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.

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

2

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.

4

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.

5

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.

6

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

9

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

10

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

12

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.

13

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

14

	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.

15

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.

16

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

17

	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.

18

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.

19

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.

20

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.

21

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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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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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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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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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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