Quicksilver Resources (KWK) 10-Q 2003 Q3 Quarterly report

UNITED STATES

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 September 30, 2003

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

(State or other jurisdiction of incorporation or organization)

75-2756163

(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. Yesx 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 November 5, 2003, the registrant had 24,724,927 outstanding shares of its common stock, $0.01 par value.

QUICKSILVER RESOURCES INC.

INDEX TO FORM 10-Q

For the Period Ending September 30, 2003

		Page
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Independent Accountants’ Report	3
	Condensed Consolidated Balance Sheets at September 30, 2003 and December 31, 2002	4
	Condensed Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2003 and 2002	5
	Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2003 and 2002	6
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2003 and 2002	7
	Notes to Condensed Consolidated Interim Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4.	Controls and Procedures	23
PART II. OTHER INFORMATION
Item 6.	Exhibits and Reports on Form 8-K	24
Signatures		26

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

INDEPENDENT ACCOUNTANTS’ REPORT

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 September 30, 2003, and the related condensed consolidated statements of income and comprehensive income for the three and nine month periods ended September 30, 2003 and 2002 and of cash flows for the nine-month periods ended September 30, 2003 and 2002. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. 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 auditing standards generally accepted in the United States of America, 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 auditing standards generally accepted in the United States of America, the consolidated balance sheet of the Company as of December 31, 2002, 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 14, 2003, 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, 2002, 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

November 10, 2003

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

	September 30, 2003			December 31, 2002
ASSETS
Current assets
Cash and cash equivalents	$	10,359		$	9,116
Accounts receivable		22,018			21,075
Current deferred income taxes		10,064			9,045
Inventories and other current assets		7,715			5,540
Total current assets		50,156			44,776
Investments in and advances to equity affiliates		10,173			10,219
Properties, plant and equipment – net (“full cost”)		567,752			470,078
Other assets		4,153			4,465
	$	632,234		$	529,538
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	311		$	951
Accounts payable		16,895			14,931
Accrued derivative obligations		29,531			26,362
Accrued liabilities		24,477			26,210
Total current liabilities		71,214			68,454
Long-term debt		234,640			248,493
Derivative obligations		13,718			26,387
Asset retirement obligations		13,832			234
Deferred income taxes		66,465			57,065
Stockholders’ equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 1 share issued and outstanding		—			—
Common stock, $0.01 par value, 40,000,000 shares authorized, 27,303,631 and 23,663,447 shares issued, respectively		273			237
Paid in capital in excess of par value		194,395			114,113
Treasury stock of 2,578,904 and 2,570,502 shares, respectively		(10,299	)		(10,099	)
Accumulated other comprehensive loss		(21,281	)		(34,170	)
Retained earnings		69,277			58,824
Total stockholders’ equity		232,365			128,905
	$	632,234		$	529,538

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

In thousands, except for per share data – Unaudited

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2003			2002		2003			2002
Revenues
Oil, gas and related product sales	$	32,941		$	28,959	$	102,485		$	81,078
Other revenue		572			1,348		1,639			9,128
Total revenues		33,513			30,307		104,124			90,206
Expenses
Oil and gas production costs		12,376			9,608		38,406			31,213
Other operating costs		220			407		1,002			1,050
Depletion, depreciation and accretion		7,912			7,805		23,094			22,611
General and administrative		1,802			1,578		6,008			5,934
Total expenses		22,310			19,398		68,510			60,808
Income (loss) from equity affiliates		456			136		1,109			107
Operating income		11,659			11,045		36,723			29,505
Other (income) expense-net		(65	)		81		(52	)		(367	)
Interest expense		3,566			5,188		16,693			15,026
Income before income taxes and cumulative effect of change in accounting principle		8,158			5,776		20,082			14,846
Income tax expense		2,929			2,136		7,332			5,344
Net income before cumulative effect of change in accounting principle		5,229			3,640		12,750			9,502
Cumulative effect of change in accounting principle, net of tax		—			—		2,297			—
Net income	$	5,229		$	3,640	$	10,453		$	9,502
Basic net income per common share:
Net income before cumulative effect of accounting change	$	0.23		$	0.18	$	0.59		$	0.48
Cumulative effect of accounting change, net of tax		—			—		(0.11	)		—
Net income	$	0.23		$	0.18	$	0.48		$	0.48
Diluted net income per common share:
Net income before cumulative effect of accounting change	$	0.23		$	0.18	$	0.58		$	0.47
Cumulative effect of accounting change, net of tax		—			—		(0.11	)		—
Net income	$	0.23		$	0.18	$	0.47		$	0.47
Weighted average common shares outstanding
Basic		22,547			19,894		21,610			19,598
Diluted		22,965			20,411		22,063			20,197

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 COMPREHENSIVE INCOME

In thousands – Unaudited

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2003		2002			2003			2002
Net income	$	5,229	$	3,640		$	10,453		$	9,502
Other comprehensive income (loss) – net of taxes
Reclassification adjustments – hedge settlements		5,777		1,644			22,279			3,541
Change in derivative fair value		6,174		(2,997	)		(16,002	)		(18,152	)
Change in foreign currency translation adjustment		2		(915	)		6,612			(5	)
Comprehensive income (loss)	$	17,182	$	1,372		$	23,342		$	(5,114	)

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 Nine Months Ended September 30,
	2003			2002
Operating activities:
Net income	$	10,453		$	9,502
Charges and credits to net income not affecting cash
Cumulative effect of accounting change, net of tax		2,297			—
Depletion, depreciation and accretion		23,094			22,611
Deferred income taxes		7,143			5,295
Recognition of unearned revenues		507			(4,561	)
(Income) loss from equity affiliates		(1,109	)		(107	)
Non-cash gain from hedging activities		(963	)		(149	)
Amortization of deferred loan costs		2,328			1,228
Other		54			418
Changes in assets and liabilities, net of acquisition
Accounts receivable		52			2,142
Inventory, prepaid expenses and other		(916	)		(1,303	)
Accounts payable		2,060			(1,647	)
Accrued liabilities and other		(3,303	)		(9,653	)
Net cash from operating activities		41,697			23,776
Investing activities:
Development and exploration costs and other property additions		(104,686	)		(32,164	)
Purchase of Voyager Compression Services assets		(684	)		—
Distributions and advances from equity affiliates – net		378			2,842
Proceeds from sale of assets		105			1,263
Net cash used for investing activities		(104,887	)		(28,059	)
Financing activities:
Notes payable, bank proceeds		99,000			7,000
Principal payments on long-term debt		(113,042	)		(14,481	)
Deferred financing costs		(1,420	)		(1,362	)
Issuance of common stock, net of issuance costs		79,895			16,812
Payments to acquire common stock		—			(189	)
Net cash from financing activities		64,433			7,780
Net increase in cash and cash equivalents		1,243			3,497
Cash and cash equivalents at beginning of period		9,116			8,726
Cash and cash equivalents at end of period	$	10,359		$	12,223
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid	$	16,636		$	14,752
Income taxes paid	$	38		$	115
Distribution of equity to Mercury Exploration Company	$	(505	)	$	—
Shares issued for payment of executives’ compensation	$	—		$	364

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

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QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated interim financial statements of Quicksilver Resources Inc. (“Quicksilver” or the “Company”) have not been audited by independent public accountants. In the opinion of Company management, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to present fairly the financial position of the Company as of September 30, 2003, its income and comprehensive income for the three and nine month periods ended September 30, 2003 and 2002 and its cash flows for the nine month periods ended September 30, 2003 and 2002. 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, 2002.

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 to net income and common shares for the potential dilution from stock options, stock warrants, and any other convertible securities outstanding. For the three and nine month periods ended September 30, 2003 and 2002 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 nine month periods ended September 30, 2003 and 2002.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002
	(in thousands)		(in thousands)
Weighted average common shares-basic	22,547	19,894	21,610	19,598
Potentially dilutive securities
Stock options	418	511	453	561
Stock warrants	—	6	—	38
Weighted average common shares-diluted	22,965	20,411	22,063	20,197

For the nine months ended September 30, 2003, options covering 20,210 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. For the nine months ended September 30, 2002, warrants representing 550,000 shares of common stock were excluded from the diluted net income per share calculation for the period prior to their exercise as the exercise price exceeded the average market price of the Company’s common stock.

Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141,Business Combinations, which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142,Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS Nos. 141 and 142 clarify that more assets

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should be distinguished and classified between tangible and intangible. The Company did not change or reclassify contractual mineral rights included in oil and gas properties on the balance sheet upon adoption of SFAS No. 142. The Company believes the treatment of such mineral rights as tangible assets under the full cost method of accounting for crude oil and natural gas properties is appropriate. An issue has arisen regarding whether contractual mineral rights should be classified as intangible rather than tangible assets. If it is determined that reclassification is necessary, the Company’s gross oil and gas properties would be reduced by $34,874,000 and $68,285,000 and intangible assets would be increased by like amounts at December 31, 2002 and September 30, 2003, respectively, representing cost incurred from the effective date of June 30, 2001. The provisions of SFAS Nos. 141 and 142 impact only the balance sheet and associated footnote disclosure. The reclassifications would not affect the Company’s cash flows or results of operations.

SFAS No. 145,Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections was issued in April 2002. The Statement rescinds SFAS No. 4,Reporting Gains and Losses from Extinguishment of Debtand an amendment of that Statement, SFAS No. 64,Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements. As a result of the rescission of SFAS No 4, debt extinguishment will no longer be classified as extraordinary under APB No. 30,Reporting the Results of Operations – Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. The Company has adopted this statement.

The FASB issued SFAS No. 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities, in April 2003. The statement clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The Company will comply with the provisions in this statement.

In May 2003, the FASB issued SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. The statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period after June 15, 2003. The Company does not believe the provisions in this statement affect the Company’s liabilities or equity.

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.

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The following table reflects pro forma income for all periods assuming that SFAS No. 143 was applied retroactively.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2003		2002			2003		2002
	(in thousands)					(in thousands)
Net income before cumulative effect of change in accounting principle	$	5,229	$	3,640		$	12,750	$	9,502
Deduct: accretion of asset retirement obligation, net of tax effects		—		(130	)		—		(379	)
Pro forma net income before cumulative effect of change in accounting principle	$	5,229	$	3,510		$	12,750	$	9,123
Pro forma net income per common share
Basic	$	0.23	$	0.18		$	0.59	$	0.47
Diluted		0.23		0.17			0.58		0.45

The following table provides a reconciliation of the changes in the estimated asset retirement obligation from the amount recorded upon adoption of SFAS No. 143 on January 1, 2003 through September 30, 2003.

	Nine Months Ended September 30, 2003
	(in thousands)
Beginning asset retirement obligation	$	13,326
Additional liability incurred		724
Accretion expense		602
Asset retirement costs incurred		(92	)
Currency translation adjustment		128
Ending asset retirement obligation	$	14,688

During the nine months ended September 30, 2003, accretion expense was recognized and included in the $23.0 million of depletion, depreciation and accretion expense reported in the 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 2003. Asset retirement obligations at September 30, 2003 are $14.7 million, of which $0.9 million 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 September 30, 2003 and December 31, 2002 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.

	September 30, 2003		December 31, 2002
	(in thousands)
Derivative assets:
Crude oil financial collars	$	245		—
Natural gas financial collars		11		—
Fixed price commitments		468		29
Floating price natural gas financial swaps		8		269
Fixed price basis swap		12		—
Fixed to floating interest rate swap		490		—
	$	1,234	$	298
Derivative liabilities:
Fixed price natural gas financial swaps	$	40,167	$	48,560
Fixed price crude oil financial swaps		—		292
Crude oil financial collars		24		379
Fixed price commitments		9		226
Floating price natural gas financial swaps		432		382
Floating to fixed interest rate swap		2,616		2,910
	$	43,248	$	52,749

The fair values of all natural gas and crude oil financial instruments and firm sale and purchase commitments as of September 30, 2003 and December 31, 2002 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. The fair values of the interest rate swaps were based upon third-party estimates of the fair values of the swaps.

At September 30, 2003, derivative assets of $0.7 million and derivative liabilities of $29.5 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $18.7 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:

	September 30, 2003			December 31, 2002
	(in thousands)
Notes payable to banks	$	163,000		$	192,000
Subordinated notes payable		—			53,000
Second mortgage notes payable		70,000			—
Mercury note payable		—			1,920
Other loans		1,460			1,582
Fair value interest hedge		491			942
		234,951			249,444
Less current maturities		(311	)		(951	)
	$	234,640		$	248,493

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 lien 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.

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The new $70 million second lien notes (“Second Mortgage Notes”) are a combined LIBOR based floating and 7.5% fixed rate interest commitment with a termination date of December 31, 2006. A total of $30 million of the $70 million Second Mortgage Notes will be at the floating rate based upon the three-month LIBOR rate plus 5.48%, or 6.53% initially.

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 converts the debt’s 7.5% fixed-rate to a floating six-month LIBOR base rate plus 4.07% through the termination of the notes.

As of September 30, 2003, the Company’s borrowing base under its credit facility was $250 million of which $85.5 million was available. On November 3, 2003, the borrowing base of $250 million was reaffirmed. The loan agreements for the credit facility prohibit the declaration or payments of dividends by the Company and contain certain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio and an earnings ratio before interest, taxes, depreciation and amortization and non-cash income and expense. Additionally, the Second Mortgage Notes contain restrictive covenants, which, among other things, require maintenance of a minimum current ratio, a collateral coverage ratio and an earnings ratio before interest, taxes, depreciation and amortization and non-cash income and expense. The Company currently is in compliance with all such restrictions.

5. TAX CREDIT SALES

On March 31, 2000, the Company conveyed to a bank Internal Revenue Code Section 29 credits in Devonian shale gas production from certain wells located in Michigan. These wells represented 99.5% of the interests acquired from CMS Oil and Gas Company, including the interests in Terra Energy Ltd. Cash proceeds received from the sale were $25.0 million and were recorded as unearned revenue. Revenue was recognized as reserves were produced. Revenue of $4.6 million was recognized in the first nine months of 2002 in other revenue.

During 1997, other tax credits were conveyed through the sale of certain working interests to a bank. Revenue of $1.1 million related to these conveyances was recognized in the first nine months of 2002 in other revenue.

On July 3, 2003, Quicksilver repurchased interests owned by the bank as a result of the Company’s tax credit sales. Quicksilver paid $6.3 million to acquire all such interests in the Section 29 tax-eligible properties. As a result of the planned repurchase, the Company recorded, in the first quarter of 2003, a $0.5 million reduction of deferred revenue previously recognized.

6. COMMITMENTS AND CONTINGENCIES

In August 2001, a group of royalty owners (Athel E. Williams et al.) brought suit against Quicksilver 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 acquired in 2000, 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. Due to administrative oversight an answer was not timely filed and a default was entered against Quicksilver in December 2001. On October 24, 2002, the trial court granted Terra’s motion to set aside the default. The court heard arguments on class certification on November 8, 2002; on December 6, 2002, the court issued a memorandum opinion granting class certification in part and denying it in part. The court stated that those portions of the royalty owner’s complaint against the Company, which alleged that the Company deducted excessive post production costs from royalty payments should not be certified as class action. The court certified the remainder of the complaint for class action status. 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. Based on information currently available to the Company, Quicksilver believes that the final resolution of this matter will not have a material effect on its operations, equity or cash flows.

7. STOCK BASED COMPENSATION

Quicksilver has one stock-based employee compensation plan, the 1999 Stock Option and Stock Retention Plan. The Company accounts for the plan 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 February 11, 2003, the Company granted stock options covering 31,884 shares of common stock to the Company’s officers. These options were granted at an exercise price of $22.08. Non-employee directors were granted stock options on March 10, 2003 covering 20,210 shares of stock in lieu of compensation for 2003. These

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options were granted at an exercise price of $24.10 and vest one year from the date of grant. 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.

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 September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(in thousands)						(in thousands)
Net income before effect of cumulative change in accounting principle	$	5,229		$	3,640		$	12,750		$	9,502
Deduct: Total stock – based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(102	)		(169	)		(334	)		(533	)
Pro forma net income before effect of cumulative change in accounting principle	$	5,127		$	3,471		$	12,416		$	8,969
Net income before accounting change per common share as reported
Basic	$	0.23		$	0.18		$	0.59		$	0.48
Diluted		0.23			0.18			0.58			0.47
Pro forma net income before accounting change per common share
Basic	$	0.23		$	0.17		$	0.57		$	0.46
Diluted		0.22			0.17			0.56			0.44

8. ISSUANCE OF COMMON STOCK

On August 26, 2003, the Company issued 3.5 million common shares for proceeds of $79.2 million, net of offering costs. At that time, Mercury Exploration Company (“Mercury”), a related party sold 525,000 shares of its holdings in Quicksilver common stock to cover over-allotments.

9. RELATED PARTY TRANSACTIONS

The Darden family has effective ownership of approximately 38% of Quicksilver’s shares outstanding including shares owned by Mercury Exploration Company (“Mercury”) and Quicksilver Energy L.C. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

During the first nine months of 2003, Quicksilver paid $2,038,000 for principal and interest on a note payable to Mercury associated with an acquisition of assets from Mercury. On September 30, 2003, the Company paid off the remaining balance of the note of $1,600,000. Quicksilver and its associated entities paid $578,000 and $548,000 during the nine months ended September 30, 2003 and 2002, respectively, for rent on buildings, which are owned by a Mercury affiliate.

Quicksilver accounts for its 65% holdings in Voyager Compression Services, LLC (“Voyager”) under the equity method since control over Voyager is shared equally with Mercury. In February 2003, Quicksilver acquired Voyager’s compressor service contracts and other assets with an estimated fair value of $2,903,000. The fair value of the compressor service contracts was determined to be $2,219,000. The transaction was reviewed and approved by the independent members of Quicksilver’s Board of Directors. Mercury’s portion of Voyager’s gain on the sale of the service contracts was $505,000, net of tax. Quicksilver recorded the amount as an equity distribution by the Company as the Darden family, including its ownership of Mercury, is considered to have a controlling interest in Quicksilver. Quicksilver’s gain on the sale of the contracts was eliminated.

Voyager also paid lease cancellation costs of $437,000 to a Mercury affiliate to cancel real estate leases between Voyager and the Mercury affiliate. The Mercury affiliate purchased certain leasehold improvements to the real estate associated with the cancelled leases from Voyager at historical cost, which approximated fair value, of approximately $844,000.

13

As a result of these transactions, the Company purchased assets, other than the compressor service contracts, of $684,000, received a $241,000 cash distribution from Voyager and recorded a $505,000 equity distribution to Mercury for its share of Voyager’s gain from the disposition of its compressor service contracts to Quicksilver.

14

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

The following should be read in conjunction with our condensed consolidated interim financial statements contained herein and our annual report for the year ended December 31, 2002, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such annual report. Any capitalized terms used but not defined in the following discussion have the same meaning given to them in the annual report.

The statements contained in this quarterly report on Form 10-Q that are not historical facts, including, but not limited to, statements found in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and 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. Such forward-looking statements generally are accompanied by words such as “anticipate,” “believe,” “budgeted,” “expect,” “intend,” “plan,” “project,” “potential” or similar statements. Such forward-looking information is based upon our current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on our behalf. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for our oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2003 Compared with Three Months Ended September 30, 2002

	Three Months Ended September 30,
	2003		2002
	(in thousands)
Total operating revenues	$	33,513	$	30,307
Total operating expenses		22,310		19,398
Operating income		11,659		11,045
Net income		5,229		3,640

We recorded net income of approximately $5.2 million ($0.23 per diluted share) for the three months ended September 30, 2003, compared to net income of approximately $3.6 million ($0.18 per diluted share) for the third quarter of 2002.

Operating Revenues

Revenues for the third quarter of 2003 were $33.5 million; a $3.2 million increase from the $30.3 million reported for the three months ended September 30, 2002. Production revenue increased $4.0 million as a result of a 15% increase in realized sales prices that was partially offset by slightly lower sales volumes. Other revenue decreased $0.8 million from the prior year period as revenue from marketing activities decreased in the current quarter.

15

Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the three months ended September 30, 2003 and 2002 are as follows:

	Three Months Ended September 30,
	2003		2002
Average daily production volume
Natural gas – Mcfd		92,538		91,348
Crude oil – Bbld		2,088		2,387
Natural gas liquid (“NGL”) – Bbld		372		534
Total – Mcfed		107,304		108,878
Product sale revenues (in thousands)
Natural gas sales	$	27,836	$	22,879
Crude oil sales		4,483		5,305
NGL sales		622		775
Total oil, gas and NGL sales	$	32,941	$	28,959
Unit prices-including impact of hedges
Gas price per Mcf	$	3.27	$	2.72
Oil price per Bbl	$	23.33	$	24.15
NGL price per Bbl	$	18.15	$	15.77

Natural gas sales of $27.8 million for the third quarter of 2003 were 22% higher than the $22.9 million for the comparable 2002 period. Revenue increased $4.6 million from the third quarter of 2002 as a result of a $0.55 increase in realized average natural gas prices. Additional sales volumes increased revenue $0.4 million compared to the third quarter of 2002. Additional natural gas volumes in Michigan included 695,000 Mcf of natural gas production from interests acquired from Enogex Exploration Company in December 2002 and 286,000 Mcf from Antrim wells drilled during 2002 and 2003. Production from our coal bed methane projects in Canada was 404,000 Mcf during the third quarter of 2003. Production increases were partially offset by a 293,000 Mcf reduction in sales volumes due to the shutdown of third party facilities in addition to natural production declines.

Crude oil sales were $4.5 million for the three months ended September 30, 2003 compared to $5.3 million in the third quarter of 2002. Natural production declines reduced revenue $0.6 million from the prior year quarter. The third quarter average crude oil sales price for 2003 decreased to $23.33 from $24.15 in the third quarter of 2002 and decreased revenue $0.2 million.

Other Revenues

Other revenue of $0.6 million was $0.8 million lower when compared to the third quarter of 2002. Marketing revenue decreases resulted from lower marketed natural gas margins as compared to the 2002 period.

Operating Expenses

Third quarter operating expenses for 2003 were $22.3 million; an increase of $2.9 million over the $19.4 million of expenses incurred in the third quarter of 2002.

Oil and Gas Production Costs

Oil and gas production costs were $12.4 million. The $2.8 million increase over the third quarter of 2002 included a $2.3 million increase in lease operating expenses. An increase of approximately $0.9 million was the result of production volumes from the Enogex interests purchased in December 2002. Canadian operating and overhead costs increased $0.6 million as a result of production from our coal bed methane properties and our further development of those projects. The remaining $0.8 million increase in expenses was the result of moderate cost increases across a broad range of expense categories. Increased sales prices in 2003 for natural gas increased severance tax expense $0.5 million from the 2002 period.

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Depletion, Depreciation and Accretion

	Three Months Ended September 30,
	2003		2002
	(In thousands, except per unit amounts)
Depletion	$	6,708	$	7,008
Depreciation of other fixed assets		997		797
Accretion		207		—
Total depletion, depreciation and accretion	$	7,912	$	7,805
Average depletion cost per Mcfe	$	0.68	$	0.70

Third quarter 2003 depletion of $6.7 million was $0.3 million lower than depletion for the third quarter of 2002 primarily as a result of a decrease in the depletion rate. Accretion expense of $0.2 million in the third quarter of 2003 was the result of the adoption of SFAS No. 143 as of January 1, 2003.

General and Administrative Expense

General and administrative costs incurred during the three months ended September 30, 2003 were $1.8 million. The $0.2 million increase over third quarter of 2002 expense was primarily the result of an increase in legal and professional fees in the 2003 quarter.

Interest Expense

Interest expense for the third quarter of 2003 was $3.5 million, a decrease of $1.6 million compared to the third quarter of 2002. Interest expense decreased $1.9 million as a result of lower effective interest rates. The lower rates resulted primarily from the June 2003 refinancing of our subordinated debt. The reduction was partially offset by an increase in average debt outstanding.

Income Tax Expense

Our income tax provision of $2.9 million was established using an effective U.S. Federal tax rate of 35%. The provision also includes $0.4 million for Canadian and state income tax expense. Income tax expense increased over the prior year period as a result of higher pretax income for the third quarter of 2003.

Nine Months Ended September 30, 2003 Compared with Nine Months Ended September 30, 2002

	Nine Months Ended September 30,
	2003		2002
	(in thousands)
Total operating revenues	$	104,124	$	90,206
Total operating expenses		68,510		60,808
Operating income		36,723		29,505
Net income before accounting change		12,750		9,502
Net income after accounting change		10,453		9,502

We recorded net income of approximately $10.5 million ($0.47 per diluted share) for the nine months ended September 30, 2003, compared to net income of approximately $9.5 million ($0.47 per diluted share) for the first nine months of 2002. Included in the 2003 period was a $2.3 million charge ($0.11 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 amount of our subordinated notes payable.

Operating Revenues

Revenues for the nine months ended September 30, 2003 were $104.1 million; a $13.9 million increase from the $90.2 million reported for the nine months ended September 30, 2002. Higher realized prices increased product sales revenue $20.2 million while additional sales volumes further increased revenue $1.2 million. Volume increases were primarily the result of production from natural gas interests purchased from Enogex in December 2002 and initial production from our Canadian CBM projects. Other revenue decreased $7.5 million from the prior year period. The 2002 recognition of $5.7 million from the sale of Section 29 tax credits did not recur in 2003 as the tax

17

credits expired in 2002. In March of 2003, other revenue was reduced by $0.5 million as a result of the completion of our negotiations to purchase the tax credit properties.

Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the nine months ended September 30, 2003 and 2002 are as follows:

	Nine Months Ended September 30,
	2003		2002
Average daily production volume
Natural gas – Mcfd		92,464		88,894
Crude oil – Bbld		2,269		2,536
NGL – Bbld		350		399
Total – Mcfed		108,180		106,505
Product sale revenues (in thousands)
Natural gas sales	$	85,401	$	64,847
Crude oil sales		14,989		14,637
NGL sales		2,095		1,594
Total oil, gas and NGL sales	$	102,485	$	81,078
Unit prices-including impact of hedges
Gas price per Mcf	$	3.38	$	2.67
Oil price per Bbl	$	24.20	$	21.14
NGL price per Bbl	$	21.91	$	14.63

Natural gas sales of $85.4 million for the nine months ended September 30, 2003 were 32% higher than the $64.8 million of revenue for the comparable 2002 period. Revenue increased $17.3 million from the 2002 period as a result of a $0.71 increase in average realized natural gas prices. Additional sales volumes increased revenue $3.3 million compared to the first nine months of 2002. Additional natural gas volumes in Michigan included 2,047,000 Mcf from interests acquired from Enogex, 237,000 Mcf of Prairie du Chien production from wells fracture stimulated during the first half of 2002 and 719,000 Mcf from Antrim wells drilled during 2002 and 2003. Initial production from our coal bed methane projects in Canada was 883,000 Mcf during the first nine months of 2003. Sales volume increases described above were partially offset by an approximate 260,000 Mcf reduction in first quarter sales volumes due to extreme winter conditions in Michigan, an estimated 613,000 Mcf reduction in sales volumes due to the shutdown of third party facilities in the second and third quarters and natural production declines.

Crude oil sales were $15.0 million for the nine months ended September 30, 2003 compared to $14.6 million in the first nine months of 2002. The average crude oil sales price for the first nine months of 2003 increased to $24.20 from $21.14 and improved revenue $2.1 million from the first nine months of 2002. Wyoming and Texas property sales in 2002 decreased sales volumes 20,300 Bbl. The volumes lost due to the property sales and natural production declines, reduced revenue $1.8 million from the prior year period.

NGL sales were $2.1 million for the nine months period ended September 30, 2003. The $0.5 million increase was primarily the result of higher prices.

Other Revenues

Other revenue of $1.6 million was $7.5 million lower when compared to the nine months ended September 30, 2002. Revenue from the sale of Section 29 tax credits was $5.7 million in the first nine months of 2002. The tax credits expired at the end of 2002 and we completed the repurchase of the tax credit properties in July 2003. As a result of the repurchase of those properties, other revenue was reduced $0.5 million in the first quarter of 2003. Marketing revenue for 2003 decreased approximately $1.0 million from the 2002 period as a result of smaller margins on marketed natural gas volumes.

Operating Expenses

Operating expenses for the first nine months of 2003 were $68.5 million, an increase of $7.7 million over expenses of $60.8 million incurred in the first nine months of 2002.

Oil and Gas Production Costs

Oil and gas production costs were $38.4 million. The $7.2 million increase as compared to the nine-month period ended September 30, 2002 was primarily the result of increased lease operating expenses and production tax

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expense. Lease operating expense increased $4.6 million for the first nine months of 2003 as compared to the 2002 period. Approximately $2.7 million of the increase was the result of additional natural gas volumes from the acquired Enogex interests. Canadian operating and overhead costs increased $1.3 million as a result of production from our coal bed methane projects and our further development of those projects. The remaining $0.7 million increase is due to settlement costs for environmental issues and post-production cost allowances. Increased sales prices and volumes in 2003 resulted in additional severance tax expense of $2.6 million as compared to the 2002 period.

Depletion, Depreciation and Accretion

	Nine Months Ended September 30,
	2003		2002
	(In thousands, except per unit amounts)
Depletion	$	19,719	$	20,295
Depreciation of other fixed assets		2,773		2,316
Accretion		602		—
Total depletion, depreciation and accretion	$	23,094	$	22,611
Average depletion cost per Mcfe	$	0.67	$	0.70

Depletion for the first nine months of 2003 was $19.7 million and $0.6 million lower than the 2002 period. Depletion expense was lower due to a decrease in the depletion rate partially offset by an increase in sales volumes. Accretion expense of $0.6 million in 2003 was the result of the adoption of SFAS No. 143 as of January 1, 2003.

General and Administrative Expense

General and administrative costs incurred during the period ended September 30, 2003 were $6.0 million and almost unchanged from expense incurred in the nine months ended September 30, 2002.

Income from Equity Affiliates

Income from equity affiliates increased $1.0 million from the 2002 period primarily as a result of losses at our equity affiliate, Voyager Compression Services, in 2002.

Interest Expense

Interest expense for the first nine months of 2003 was $16.7 million, an increase of $1.7 million compared to the 2002 period. During the second quarter of 2003, we redeemed $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, 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 $2.1 million as a result of lower effective interest rates and was partially offset by additional interest expense associated with higher average debt outstanding.

Income Tax Expense

Our income tax provision of $7.3 million was established using an effective U.S. Federal tax rate of 35%. The provision also includes $1.2 million for Canadian and state income tax expense. Income tax expense increased over the prior year period as a result of higher pretax income for the first nine months of 2003.

CAPITAL RESOURCES AND LIQUIDITY

Net cash from operations of $41.7 million for the nine months ended September 30, 2003 was $17.9 million higher than the same period in 2002. The increase resulted from higher operating income before noncash items. Operating income from the production and sale of oil and gas (production revenue less production expense) increased $14.2 million as the result of additional sales volumes and higher prices for 2003. Cash from operations was reduced by $3.2 million as a result of the prepayment premium for the early redemption of $53 million in principal amount of our subordinated notes paid in June 2003.

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 nine months of 2003, we sold approximately 30% of our natural gas production under long-term contracts with an average floor price of $2.48 and an additional 41% of our natural gas production was sold under fixed-price swap agreements. We also sold 22% of our crude oil production under

19

fixed-price swap agreements. Additionally, price collars covered 4% and 66% of our natural gas and crude oil production, respectively. As a result of our hedging activities, we benefit from enhanced 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. During the first quarter of 2003, we increased borrowings under our credit facility in part as the result of settlement of our hedge derivatives for the months of January through March.

Through September 30, 2003, we have expended $104.7 million on the additions of oil and gas properties and related equipment. Investing activities were comprised of $95.6 million expended for exploration and development activities and $9.1 million for construction and acquisition of gathering and processing facilities and other fixed assets. Of the $95.6 million expended for exploration and development, $28.7 million was incurred in leasehold acquisitions. Those acquisitions included $8.9 million in Canada, $9.6 million in Indiana and Kentucky and $10.0 million in Texas. We also purchased compression maintenance service contracts and associated fixed assets from our affiliate, Voyager Compression Services, in February of 2003 for $0.7 million.

Capital expenditures

	Nine Months Ended September 30, 2003
	(in thousands)
Exploration and development
United States	$	50,374
Canada		45,257
Total exploration and development		95,631
Gas processing/transportation and other		9,055
Total capital expenditures	$	104,686

Net cash provided by financing activities for the nine months ended September 30, 2003 was $64.4 million. On June 27, 2003, we redeemed $53 million in principal amount of our subordinated notes payable through the issuance of $70 million in principal amount of second lien notes. The refinancing resulted in net proceeds of $15.6 million. The $3.2 million prepayment premium paid in connection with the refinancing was included in interest expense for the period and is included in cash from operations. On August 26, 2003, we issued 3.5 million shares of common stock for $79.2 million, net of issuance costs. As a result of these activities, we have reduced the balance outstanding under our credit facility by $29 million as of September 30, 2003.

As of September 30, 2003 and December 31, 2002, our total capitalization was as follows:

	September 30, 2003		December 31, 2002
	(in thousands)
Long-term and short-term debt:
Notes payable to banks	$	163,000	$	192,000
Subordinated notes payable		—		53,000
Second mortgage notes payable		70,000		—
Mercury note payable		—		1,920
Various loans		1,460		1,582
Fair value interest hedge		491		942
Total debt		234,951		249,444
Stockholders’ equity		232,365		128,905
Total capitalization	$	467,316	$	378,349

Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141,Business Combinations, which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142,Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS Nos. 141 and 142 clarify that more assets

20

should be distinguished and classified between tangible and intangible. We did not change or reclassify contractual mineral rights included in oil and gas properties on our balance sheet upon adoption of SFAS No. 142. We believe the treatment of such mineral rights as tangible assets under the full cost method of accounting for crude oil and natural gas properties is appropriate. An issue has arisen regarding whether contractual mineral rights should be classified as intangible rather than tangible assets. If it is determined that reclassification is necessary, our gross oil and gas properties would be reduced by $34,874,000 and $68,285,000 and intangible assets would be increased by like amounts at December 31, 2002 and September 30, 2003, respectively, representing cost incurred from the effective date of June 30, 2001. The provisions of SFAS Nos. 141 and 142 impact only our balance sheet and associated footnote disclosure. The reclassifications would not affect our cash flows or results of operations.

SFAS No. 145,Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections was issued in April 2002. The Statement rescinds SFAS No. 4,Reporting Gains and Losses from Extinguishment of Debt and an amendment of that Statement, SFAS No. 64,Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements. As a result of the rescission of SFAS No 4, debt extinguishment will no longer be classified as extraordinary under APB No. 30,Reporting the Results of Operations – Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. We have adopted this statement.

The FASB issued SFAS No. 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities, in April 2003. The statement clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. We will comply with the provisions in this statement.

In May 2003, the FASB issued SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. The statement establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period after June 15, 2003. We do not believe the provisions in this statement affect our liabilities or equity.

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 6,900 Mcfd sold under these contracts are third party volumes controlled by us. Approximately 38,028 Mcfd of our equity natural gas is hedged using fixed price swap agreements and an additional 5,000 Mcfd is hedged with price collars. Additionally, our crude oil production is hedged by price collars for 1,500 Bbld. As a result, we benefit from significant predictability of our natural gas and crude oil revenues.

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 2004. Additional gas volumes of 16,500 Mcfd are committed at market price through September 2008. Approximately 15,600 Mcfd sold under these contracts are third party volumes controlled by us.

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The following table summarizes our open financial hedge positions as of September 30, 2003 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	Oct 2003-Apr 2004	7,500 Mcfd	$	2.40	$	(4,098	)
Gas	Fixed Price	Oct 2003-Dec 2004	520 Mcfd		2.41		(426	)
Gas	Fixed Price	Oct 2003-Apr 2005	10,000 Mcfd		2.79		(11,853	)
Gas	Fixed Price	Oct 2003-Apr 2005	10,000 Mcfd		2.79		(11,895	)
Gas	Fixed Price	Oct 2003-Apr 2005	10,000 Mcfd		2.79		(11,895	)
Gas	Collar	Oct 2003-Dec 2003	5,000 Mcfd		4.00-6.50		11
Oil	Collar	Oct 2003-Dec 2003	1,500 Bbld		21.00-28.80		153
Oil	Collar	Jan 2004-Dec 2004	500 Bbld		21.00-34.60		92
Oil	Collar	Jan 2004-Dec 2004	500 Bbld		21.00-29.35		(24	)
					Total	$	(39,935	)

Cinnabar Energy Services & Trading, LLC, our wholly owned marketing company, also enters into financial contracts to hedge its exposure to commodity price risk associated with future contractual natural gas sales and purchases. These contracts consist of fixed price sales or purchases from third parties. As a result of these firm sale and purchase commitments and associated financial price swaps, the hedge derivatives have qualified as fair value hedges. At September 30, 2003, we recorded assets and liabilities of $468,000 and $9,000, respectively, for the fair value of firm purchase and sale commitments. Additionally, we have recorded current assets and liabilities of $20,000 and $432,000, respectively, associated with the fair value of the financial price and basis swaps.

The following table summarizes Cinnabar’s open financial derivative positions and hedged firm commitments as of September 30, 2003 related to natural gas marketing.

Product	Type	Contract Period	Volume	Weighted Avg Price per Mcf		Fair Value
						(in thousands)
Fixed price sale and purchase contracts
Gas	Purchase	Oct 2003	258 Mcfd	$	4.05		5
Gas	Sale	Oct 2003	275 Mcfd	$	6.43		15
Gas	Sale	Oct 2003-Nov 2003	328 Mcfd	$	5.07		5
Gas	Sale	Dec 2003	323 Mcfd	$	5.49		2
Gas	Sale	Oct 2003-Mar 2004	328 Mcfd	$	5.94		43
Gas	Sale	Nov 2003-Mar 2004	329 Mcfd	$	4.91		(9	)
Gas	Sale	Oct 2003-May 2004	656 Mcfd	$	5.51		57
Gas	Sale	Oct 2003-Jun 2004	328 Mcfd	$	6.48		122
Gas	Sale	Oct 2003-Oct 2004	2,286 Mcfd	$	5.26		219
							459
Financial derivatives
Gas	Floating Price	Oct 2003	323 Mcfd				(6	)
Gas	Floating Price	Oct 2003	323 Mcfd				(17	)
Gas	Floating Price	Oct 2003-Nov 2003	328 Mcfd				(6	)
Gas	Floating Price	Dec 2003	323 Mcfd				(3	)
Gas	Floating Price	Oct 2003-Mar 2004	328 Mcfd				(41	)
Gas	Floating Price	Nov 2003-Mar 2004	329 Mcfd				8
Gas	Floating Price	Oct 2003-May 2004	656 Mcfd				(71	)
Gas	Floating Price	Oct 2003-Jun 2004	328 Mcfd				(119	)
Gas	Floating Price	Oct 2003-Oct 2004	2,368 Mcfd				(169	)
Gas	Fixed Basis	Oct 2003	20,000 Mcfd				12
							(412	)
					Total-net	$	47

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 $32.8 million and $2.9 million lower as a result of the hedging programs in the first nine months of 2003 and 2002,

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respectively. Marketing revenue was $0.5 million higher and $1.9 million lower as a result of hedging activities in the first nine months of 2003 and 2002, respectively.

The fair value of all natural gas financial contracts and associated firm sale and purchase commitments as of September 30, 2003 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 September 30, 2003, 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 $2.6 million at September 30, 2003.

On September 10, 2003, we entered into an interest rate swap to hedge the $40.0 million of fixed-rate second lien notes issued on June 27, 2003. The swap converts the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base resulting in an asset of $0.5 million at September 30, 2003.

Interest expense for the first nine months of 2003 and 2002 was $0.5 million and $1.8 million higher, respectively, as a result of interest rate swaps.

As a result of our issuance of $70 million in principal amount of second lien notes, which includes $30 million in principal amount accruing interest at a floating rate based upon the three-month LIBOR rate plus 5.48% and $40 million in principal amount accruing interest at a floating rate based upon the six-month LIBOR rate plus 4.07% as a result of an interest rate swap, our exposure to a change in short term interest rates has increased. If the three-month or six-month LIBOR rate increases or decreases one percent, our annual pretax income will decrease or increase by $1.6 million, a $0.4 million increase from the effect of a one percent change at December 31, 2002.

Foreign Currency Risk

The effects of a change in the Canadian-U.S. exchange rate have increased since December 31, 2002 as a result of our additional investment in MGV Energy Inc.’s coal bed methane projects and changes in the exchange rate. After consideration of the increase in our net Canadian assets and changes in the exchange rate, a ten percent increase or decrease in the Canadian-U.S. exchange rate would increase or decrease equity by approximately $7.5 million, at September 30, 2003. A $7.5 million change in equity represents approximately 3% of our consolidated equity at September 30, 2003.

ITEM 4. Controls and Procedures

An evaluation was carried out under supervision and with the participation of our 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 defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the design and operation of these disclosure controls and procedures are effective to ensure that information required to be disclosed by us in this quarterly report on Form 10-Q and in other reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There were no significant changes in our internal control over financial reporting or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

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PART II - OTHER INFORMATION

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. (filed as Exhibit 4.1 to the Company’s Form S-4 File No. 333-66709, filed November 3, 1998 and included herein by reference).
3.2	Certificate of Designation, Preferences and Rights of Preferred Stock (filed as Exhibit 3.2 to the Company’s Form 10-K filed March 27, 2001 and included herein by reference).
3.3	Certificate of Amendment to the Restated Certificate of Incorporation of Quicksilver Resources Inc. (filed as Exhibit 3.1 to the Company’s Form 10-Q filed August 14, 2001 and included herein by reference).
3.4	Certificate of Designation of Series A Junior Participating Preferred Stock of Quicksilver Resources Inc. (filed as Exhibit 3.4 to the Company’s Form 10-K filed March 26, 2003 and included herein by reference).
3.5	Bylaws of Quicksilver Resources Inc. (filed as Exhibit 4.2 to the Company’s Form S-4 File No. 333-66709, filed November 3, 1998 and included herein by reference).
3.6	Amendment to Bylaws of Quicksilver Resources Inc. adopted on November 30, 1999 (filed as Exhibit 3.4 to the Company’s Form 10-K filed March 27, 2001 and included herein by reference).
3.7	Amendment to the Bylaws of Quicksilver Resources Inc., adopted June 5, 2001 (filed as Exhibit 3.2 to the Company’s Form 10-Q filed August 14, 2001 and included herein by reference).
3.8	Amendment to the Bylaws of Quicksilver Resources Inc., adopted March 11, 2003 (filed as Exhibit 3.8 to the Company’s Form 10-K filed March 26, 2003 and included herein by reference).
4.1	Rights Agreement, dated as of March 11, 2003, between Quicksilver Resources Inc. and Mellon Investor Services LLC, as Rights Agent (filed as Exhibit 4.1 to the Company’s Form 8-A filed March 14, 2003 and included herein by reference).
4.2	Note Purchase Agreement, dated June 27, 2003, between the Company and the Purchasers identified therein (filed as Exhibit 4.2 to the Company’s Form 10-Q filed August 14, 2003 and included herein by reference).
10.1	Master Gas Purchase and Sale Agreement dated March 1, 1999, by and between Quicksilver Resources Inc. and Reliant Energy Services, Inc. (filed as Exhibit 10.10 to the Company’s Form S-1 File No. 333-89229, filed October 18, 1999 and included herein by reference).
10.2	Wells Agreement (filed as an exhibit to the Registration Statement on Form S-4 File No. 333-29769, and included herein by reference).
+ 10.3	Quicksilver Resources Inc. 1999 Stock Option and Retention Stock Plan (filed as Exhibit 10.28 to the Company’s Form S-1 File No. 333-89229, filed October 18, 1999 and included herein by reference).
10.4	Fourth Amended and Restated Credit Agreement, dated as of May 13, 2002, among Quicksilver Resources Inc., as Borrower, Bank of America, N.A., as Administrative Agent, and the financial institutions listed therein (filed as Exhibit 10.6 to the Company’s Form 10-Q filed May 15, 2002 and included herein by reference).
10.5	First Amendment to Fourth Amended and Restated Credit Agreement, dated as of September 25, 2002, among Quicksilver Resources Inc., as Borrower, Bank of America, N.A., as Administrative Agent, and the financial institutions listed therein (filed as Exhibit 10.5 to the Company’s Form 10-Q filed August 14, 2003 and included herein by reference).
10.6	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of June 27, 2003, among Quicksilver Resources Inc., as Borrower, Bank of America, N.A., as Administrative Agent, and the financial institutions listed therein (filed as Exhibit 10.6 to the Company’s Form 10-Q filed August 14, 2003 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

+ Identifies management contracts and compensatory plans or arrangements

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(b) Reports on Form 8-K

We filed a Current Report on Form 8-K on July 3, 2003, reporting under Items 5 and 7 a press release announcing our redemption of $53 million of 14.75% Second Mortgage Notes due in 2009.

We filed a Current Report on Form 8-K on August 14, 2003, reporting under Items 7 and 12 a press release announcing second quarter operating results.

We filed a Current Report on Form 8-K as of August 22, 2003, reporting under Items 5 and 7 that we entered into an Underwriting Agreement with Bear, Stearns & Co. Inc. with respect to the sale by us and the purchase by Bear, Stearns of 3,500,000 shares of our common stock and with respect to the grant by Mercury Exploration Company, a principal shareholder of ours, to Bear, Stearns of an option to purchase all or any part of 525,000 shares of common stock.

We filed a Current Report on Form 8-K as of October 6, 2003, reporting under Items 7 and 12 a press release announcing an operations update with production and earnings guidance.

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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: November 10, 2003

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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