QUICKSILVER RESOURCES INC - 10-Q Quarterly Report

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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, 2002

¨ 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)

Registrant’s telephone number, including area code: (817) 665-5000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock, par value $0.01 per share		New York Stock Exchange

Securities registered pursuant to Section 12 (g) of the Act: None

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 November 8, 2002, the registrant had 19,942,245 outstanding shares of its common stock, $0.01 par value.

QUICKSILVER RESOURCES INC.

INDEX

		Page

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

Independent Accountants’ Report		3

Condensed Consolidated Balance Sheets at September 30, 2002 and December 31, 2001		4

Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2002 and 2001		5

Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2002 and 2001		6

Notes to Condensed Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		11

Item 3. Quantitative and Qualitative Disclosures About Market Risk		17

Item 4. Controls and Procedures		19

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		20

Item 5. Other Information		20

Item 6. Exhibits and Reports on Form 8-K		20

Signatures		21

Certifications		22

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements

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, 2002, and the related condensed consolidated statements of income for the three and nine month periods ended September 30, 2002 and 2001 and cash flows for the nine month periods ended September 30, 2002 and 2001. These financial statements are the responsibility of the Company’s management.

We conducted our review 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 to financial data and of 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 review, we are not aware of any material modifications that should be made to such condensed consolidated 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, 2001, and the related consolidated statements of income, stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated March 8, 2002, 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, 2001, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas

November 8, 2002

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data

	September 30, 2002			December 31, 2001
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	12,223		$	8,726
Accounts receivable		19,371			21,489
Inventories and other current assets		5,786			5,079

Total current assets		37,380			35,294

Investments in and advances to equity affiliates		11,337			14,248

Properties, plant and equipment – net (“full cost”)		420,876			412,455

Other assets		4,479			7,247

	$	474,072		$	469,244

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	945		$	945
Accounts payable		10,572			12,168
Accrued derivative obligations		20,429			9,025
Accrued liabilities		24,110			34,937

Total current liabilities		56,056			57,075

Long-term debt		240,065			248,425

Unearned revenue		—			4,561

Deferred derivative obligations		22,790			13,461

Other long-term liabilities		220			222

Deferred income taxes		48,523			51,113

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, 23,632,864 and 22,534,875 shares issued, respectively		236			225
Paid in capital in excess of par value		94,804			77,814
Treasury stock of 3,714,752 and 3,751,852 shares, respectively		(14,490	)		(14,634	)
Accumulated other comprehensive income		(28,623	)		(14,007	)
Retained earnings		54,491			44,989

		106,418			94,387

	$	474,072		$	469,244

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

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,
	2002		2001			2002			2001
Revenues
Oil, gas and related product sales	$	28,959	$	28,381		$	81,078		$	100,291
Other revenue		1,484		3,847			9,235			13,656

Total revenues		30,443		32,228			90,313			113,947
Expenses
Oil and gas production costs		9,608		11,639			31,213			40,190
Other operating costs		407		363			1,050			1,057
Depletion and depreciation		7,805		7,168			22,611			21,615
Provision for doubtful accounts		—		—			—			(1,071	)
General and administrative		1,578		2,187			5,934			6,713

Total expenses		19,398		21,357			60,808			68,504

Operating income		11,045		10,871			29,505			45,443

Other (income) expense-net		81		(36	)		(367	)		(408	)
Interest expense		5,188		6,002			15,026			18,544


Income before income taxes		5,776		4,905			14,846			27,307

Income tax expense		2,136		1,785			5,344			9,779


Net income	$	3,640	$	3,120		$	9,502		$	17,528


Basic earnings per share	$	0.18	$	0.17		$	0.48		$	0.94
Diluted earnings per share	$	0.18	$	0.16		$	0.47		$	0.91

Basic weighted average shares outstanding		19,894		18,686			19,598			18,623
Diluted weighted average shares outstanding		20,411		19,284			20,197			19,170

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

QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited

	For the Nine Months Ended September 30,
	2002			2001
Operating activities:
Net income	$	9,502		$	17,528
Charges and credits to net income not affecting cash
Depletion and depreciation		22,611			21,615
Deferred income taxes		5,295			9,362
Recognition of unearned revenues		(4,561	)		(7,087	)
Other		1,390			326
Changes in assets and liabilities
Accounts receivable		2,142			4,573
Inventory, prepaid expenses and other		(1,303	)		(1,917	)
Accounts payable		(1,647	)		13
Accrued and other liabilities		(10,653	)		(1,877	)

Net cash from operating activities		22,776			42,536

Investing activities:
Development and exploration costs and other property additions		(32,164	)		(46,959	)
Advances from (to) equity affiliates – net		2,842			(1,122	)
Proceeds from sale of assets		1,263			40

Net cash used for investing activities		(28,059	)		(48,041	)

Financing activities:
Notes payable, bank proceeds		7,000			10,000
Principal payments on long-term debt		(14,481	)		(14,427	)
Deferred financing costs		(1,362	)		—
Issuance of common stock, net of issuance costs		16,812			1,895
Proceeds from settlement of interest rate hedge		1,000			—
Payments to acquire common stock		(189	)		(78	)

Net cash from (used for) financing activities		8,780			(2,610	)

Net increase (decrease) in cash and equivalents		3,497			(8,115	)

Cash and equivalents at beginning of period		8,726			12,833


Cash and equivalents at end of period	$	12,223		$	4,718


SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Interest paid	$	14,752		$	18,457

Income taxes paid	$	115		$	297

Treasury shares issued for payment of executives’ compensation	$	364		$	—

Treasury shares issued for payment of directors’ compensation	$	—		$	100

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

QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ACCOUNTING POLICIES AND DISCLOSURES

In the opinion of management of Quicksilver Resources Inc. (“Quicksilver” or the “Company”), the Company’s condensed consolidated financial statements contain all adjustments (consisting of only normal, recurring accruals) necessary to present fairly the financial position of the Company as of September 30, 2002, and the results of operations for the three and nine months ended September 30, 2002 and 2001 and cash flows for the nine months ended September 30, 2002 and 2001.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. 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, 2001. The results of operations for the three and nine month periods ended September 30, 2002 are not necessarily indicative of the operating results to be expected for the full fiscal year.

Certain reclassifications have been made for comparative purposes for presentations adopted in 2002.

In July 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 146 (“SFAS No. 146”), “Accounting for Costs Associated with Exit or Disposal Activities.” SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. SFAS No. 146 supercedes EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 is to be applied prospectively to exit or disposal activities initiated after 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 months ended September 30, 2002 and 2001 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 months ended September 30, 2002 and 2001.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2002	2001	2002	2001
	(Unaudited, in thousands)		(Unaudited, in thousands)
Weighted average common shares-basic	19,894	18,686	19,598	18,623

Potentially dilutive securities
Stock options	511	495	561	486
Stock warrants	6	103	38	61

Weighted average common shares-diluted	20,411	19,284	20,197	19,170

For the nine month period 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. For the three and nine month periods ended September 30, 2001, warrants representing 550,000 shares of common stock were excluded from the diluted net income per share calculation as the exercise price exceeded the average market price of the Company’s common stock.

2. HEDGING

The estimated fair values of all hedge derivatives and the associated fixed price firm sale and purchase commitments as of September 30, 2002 and December 31, 2001 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, 2002		December 31, 2001
	(Unaudited)
	(in thousands)
Derivative assets:
Fixed price commitments	$	—	$	1,476
Natural gas financial collars		—		255
Floating price natural gas financial swaps		185		93
Fixed price natural gas financial swaps		28		28
Fixed to floating interest rate swap		—		1,853

	$	213	$	3,705


Derivative liabilities:
Fixed price natural gas financial swaps	$	40,479	$	17,134
Fixed price crude oil financial swaps		182		—
Floating price natural gas financial swaps		—		1,521
Natural gas financial collars		23		—
Crude oil financial collars		487		—
Fixed price commitments		136		—
Floating to fixed interest rate swap		1,912		3,832

	$	43,219	$	22,487

The fair values of all hedge derivatives and firm sale and purchase commitments as of September 30, 2002 and December 31, 2001 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 value of interest rate swaps was based upon third-party estimates of the fair value of such swaps.

As of September 30, 2002, $75,000,000 of the Company’s variable-rate debt was hedged with interest rate swaps converting the debt’s floating LIBOR base to a 6.72% fixed-rate resulting in a liability of $1,912,000. On October 24, 2002, the Company closed its fixed-rate interest swaps related to $75,000,000 of variable-rate debt and entered into a new fixed-rate interest swap that converts the interest rate to a fixed-rate of 3.74% through March 31, 2005. The realized loss of $1,854,000 on the closed swaps will be reclassified out of other comprehensive income through March 31, 2003, the original maturity of such swaps.

A total of $53,000,000 of the Company’s fixed-rate Subordinated Notes was hedged through March 30, 2009 with an interest rate swap that converted the debt’s 14.75% fixed-rate debt to a floating three-month LIBOR base. This hedge was closed on July 15, 2002, and the Company received a cash settlement of $1,000,000. The settlement was deferred and is being recognized as a reduction of interest expense over the original life of the swap.

3. LONG-TERM DEBT

	September 30, 2002			December 31, 2001
	(Unaudited)
	(in thousands)
Long-term debt, in thousands, consists of:
Notes payable to banks-3.735% and 4.85% interest at September 30, 2002 and December 31, 2001	$	183,000		$	190,000
Subordinated Notes-14.75% interest		53,975			54,853
Other loans		4,035			4,517

		241,010			249,370
Less current maturities		(945	)		(945	)

	$	240,065		$	248,425

In May 2002, Quicksilver’s three-year revolving credit facility was amended to mature on May 13, 2005. It permits the Company to obtain revolving credit loans and to issue letters of credit for the account of the Company from time to time in an aggregate amount not to exceed $250,000,000. As of September 30, 2002, the Company’s borrowing base was $210,000,000 of which $26,085,188 was available. On October 2, 2002, the Company’s interest rate was set at 3.665% through January 2, 2003 on $177,000,000. During 2002, the Company has made net principal repayments of $7,000,000 and reduced the balance payable under its credit facility to $183,000,000. The loan agreement for the credit facility contains certain dividend restrictions and restrictive covenants, which, among other things, require the maintenance of a minimum current ratio. Additionally, the purchase agreement relating to the Company’s subordinated notes contains restrictive covenants, which, among other things, require maintenance of a specified minimum working capital, a collateral coverage ratio and an earnings ratio. The Company currently is in compliance with all such restrictions.

4. UNEARNED REVENUE

On March 31, 2000, the Company conveyed to a bank Section 29 tax credits for 99.5% of the interests acquired from CMS Oil and Gas Company, including the interests of Terra Energy Ltd., in Devonian shale gas production from certain wells located in Michigan. Cash proceeds received from the sale were $25,000,000 and were recorded as unearned revenue. Revenue is recognized as reserves are produced. Revenue of $4,561,000 and $7,087,000 was recognized in the 2002 and 2001 periods, respectively, in other revenue.

During 1997, other tax credits were conveyed through the sale of certain working interests to a bank. Revenue of $1,137,000 and $1,189,000 was recognized in the 2002 and 2001 periods, respectively, in other revenue.

In September 2002, the Company notified the bank owner of the 2000 Section 29 tax credit properties of its intent to reacquire the properties as of year-end. In November 2002, the Company notified the bank owner of its intent to reacquire interests from the 1997 tax credit sales. During the third quarter, the Company estimated the maximum value of the Section 29 credits to be recognized from the CMS interests. As a result, in the third quarter the Company ceased recognition of Section 29 deferred revenue from the CMS interests and reclassified previously estimated unearned revenues as accrued liabilities.

5. STOCKHOLDERS’ EQUITY

On February 1, 2002, the Company granted incentive stock options covering 48,300 shares of common stock to certain employees. Stock options covering 20,835 shares of common stock were granted to non-employee directors as payment of compensation for 2002. These options were granted at an exercise price of $17.02 and vest one year from the date of grant. No compensation expense was recognized at the date of grant, as the exercise price was equal to the fair value of the common stock at the date of grant.

Warrants for 550,000 shares at $20.00 per share and 430,000 shares at $12.50 per share were exercised during the first quarter of 2002. Fees of $297,000 were incurred in association with the exercise of warrants for 495,000 shares at $20.00. Additionally, 127,989 shares of common stock were issued upon exercise of options during the current year and 37,100 treasury shares were issued to executives for payment of bonuses earned during 2000.

During 2002, 10,000 MGV exchangeable shares were presented to Quicksilver for purchase for $189,100. A total of 42,748 of MGV exchangeable shares were converted to Quicksilver common stock. At September 30, 2002, 227,421 MGV exchangeable shares remain outstanding.

Comprehensive Income (Loss)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2002			2001			2002			2001
	(Unaudited, in thousands)						(Unaudited, in thousands)
Net income	$	3,640		$	3,120		$	9,502		$	17,528
Other comprehensive income (loss), net of tax:
Adoption of SFAS No. 133 at January 1, 2001		—			—			—			(60,304	)
Reclassification adjustment – hedge settlements		1,644			1,012			3,541			15,416
Change in cash-flow hedge derivative fair value		(2,997	)		18,403			(18,152	)		31,996
Change in foreign currency translation adjustment		(915	)		(355	)		(5	)		(539	)

Comprehensive income (loss)	$	1,372		$	22,180		$	(5,114	)	$	4,097

6. RELATED PARTY TRANSACTIONS

The Darden family has effective beneficial ownership of 49.6% 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 2002, Quicksilver paid $431,000 for principal and interest on a note payable to Mercury associated with an earlier acquisition of assets from Mercury. At September 30, 2002, the balance of the note was $2,240,000. Quicksilver and its associated entities paid $548,000 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. During 2002, Quicksilver purchased compressors and equipment for $3,961,000 and maintenance and related services for $1,610,000 from Voyager on terms as favorable to Quicksilver as those granted by Voyager to third parties.

In the second quarter, Voyager recognized an impairment loss of $788,000 related to its inventory, fixed assets and operating leases for facilities. During the third quarter, Voyager sold, to a third party, its Michigan inventory and fixed assets and recognized a gain on the sale of $203,000. Quicksilver recognized $512,000 (its 65% share) of the impairment in the second quarter and its proportionate share of the gain, $132,000, in the third quarter.

Effective as of September 1, 2002, Voyager intends to sell its compressor service fixed assets and the majority of its Texas inventory to Quicksilver for $1,232,000 (its historical cost that approximated fair value). In addition, Quicksilver will pay Voyager $2,219,000 for the fair value of its compressor service contracts. Since Mercury and the Darden family are considered as having a controlling interest in Quicksilver, their 35% interest in the gain on the sale of the compressor service contracts of $777,000 will be treated by Quicksilver as an equity distribution. Quicksilver’s gain on the sale of the contracts will be eliminated. The transaction is subject to the review and approval by the non-related party members of the Board of Directors.

Voyager also anticipates selling certain leasehold improvements on operating leases with a Mercury affiliate at historical cost of approximately $1,000,000. The leases will be cancelled and Voyager estimates the lease cancellation costs will be $437,000.

At September 30, 2002, Quicksilver’s carrying value of its investment in Voyager is $1,115,000. The Company expects to receive distributions of cash from Voyager during the fourth quarter as Voyager ceases its activities.

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

Forward-Looking Information

The following should be read in conjunction with our financial statements contained herein and in our Form 10-K for the year ended December 31, 2001, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K.

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, that involve a number of risks and uncertainties. Such forward-looking statements may be or may concern, among other things, our capital expenditures, drilling activity, acquisition plans and proposals and dispositions, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory matters and competition. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “budgeted,” “expect,” “predict,” “anticipate,” “projected,” “should,” “assume,” “believe” or other words that convey the uncertainty of future events or outcomes. 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 us. 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

Summary Financial Data

Three Month Periods Ended September 30, 2002 and 2001

	Three Months Ended September 30,
	2002		2001
	(in thousands)
Total operating revenues	$	30,443	$	32,228
Total operating expenses		19,398		21,357
Operating income		11,045		10,871
Net income		3,640		3,120

We recorded net income of $3,640,000 ($0.18 per diluted share) for the three months ended September 30, 2002, compared to net income of $3,120,000 ($0.16 per diluted share) for the third quarter of 2001.

Operating Revenues

Total revenues for the three months ended September 30, 2002 were $30,443,000; a decrease of 6% from the $32,228,000 reported for the three months ended September 30, 2001. The $578,000 increase in product revenues was primarily the result of higher prices for the current quarter as compared to the prior year period. Other revenue was $2,363,000 lower due primarily to a $2,732,000 decrease in the recognition of revenue derived from Section 29 tax credits. An additional $533,000 of marketing revenue partially offset the decrease.

Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the three months ended September 30, 2002 and 2001 were as follows:

	Three Months Ended September 30,
	2002		2001
Average daily production volume
Gas – Mcfd		91,348		89,161
Oil – Bbld		2,387		2,787
Natural gas liquid (“NGL”) – Bbld		534		379
Total – Mcfed		108,878		108,157

Product sale revenues (in thousands)
Natural gas sales	$	22,879	$	22,069
Oil sales		5,305		5,672
NGL sales		775		640

Total oil, gas and NGL sales	$	28,959	$	28,381

Unit prices-including impact of hedges
Gas price per Mcf	$	2.72	$	2.69
Oil price per Bbl	$	24.15	$	22.12
NGL price per Bbl	$	15.77	$	18.37

Gas sales of $22,879,000 for the third quarter of 2002 were 4% higher than the $22,069,000 for the comparable 2001 period. Slightly higher sales volumes of 2,187 Mcfd increased revenue $548,000 as compared to the third quarter of 2001. An approximate 2,700 Mcfd increase in third quarter 2002 production occurred in the PdC formation where Garfield wells were fracture stimulated. Smaller increases were also seen in Indiana and Sturgeon Valley Ranch in Michigan due to capital expenditures in late 2001 and early 2002. Higher prices increased revenue by $262,000 from the 2001 period. Our company-wide average gas price of $2.72 per Mcf was $0.03 per Mcf higher than the prior year quarter.

Oil sales were $5,305,000 for the three months ended September 30, 2002 compared to $5,672,000 in the third quarter of 2001. A 400 Bbld decrease in sales volumes reduced revenue $889,000 from the prior year quarter. The decreases were due in part to the sale of oil properties in Wyoming and Texas in June and July of this year. The average oil sales price for the third quarter of 2002 increased $2.03 per barrel to $24.15 per barrel as compared to the $22.12 per barrel for the 2001 third quarter and increased oil revenue $522,000.

NGL sales of $775,000 for the third quarter of 2002 increased $135,000 from $640,000 for the 2001 period. Higher volumes increased sales $226,000 and were primarily the result of recording revenue for sales of approximately 16,000 barrels as a result of the finalization of a joint venture audit. NGL prices decreased from $18.37 to $15.77 per Bbl and reduced revenue $91,000 from the prior year quarter.

Other Revenues

Other revenue of $1,484,000 was $2,363,000 lower when compared to the third quarter of 2001. Third quarter recognition of revenue derived from Section 29 tax credit monetizations decreased $2,732,000 from the prior year period. Recognition of deferred revenue associated with the 2000 tax credit monetization ceased in the third quarter. Marketing revenue increased $533,000 as compared to the prior year quarter and partially offset the decrease. Higher marketing revenue was the result of additional margins from the marketing of natural gas.

Operating Expenses

Third quarter operating expenses for 2002 were $19,398,000, 9% lower than the $21,357,000 incurred in the third quarter of 2001.

Oil and Gas Production Costs

Oil and gas production costs were $9,608,000, a 17% decrease from the 2001 third quarter oil and gas production costs of $11,639,000. Lower operating expenses were primarily the result of a $1,164,000 increase in cost recoveries in 2002. The increase was primarily the result of a company-wide review of operating agreements under which we operate both oil and gas properties and other partnerships. As a result of the review, amounts were recovered from the oil and gas properties and partnerships. Production overhead expense decreased $540,000 in the 2002 period as compared to the 2001 period primarily as a result of a reduction in estimated bonuses and 401(k) contributions. Lease operating expenses were $366,000 lower primarily as a result of cost reduction measures undertaken early in 2002.

Depletion and Depreciation

	Three Months Ended September 30,
	2002		2001
	(In thousands, except per unit amounts)
Depletion	$	7,008	$	6,382
Depreciation of other fixed assets		797		786

Total depletion and depreciation	$	7,805	$	7,168

Average depletion cost per Mcfe	$	0.70	$	0.64

Third quarter 2002 depletion of $7,008,000 was $626,000 higher than the prior year quarter due primarily to an increase in the depletion rate for 2002. The higher depletion rate was the result of a combination of capital costs incurred and a proportionately smaller increase in proved oil and gas reserves due to lower product prices when compared to the prior year period.

General and Administrative Expenses

General and administrative costs incurred during the three months ended September 30, 2002 were $1,578,000, 28% lower than the expense incurred in the third quarter of 2001. The decrease was primarily due to a $340,000 decrease in salary and personnel expenses and a $206,000 decrease in legal costs. Lower personnel costs were primarily the result of a reduction in estimated 2002 bonuses and 401(k) contributions as compared to the prior year quarter.

Interest and Other Income/Expense

Interest expense for the third quarter of 2002 was $5,188,000, a decrease of $814,000 from the comparable 2001 period. The decrease was the result of lower effective interest rates partially offset by higher debt levels.

Income Tax Expense

The income tax provision of $2,136,000 was established using an effective U.S. Federal tax rate of 35%. The provision also includes a $31,000 state and foreign income tax benefit. Canadian tax rates result in an effective rate in excess of 35%. Income tax expense increased over the prior year period as a result of higher pretax income as compared to the third quarter of 2001.

Summary Financial Data

Nine Month Periods Ended September 30, 2002 and 2001

	Nine Months Ended September 30,
	2002		2001
	(in thousands)
Total operating revenues	$	90,313	$	113,947
Total operating expenses		60,808		68,504
Operating income		29,505		45,443
Net income		9,502		17,528

We recorded net income of $9,502,000 ($0.47 per diluted share) in the nine months ended September 30, 2002, compared to net income of $17,528,000 ($0.91 per diluted share) for the first nine months of 2001.

Operating Revenues

Total revenues for the nine months ended September 30, 2002 were $90,313,000; a decrease of 21% from the $113,947,000 reported for the nine months ended September 30, 2001. Lower prices decreased revenue $15,296,000 while a decrease in sales volumes further reduced revenue $3,917,000. The decrease in volumes from the prior year period was primarily the result of recognition in 2001 of volumes related to properties where payouts occurred, which enabled us to record additional volumes and revenues in 2001 attributable to our increased interests. Other revenue decreased $4,421,000 from the prior year period primarily as a result of a $2,577,000 decrease in revenue derived from Section 29 tax credits and an $843,000 decrease in income from investments in subsidiaries. Additional decreases in other revenue were due to lower gas marketing margins for the 2002 period and $580,000 recognized in 2001 in connection with the bankruptcy settlement of a natural gas purchaser of ours.

Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the nine months ended September 30, 2002 and 2001 were as follows:

	Nine Months Ended September 30,
	2002		2001
Average daily production volume
Gas – Mcfd		88,894		89,971
Oil – Bbld		2,536		3,004
Natural gas liquid (“NGL”) – Bbld		399		506
Total – Mcfed		106,505		111,037

Product sale revenues (in thousands)
Natural gas sales	$	64,847	$	78,309
Oil sales		14,637		18,969
NGL sales		1,594		3,013

Total oil, gas and NGL sales	$	81,078	$	100,291

Unit prices-including impact of hedges
Gas price per Mcf	$	2.67	$	3.19
Oil price per Bbl	$	21.14	$	23.13
NGL price per Bbl	$	14.63	$	21.79

Gas sales of $64,847,000 for the nine months ended September 30, 2002 were 17% lower than the $78,309,000 reported for the comparable 2001 period. Lower prices reduced revenue $12,676,000 from the 2001 period. Average prices decreased to $2.67 per Mcf from $3.19 per Mcf in the prior year. Reduced sales volumes of 294,000 Mcf decreased revenue $786,000 as compared to the first nine months of 2001. Gas volumes in 2001 included 540,000 Mcf that were the result of the identification, in 2001, of properties where payouts had occurred, which enabled us to record additional volumes and revenue in 2001 attributable to our increased interests. The 2001 volumes due to payout identifications were partially offset by approximately 245,500 Mcf of net increases in natural gas production in 2002. Significant increases in Michigan included 528,000 Mcf at Sturgeon Valley Ranch where 15 wells were drilled in late 2001 and at Garfield Field where PdC wells were fracture stimulated in June and July of 2002 and resulted in production increases of 251,000 Mcf in the third quarter of 2002. Drilling in Indiana resulted in additional production of 105,000 Mcf in 2002 and additional compression at Cinco Ranch in Texas increased 2002 production 72,000 Mcf. Capital expenditures at the Bindloss field in Canada increased production 44,000 Mcf over 2001. These increases were partially offset by normal production declines.

Oil sales were $14,637,000 for the nine months ended September 30, 2002 compared to $18,969,000 for the 2001 period. The average oil sales price for the nine-month period in 2002 decreased $1.99 per barrel to $21.14 per barrel and reduced oil revenue $1,630,000. A 468 Bbld decrease in sales volumes reduced revenue $2,702,000 from the prior year period. The decrease was due in part to the sale of Wyoming and Texas properties in June and July of this

year. Higher volumes in the 2001 period were primarily due to adjustments recognized in the second quarter of 2001 related to properties acquired in 2000.

NGL sales of $1,594,000 for the 2002 period decreased $1,419,000 from $3,013,000 for the 2001 nine-month period. Average NGL prices decreased from $21.79 to $14.63 per barrel and reduced revenue $990,000. The decrease in sales volumes occurred despite the third quarter recognition of sales of approximately 16,000 barrels as a result of the finalization of a joint venture audit.

Other Revenues

Other revenue of $9,235,000 for the nine-month 2002 period was $4,421,000 lower when compared to the 2001 period. Revenue derived from Section 29 tax credit monetizations decreased $2,577,000. Deferred revenue recognition associated with the 2000 Section 29 tax credit monetization ceased in the third quarter. The prior year included $580,000 of revenue associated with the settlement of bankruptcy proceedings of a former gas purchaser of ours. Gas marketing margins decreased by $363,000 from the 2001 period. Additionally, losses of $843,000 from our equity affiliate, Voyager Compression Services LLC (“Voyager”), were recorded in 2002 as a result of its impairment of assets and the wind down of its operations.

Operating Expenses

Operating expenses for the first nine months of 2002 were $60,808,000, 11% lower than the $68,504,000 incurred in the 2001 period.

Oil and Gas Production Costs

Oil and gas production costs were $31,213,000, a decrease of 22% from 2001 oil and gas production costs of $40,190,000. A reduction in sales volumes, including the absence of 2001 payout volumes, and cost reduction measures we instituted early in 2002 resulted in a decrease in lease operating expense of approximately $1,966,000. Additional expense recoveries of $3,127,000 were the result of review of various operating agreements under which we operate both oil and gas properties and other partnerships. The review resulted in an increase of expenses recovered from the oil and gas properties and partnerships. Reductions in production overhead of $1,101,000 were primarily the result of reductions in estimated bonus and 401(k) contributions. Lower sales prices and volumes resulted in a $2,783,000 decrease of severance tax expense as compared to the 2001 nine-month period.

Depletion and Depreciation

	Nine Months Ended September 30,
	2002		2001
	(In thousands, except per unit amounts)
Depletion	$	20,295	$	19,364
Depreciation of other fixed assets		2,316		2,251

Total depletion and depreciation	$	22,611	$	21,615

Average depletion cost per Mcfe	$	0.70	$	0.64

Depletion for the first nine months of 2002 was $20,295,000, $931,000 higher than the 2001 period. Depletion expense increased $1,794,000 due to an increase in the depletion rate for 2002 but the increase was partially offset by a decrease due to lower sales volumes. The higher depletion rate was the result of a combination of capital costs incurred and a proportionately smaller increase in proved oil and gas reserves due to lower product prices when compared to the prior year period.

General and Administrative Expenses

General and administrative costs incurred during the nine months ended September 30, 2002 were $5,934,000, 12% lower than the expense incurred in the 2001 period. The decrease was due to lower personnel costs of $1,172,000 resulting primarily from a reduction in estimated 2002 bonuses and 401(k) contributions. Reductions occurred in several other expense categories as compared to the prior year. A $594,000 increase in legal expenses partially

offset the expense reductions. The increased legal expense was incurred in connection with a royalty lawsuit filed against us in 2001.

Interest and Other Income/Expense

Interest expense for the first nine months of 2002 was $15,026,000, a decrease of $3,518,000 from the comparable 2001 period. The decrease was the result of lower effective interest rates partially offset by higher debt levels.

Income Tax Expense

The income tax provision of $5,344,000 was established using an effective U.S. Federal tax rate of 35%. The provision also includes a $70,000 state and foreign income tax benefit. Canadian tax rates result in an effective rate in excess of 35%. Income tax expense decreased over the prior year period as a result of lower pretax income as compared to the first nine months of 2001.

As of September 30, 2002, we had a deferred tax liability of $48,251,000. Deferred tax expense of $5,295,000 incurred in 2002 was offset by an additional $7,885,000 of deferred tax benefit associated with derivative obligations.

Liquidity and Capital Resources

We believe that our capital resources are adequate to meet the requirements of our business. We anticipate that the current remaining 2002 planned capital expenditures of $19,500,000 will be funded by cash flow from operations and credit facility utilization. However, future cash flows from operations are subject to a number of variables including the level of production and oil and gas prices, and there can be no assurance those operations and capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures.

Our principal operating sources of cash include sales of natural gas and crude oil and revenues from gas marketing, transportation and processing. We sell approximately 31% of our natural gas production under fixed-price long-term contracts and an additional 43% of natural gas production is sold under fixed-price swap agreements. As a result, we benefit from significant predictability of our natural gas revenues. Commodity market prices affect cash flows for that portion of natural gas not under contract as well as our crude oil and NGL sales.

Net cash from operations for the nine months ended September 30, 2002 was $22,776,000, compared to cash provided from operations of $42,536,000 for the same period last year. The decrease resulted from lower earnings due primarily to reduced revenues, caused by lower average prices and reduced volumes. In addition, changes in working capital reduced cash by $11,452,000 due to timing of expense and capital accruals and payment for those items.

Net cash used for investing activities for the nine months ended September 30, 2002 was $28,059,000. Investing activities were comprised primarily of $32,164,000 expended for drilling of oil and gas properties and construction of service facilities, including Canadian capital expenditures of $9,208,000, which were partially offset by $1,263,000 of proceeds from the sale of producing properties and reductions of $2,842,000 in advances to equity affiliates.

Net cash provided by financing activities for the nine months ended September 30, 2002 was $8,780,000. We received $16,812,000, after payments for agency fees of $297,000, from the exercise of warrants covering 980,000 shares of stock and from the issuance of 127,989 shares issued upon exercise of employee stock options. We decreased net borrowings under our credit facility by $7,000,000 during the first nine months of 2002. In May, our three-year revolving credit facility was amended to mature on May 13, 2005. It permits us to obtain revolving credit loans and to issue letters of credit for our account from time to time in an aggregate amount not to exceed $250,000,000. As of September 30, 2002, our borrowing base was $210,000,000 of which $26,085,188 was available.

Exploration and Development Activities

Through September 30, 2002, we drilled 58 gross (35 net) successful Michigan Antrim shale wells. We have also drilled 10 development and 4 exploratory successful New Albany shale wells in the Corydon project in Indiana, owned 100% by us. We plan to drill 25 Antrim shale wells (23 net) and 6 Indiana wells prior to year-end.

During the third quarter, we began the development of the Detroit River program in the Michigan Beaver Creek area. As of September 30, 2002, 6 gross (5 net) wells have been completed. Processing plant and connecting pipeline facilities are planned to be completed in time to commence the selling of oil from this development by year-end. We plan to drill 24 gross (23 net) additional Detroit River wells prior to year-end.

In October 2002, our Canadian subsidiary, MGV Energy Inc., announced the beginning of commercial development drilling by its first coal bed methane joint venture in the Southern Alberta West Palliser block. The joint venture anticipates having approximately 50 (17 net) new development wells drilled and completed by year-end. Additional blocks are in various stages of licensing and obtaining regulatory approvals to continue development drilling into 2003. Prior to the initiation of this development program, 100 exploration and pilot wells were drilled in the West Palliser block over the past two years. All 100 exploration and pilot wells have been tested with most being shut in awaiting connection to sales lines as development drilling progresses and facilities are constructed.

Outside of the West Palliser block, the coal bed methane joint venture has drilled 20 of 25 planned exploration wells testing multiple coal groups over a broad geographic area on our joint venture partner’s lands in Central and Southern Alberta. Due to encouraging results in some areas outside of the West Palliser block, plans are underway to license and initiate the drilling of pilot wells in 2003. Four-well pilots are drilled in the vicinity of an exploration well to validate encouraging exploration results and to conduct pilot production tests on the five-well group.

Drilling and completion activities are ongoing in two other Southern Alberta coal bed methane projects. A fourth joint venture has been established to explore for coal bed methane in Central Alberta and will drill three exploration wells this year.

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.

Commodity Price Risk

Our primary risk exposure is related to natural gas commodity prices. We are focused on growing our oil and gas operations while minimizing the effect of commodity price swings on net income and cash flow from operations. To help ensure a level of predictability in the prices received for our natural gas and crude oil production and, therefore, the resulting cash flow, we have entered into natural gas sales contracts and financial hedges with up to seven years remaining that cover approximately 78% of our natural gas production, or 62% of our total production. This commodity risk management strategy helps to ensure a predictable base level of cash flow, which allows us to execute our drilling and exploitation programs, meet debt service requirements and pursue acquisition opportunities despite price fluctuations; however, it also limits future gains from favorable movements.

We enter into various 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 fixed price contracts at

$2.49 per Mcf and $2.47 per Mcf, respectively, through March 2009. Approximately 7,400 Mcfd sold under these contracts are third party volumes controlled by us. Approximately 38,059 Mcfd of our equity natural gas are hedged using fixed price swap agreements. Additionally, we have entered into gas collars for 5,000 Mcfd through October 2002. As a result, we benefit from significant predictability of our natural gas revenues.

Crude oil collars were put into place during the second quarter of 2002. The collars are in affect through December 2003 and cover 1,500 Bbld. In September, we hedged 500 Bbld of our equity crude oil using a fixed priced swap agreement. The fixed swap agreement is in effect until September 2003.

Commodity price fluctuations affect the 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 11,500 Mcfd sold under these contracts are third party volumes controlled by us.

Utilization of our hedging program may result in natural gas and crude oil realized prices varying from market prices that we receive from the unhedged sale of natural gas and crude oil. As a result of the financial hedging programs, production revenues in the first nine months of 2002 and 2001 were $2,855,000 and $22,948,000 lower, respectively, than if the hedging programs had not been in effect.

The following table summarizes our open financial hedge positions as of September 30, 2002 related to natural gas and oil production.

Product	Type	Contract Period	Volume	Weighted Avg Price per Mcf	Fair Value
					(in thousands)
Gas	Fixed Price	Oct 2002-Apr 2004	7,500 Mcfd	$2.40	$(7,064)
Gas	Fixed Price	Oct 2002-Dec 2004	559 Mcfd	2.04	(605)
Gas	Fixed Price	Oct 2002-Apr 2005	10,000 Mcfd	2.79	(10,890)
Gas	Fixed Price	Oct 2002-Apr 2005	10,000 Mcfd	2.79	(10,960)
Gas	Fixed Price	Oct 2002-Apr 2005	10,000 Mcfd	2.79	(10,960)
Gas	Collar	Oct 2002	5,000 Mcfd	2.55-3.50	(23)
Oil	Fixed Price	Oct 2002-Sept 2003	500 Bbld	26.30	(182)
Oil	Collar	Oct 2002-Dec 2003	1,500 Bbld	21.00-28.80	(487)

				Total	$(41,171)

Cinnabar Energy Services & Trading, LLC, our wholly owned marketing company, also enters into various financial contracts to hedge its exposure to commodity price risk associated with future contractual natural gas sales and purchases. These contracts may include either fixed and floating 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 typically qualify as either cash flow or fair value hedges. As of September 30, 2002 and 2001, marketing revenues were $1,900,000 and $591,000 lower, respectively, as a result of these hedging activities.

The following table summarizes Cinnabar’s open financial derivative positions and hedged firm commitments as of September 30, 2002 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	Sale	Oct 2002-Jun 2003	952 Mcfd	$3.66	$(136)
Financial derivatives
Gas	Floating Price	Oct 2002-Jun 2003	952 Mcfd		185

				Total-net	$49

The fair value of all natural gas and crude oil financial contracts and associated firm sale and purchase commitments as of September 30, 2002 and 2001 was estimated based on published market prices of natural gas and crude oil 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, 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 our derivatives does not necessarily represent the value a third party would pay to assume our contract positions.

Interest Rate Risk

As of September 30, 2002, $75,000,000 of our variable-rate debt was hedged with interest rate swaps converting the debt’s floating LIBOR base to a 6.72% fixed-rate resulting in a liability of $1,912,000. On October 24, 2002, the Company closed its fixed-rate interest swaps related to $75,000,000 of variable-rate debt and entered into a new fixed-rate interest swap that converts the interest rate to a fixed-rate of 3.74% through March 31, 2005. The realized loss of $1,854,000 on the swaps will be reclassified out of other comprehensive income through March 31, 2003, the original maturity of such swaps.

A total of $53,000,000 of our fixed-rate Subordinated Notes was hedged through March 30, 2009 with an interest rate swap that converted the debt’s 14.75% fixed-rate debt to a floating three-month LIBOR base. This hedge was closed on July 15, 2002, and we received a cash settlement of $1,000,000. The settlement was deferred and is being recognized as a reduction of interest expense over the original life of the swap.

Interest expense for the nine-month periods ended September 30, 2002 and 2001 was $1,786,000 and $964,000 higher, respectively, as a result of the interest rate swaps.

ITEM 4. Controls and Procedures

Within the 90-day period prior to the filing of this report, 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-14(c) 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 in bringing to their attention on a timely basis material information relating to Quicksilver required to be included in the Company’s periodic filings under the Exchange Act.

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

PART II—OTHER INFORMATION

ITEM 1. Legal Proceedings

In August 2001, a group of royalty owners (Athel E. Williams et al.) brought suit against us and three of our subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd, one of our subsidiaries, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. Due to administrative oversight an answer was not timely filed and a default was entered against us 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. The court did not make a ruling on class certification or set a date by which such ruling would be made. Based on information currently available to us, we believe that the final resolution of this matter will not have a material effect on our operations, equity or cash flows.

ITEM 5. Other Information

In August of 2002, the Audit Committee approved non-audit services being performed for us by Deloitte & Touche LLP, our independent accountants. The approved services are for analysis and identification of our obligations to escheat unclaimed funds to various states and income tax consultation.

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		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).
3.5		Amendment to Bylaws of Quicksilver Resources Inc. (filed as Exhibit 3.4 to the Company’s Form 10-K filed March 27, 2001 and included herein by reference).
3.6		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.)
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).
* 15.1		Awareness letter of Deloitte & Touche LLP
* 99.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
* 99.2		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.

(b) Reports on Form 8-K

None.

Quicksilver Resources Inc.

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 14, 2002

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

CERTIFICATION

I, Glenn Darden, President and Chief Executive Officer of Quicksilver Resources Inc., certify that:

I have reviewed this quarterly report on Form 10-Q of Quicksilver Resources Inc;

Based on my knowledge, this quarterly report does not contain any untrue statement of material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Dated: November 14, 2002



By:		/s/ Glenn Darden
		Glenn Darden President and Chief Executive Officer

CERTIFICATION

I, Bill Lamkin, Executive Vice President and Chief Financial Officer of Quicksilver Resources Inc., certify that:

I have reviewed this quarterly report on Form 10-Q of Quicksilver Resources Inc;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Dated: November 14, 2002



By:		/s/ Bill Lamkin
		Bill Lamkin, Executive Vice President and Chief Financial Official

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