Quicksilver Resources (KWK) 10-Q 2005 Q2 Quarterly report

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, 2005

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, 2005, the registrant had 75,911,815 outstanding shares of its common stock, $0.01 par value.

QUICKSILVER RESOURCES INC.

INDEX TO FORM 10-Q

For the Period Ending June 30, 2005

		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, 2005 and December 31, 2004		4
Condensed Consolidated Statements of Income and Comprehensive Income for the Three and Six Months Ended June 30, 2005 and 2004		5
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004		6
Notes to Condensed Consolidated Interim Financial Statements		7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	22
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	25
Signatures		26

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

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. and subsidiaries (the Company) as of June 30, 2005, and the related condensed consolidated statements of income and comprehensive income for the three and six month periods ended June 30, 2005 and 2004 and of cash flows for the six month periods ended June 30, 2005 and 2004. 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 Quicksilver Resources Inc. and subsidiaries as of December 31, 2004, and the related consolidated statements of income and comprehensive income, stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated March 16, 2005 (August 8, 2005 as to the effects of certain reclassifications), we expressed an unqualified opinion on those consolidated financial statements. Our report on those statements referred to a change in accounting for asset retirement obligations in 2003. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2004, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas

August 9, 2005

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

	June 30, 2005			December 31, 2004 (1)
ASSETS
Current assets
Cash and cash equivalents	$	7,208		$	15,947
Accounts receivable (net of allowance of $405 and $314, respectively)		40,793			38,037
Current deferred income taxes		1,115			3,523
Inventories and other current assets		10,481			8,689
Total current assets		59,597			66,196
Investments in and advances to equity affiliates		8,552			8,254
Property, plant and equipment – net (“full cost”)		906,919			802,610
Other assets		9,065			11,274
	$	984,133		$	888,334
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	356		$	356
Accounts payable		36,662			28,407
Accrued derivative obligations		3,628			12,784
Accrued liabilities		36,424			41,904
Total current liabilities		77,070			83,451
Long-term debt		456,160			399,134
Derivative obligations		1,569			—
Asset retirement obligations		18,850			17,967
Deferred income taxes		89,885			83,506
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 shares authorized 78,493,683 and 77,752,151 shares issued, respectively		785			778
Paid in capital in excess of par value		212,474			200,690
Deferred compensation		(4,888	)		—
Treasury stock of 2,568,611 shares		(10,258	)		(10,258	)
Accumulated other comprehensive income		8,261			6,762
Retained earnings		134,225			106,304
Total stockholders’ equity		340,599			304,276
	$	984,133		$	888,334

(1) Share and per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005. The split did not affect treasury shares.

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, (1)						For the Six Months Ended June 30, (1)
	2005			2004			2005			2004
Revenues
Oil, gas and related product sales	$	67,843		$	41,600		$	122,683		$	80,724
Other revenue		697			380			1,106			1,033
Total revenues		68,540			41,980			123,789			81,757
Expenses
Oil and gas production costs		20,352			15,658			40,006			31,663
Other operating costs		654			372			1,045			662
Depletion, depreciation and accretion		13,017			9,714			25,389			18,819
Provision for bad debts		88			—			88			—
General and administrative		4,618			3,353			7,731			6,009
Total expenses		38,729			29,097			74,259			57,153
Income from equity affiliates		215			289			439			580
Operating income		30,026			13,172			49,969			25,184
Other (income) expense-net		(118	)		(23	)		(204	)		(93	)
Interest expense		4,776			3,630			9,433			7,042
Income before income taxes		25,368			9,565			40,740			18,235
Income tax expense		8,183			2,065			12,801			4,798
Net income	$	17,185		$	7,500		$	27,939		$	13,437
Other comprehensive income (loss), net of income taxes
Reclassification adjustments – hedge settlements		2,433			7,536			8,637			14,148
Unrealized gain (loss) on derivative instruments		4,333			(2,627	)		(5,930	)		(10,107	)
Foreign currency translation adjustments		(528	)		(3,064	)		(1,208	)		(4,101	)
Comprehensive income	$	23,423		$	9,345		$	29,438		$	13,377
Basic net income per common share	$	0.23		$	0.10		$	0.37		$	0.18
Diluted net income per common share	$	0.21		$	0.10		$	0.35		$	0.18
Weighted average common shares outstanding
Basic		75,888			74,550			75,704			74,475
Diluted		82,474			76,106			82,268			75,952

(1) Share and per share amounts have been adjusted to reflect a three-for-two stock split effected in the form of a stock dividend in June 2005. The split did not affect treasury shares.

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,
	2005			2004
Operating activities:
Net income	$	27,939		$	13,437
Charges and credits to net income not affecting cash
Depletion, depreciation and accretion		25,389			18,819
Deferred income taxes		12,528			4,608
Amortization of deferred loan costs		701			616
Non-cash compensation		500			—
Income from equity affiliates		(439	)		(580	)
Non-cash gain from hedging activities		(287	)		(355	)
Other		58			(2	)
Changes in assets and liabilities
Accounts receivable		(2,844	)		5,308
Inventory, prepaid expenses and other		(3,511	)		583
Accounts payable		2,542			1,204
Accrued liabilities and other		(1,459	)		(5,013	)
Net cash from operating activities		61,117			38,625
Investing activities:
Purchase of property, plant and equipment		(132,515	)		(85,161	)
Distributions and advances from equity affiliates – net		141			771
Proceeds from sales of properties		1,190			82
Net cash used for investing activities		(131,184	)		(84,308	)
Financing activities:
Issuance of debt		59,823			47,000
Repayments of debt		(161	)		(154	)
Payment of fractional shares		(18	)		—
Deferred financing costs		(107	)		—
Proceeds from exercise of stock options		1,508			932
Net cash from financing activities		61,045			47,778
Effect of exchange rates on cash		283			(265	)
Net increase (decrease) in cash and cash equivalents		(8,739	)		1,830
Cash and cash equivalents at beginning of period		15,947			4,116
Cash and cash equivalents at end of period	$	7,208		$	5,946
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid	$	9,174		$	6,823
Income taxes paid	$	857		$	58
NONCASH INVESTING ACTIVITIES
Changes in working capital related to the acquisition of property, plant and equipment	$	(1,615	)	$	(2,172	)

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 a registered independent public accounting firm. 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, 2005 and its income, comprehensive income and cash flows for the three-month and six-month periods ended June 30, 2005 and 2004. 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/A for the year ended December 31, 2004.

Reclassification

Subsequent to the issuance of the June 30, 2004 Form 10-Q, the Company determined that certain of its liabilities associated with the acquisition of property, plant and equipment were incorrectly reflected as cash inflows for operating activities and cash outflows for investing activities. Management has concluded that the misclassification was not material to the condensed consolidated financial statements, and accordingly the prior period presented has been corrected by reducing net cash from operating activities and net cash used for investing activities by $2.2 million and disclosing a noncash investing activity of the same amount.

Stock Split

On June 1, 2005, Quicksilver announced that its Board of Directors declared a three-for-two stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2005, to holders of record at the close of business on June 15, 2005. The split did not affect treasury shares.

The share and earnings per share data included in these notes and the accompanying condensed consolidated financial statements for all periods presented have been adjusted to retroactively reflect the stock split.

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Net Income per Common Share

Basic net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is computed using the treasury stock method, which considers the impact to net income and common shares from the potential issuance of common shares underlying stock options, stock warrants and outstanding convertible securities. 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-month periods ended June 30, 2005 and 2004.

	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
	(in thousands)				(in thousands)
Net income	$	17,185	$	7,500	$	27,939	$	13,437
Impact of assumed conversions – interest on 1.875% contingently convertible debentures, net of income taxes		475		—		950		—
Income available to stockholders assuming conversion of contingently convertible debentures	$	17,660	$	7,500	$	28,889	$	13,437
Weighted average common shares-basic		75,888		74,550		75,704		74,475
Effect of dilutive securities:
Stock options outstanding		1,678		1,556		1,656		1,477
Contingently convertible debentures		4,908		—		4,908		—
Weighted average common shares-diluted		82,474		76,106		82,268		75,952
Basic income per common share	$	0.23	$	0.10	$	0.37	$	0.18
Diluted income per common share	$	0.21	$	0.10	$	0.35	$	0.18

Stock-Based Compensation

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,
	2005			2004			2005			2004
	(in thousands, except for per share amounts)
Net income	$	17,185		$	7,500		$	27,939		$	13,437
Deduct: Total stock – based compensation expense determined under fair value based method for all awards, net of related tax effect		(1,907	)		(374	)		(3,838	)		(746	)
Pro forma net income before cumulative effect of change in accounting principle	$	15,278		$	7,126		$	24,101		$	12,691
Net income available assuming conversion of contingently convertible debentures	$	15,753		$	7,126		$	25,052		$	12,691
Net income per common share as reported
Basic	$	0.23		$	0.10		$	0.37		$	0.18
Diluted		0.21			0.10			0.35			0.18
Pro forma net income per common share
Basic	$	0.20		$	0.10		$	0.32		$	0.17
Diluted		0.19			0.09			0.30			0.17

Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Boards (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123(R),Share-Based Payment, which establishes accounting standards for all transactions in which an entity exchanges its equity instruments for goods and services. SFAS No. 123(R) focuses primarily on accounting for transactions with employees, and carries forward without change prior guidance for shared-based payments for transactions with non-employees.

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SFAS No. 123(R) eliminates the intrinsic value measurement objective in Accounting Principle Board (“APB”) Opinion 25 and generally requires measurement of the cost of employee services received in exchange for an award of equity instruments be based on the fair value of the award on the date of the grant. The standard requires grant date fair value to be estimated using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. Such cost must be recognized over the period during which an employee is required to provide service in exchange for the award (which is usually the vesting period). The standard also requires estimation of the number of instruments that will ultimately be issued rather than accounting for forfeitures as they occur.

SFAS No. 123(R) was to apply to all awards granted, modified or settled in our first reporting period under U.S. GAAP after June 15, 2005; however the SEC deferred required application of SFAS No. 123(R) until the first fiscal interim or annual reporting period of the first fiscal year beginning on or after June 15, 2005. The standard requires use of either the “modified prospective method” or the “modified retrospective method.” Under the modified prospective method, compensation cost is recognized for all awards granted after adoption of the standard and for the unvested portion of previous grant awards that are outstanding on that date. The modified retrospective method is used to recognize compensation cost for prior periods whereby previously issued financial statements must be restated to recognize the amounts we previously calculated and reported on a pro forma basis. Under both methods, the standard permits the use of either a straight-line or an accelerated method to amortize the cost as an expense for awards that vest over time. The standard permits and encourages early adoption.

Management has commenced analysis of the impact of this statement, but has not yet decided: (1) whether to elect early adoption, (2) if early adoption is elected, at what date to adopt the standard, (3) whether to use the modified prospective method or elect to use the modified retrospective method, and (4) whether to use straight-line amortization or an accelerated method. Additionally management cannot predict with reasonable certainty the number of options that will be unvested and outstanding on December 31, 2005. Accordingly, the effect of this standard would have on the Company’s financial position or results of operations in the future cannot be currently quantified with precision, except that a greater expense will probably be recognized for any awards granted in the future.

The FASB issued FASB Interpretation No. 47 (“FIN 47”),Accounting for Conditional Asset Retirement Obligations, in March 2005. FIN 47 clarifies that the term ‘conditional asset retirement obligation’ as used is SFAS No. 143,Accounting for Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Under FIN 47, the fair value of a liability for a conditional asset retirement obligation should be recognized when incurred. SFAS No. 143 notes that in some cases, sufficient information may not be available to reasonably estimate the fair value of the asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Management is analyzing FIN 47 and believes there will not be any significant impact on the financial position, results of operations or cash flows of the Company.

In September 2004, the SEC issued Staff Accounting Bulletin No. 106. This pronouncement requires companies that use the full cost method of accounting for oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. It also requires full cost companies to exclude any cash outflows associated with settling asset retirement obligations from their full cost ceiling test calculation. In addition, it requires specific disclosures regarding the impact of asset retirement obligations on oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. The Company adopted the provisions of this pronouncement in the first quarter of 2005. This statement has had no effect on the Company’s financial position, results of operations or cash flows.

The FASB issued SFAS No. 154,Accounting Changes and Error Corrections – a replacement of APB Opinion No. 20 and FASB Statement No. 3 in May 2005. The statement changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the instance that the pronouncement does not include specific transition provisions. This statement should not have any impact on the Company’s financial position, results of operations or cash flows.

2. ASSET RETIREMENT OBLIGATIONS

The Company records the fair value of the liability for asset retirement obligations 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

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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.

During the six-month periods ended June 30, 2005 and 2004, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the consolidated statement of income for the period. There have not been any revisions to either the timing or the amount of the original estimate of undiscounted cash flows during 2005. At June 30, 2005 and December 31, 2004, retirement obligations classified as current were $0.5 million.

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the six-month periods ended June 30, 2005 and 2004.

	Six Months Ended June 30,
	2005			2004
	(in thousands)
Beginning asset retirement obligation	$	18,471		$	15,189
Change in estimated retirement costs		—			2,479
Additional liability incurred		474			774
Accretion expense		552			448
Asset retirement costs incurred		(77	)		(86	)
Loss on settlement of liability		14			15
Currency translation adjustment		(80	)		(53	)
Ending asset retirement obligation	$	19,354		$	18,766

3. HEDGING

The estimated fair values of all hedge derivatives and the associated fixed price firm sale and purchase commitments as of June 30, 2005 and December 31, 2004 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. The assets and liabilities recorded in the balance sheet are netted where derivatives with both gain and loss positions are held by a single third party.

	June 30, 2005		December 31, 2004
	(in thousands)
Derivative assets:
Floating price natural gas financial swaps	$	49	$	—
Crude oil financial collars		—		106
Fixed price sale commitments		—		314
Fixed price natural gas financial swaps		606		—
Natural gas financial collars		—		3,563
	$	655	$	3,983
Derivative liabilities:
Fixed price natural gas financial swaps	$	—	$	12,066
Floating price natural gas financial swaps		—		322
Fixed price sale commitments		26		—
Crude oil financial collars		977		5
Natural gas financial collars		4,258		158
Floating to fixed interest rate swap		—		233
	$	5,261	$	12,784

The fair values of all natural gas and crude oil financial instruments and firm sale and purchase commitments as of June 30, 2005 and December 31, 2004 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.

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At June 30, 2005, derivative assets of $0.6 million and derivative liabilities of $3.6 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $1.9 million of after-tax losses will be reclassified from other comprehensive income over the next twelve months.

4. LONG-TERM DEBT

Long-term debt consists of:

	June 30, 2005			December 31, 2004
	(in thousands)
Senior secured credit facility	$	237,606		$	180,422
Contingently convertible debentures, net of unamortized discount		147,825			147,769
Second mortgage notes payable		70,000			70,000
Other loans		913			1,073
Deferred gain – fair value interest hedge		172			226
		456,516			399,490
Less current maturities		(356	)		(356	)
	$	456,160		$	399,134

As of June 30, 2005, the Company’s borrowing base under its senior secured credit facility was $400 million, of which approximately $161.2 million was available for borrowing. The loan agreements for the senior credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion, amortization, non-cash income and expense and exploration costs) to interest ratio. The Company was in compliance with all such restrictions at June 30, 2005.

Effective June 25, 2005, the fifth amendment to the second note purchase agreement was completed. Included in the amendment to the note purchase agreement was a change to the floating interest rate. Under the amendment, the $30 million of variable rate notes will bear interest at a variable annual rate based upon the three-month LIBOR rate plus 4.06%, a decrease from the previous variable annual rate of three-month LIBOR rate plus 5.48%. The $40 million fixed rate notes continue to bear interest at the fixed rate of 7.5% per annum. Additionally, the Second Mortgage Notes contain restrictive covenants, which, among other things, require maintenance of a minimum current ratio of at least 1.0, a ratio of net present value of proved reserves to total debt of at least 1.8 to 1.0, and a ratio of earnings before interest, taxes, depreciation, depletion and amortization, non-cash income and expense to interest expense (consolidated net interest expense and current maturities of debt) of at least 1.25 (calculated in accordance with provisions of the Second Mortgage Notes). The Company was in compliance with all such restrictions at June 30, 2005.

On September 11, 2003, the Company entered into a fair value interest swap covering $40 million of the fixed rate Second Mortgage Notes. The swap converted the debt’s 7.5% fixed-rate to a floating six-month LIBOR base rate plus 4.07% through the termination of the notes. In January 2004, the swap position was cancelled, and the Company received $0.3 million. The gain on the swap settlement will be recognized over the period remaining to the original maturity date of the swap, December 31, 2006.

5. COMMITMENTS AND CONTINGENCIES

On October 6, 2004, Quicksilver entered into an Incentive Arrangements Agreement (the “Agreement”) with three executives of the Company’s Canadian subsidiary, MGV Energy Inc., and one employee of Quicksilver. The Agreement provides for the amendment and restatement of employment agreements with two MGV executives and terminates incentive agreements with the other two individuals. The Agreement provides for awards of cash bonuses based upon the achievement of specified proved reserve targets, as well as options granted under the Company’s Amended and Restated 1999 Stock Option and Retention Stock Plan covering 1,775,135 shares of common stock at an exercise price of $20.85. In addition, the agreement provides for payment of $4.0 million no later than January 1, 2006 as compensation for a two-year non-compete period to commence at the date an individual executive or employee should end their employment with MGV or QRI. The cash bonuses, in the aggregate, will be determined as a base amount of $5.0 million for achieving proved reserves of 400 billion cubic feet equivalent (Bcfe) at December 31, 2005 as determined by third party reserve engineers. Proved reserves in excess of 400 Bcfe, but not exceeding 1,000 Bcfe, will increase the cash bonuses earned by $0.05 per Mcfe. Presently, the Company has not recognized an obligation for the cash bonuses; however, 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 estimable.

11

In August 2001, a group of royalty owners, Athel E. Williams et al., brought suit against the Company and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of Quicksilver’s subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. The court heard arguments on class certification on November 8, 2002, and on December 6, 2002 the court issued a memorandum opinion granting class certification in part and denying it in part. On December 20, 2002, the Company filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. After an extended delay resulting from the retention of new counsel by the plaintiffs and the initiation of settlement discussions, on January 21, 2005, the Circuit Court issued an order certifying certain claims to proceed on behalf of a class. The Circuit Court also entered a scheduling order setting trial for January 2007, and declined Defendants’ request to stay proceedings in that court pending an appeal of the certification order.

Defendants have sought leave to appeal the certification order by filing an Application for Leave to Appeal on February 11, 2005 with the Michigan Court of Appeals. Defendants have also requested that the Court of Appeals stay proceedings in the Circuit Court pending the consideration of its appeal, and have requested that the Court of Appeals consider all matters in an expedited manner. On April 22, 2005, the Court of Appeals vacated the certification order and remanded the case to the trial court with instructions to address several particular issues by way of a new order. After limited discovery relating to those issues, the trial court held a follow-up certification hearing on June 1, 2005. The Company is currently awaiting a ruling from the trial court on the certification motion, and the case (including the appeal) is stayed in the meantime.

Based on information currently available to the Company, the Company’s management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations, or cash flows.

6. STOCKHOLDERS’ EQUITY

Quicksilver has two stock-based compensation plans, the Amended and Restated 1999 Stock Option and Stock Retention Plan and the Amended and Restated 2004 Non-Employee Director Equity 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.

Stock Options

On January 3, 2005, the non-employee directors of the Company received options to purchase a total of 11,654 shares of stock at a strike price of $23.42. Additional options to purchase 2,456 shares at a stock price of $32.89 were granted to a newly appointed non-employee a director of the Company on March 8, 2005. No compensation expense was recognized at the dates of grant, as the exercise price was equal to the market value of the common stock at the dates of grant.

Restricted Stock Grants

Executive officers received a grant of 50,473 restricted shares, valued at $29.67 per share, on February 9, 2005. The Company also granted 7,488 restricted shares, valued at $33.19 per share, to executive officers of MGV on February 28, 2005. On April 21, 2005, all other employees of Quicksilver were granted restricted shares totaling 78,040 shares valued at $35.64 while MGV employees received 23,212 restricted stock units. The restricted stock and restricted stock units grants provide for vesting at a rate of one-third per year over the proceeding three years and immediate vesting for employees retiring with five or more years of service with the Company and at least 55 years of age. On May 17, 2005, the non-employee directors of the Company received a grant of 2,960 restricted shares valued at $33.80 per share. These restricted shares will become fully vested one year from the date of grant provided the non-employee director remains a member of the Board of Directors of the Company. Expense for the grants of restricted stock was initially recorded as deferred compensation on the consolidated balance sheet and has been recognized as vested in the consolidated statement of operations from the date of grant.

7. RELATED PARTY TRANSACTIONS

As of June 30, 2005, members of the Darden family, Mercury Exploration Company and Quicksilver Energy L.P., entities that are owned by members of the Darden family, 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 associated entities paid $0.4 million for rent during each of the six-month periods ended June 30, 2005 and 2004 for office space in buildings which are owned by Pennsylvania Avenue Limited Partnership, a partnership owned by members of the Darden family and Mercury. 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 and property, plant and equipment costs incurred (purchases of property, plant and equipment plus noncash changes in working capital related to the acquisition of property, plant and equipment).

For the Three Months Ended	United States		Canada		Corporate			Consolidated
	(in thousands)
June 30, 2005
Revenues	$	48,351	$	20,189	$	—		$	68,540
Depletion, depreciation and accretion		8,604		4,267		146			13,017
Operating income		22,874		11,916		(4,764	)		30,026
Property, plant and equipment costs incurred		53,447		23,286		289			77,022
June 30, 2004
Revenues	$	33,006	$	8,974	$	—		$	41,980
Depletion, depreciation and accretion		7,786		1,860		68			9,714
Operating income		11,838		4,755		(3,421	)		13,172
Property, plant and equipment costs incurred		23,231		24,140		45			47,416
For the Six Months Ended	United States		Canada		Corporate			Consolidated
	(in thousands)
June 30, 2005
Revenues	$	83,625	$	40,164	$	—		$	123,789
Depletion, depreciation and accretion		16,522		8,572		295			25,389
Operating income		33,707		24,288		(8,026	)		49,969
Property, plant and equipment costs incurred		84,068		49,766		296			134,130
June 30, 2004
Revenues	$	65,091	$	16,666	$	—		$	81,757
Depletion, depreciation and accretion		15,118		3,515		186			18,819
Operating income		22,663		8,716		(6,195	)		25,184
Property, plant and equipment costs incurred		43,741		43,517		75			87,333
Fixed Assets - net
June 30, 2005	$	648,294	$	256,823	$	1,802		$	906,919
December 31, 2004	$	581,575	$	219,369	$	1,666		$	802,610

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

Forward-Looking Information

Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. 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 reflect our views, assumptions and current expectations with respect to future events, outcomes, results or performance. Words such as “may,” “could,” “should,” “assume,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “project,” “forecast,” “budget,” “strategy,” “predict,” “potential,” “continue,” or “future,” and similar expressions are used to identify forward-looking statements. Forward-looking statements can be affected by assumptions upon which they are based and by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual events, outcomes, results or performance may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and you should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause actual events, outcomes, results or performance to differ materially from the results contemplated by such forward-looking statements, or which could otherwise materially affect our financial condition, results of operations or cash flows, include:

• changes in general economic conditions;

• fluctuations in natural gas and crude oil prices;

• failure or delays in achieving expected production from natural gas and crude oil exploration and development projects;

• uncertainties inherent in estimates of natural gas and crude oil reserves and predicting natural gas and crude oil 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, weather-related delays, 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/A for the year ended December 31, 2004.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

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RESULTS OF OPERATIONS

Summary Financial Data

Three Months Ended June 30, 2005 Compared with the Three Months Ended June 30, 2004

	Three Months Ended June 30,
	2005		2004
	(in thousands)
Total operating revenues	$	68,540	$	41,980
Total operating expenses		38,729		29,097
Operating income		30,026		13,172
Net income		17,185		7,500

We recorded net income of $17.2 million ($0.21 per diluted share) for the three months ended June 30, 2005, compared to net income of $7.5 million ($0.10 per diluted share) for the second quarter of 2004.

Operating Revenues

Revenues for the second quarter of 2005 were $68.5 million; a $26.5 million increase from the $42.0 million reported for the three months ended June 30, 2004. Production revenue increased $26.2 million as a result of a 17% increase in sales volumes and a 39% increase in realized sales prices.

Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the three months ended June 30, 2005 and 2004 are as follows:

	Three Months Ended June 30,
	2005		2004
Natural gas, oil and NGL sales (in thousands)
United States	$	47,777	$	32,629
Canada		20,066		8,971
Total	$	67,843	$	41,600
Product sale revenues (in thousands)
Natural gas sales	$	59,913	$	34,812
Crude oil sales		6,425		6,030
NGL sales		1,505		758
Total	$	67,843	$	41,600
Average daily sales volume
Natural gas – Mcfd
United States		87,596		83,046
Canada		37,985		20,165
Total		125,581		103,211
Crude oil – Bbld
United States		1,569		2,032
Canada		—		—
Total		1,569		2,032
NGL – Bbld
United States		486		363
Canada		11		1
Total		497		364
Total sales – Mcfed
United States		99,914		97,409
Canada		38,061		20,177
Total		137,975		117,586

15

	Three Months Ended June 30,
	2005		2004
Unit prices - including impact of hedges
Natural gas - per Mcf
United States	$	5.00	$	3.42
Canada		5.80		4.88
Consolidated		5.24		3.71
Crude oil - per Bbl
United States	$	45.01	$	32.62
Canada		—		—
Consolidated		45.01		32.62
NGL - per Bbl
United States	$	33.14	$	22.71
Canada		39.03		55.38
Consolidated		33.27		22.85

Natural gas sales of $59.9 million for the second quarter of 2005 were 72% higher than the $34.8 million for the 2004 second quarter. Second quarter 2005 natural gas revenue increased by $14.4 million as a result of a $1.54 per Mcf increase in the average sales price. The termination of our $2.79 per Mcf fixed-swaps as of April 30, 2005 resulted in a $7.1 million increase in revenue compared to the 2004 period. Natural gas revenue also increased $10.7 million because of a 22% increase in sales volumes as compared to the second quarter of 2004. Production from our coal bed methane (“CBM”) projects and conventional properties in Canada increased for the second quarter of 2005 by approximately 2,308,000 Mcf from the 2004 second quarter as a result of new wells placed into production since June 30, 2004. Natural production declines partially offset the Canadian production increases. New productive wells in the Barnett Shale and New Albany Shale increased sales volumes by approximately 620,000 Mcf and 179,000 Mcf, respectively, for the second quarter of 2005 compared to the second quarter of 2004. Michigan natural gas volumes included about 194,000 Mcf from Antrim wells and nearly 98,000 Mcf from Prairie du Chien wells placed into production after the second quarter of 2004. Antrim Shale interests purchased in the third quarter of 2004 added approximately 62,000 Mcf of natural gas sales volumes during the second quarter of 2005 while volumes from our Michigan Niagaran wells increased nearly 32,000 Mcf as a result of work performed on those wells. These U.S. production increases were partially offset by natural production declines.

Crude oil sales were $6.4 million for the three months ended June 30, 2005 compared to $6.0 million in the second quarter of 2004. Lower production reduced revenue by $1.9 million compared to the prior year quarter. The absence of production from Wyoming and Michigan crude oil properties sold in the third quarter of 2004 lowered volumes by about 54,000 barrels for the second quarter of 2005. Work performed on our Niagaran wells in Michigan increased crude oil production by over 2,200 barrels in the second quarter of 2005. The average crude oil sales price for the second quarter of 2005 was $45.01 per Bbl compared to $32.62 per Bbl in the second quarter of 2004. Higher sales prices increased revenue by $2.3 million.

Operating Expenses

Second quarter operating expenses for 2005 were $38.7 million; an increase of $9.6 million over the $29.1 million of expenses incurred in the second quarter of 2004.

Oil and Gas Production Costs

	Three Months Ended June 30,
	2005		2004
	(in thousands, except per unit amounts)
Production expenses
United States	$	16,346	$	13,299
Canada		4,006		2,359
Total	$	20,352	$	15,658
Production expenses – per Mcfe
United States	$	1.80	$	1.51
Canada		1.16		1.29
Consolidated		1.62		1.46

16

Oil and gas production costs were $20.4 million for the 2005 second quarter. The $4.6 million increase over the prior year quarter included a $1.6 million increase in Canadian production costs. Canadian production increased approximately 1,630,000 Mcfe, net, primarily as a result of CBM and conventional wells drilled since the second quarter of 2004. Canadian production expenses decreased $0.13 per Mcfe to $1.16 per Mcfe as a result of the improving economies of scale.

Oil and gas production costs for U.S. operations increased $3.0 million from the prior year quarter to $16.3 million for the second quarter of 2005. Production expenses for Barnett Shale wells placed into production over the past twelve months resulted in $1.7 million of the increase from the 2004 second quarter. Transportation and processing costs for Barnett Shale natural gas production were $1.1 million for the second quarter of 2005. Additionally, costs for labor and water disposal increased almost $0.5 million. These well costs are typically greater when production begins as initial production includes high water rates from the fracture stimulations and well operations require greater monitoring. These operating costs for each well will decrease following a period of initial production. Production expenses in Michigan increased approximately $1.6 million from the 2004 period. Environmental compliance expense of $0.8 million was the primary reason for the increase. Compressor overhauls cost and repairs and maintenance expense also increased by nearly $0.5 million. The number of compressors undergoing routine, periodic overhauls was greater in the current year quarter. Partially offsetting these increases was a $0.6 million decrease in production expense that resulted from the 2004 third quarter sale of Wyoming crude oil properties. These items increased U.S. production expense by approximately $0.32 per Mcfe for the second quarter of 2005.

Depletion, Depreciation and Accretion

	Three Months Ended June 30,
	2005		2004
	(In thousands, except per unit amounts)
Depletion	$	10,860	$	8,232
Depreciation of other fixed assets		1,875		1,252
Accretion		282		230
Total depletion, depreciation and accretion	$	13,017	$	9,714
Average depletion cost per Mcfe	$	0.86	$	0.77

Second quarter 2005 depletion of $10.9 million was $2.6 million higher than depletion for the 2004 quarter primarily as a result of an increase in the depletion rate as well as additional sales volumes. Our depletion rate increased over the prior year period as a result of the significant capital expenditures and proved reserves added for our Canadian CBM and Texas Barnett Shale properties.

General and Administrative Expense

General and administrative costs incurred during the three months ended June 30, 2005 were $4.6 million. The $1.3 million increase over second quarter of 2004 expense was primarily the result of a $1.0 million increase in personnel costs, which included approximately $0.3 million of expense for restricted stock grants. In addition, legal costs for corporate governance and debt agreements were approximately $0.5 million higher for the quarter ended June 30, 2005.

Interest Expense

Interest expense for the second quarter of 2005 was $4.8 million net of capitalized interest of $0.5 million, an increase of $1.1 million compared to the second quarter of 2004. Interest expense increased as a result of higher debt levels in 2005. Capitalized interest recorded in 2005 was associated with the construction of transportation and processing facilities in the Barnett Shale and in Canada.

Income Tax Expense

Our provision for income taxes increased $6.1 million from the prior year period as a result of higher pretax income for the second quarter of 2005. Our U.S. income tax provision of $5.2 million was established using the statutory U.S. federal rate of 35%. The Canadian tax provision of approximately $2.9 million was accrued at a Canadian combined federal and provincial statutory rate of 33.6% and included a current tax provision of $0.1 million.

17

Summary Financial Data

Six Months Ended June 30, 2005 Compared with the Six Months Ended June 30, 2004

	Six Months Ended June 30,
	2005		2004
	(in thousands)
Total operating revenues	$	123,789	$	81,757
Total operating expenses		74,259		57,153
Operating income		49,969		25,184
Net income		27,939		13,437

We recorded net income of $27.9 million ($0.35 per diluted share) for the six months ended June 30, 2005, compared to net income of $13.4 million ($0.18 per diluted share) for the first half of 2004.

Operating Revenues

Revenues for the first half of 2005 were $123.8 million, a $42.0 million increase from the $81.8 million reported for the six months ended June 30, 2004 as a result of a 16% increase in sales volumes and a 31% increase in realized sales prices.

Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the three months ended June 30, 2005 and 2004 are as follows:

	Six Months Ended June 30,
	2005		2004
Natural gas, oil and NGL sales (in thousands)
United States	$	82,935	$	64,066
Canada		39,748		16,658
Total	$	122,683	$	80,724
Product sale revenues (in thousands)
Natural gas sales	$	107,781	$	67,845
Crude oil sales		12,341		11,229
NGL sales		2,561		1,650
Total	$	122,683	$	80,724
Average daily sales volume
Natural gas – Mcfd
United States		85,778		82,878
Canada		38,673		19,403
Total		124,451		102,281
Crude oil – Bbld
United States		1,498		2,038
Canada		—		—
Total		1,498		2,038
NGL – Bbld
United States		420		379
Canada		7		1
Total		427		380
Total sales – Mcfed
United States		97,282		97,373
Canada		38,722		19,420
Total		136,004		116,793

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	Six Months Ended June 30,
	2005		2004
Unit prices - including impact of hedges
Natural gas - per Mcf
United States	$	4.38	$	3.39
Canada		5.67		4.71
Consolidated		4.78		3.64
Crude oil - per Bbl
United States	$	45.51	$	30.27
Canada		—		—
Consolidated		45.51		30.27
NGL - per Bbl
United States	$	33.05	$	23.72
Canada		38.29		41.76
Consolidated		33.13		23.83

Natural gas sales of $107.8 million for the first half of 2005 were 59% higher than the $67.8 million for the 2004 period. Six-month 2005 gas revenue increased $21.2 million as a result of a $1.19 per Mcf increase in the average sales price, which included a $7.1 increase due to the expiration of our $2.79 per Mcf natural gas swaps as of April 2005. A 21% increase in sales volumes added $18.7 million of revenue for the first half of 2005 as compared to the first six months of 2004. Production from our coal bed methane (“CBM”) projects and conventional properties in Canada increased for the first half of 2005 by approximately 4,595,000 Mcf from the 2004 period as a result of new wells placed into production. Natural production declines partially offset the Canadian production increases. New productive wells in the Texas Barnett Shale and New Albany Shale increased sales volumes by approximately 950,000 Mcf and 460,000 Mcf, respectively, for the first half of 2005 compared to the 2004 period. Michigan natural gas volumes included 396,000 Mcf from Antrim wells and 237,000 Mcf from Prairie du Chien wells placed into production since June of 2004. Antrim Shale interests purchased in the third quarter of 2005 added approximately 123,000 Mcf of natural gas volumes during the first half of 2005 while work performed on our Niagaran wells increased production by 64,000 Mcf. These U.S. production increases were partially offset by natural production declines.

Crude oil sales were $12.3 million for the six months ended June 30, 2005 compared to $11.2 million in the first half of 2004. The average crude oil sales price for the first half of 2005 was $45.51 per Bbl compared to $30.27 per Bbl in the 2004 period. The increase in sales prices increased revenue $5.6 million. Lower production reduced revenue $4.5 million compared to the prior year. The absence of production from Wyoming and Michigan crude oil properties sold in the third quarter of 2004 lowered volumes by approximately 105,000 barrels for the first six months of 2005 and was partially offset by a 7,000 barrel increase from Niagaran wells in Michigan.

Operating Expenses

Operating expenses for the first half of 2005 were $74.3 million; an increase of $17.1 million over the $57.1 million of expenses incurred in the first half of 2004.

Oil and Gas Production Costs

	Six Months Ended June 30,
	2005		2004
	(in thousands, except per unit amounts)
Production expenses
United States	$	32,702	$	27,228
Canada		7,304		4,435
Total	$	40,006	$	31,663
Production expenses – per Mcfe
United States	$	1.86	$	1.54
Canada		1.04		1.25
Consolidated		1.63		1.49

Oil and gas production costs were $40.0 million for the 2005 six-month period. The $8.3 million increase over the prior period included a $2.9 million increase in Canadian production costs. Canadian production increased approximately 3,475,000 Mcfe, net, primarily as a result of new CBM and conventional wells placed into production. Canadian production expenses decreased $0.21 per Mcfe to $1.04 per Mcfe as a result of the improving economies of scale.

19

U.S. production expenses increased $5.4 million for the first six months of 2005 compared to the prior year period. Operating expenses for Barnett Shale wells increased production expenses approximately $2.6 million. Transportation and processing costs for natural gas production from the Barnett Shale were $1.4 million for the first half of 2005. Additionally, costs for labor and water disposal increased almost $0.9 million. Initial operating expenses for water disposal and labor are typically greater when production begins as initial production includes high water production from the fracture stimulations. Operating costs for each well tend to decrease following a period of initial production. In Michigan, compressor overhauls, workovers and repair and maintenance increased production expense $1.7 million for the first half of 2005. The number of compressors undergoing routine, periodic overhauls was greater in the current year. Additional expense of $0.9 million was incurred in 2005 for environmental compliance in Michigan and Indiana. The producing well count for Michigan, Indiana and Kentucky increased from the 2004 period and also contributed to higher operating expenses. Partially offsetting these increases was a $1.2 million decrease in Wyoming production expense as a result of the 2004 third quarter sale of Wyoming crude oil properties. These items increased U.S. production expenses by approximately $0.29 per Mcfe for the first half of 2005.

Depletion, Depreciation and Accretion

	Six Months Ended June 30,
	2005		2004
	(In thousands, except per unit amounts)
Depletion	$	21,598	$	15,935
Depreciation of other fixed assets		3,238		2,436
Accretion		553		448
Total depletion, depreciation and accretion	$	25,389	$	18,819
Average depletion cost per Mcfe	$	0.88	$	0.75

Six-month 2005 depletion of $21.6 million was $5.7 million higher than depletion for the 2004 period primarily as a result of an increase in the depletion rate as well as additional sales volumes. Our depletion rate increased over the prior year period as a result of the significant capital expenditures and proved reserves added for our Canadian CBM and Texas Barnett Shale properties.

General and Administrative Expense

General and administrative costs incurred during the six months ended June 30, 2005 were $7.7 million. The $1.7 million increase over 2004 expense was primarily the result of a $0.8 million increase in legal and accounting fees due largely to compliance with Sarbanes-Oxley, corporate governance and debt agreements, $0.7 million for additional salary and benefit expense, and $0.3 million of expense recorded for restricted stock granted to employees and executives in the first and second quarters.

Interest Expense

Interest expense for the first half of 2005 was $9.4 million, after interest capitalization of $0.5 million; an increase of $2.4 million compared to the first half of 2004. Interest expense increased as a result of higher debt levels in 2005; however, a decrease in our overall effective interest rate partially offset that increase. The decrease in our effective interest rate was the result, in part, of the 1.875% interest rate borne by our $150.0 million contingently convertible debentures issued in November 2004. Capitalized interest recorded in 2005 was associated with the construction of transportation and processing facilities in the Barnett Shale of Texas and in Canada.

Income Tax Expense

Our provision for income taxes increased $8.0 million from the prior year period as a result of higher pretax income for the first six months of 2005. Our U.S. income tax provision of $6.9 million was established using the statutory U.S. federal rate of 35%. The Canadian tax provision of approximately $5.9 million was accrued at a Canadian combined federal and provincial statutory rate of 33.6% and included a current tax provision of $0.2 million.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Net cash from operations was $61.1 million for the six months ended June 30, 2005, an increase of $22.5 million compared to the same period in 2004. Operating income of $50.0 million was $24.8 million higher from the 2004 six-month period primarily as a result of a 16% increase in sales volumes and a 31% increase in realized prices. A portion of the increase in realized prices resulted from the April expiration of our $2.79 per Mcf fixed-price natural gas swaps.

20

Additionally, non-cash expenses for depletion, depreciation and amortization and deferred tax expense increased for 2005, but were partially offset by the use of working capital associated with higher operations activities. Interest expense for the first half of 2005 was $2.4 million higher than the 2004 period. The additional interest expense resulted from debt incurred to fund our capital budget.

Our principal sources of cash include sales of natural gas, crude oil and NGLs and revenues from natural gas transportation and processing. We sold approximately 20% of our natural gas production using price swaps with an average price of $2.79 per Mcf and an additional 24% of our natural gas production was sold under long-term contracts with price floors. Additionally, price collars covered 23% of our 2005 production. The $2.79 per Mcf fixed-price swaps have been replaced with hedges covering shorter terms. Our current hedges include fixed-price swaps covering 15,000 Mcfd of our U.S. natural gas sales at $7.35 per Mcf for the months of July through October 2005, and price collars hedging approximately 23,000 Mcfd and 27,000 Mcfd of U.S. and Canadian production, respectively, for the remainder of 2005. These U.S. and Canadian price collars have weighted average price floors of $6.50 per Mcf and $6.25 per Mcf, respectively, and weighted average price caps of $8.48 per Mcf and $8.86 per Mcf, respectively. An average of approximately 26,000 Mcfd and 19,000 Mcfd of our 2006 projected gas sales for the U.S. and Canada, respectively, have been hedged using price collars with average price floors of $6.88 per Mcf and $6.63 per Mcf, respectively, and cap prices of $8.98 per Mcf and $9.51 per Mcf, respectively.

In the first half of 2005, we purchased $132.5 million of property, plant and equipment, an increase of $47.4 million when compared to the first six months of 2004. Property, plant and equipment costs incurred (purchases of property, plant and equipment plus noncash changes in working capital related to the acquisition of property, plant and equipment) for the 2005 period totaled $134.1 million, which consisted of $118.2 million expended for exploration and development activities and $14.3 million expended for construction of the Cowtown Pipeline’s first phase and a gas processing plant in Hood County, Texas. Of the $69.1 million incurred for U.S. exploration and development, $57.8 million was incurred in Texas, including $14.5 million for leasehold acquisitions.

	Six Months Ended June 30, 2005
	(in thousands)
Exploration and development
United States	$	69,149
Canada		49,123
Total exploration and development		118,272
Gas processing/transportation and other		15,858
Total property, plant and equipment costs incurred	$	134,130

Net cash provided by financing activities for the six months ended June 30, 2005 was $61.0 million. During the first half of 2005, we increased borrowings under our senior credit facility by $59.8 million. We also received $1.5 million in proceeds from the exercise of employee stock options. As of June 30, 2005, we had approximately $161.2 million of borrowing capacity available under our $400 million senior credit facility, and we were in compliance with the restrictive covenants contained in our senior credit facility.

Effective June 25, 2005, the fifth amendment to the second mortgage note purchase agreement was completed. Included in the amendment to the note purchase agreement was a change to the floating interest rate. Under the amendment, the $30 million of variable rate notes will bear interest at a variable annual rate based upon the three-month LIBOR rate plus 4.06%, a decrease from the previous variable annual rate of three-month LIBOR rate plus 5.48%. The $40 million fixed rate notes continue to bear interest at the fixed rate of 7.5% per annum. We were in compliance with all covenants contained in the second mortgage notes payable at June 30, 2005.

As of June 30, 2005 and December 31, 2004, our total capitalization was as follows:

	June 30, 2005		December 31, 2004
	(in thousands)
Senior secured credit facility	$	237,606	$	180,422
Convertible subordinated debentures		147,825		147,769
Second mortgage notes payable		70,000		70,000
Other loans		913		1,073
Deferred gain – fair interest hedge		172		226
Total debt		456,516		399,490
Stockholders’ equity		340,599		304,276
	$	797,115	$	703,766

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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 no-cost collars and fixed price swaps. We sell approximately 25,000 Mcfd and 10,000 Mcfd of natural gas for floor prices of $2.49 per Mcf and $2.47 per Mcf, respectively, under long-term contracts that extend through March 2009. Approximately 4,900 Mcfd sold under these contracts during the first six months of 2005 were third party volumes controlled by us.

Equity natural gas volumes of approximately 15,000 Mcfd and 5,000 Mcfd are hedged for the third and fourth quarters of 2005, respectively, using fixed price swap agreements. We have also used price collars to hedge natural gas volumes of approximately 40,000 Mcfd and 60,000 Mcfd, respectively, for the third and fourth quarters of 2005. We have hedged our crude oil production with price collars hedging 750 Bbld for the remainder of the year.

Price collars have been put in place to hedge 2006 U.S. production of approximately 24,000 Mcfd and Canadian production of approximately 18,000 Mcfd. U.S. natural gas production of approximately 10,000 Mcfd has also been hedged for the first quarter of 2007 using price collars.

The following table summarizes our open financial hedge positions as of June 30, 2005 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	Swap	Jul 2005-Oct 2005	10,000 Mcfd	$7.35	$	400
Gas	Swap	Jul 2005-Oct 2005	5,000 Mcfd	7.36		206
Gas	Collar	Jul 2005-Oct 2005	10,000 Mcfd	5.50– 6.75		(561	)
Gas	Collar	Jul 2005-Oct 2005	5,000 Mcfd	5.50– 6.75		(280	)
Gas	Collar	Jul 2005-Oct 2005	15,000 Mcfd	5.50– 7.15		(465	)
Gas	Collar	Jul 2005-Oct 2005	5,000 Mcfd	6.50– 8.15		35
Gas	Collar	Jul 2005-Oct 2005	5,000 Mcfd	6.50– 8.22		36
Gas	Collar	Nov 2005-Mar 2006	10,000 Mcfd	6.50-11.20		(52	)
Gas	Collar	Nov 2005-Mar 2006	10,000 Mcfd	6.50-11.20		(52	)
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.00-10.00		(136	)
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.00-10.00		(136	)
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.00-10.10		(83	)
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.00-10.17		(48	)
Gas	Collar	Nov 2005-Mar 2006	10,000 Mcfd	7.50– 9.55		(142	)
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.50– 9.55		(71	)
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.50– 9.60		(63	)
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.50-10.55		69
Gas	Collar	Nov 2005-Mar 2006	5,000 Mcfd	7.50-10.60		74
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	5.50– 8.10		(532	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	5.50– 8.25		(487	)
Gas	Collar	Apr 2006-Oct 2006	10,000 Mcfd	6.50– 8.25		(605	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	6.50– 8.25		(302	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00– 8.35		(87	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00– 8.35		(87	)
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd	7.00– 8.35		(87	)
Gas	Collar	Nov 2006-Apr 2007	10,000 Mcfd	7.50– 9.65		(195	)
Oil	Collar	Jul 2005-Dec 2005	250 Bbld	38.00-47.75		(507	)
Oil	Collar	Jul 2005-Jun 2006	500 Bbld	47.00-62.20		(470	)
				Total	$	(4,628	)

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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 7,500 Mcfd and 9,000 Mcfd are committed at market price through Decenber 2007 and September 2008, respectively. Approximately 14,700 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. The following table summarizes our open financial derivative positions and hedged firm commitments as of June 30, 2005 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 2005-Oct 2005	1,129 Mcfd	$	6.83	$	(26	)
Financial derivatives
Gas	Floating Price	Jul 2005-Oct 2005	1,138 Mcfd				49
					Total-net	$	23

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 $13.3 million and $21.0 million lower as a result of the hedging programs for the first half of 2005 and 2004, respectively. Marketing revenue was $0.3 million lower and $0.3 million higher as a result of hedging activities in the first half of 2005 and 2004, respectively.

Interest Rate Risk

Our interest rate swap covering $75.0 million notional variable-rate debt ended on March 31, 2005. The interest rate swap converted a floating three-month LIBOR base to a 3.74% fixed-rate.

We closed an interest rate swap hedging $40.0 million of fixed-rate second lien notes in January 2004. We received a cash settlement of $0.3 million that will continue to be recognized over the period remaining to original maturity date for the swap, December 31, 2006.

Interest expense was $0.2 million lower and $0.5 million higher, respectively, for the six months ended June 30, 2005 and 2004 as a result of our interest hedging activities.

ITEM 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Securities Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the second quarter of 2005, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us (including our consolidated subsidiaries) in reports that we file or submit under the Securities Exchange Act is recorded, processed, summarized and reported on a timely basis.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended June 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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 held on May 17, 2005. 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 2008 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
Thomas F. Darden	48,015,444	536,524
Mark J. Warner	48,298,275	253,693

Glenn Darden, James Hughes, Steven Morris, Anne Darden Self and W. Yandell Rogers, III continue to serve as directors of the Company.

Ratification of Appointment of Independent Registered Accounting Firm

At the meeting, the stockholders ratified the appointment by the Company’s Audit Committee of Deloitte & Touche as our independent registered accounting firm for fiscal year ending December 31, 2005. The vote on such proposal was as follows:

For	48,421,265
Against	15,432
Abstentions	5,293

Amended and Restated 2004 Non-Employee Director Equity Plan

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

For	43,015,779
Against	540,709
Abstentions	39,410

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ITEM 6. Exhibits:

Exhibit No.	Description
10.1	Fourth Amendment to Note Purchase Agreement, dated as of April 12, 2005, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, collateral agent, and the purchasers identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference)
10.2	Fifth Amendment to Note Purchase Agreement, dated as of June 24, 2005, among Quicksilver Resources Inc., certain of its subsidiaries listed therein, BNP Paribas, collateral agent, and the purchasers identified therein (filed as Exhibit 10.2 to the Company’s Form 8-K filed June 28, 2005 and included herein by reference)
10.3	Third Amendment to Combined Credit Agreements, dated as of June 17, 2005, among Quicksilver Resources Inc., MGV Energy Inc. and the agents and combined lenders identified therein (filed as Exhibit 10.1 to the Company’s Form 8-K filed June 28, 2005 and included herein by reference)
10.4	Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference)
10.5	Form of Retention Share Agreement for the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.3 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference)
10.6	Form of Restricted Stock Unit Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.4 to the Company’s Form 8-K filed April 19, 2005 and included herein by reference)
10.7	Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Appendix B to the Company’s Proxy Statement filed April 18, 2005 and included herein by reference)
10.8	Form of Restricted Share Agreement pursuant to the Quicksilver Resources Inc. Amended and Restated 2004 Non-Employee Director Equity Plan (filed as Exhibit 10.2 to the Company’s Form 8-K filed May 18, 2005 and included herein by reference)
*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

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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 9, 2005

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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