in accordance with their customary practices for oil and gas loans based upon the estimated value of our year-end proved reserves. Because borrowings under the facility are secured by our oil and gas properties and the lenders annually re-determine our global borrowing base, decreases in the amount of our oil and gas reserves and/or the value of our oil and gas reserves could have the effect of limiting our borrowing base under the facility or require the repayment of outstanding borrowings. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio.

 

As of June 30, 2004 and December 31, 2003, our total capitalization was as follows:

 

     June 30,
2004


   December 31,
2003


     (in thousands)

Long-term and short-term debt:

             

Notes payable to banks

   $ 225,000    $ 178,000

Subordinated notes payable

     70,000      70,000

Various loans

     1,232      1,386

Fair value interest hedge

     277      50
    

  

Total debt

     296,509      249,436

Stockholders’ equity

     256,489      241,816
    

  

Total capitalization

   $ 552,998    $ 491,252
    

  

 

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

 

We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.

 

Our primary risk exposure is related to natural gas and crude oil commodity prices. We have mitigated the risk of adverse price movements through the use of swaps and collars; however, we have also limited future gains from favorable movements.

 

Commodity Price Risk

 

We enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. These contracts have included price ceilings and floors, no-cost collars and fixed price swaps. We sell approximately 25,000 Mcfd and 10,000 Mcfd of natural gas under long-term contracts with floor prices of $2.49 per Mcf and $2.47 per Mcf, respectively, through March 2009. Approximately 6,800 Mcfd sold under these contracts are third party volumes controlled by us.

 

Equity natural gas volumes of approximately 50,500 Mcfd and 37,200 Mcfd are hedged for the third and fourth quarters of 2004, respectively, using fixed price swap agreements. The weighted averaged price for those natural gas volumes is $3.79 per Mcf and $3.24 per Mcf, respectively. Additionally, our crude oil production is hedged by price collars for 500 Bbld for the remainder of the year.

 

In July, we hedged 20,000 Mcfd of our Canadian natural gas production for the five months from November 2004 through March 2005 using price collars with an average price floor of $5.50 and an average price ceiling of $9.69. A price collar was also entered into to hedge 15,000 Mcfd of our Canadian natural gas production at a price floor of $5.50 and a price ceiling of $6.75 from April through October 2005. A final price collar was entered into that hedges 15,000 Mcfd of our U.S. natural gas production from May through October 2005 with a price floor of $5.50 and a price ceiling of $7.15.

 

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The following table summarizes our open financial hedge positions as of June 30, 2004 related to natural gas and crude oil production.

 

Product


 

Type


 

Contract Period


 

Volume


 

Weighted Avg
Price per

Mcf or Bbl


 

Fair Value


                    (in thousands)

Gas

  Fixed Price   Jul 2004-Oct 2004   10,000 Mcfd   5.32   $(1,044)

Gas

  Fixed Price   Jul 2004-Oct 2004   10,000 Mcfd   5.32   (1,044)

Gas

  Fixed Price   Jul 2004-Dec 2004   503 Mcfd   2.30   (269)

Gas

  Fixed Price   Jul 2004-Apr 2005   10,000 Mcfd   2.79   (10,861)

Gas

  Fixed Price   Jul 2004-Apr 2005   10,000 Mcfd   2.79   (10,883)

Gas

  Fixed Price   Jul 2004-Apr 2005   10,000 Mcfd   2.79   (10,883)

Oil

  Collar   Jul 2004-Dec 2004   500 Bbld   21.00-29.35   (585)
                   
                Total   $(35,569)
                   

 

Commodity price fluctuations affect our remaining natural gas and crude oil volumes as well as our NGL volumes. Up to 4,500 Mcfd of natural gas is committed at market price through May 2005. Additional gas volumes of 16,500 Mcfd are committed at market price through September 2008. Approximately 15,200 Mcfd sold under these contracts are third party volumes controlled by us.

 

We also enter into financial contracts to hedge our exposure to commodity price risk associated with future contractual natural gas sales and purchases. These contracts consist of fixed price sales to third parties. As a result of these firm sale commitments the associated financial price swaps have qualified as fair value hedges. At June 30, 2004, we recorded assets and liabilities of $143,000 and $147,000, respectively, for the fair value of firm sale commitments and the associated financial price swaps.

 

The following table summarizes our open financial derivative positions and hedged firm commitments as of June 30, 2004 related to natural gas marketing.

 

Product


 

Type


 

Contract Period


 

Volume


 

Weighted Avg

Price per Mcf


 

Fair Value


                    (in thousands)

Fixed price sale contracts

               

Gas

  Sale   Jul 2004-Oct 2004   1,554 Mcfd   $5.52   $(147)
                   

Financial derivatives

                   

Gas

  Floating Price   Jul 2004-Oct 2004   1,545 Mcfd       143
                   
                Total-net   $(4)
                   

 

Utilization of our hedging program may result in natural gas and crude oil realized prices varying from market prices that we receive from the sale of natural gas and crude oil. Our revenue from oil and gas production was $21.0 million and $24.3 million lower as a result of the hedging programs in the first half of 2004 and 2003, respectively. Marketing revenue was $0.3 million and $0.5 million higher as a result of hedging activities in the first half of 2004 and 2003, respectively.

 

The fair value of all natural gas financial contracts and associated firm sale commitments as of June 30, 2004 was estimated based on published market prices of natural gas for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, was applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the fixed price natural gas financial contract value does not necessarily represent the value a third party would pay to assume our contract positions.

 

Interest Rate Risk

 

As of June 30, 2004, the interest payments for $75.0 million notional variable-rate debt are hedged with an interest rate swap that converts a floating three-month LIBOR base to a 3.74% fixed-rate through March 31, 2005. Our liability associated with the swap is $0.9 million at June 30, 2004.

 

Interest expense for the first half of 2004 and 2003 was $0.5 million and $0.3 million higher, respectively, as a result of interest rate swaps.

 

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Table of Contents

ITEM 4. Controls and Procedures

 

Management, including our president and chief executive officer and executive vice president and chief financial officer, evaluated effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2004. Based upon, and as of the date of, that evaluation, the president and chief executive officer and executive vice president and chief financial officer concluded that the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required.

 

There has not been any change in our internal control over financial reporting during our most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

 

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Table of Contents

PART II - OTHER INFORMATION

 

ITEM 4. Submission of Matters to a Vote of Security Holders

 

The following items of business were presented to the stockholders at the annual meeting. The numbers of votes or abstentions below have not been adjusted to reflect the common stock split described above.

 

Election of Directors

 

At the meeting, two directors were elected to serve terms expiring at the Company’s 2007 Annual Meeting of Stockholders. The vote with respect to the election of these directors was as follows:

 

Name


   Total Vote for
Each Director


   Total Vote
Withheld for
Each
Director


Anne Darden Self

   22,874,604    575,061

Steven M. Morris

   22,991,072    458,593

 

Thomas F. Darden, D. Randall Kent, Mark J. Warner, Glenn Darden and W. Yandell Rogers, III continue to serve as directors of the Company.

 

Ratification of Appointment of Auditor

 

At the meeting, the stockholders ratified the appointment by the Company’s Audit Committee of our independent auditor for fiscal year ending December 31, 2004. The vote on such proposal was as follows:

 

For

   23,244,991

Against

   203,956

Abstentions

   718

 

Amendment to the Restated Certificate of Incorporation

 

At the meeting, stockholders approved the amendment to the Restated Certificate of Incorporation increasing the number of authorized shares to 100 million shares. The vote on such proposal was as follows:

 

For

   21,296,877

Against

   2,141,390

Abstentions

   11,398

 

Amended and Restated 1999 Stock Option and Retention Stock Plan

 

At the meeting, stockholders approved the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan. The vote on such proposal was as follows:

 

For

   18,165,771

Against

   2,976,574

Abstentions

   15,038

 

2004 Non-Employee Director Stock Option Plan

 

At the meeting, stockholders approved the Quicksilver Resources Inc. 2004 Non-Employee Director Stock Option Plan. The vote on such proposal was as follows:

 

For

   19,171,251

Against

   1,393,803

Abstentions

   591,009

 

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Table of Contents

ITEM 6. Exhibits and Reports on Form 8-K:

 

  (a) Exhibits

 

Exhibit No.

  

Sequential Description


*3.1    Restated Certificate of Incorporation of Quicksilver Resources Inc., as amended
*3.2    Certificate of Designation, Preferences and Rights of Preferred Stock
*3.3    Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc.
*4.1    Second Amendment to Note Purchase Agreement, dated as of July 28, 2004, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, Collateral Agent, and the Purchasers identified therein.
*10.1    Credit Agreement, dated as of July 28, 2004, among Quicksilver Resources Inc., as Borrower, Bank One, NA, Global Administrative Agent, and the other agents and financial institutions listed therein.
*10.2    Credit Agreement, dated as of July 28, 2004, among MGV Energy, Inc., as Borrower, Bank One, NA, Canada Branch, Canadian Administrative Agent, Bank One, NA, Global Administrative Agent, and the financial institutions listed therein.
*15.1    Awareness Letter of Deloitte & Touche LLP
*31.1    Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2    Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1    Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

* Filed herewith

 

  (b) Reports on Form 8-K

 

Current Report on Form 8-K dated and furnished to the SEC on May 5, 2004, reporting under Items 7 and 12 a press release announcing first quarter operating results.

 

Current Report on Form 8-K dated and filed with the SEC on June 4, 2004, reporting under Item 5 approval of a two-for-one stock split by our Board of Directors.

 

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Table of Contents

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.

 

Dated: August 6, 2004

 

Quicksilver Resources Inc.
 
 
By:  

/s/ Glenn Darden

   

Glenn Darden

President and Chief Executive Officer

 
By:  

/s/ Bill Lamkin

   

Bill Lamkin

Executive Vice President and Chief Financial Officer

 

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