Quicksilver Resources (KWK) 10-K/A 2004 FY Annual report (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 1)

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

OR

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

For the transition period from            to            .

Commission file number: 001-14837

QUICKSILVER RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware (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
Preferred Share Purchase Rights	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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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

As of June 30, 2004, the aggregate market value of the voting stock held by non-affiliates of Quicksilver Resources Inc. was approximately $993,572,897 based on the New York Stock Exchange composite trading closing price of $33.53 on June 30, 2004. Shares of the registrant’s voting stock owned by its directors, executive officers and certain Darden family members and related entities were excluded from this aggregate market value calculation; however, such exclusion does not represent a conclusion by the registrant that any or all of such directors, executive officers and certain Darden family members and related entities are affiliates of the registrant.

As of February 28, 2005, 50,233,180 shares of common stock of Quicksilver Resources Inc. were outstanding.

Documents incorporated by reference: Proxy statement of the registrant relating to the annual meeting of stockholders to be held on May 17, 2005 which is incorporated into Part III of this Form 10-K.

EXPLANATORY NOTE

This Amendment No. 1 on Form 10-K/A amends our Annual Report on Form 10-K filed on March 16, 2005 for the fiscal year ended December 31, 2004. We are filing this Amendment to correct the classification of certain amounts presented in the Consolidated Statements of Cash Flows in the original Form 10-K. A description of these reclassifications and a summary showing their effect on the Consolidated Statements of Cash Flows is provided in Note 21 to the Consolidated Financial Statements. These reclassifications affect only respective amounts in the Consolidated Statements of Cash Flows of accounts payable, accrued liabilities and other, purchase of property, plant and equipment and related totals of operating activities and investing activities and do not affect the Consolidated Balance Sheets, Statements of Income and Comprehensive Income or Statements of Stockholders’ Equity.

This Amendment includes corresponding changes in Items 6, 7 and 8 of Part II to our original Form 10-K. All other portions of the original Form 10-K remain unchanged.

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PART II

ITEM 6. Selected Financial Data

The following tables set forth, as of the dates and for the periods indicated, our selected financial information. Our financial information is derived from our audited consolidated financial statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto contained in this document. The following information is not necessarily indicative of our future results.

Selected Financial Data

(in thousands, except for per share data)

	Years Ended December 31,
	2004			2003			2002			2001			2000
Consolidated Statements of Income Data:
Total revenues	$	179,729		$	140,949		$	121,979		$	141,963		$	118,392
Income before income taxes		45,446			28,502			21,333			30,110			27,731
Income before cumulative effect of change in accounting principle		31,272			18,505			13,835			19,310			17,618
Net income		31,272			16,208			13,835			19,310			17,618
Earnings – per share before accounting change (1)
Basic	$	0.63		$	0.41		$	0.35		$	0.52		$	0.48
Diluted		0.62			0.41			0.34			0.50			0.48
Earnings – per share (1)
Basic	$	0.63		$	0.36		$	0.35		$	0.52		$	0.48
Diluted		0.62			0.35			0.34			0.50			0.48
Consolidated Statements of Cash Flows Data:
Net cash provided by (used in):
Operating activities	$	82,798		$	48,687		$	41,650		$	51,624		$	45,135
Investing activities		(203,849	)		(136,829	)		(81,111	)		(60,930	)		(192,962	)
Financing activities		134,389			79,369			40,050			5,199			158,103
Purchases of property, plant and equipment	$	215,106		$	138,579		$	86,417		$	61,112		$	188,601
Consolidated Balance Sheets Data:
Working capital (deficit) (2)	$	(17,255	)	$	(30,803	)	$	(23,678	)	$	(19,141	)	$	935
Properties – net		802,610			604,576			470,078			412,455			374,099
Total assets		888,334			666,934			529,538			471,884			440,111
Long-term debt		399,134			249,097			248,493			248,425			239,986
Stockholders’ equity		304,276			241,816			128,905			94,387			86,758

⁽¹⁾ Per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in June 2004.

⁽²⁾ Working capital includes the current portion of assets and liabilities, which reflect estimated fair value of derivative obligations.

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following Management’s Discussion and Analysis (“MD&A”) is intended to help the reader understand Quicksilver Resources Inc. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report on Form 10-K, including “Item 1. Business”, “Item 2. Properties”, “Item 6. Selected Financial Data”, and “Item 8. Financial Statements and Supplementary Data.” Our MD&A includes the following sections:

• Overview – a general description of our business; the value drivers of our business; measurements; and opportunities, challenges and risks.

• Financial Risk Management – information about debt financing and financial risk management.

• Application of critical accounting policies – a discussion of accounting policies that require critical judgments and estimates.

• Results of Operations – an analysis of our consolidated results of operations for the three years presented in our financial statements. We operate in one business – exploration, development and production of natural gas, crude oil and NGLs. Except to the extent those differences between our two geographic operating segments are material to an understanding of our business as a whole, we present the discussion to this MD&A on a consolidated basis.

• Liquidity and Capital Resources –an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments.

• Forward-Looking Statements – cautionary information about forward-looking statements and a description of certain risks and uncertainties that could cause our actual results to differ materially from our historical results or our current expectations or projections.

OVERVIEW

We are an independent oil and gas company engaged in the exploration, acquisition, development, production and sale of natural gas, crude oil and natural gas liquids primarily from unconventional reservoirs such as fractured shales, coal beds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, crude oil and natural gas liquids. We produce these products in quantities and at prices that, in addition to generating operating income, allow us to conduct exploration, development and acquisition activities to replace the reserves that have been produced.

At December 31, 2004, approximately 92% of our proved reserves were natural gas. Our Michigan reserves make up approximately 62% of those reserves. Our Michigan activities in the Antrim shale have allowed us to develop a technical and operational expertise in the acquisition, development and production of unconventional natural gas reserves. Consistent with one of our business strategies, we have applied our expertise gained in our Michigan activities to our Canadian coal bed methane (“CBM”) projects in Alberta, Canada. Our Canadian reserves made up about 27% of our proved reserves at December 31, 2004. Our Indiana/Kentucky New Albany Shale and Texas Barnett Shale projects represent additional extensions of that expertise.

For 2005, we plan to continue our focus on the exploration and development of CBM properties in Alberta, Canada and our Barnett Shale acreage in Texas. We expect budgeted capital expenditures in 2005 to be as much as $261 million, of which about $107 million is allocated to our Canadian CBM projects and approximately $115 million is allocated to our Barnett Shale position in north Texas. The remainder is allocated to our fractured shale projects in Michigan and Indiana/Kentucky.

Our Company focuses on three key value drivers:

• reserve growth;

• production growth; and

• improving the Company’s cash flows.

The Company’s reserve growth is dependent upon our ability to apply the Company’s technical and operational expertise in our exploration and development of unconventional natural gas reservoirs. We strive to increase reserves and production through aggressive management of operations and relatively low-risk development drilling. We will also continue to identify high potential exploratory projects with higher levels of financial risk. Both our low-risk development programs and exploratory projects are aimed at providing the Company with opportunities to explore for, and develop, unconventional natural gas reservoirs to which our technical and operational expertise is well suited.

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Our principal properties are well suited for production increases through exploitation activities and development drilling. We perform workover and infrastructure projects to reduce operating costs and increase current and future production. We regularly review operations on operated properties to determine if steps can be taken to profitably increase reserves and production.

As these elements are implemented, our results are measured through these key measurements: earnings; cash flow from operating activities; production and overhead costs per unit of production; production volumes; reserve growth; and finding costs per unit of reserve addition.

	Years Ended December 31,
	2004		2003		2002
	(in thousands)
Operating income	$	60,693	$	48,498	$	40,702
Cash flow from operations		82,798		48,687		41,650
Production cost per mcfe(1)	$	1.24	$	1.08	$	0.94
General and administrative cost per mcfe		0.29		0.20		0.19
Production (MMcfe)		44,257		40,192		39,209

⁽¹⁾ Excludes production taxes.

The possibility of decreasing prices received for production is among the several risks that we face. We seek to manage this risk by entering into natural gas sales contracts with price floors and natural gas and crude oil financial hedges. Our use of pricing collars and, to a lesser degree, fixed price swaps for both natural gas and crude oil helps to ensure a predictable base level of cash flow while allowing Quicksilver to participate in all, or a portion, of any favorable price increases. This commodity price strategy enhances our ability to execute our drilling and exploration programs, meet debt service requirements and pursue acquisition opportunities despite price fluctuations. If our revenues were to decrease significantly as a result of presently unexpected declines in natural gas prices or otherwise, we could be forced to curtail our development and exploratory drilling and acquisition activities. We might also be forced to sell some of our assets on an untimely or unfavorable basis.

Natural gas prices were favorable throughout 2004 and 2003 and industry analysts expect them to remain favorable for the foreseeable future. With continued favorable gas prices, the expiration of our remaining fixed price natural gas hedges in April 2005 and increasing natural gas production, we expect to fund more of our capital expenditures with cash flow from operations; however, we do not expect our cash flow from operations to be sufficient to satisfy our total budgeted capital expenditures. We plan to use cash flows from operations, credit facility utilization and possible issuance of debt or equity securities to fund our total budgeted capital expenditures in 2005.

FINANCIAL RISK MANAGEMENT

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 downside risk of adverse price movements through the use of long-term sales contracts, swaps and collars; however, in doing so, we have also limited future gains from favorable price movements.

Commodity Price Risk

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 5,300 Mcfd sold under these contracts in 2004 were third party volumes controlled by us. We also enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas and crude oil production. These contracts have included price ceilings and floors, no-cost collars and fixed price swaps.

Natural gas sales volumes of 30,000 Mcfd are hedged for the first four months of 2005 using fixed price swap agreements entered into in May 2000. The weighted average price for natural gas volumes under those agreements is $2.79. Natural gas price collars hedge approximately 20,000 Mcfd of our budgeted natural gas sales volumes for the first quarter of 2005. Natural gas price collars hedge nearly 33,000 Mcfd of our budgeted natural gas sales volumes for the remainder of 2005. Additionally, price collars hedge approximately 750 Bbld of our 2005 budgeted crude oil sales.

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The following table summarizes our open financial derivative positions as of December 31, 2004 related to natural gas and crude oil production.

Product	Type	Contract Period	Volume	Weighted Avg Price Per Mcf or Bbl		Fair Value
						(in thousands)
Gas	Swap	Jan 2005-Apr 2005	10,000 Mcfd	$	2.79	$	(4,016	)
Gas	Swap	Jan 2005-Apr 2005	10,000 Mcfd		2.79		(4,025	)
Gas	Swap	Jan 2005-Apr 2005	10,000 Mcfd		2.79		(4,025	)
Gas	Collar	Jan 2005-Mar 2005	5,000 Mcfd		5.50-9.60		62
Gas	Collar	Jan 2005-Mar 2005	10,000 Mcfd		5.50-9.63		115
Gas	Collar	Jan 2005-Mar 2005	5,000 Mcfd		5.50-9.90		86
Gas	Collar	Apr 2005-Oct 2005	5,000 Mcfd		5.50-6.75		(109	)
Gas	Collar	Apr 2005-Oct 2005	10,000 Mcfd		5.50-6.75		(219	)
Gas	Collar	May 2005-Oct 2005	15,000 Mcfd		5.50-7.15		(15	)
Gas	Collar	May 2005-Oct 2005	5,000 Mcfd		6.50-8.15		624
Gas	Collar	May 2005-Oct 2005	5,000 Mcfd		6.50-8.22		632
Gas	Collar	Nov 2005-Mar 2006	10,000 Mcfd		6.50-11.20		779
Gas	Collar	Nov 2005-Mar 2006	10,000 Mcfd		6.50-11.20		779
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd		5.50-8.10		332
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd		5.50-8.25		339
Oil	Collar	Jan 2005-Jun 2005	500 Bbld		40.00-52.80		93
Oil	Collar	Jan 2005-Jun 2005	500 Bbld		40.00-46.75		(5	)
Oil	Collar	Jul 2005-Dec 2005	250 Bbld		38.00-47.75		13
					Net open positions	$	(8,560	)

Utilization of our financial hedging program may result in realization of natural gas and crude oil prices that vary from the actual prices that we receive from the sale of natural gas and crude oil. As a result of the hedging programs, revenues from production were lower than if the hedging programs had not been in effect by $43.9 million in 2004, $39.8 million in 2003 and $7.4 million in 2002.

Commodity price fluctuations affect our remaining natural gas and crude oil volumes as well as our NGL volumes. Up to 4,500 Mcfd of natural gas is committed at market price through May 2005. Additional natural gas volumes of 16,500 Mcfd are committed at market price through September 2008. During 2004, approximately 6,400 Mcfd of our natural gas production was sold under these contracts. The remaining Mcfd contractual volumes were third-party volumes controlled by us.

Based on our 2004 average production and long-term natural gas sales contracts with floor prices of $2.49 per Mcf and $2.47 per Mcf, and our 2004 average production, each $1.00 per Mcf increase/decrease in the price of natural gas would increase/decrease our revenue by approximately $28.1 million. Should additional revenue of $28.1 million be realized, approximately $3.6 million would be required for settlement of our remaining fixed price hedges.

We have entered into various financial contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales and purchases with derivative instruments. These contracts include either fixed and floating price sales to, or purchases from, third parties. As a result of these firm sale and purchase commitments and associated financial price swaps, the hedge derivatives qualified as fair value hedges for accounting purposes. Marketing revenues were $0.5 million and $0.3 million higher and lower by $2.2 million as a result of our hedging activities in 2004, 2003 and 2002, respectively. Hedge ineffectiveness resulted in $118,000 of net losses, $188,000 of net gains and $26,000 net losses recorded to other revenue for 2004, 2003 and 2002, respectively.

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The following table summarizes our open financial derivative positions and hedged firm commitments as of December 31, 2004 related to natural gas marketing.

Contract Period	Volume	Weighted Avg Price per Mcf		Fair Value
				(in thousands)
Natural Gas Sales Contracts
Jan 2005	2,262 Mcfd	$	7.74	$	104
Feb 2005	3,935 Mcfd	$	7.53		136
Mar 2005	1,935 Mcfd	$	7.58		74
				$	314
Natural Gas Financial Derivatives
Jan 2005-Mar 2005	1,333 Mcfd		Floating Price	$	(171	)
Jan 2005-Mar 2005	333 Mcfd		Floating Price		(44	)
Jan 2005	645 Mcfd		Floating Price		(35	)
Feb 2005	1,428 Mcfd		Floating Price		(43	)
Feb 2005	714 Mcfd		Floating Price		(17	)
Mar 2005	323 Mcfd		Floating Price		(12	)
					(322	)
	Total-net			$	(8	)

The fair value of fixed price and floating price natural gas and crude oil derivatives and associated firm commitments as of December 31, 2004 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 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 our derivatives and commitments does not necessarily represent the value a third party would pay to assume our contract positions.

Interest Rate Risk

We manage our exposure associated with interest rates by entering into interest rate swaps. As of December 31, 2004, the interest payments for $75.0 million notional variable-rate debt are hedged with an interest rate swap that converts a floating three-month LIBOR base to a 3.74% fixed-rate through March 31, 2005. Our liability associated with the swap was $0.2 million at December 31, 2004 and $2.0 million at December 31, 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 converted the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base. In January 2004, the swap position was cancelled, and we received a cash settlement of $0.3 million that is being recognized over the original term for the swap, which ends December 31, 2006. A deferred gain of $0.2 million remains at December 31, 2004.

Interest expense for the years ended December 31, 2004, 2003 and 2002 was $0.8 million, $1.4 million and $2.6 million higher, respectively, as a result of the interest rate swaps.

If interest rates on our variable interest-rate debt of $112.8 million, as of February 28, 2004, and $75 million of variable rate debt hedged through March 31, 2005 increase or decrease by one percentage point, our annual pretax income will decrease or increase by $1.7 million.

Credit Risk

Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. We sell a portion of our natural gas production directly under long-term contracts with the remainder of our natural gas and crude oil production sold at spot or short-term contract prices. All our natural gas and crude oil production is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products. We also enter into hedge derivatives with financial counterparties. We monitor exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees and collateral to support the obligations of our counterparty are required according to our established policy. Each customer and/or counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. In this manner, we reduce credit risk.

While we follow our credit policies at the time we enter into sales contracts, the credit worthiness of counterparties could change over time. The credit ratings of the parent companies of the two counterparties to our long-term gas contracts were downgraded in early 2003 and remain below the credit ratings required for the extension of credit to new customers. Please see “Item 1. Business – Risk Factors.”

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Performance Risk

Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. We manage performance risk through management of credit risk. Each customer and/or counterparty is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter.

Foreign Currency Risk

Our Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, we are exposed to foreign currency exchange rate risk. During October and November 2004, Quicksilver loaned MGV approximately $11.4 million. To reduce its exposure to exchange rate risk, MGV entered into a forward contract that fixed the Canadian-to-US exchange rate. The balance of the loan was repaid at the end of November and upon settlement of the forward contract, MGV recognized a gain of $0.2 million.

While cross-currency transactions are minimized, the result of a ten percent change in the Canadian-U.S. exchange rate would increase or decrease equity by approximately $6.4 million at December 31, 2004.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

Management discusses with our Audit Committee the development, selection and disclosure of our critical accounting policies and estimates and the application of these policies and estimates. Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States. We believe our accounting policies are appropriately selected and applied.

Use of Estimates

In preparing the financial statements, our management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including asset retirement obligations, litigation, income taxes and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Oil and Gas Properties

We employ the full cost method of accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in cost centers on a country-by-country basis. This includes any internal costs that are directly related to exploration and development activities, but does not include any costs related to production, general corporate overhead or similar activities. Effective with the adoption of SFAS No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs and higher depletion rates compared to the successful efforts method of accounting for oil and gas properties. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production basis using proved oil and gas reserves as determined by independent petroleum engineers.

Net capitalized costs are limited to the lower of unamortized cost net of related deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge our oil and gas revenue and asset retirement obligations; (ii) the cost of properties not being amortized; (iii) the lower of cost or market value of unproved properties included in the costs being amortized less (iv) income tax effects related to differences between the book and tax basis of the oil and gas properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.

Oil and Gas Reserves

Proved oil and gas reserves, as defined by SEC Regulation S-X Rule 4-10(a) 2(i), 2(ii), 2(iii), (3) and (4), are the estimated quantities of crude oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, which include financial derivatives that hedge our oil and gas revenue.

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The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates, made by the Company’s engineers, are reviewed annually and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to reaching economic limits sooner. A material change in the estimated volumes of reserves could have an impact on the DD&A rate calculation and the financial statements.

Ceiling Test

Companies that use the full cost method of accounting for oil and gas properties are required to perform the ceiling test each quarter. The ceiling is an impairment test performed on a country-by-country basis as prescribed by SEC Regulation S-X Rule 4-10. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after-tax value of the future net cash flows from proved natural gas and crude oil reserves, including the effect of cash flow hedges, discounted at ten percent per annum. This ceiling is compared to the net book value of the oil and gas properties reduced by the related net deferred income tax liability and asset retirement obligations. If the net book value reduced by the related net deferred income tax liability and asset retirement obligations exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give the Company a significant loss for a particular period; however, future depletion expense would be reduced.

The ceiling test is affected by a decrease in net cash flow from reserves due to higher operating or capital costs or reduction in market prices for natural gas and crude oil. These changes can reduce the amount of economically producible reserves. At December 31, 2004, capitalized costs, inclusive of future development costs, for U.S. and Canadian reserves were $1.18 per Mcfe and $0.78 per Mcfe, respectively.

Derivative Instruments

We enter into financial derivative instruments to hedge risk associated with the prices received from natural gas and crude oil production and marketing. We also utilize financial derivative instruments to hedge the risk associated with interest rates on our debt outstanding. We account for our derivative instruments under the provisions of Statement of Financial Accounts Standard (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities. Under this statement, derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on our balance sheet as either assets or liabilities measured at fair value determined by reference to published future market prices and interest rates. The cash settlement of all derivative instruments is recognized as income or expense in the period in which the hedged transaction is recognized. Gains or losses on derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. The ineffective portion of hedges is recognized currently in earnings.

Portions of our hedge derivatives were classified as current based upon the maturity of the derivative instruments. Based upon the estimated fair values of those hedge derivatives as of December 31, 2004, our revenues for 2005 will decrease approximately $10.2 million and interest expense will increase approximately $0.2 million. Net income, after income taxes, will be approximately $6.8 million lower. These amounts will be reclassified from accumulated other comprehensive income in 2005.

Asset Retirement Obligations

We have significant obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. We adopted Statement of Financial Accounting Standard (“SFAS”) No. 143,Accounting for Asset Retirement Obligations” effective January 1, 2003. Under SFAS No. 143, the estimated fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets is recorded in the periods in which it is incurred. When the liability is recorded, we increase the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of the settlement over the useful life of the asset, and the capitalized cost is depleted or depreciated over the useful life of the related asset.

The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation of these costs, the productive life of the asset and our risk adjusted costs to settle such obligations discounted using our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset obligation are recorded with an offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of our oil and gas assets, the costs to ultimately retire these assets may vary significantly from previous estimates.

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Income Taxes

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in years in which the temporary differences are expected to reverse. MGV, the Company’s Canadian subsidiary, computes taxes at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested by MGV and thus are not considered available for distribution to the parent Company.

Included in our net deferred tax liability are $51.8 million of future tax benefits from prior unused tax losses. Realization of these tax assets depends on sufficient future taxable income before the benefits expire. We believe we will have sufficient future taxable income to utilize the loss carry forward benefits before they expire; however, if not, we could be required to recognize a loss for some or all of these tax assets. Net operating loss carry forwards and other deferred tax assets are reviewed annually for recoverability, and are recorded, net of a valuation allowance, if necessary.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements within the meanings of Item 303(a)(4) of SEC Regulation S-K.

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RESULTS OF OPERATIONS

Summary Financial Data

Years Ended December 31, 2004, 2003 and 2002

	Years Ended December 31,
	2004		2003		2002
	(in thousands)
Total operating revenues	$	179,729	$	140,949	$	121,979
Total operating expenses		120,214		93,782		81,477
Operating income		60,693		48,498		40,702
Income before accounting change		31,272		18,505		13,835
Net income		31,272		16,208		13,835

Net income for each of the years ending December 31, 2004, 2003 and 2002 was $31.3 million ($0.62 per diluted share), $16.2 million ($0.35 per diluted share) and $13.8 million ($0.34 per diluted share), respectively. Included in 2003 was a $2.3 million charge ($0.05 per diluted share), net of tax, for the adoption of 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 ($2.5 million after tax) to interest expense as a result of our early redemption of $53 million in principal amount of our subordinated notes payable.

Operating Revenues

Our 2004 revenues were $179.7 million as compared to $141.0 million for 2003, primarily as a result of additional Canadian revenue in 2004. The additional Canadian revenue was from a 5,776,000 net Mcfe increase in Canadian production from coal bed methane (“CBM”) projects and a 24% increase in realized prices. U.S. production revenue increased by approximately 5% over 2003 revenue with an 11% increase in realized prices being partially offset by a decrease in production of 1,711,000 Mcfe.

Total revenues for 2003 were $141.0 million, a $19.0 million increase from the $122.0 million reported in 2002. Higher realized prices and additional sales volumes increased revenue $26.7 million. The increase was primarily the result of sales volumes added from our Canadian CBM development projects and an 84% increase in Canadian realized sales prices. Additionally, U.S. realized prices increased approximately 19%. Additional revenue associated with U.S. prices increases was partially offset by an approximately 1,000,000 Mcfe decrease in U.S. sales volumes. Other revenue for 2003 was $7.8 million lower from the prior year. Revenue of $5.1 million was recognized from the sale of Section 29 tax credits in 2002. The tax credits expired in 2002. In 2003, a $0.5 million decrease in other revenue was the result of the completion of our negotiations to purchase the tax credit properties.

Gas, Oil and NGL Sales

Our sales volumes, revenues and average prices for the years ended December 31, 2004, 2003 and 2002 are as follows:

	Years Ended December 31,
	2004	2003	2002
Average daily sales volume
Natural gas – Mcfd
United States	83,727	86,608	87,425
Canada	23,789	8,011	2,563
Total	107,516	94,619	89,988
Crude oil – Bbld
United States	1,882	2,212	2,479
Canada	—	1	—
Total	1,882	2,213	2,479
NGL – Bbld
United States	351	365	426
Canada	1	4	—
Total	352	369	426
Total sales – Mcfed
United States	97,120	102,073	104,858
Canada	23,802	8,042	2,563
Total	120,922	110,115	107,421

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	Years Ended December 31,
	2004		2003		2002
Natural gas, oil and NGL sales (in thousands)
United States	$	134,268	$	127,339	$	110,263
Canada		42,905		11,698		2,033
Total natural gas, oil and NGL sales	$	177,173	$	139,037	$	112,296
Product sale revenues (in thousands)
Natural gas sales	$	150,716	$	116,563	$	90,289
Crude oil sales		22,782		19,576		19,679
NGL sales		3,675		2,898		2,328
Total oil, gas and NGL sales	$	177,173	$	139,037	$	112,296
Unit prices - including impact of hedges
Natural gas - per Mcf
United States	$	3.52	$	3.32	$	2.77
Canada		4.92		3.98		2.13
Consolidated		3.83		3.38		2.75
Crude oil - per Bbl
United States	$	33.07	$	24.23	$	21.74
Canada		—		24.46		—
Consolidated		33.07		24.23		21.74
NGL - per Bbl
United States	$	28.55	$	21.45	$	14.97
Canada		22.18		26.01		—
Consolidated		28.52		21.50		14.97

Our natural gas sales for 2004 were $150.7 million and increased $34.1 million from 2003 natural gas sales of $116.6 million. Our realized gas prices in the U.S. and Canada increased 6% and 24%, respectively. Increased prices contributed $23.8 million of the increase in 2004 sales. Natural gas sales volumes showed a net increase of 4,815,000 Mcf for 2004. Canadian 2004 sales volumes were nearly 5,760,000 Mcf over 2003 production of 2,935,000 Mcf; an increase of almost 200%. U.S. sales volumes were increased by production from new wells drilled in the New Albany Shale in Indiana and Kentucky, 1,380,000 Mcf; the Michigan Antrim Shale, 975,000 Mcf; the Michigan Prairie du Chien formation, 185,000 Mcf; and our initial production from the Barnett Shale in north Texas, 130,000 Mcf. Declining production rates on existing wells was the primary factor in production decreases that partially offset the production from new wells.

Our 2004 revenue from crude oil was $22.8 million and $3.2 million higher than 2003 crude oil revenue of $19.6 million. A 36% increase in realized crude oil prices from $24.23 to $33.07 per barrel boosted revenue $7.1 million. Lower volumes partially offset the increase due to prices by $3.9 million. The sale of Wyoming crude oil properties to Meritage Energy Partners LLC in the third quarter of 2004 lowered volumes by approximately 53,200 barrels. The remainder of the decrease was primarily due to natural declines from existing wells.

Sales of NGLs increased $0.8 million for 2004 to $3.7 million. The additional revenue was primarily the result of a 33% increase in realized NGL prices to $28.52 per barrel for 2004. A decrease in NGL volumes of approximately 6,000 barrels partially offset the increase from higher prices. Property dispositions in the third quarter of 2004 caused approximately 1,100 barrels of the volume decrease.

Natural gas sales for 2003 increased $26.3 million from 2002 to $116.6 million. Our average realized natural gas price increased 23% to $3.38 per Mcf for 2003 and increased sales $20.6 million. Volumes increased 1,690,000 Mcf from 2002 to 2003 and increased sales $5.7 million. Sales volumes for 2003 increased approximately 5,856,000 Mcf as a result of our drilling programs in the U.S. and Canada. Sales volumes from our Canadian CBM projects, which started production in January 2003, were approximately 2,113,000 Mcf for 2003. U.S. sales volumes increased 2,434,000 Mcf as a result of the additional interests in Michigan properties purchased from Enogex in December 2002. New wells drilled in the Michigan Antrim and Indiana New Albany formations increased sales volumes 1,071,000 Mcf and 239,000 Mcf, respectively. These increases were offset by curtailments in sales volumes as a result of extremely cold weather in the first quarter of 2003 and shutdowns of third party processing plants and pipelines in the second through fourth quarters of 2003. These events reduced sales volumes by approximately 260,000 Mcf and 814,000 Mcf, respectively. Additionally, March through September 2003 sales from our Indiana properties were curtailed when our local end-user reduced its deliveries of gas by approximately 161,000 Mcf. The remaining decreases were the result of natural decline in production from our existing natural gas wells.

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Crude oil sales were $19.6 million for 2003 compared to $19.7 million in 2002. The $2.49 per barrel increase in our average realized crude oil price increased sales $2.3 million, which was nearly offset by the decrease in oil sales volumes for 2003. The 11% decrease in sales volumes to 808,000 barrels for the year was the result, in part, of a decrease of approximately 20,300 barrels due to the sale of Wyoming and Texas oil properties in June 2002. Natural production declines on existing wells contributed most of the remaining decreases. These reductions were partially offset by a full year’s production from wells drilled in the Beaver Creek Detroit River Zone 3 development that increased sales volumes 31,800 barrels.

NGL sales for 2003 increased $0.6 million to $2.9 million. NGL prices increased $6.53 from 2002 to $21.50 and resulted in a $1.0 million increase in sales that was partially offset by a decrease in sales volumes.

Other Revenues

Other revenue, consisting primarily of revenue from the marketing, transportation and processing of natural gas, was $2.6 million for 2004 and about $0.6 million higher than other revenue for 2003. Other revenue in 2003 was reduced by $0.5 million as a result of the repurchase of Section 29 tax credit properties.

Other revenue of $1.9 million in 2003 consisted of revenue from the marketing, transportation and processing of natural gas. In 2002, other revenue also included revenue of $5.1 million from the sale of Section 29 tax credits. The tax credits expired in 2002. In 2003, a $0.5 million reduction in other revenue was the result of the repurchase of the tax credit properties. Natural gas marketing, transportation and processing revenue for 2003 was $2.5 million as compared to $4.6 million in 2002. Marketing revenue in 2003 decreased $1.8 million from 2002 primarily as a result of pipeline delivery imbalances that occurred during 2003. Repayments of those imbalances required the purchase of natural gas when natural gas prices had increased from the time in which the imbalances occurred resulting in marketing margin losses.

Operating Expenses

Our operating expenses for 2004 were $120.2 million and $26.4 million higher than operating expenses for 2003. Increases were primarily the result of higher sales volumes and producing well counts in Canada and Indiana, higher depletion rates and added depreciation on facilities and pipelines placed into service since mid-2003, and an increase in U.S. compressor overhauls performed in 2004 as compared to 2003. General and administrative costs also increased by $4.8 million in 2004.

Operating expenses were $93.8 million in 2003 compared to $81.5 million for 2002. The increase was primarily the result of additional sales volumes.

Oil and Gas Production Costs

	Years Ended December 31,
	2004		2003		2002
	(in thousands, except per unit amounts)
Production expenses
United States	$	54,783	$	48,243	$	40,505
Canada		10,403		3,951		1,723
	$	65,186	$	52,194	$	42,228
Production expenses – per Mcfe
United States	$	1.54	$	1.29	$	1.06
Canada		1.19		1.35		1.84
Consolidated		1.47		1.30		1.08

Costs for the production of oil and gas were $65.2 million and $13.0 million higher in 2004 as compared to 2003. Higher oil and gas prices, as well as higher Canadian sales volumes for 2004, increased production tax expense $1.5 million. U.S. production expense increased $6.0 million in 2004, excluding production tax increases of $0.6 million. Initial operating expenses associated with new Indiana and Kentucky wells and production increased production expense approximately $2.2 million. The increase included approximately $0.9 million for salt-water disposal and equipment rentals. These expenses were the result of inadequate salt-water disposal capacity and delays in completing electricity connections at each well. During 2004, 35 new wells and 22 non-producing wells acquired in 2003 began production, in addition to 47 wells that began production in the fourth quarter of 2003. Operating costs began to decrease as initial production containing high concentrations of water was followed by natural gas production increases. Production overhead in Indiana increased approximately $0.8 million as a result of personnel added to operate and maintain these properties. Michigan and Indiana operating expenses increased approximately $1.5 million and $0.2 million, respectively, as a result of the routine periodic

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overhaul of several compressors. Similar overhaul expenses were not incurred during 2003. These items increased U.S. production expenses by $0.14 per Mcfe for 2004 compared to 2003. Remaining production expense increases were attributable to modest price increases across a broad range of expense categories.

Canadian production expenses in 2004, excluding a production tax increase of $0.9 million, increased $5.5 million for 2004. A net increase in Canadian production of approximately 5,780,000 Mcf and higher well counts were the primary factors for the increase. Total Canadian production expense, including production taxes, continued to reflect improving economies of scale as expense decreased on a Mcfe-basis to $1.19 per Mcfe.

Oil and gas production expense for 2003 was $52.2 million, compared to 2002 expense of $42.2 million. Production taxes were $3.0 million higher as a result of higher sales volumes and higher average natural gas and crude oil prices in 2003. Production expenses for U.S. properties in 2003 increased $5.0 million, excluding production tax increases of $2.7 million. Notable production expense increases included $3.1 million of additional expense associated with natural gas volumes produced from the acquired Enogex interests and $0.8 million resulting from settlement costs for post-production cost allowances in Michigan and environmental issues in Indiana and Michigan. Inventory losses, primarily in Indiana, increased expense $0.3 million in 2003. Additional operating expenses of approximately $0.8 million were primarily due to the start-up of producing wells in Indiana during the fourth quarter.

Canadian production expenses in 2003, excluding production taxes of $0.3 million, increased $1.9 million. Canadian production increased approximately 2,000,000 Mcf, primarily as a result of the start-up of production from our CBM projects in January 2003. Although absolute Canadian production expense increased, expense per Mcfe, including production taxes, decreased $0.49 to $1.35 per Mcfe for 2003 as a result of 2003 CBM production.

Depletion, Depreciation and Accretion

	Years Ended December 31,
	2004		2003		2002
	(in thousands, except per unit amounts)
Depletion	$	34,530	$	27,379	$	26,953
Depreciation of other fixed assets		5,179		3,949		3,206
Accretion		982		739		—
Total depletion, depreciation and accretion	$	40,691	$	32,067	$	30,159
Average depletion cost per Mcfe	$	0.78	$	0.68	$	0.69

Depletion expense for 2004 was $34.5 million, as compared to 2003 depletion expense of $27.4 million. Additional sales volumes of approximately 4,070,000 Mcfe and a $0.10 per Mcfe increase in the consolidated depletion rate added $7.2 million of depletion expense from 2003 to 2004. The $0.10 per Mcfe higher consolidated depletion rate was the result of additional increases in future development costs as compared to increases in proved reserves when comparing engineering estimates of proved reserves for December 31, 2004 and 2003. The $1.2 million increase in 2004 depreciation was primarily the result of the addition of compression and transportation assets and overhead assets.

Depletion expense increased $0.4 million to $27.4 million in 2003. Increased depletion expense was the result of higher sales volumes partially offset by a slight decrease in our consolidated depletion rate. Additional depreciation of $0.7 million was primarily the result of additions to processing and transportation assets including the Cardinal Pipeline, which began operations in September 2003. Accretion expense of $0.7 million in 2003 was the result of the adoption of SFAS No. 143 as of January 1, 2003.

General and Administrative Expenses

General and administrative expenses were $12.9 million for 2004. Of the $4.8 million increase from 2003, additional expenses of $2.3 million were primarily the result of an increase in management and administrative personnel from August 2003 through March 2004. Contract labor, legal and accounting fees increased approximately $1.0 million for 2004 due largely to new Sarbanes-Oxley and corporate governance requirements. Engineering and other professional fees increased approximately $0.4 million from 2003 due primarily to additional fees for preparation of required outside engineering reserve reports. Various other expenses including outside directors’ fees, charitable donations, insurance, investor relations and stock exchange fees increased a total of $0.6 million from 2003 expense amounts.

General and administrative expenses were $8.1 million for 2003 and $0.6 million higher than 2002 general and administrative expenses. The increase is primarily the result of $0.7 million in additional bonuses earned in 2003 and $0.3 million due to the addition of management personnel in the last half of the year. Professional fees were $0.2 million higher than in 2002 and were related to the use of additional engineering and accounting services. These increases were partially offset by the $0.3 million reduction in expense for contract labor in 2003.

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Income from Equity Affiliates

Income from equity affiliates for 2003 increased $1.1 million from the prior year when we recorded losses of $0.8 million associated with Voyager Compression Services LLC. During 2002, Voyager recorded operating losses in addition to an impairment of its assets and lease termination costs in conjunction with ending its operations.

Interest Expense

Interest expense for 2004 was $15.7 million and $4.5 million less than 2003 interest expense. Interest expense in 2003 included a charge of $3.8 million as a result of the early redemption of $53.0 million in principal amount of our subordinated notes payable, which included a $3.2 million prepayment penalty and the write-off of $1.5 million of remaining deferred financing costs, partially offset by a deferred hedging gain of $0.9 million. Ongoing interest expense decreased approximately $0.7 million due to a decrease in LIBOR interest rates and the 2003 issuance of our second mortgage notes, which accrue interest at a substantially lower rate than the subordinated notes payable that were retired in mid-2003, partially offset by an increase in our average debt outstanding during 2004 as compared to 2003.

Interest expense was $20.2 million in 2003. Interest expense for 2003 included a charge of $3.8 million as a result of the early redemption of $53.0 million in principal amount of our subordinated notes payable through the issuance of $70.0 million in principal amount of second mortgage notes. The $3.8 million charge consisted of a prepayment premium of $3.2 million and the write-off of $1.5 million of remaining deferred financing costs, partially offset by an associated deferred hedging gain of $0.9 million. Ongoing interest expense decreased $2.8 million as a result of a significant decrease in our effective interest rates that was partially offset by an increase in our average debt outstanding in 2003. The interest rates paid on our debt were lower in 2003 because of lower LIBOR rates and the refinancing of our subordinated notes payable through the issuance of our second mortgage notes.

Income Taxes

	Years Ended December 31,
	2004			2003			2002
Income tax provision (in thousands)	$	14,174		$	9,997		$	7,498
Effective tax rate		31.2	%		35.1	%		35.2	%

Our income tax provision for 2004 was $14.2 million. Our U.S. income tax provision was established using the statutory U.S. federal tax rate of 35.0%. In addition to the deferred tax provision of approximately $8.8 million, a current U.S. tax provision of $0.8 million was accrued for U.S. federal income tax due on a dividend distribution of approximately $86.5 million made to us by MGV in 2004 and consisted of estimated earnings and profits of $15.5 million. We have planned for reinvestment of the dividend in the U.S. under a qualified domestic reinvestment plan as defined under recently enacted Internal Revenue Code Section 965(a)(1), which allows 85% of the dividend to be excluded from U.S. taxable income for the year. The Canadian income tax provision consisted of a deferred tax provision of approximately $5.9 million accrued at a Canadian combined federal and provincial statutory rate of 33.6% and a current tax provision of $0.3 million. The deferred tax provision was reduced by a scientific, research and experimental development tax credit of $1.7 million. This credit was granted by Revenue Canada to MGV in 2004 for expenditures incurred in 2001.

Our income tax provision of $10.0 million for 2003 was established using an effective U.S. federal tax rate of 35%. The provision also includes $1.7 million for Canadian federal and provincial income tax expense. Canadian income tax expense includes consideration of tax rate reductions that were enacted during 2003. Income tax expenses increased from the prior year as a result of higher 2003 pretax income as compared to 2002.

LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION

Our statements of cash flows are summarized as follows:

	Year ended December 31,
	2004		2003		2002
	(in thousands)
Net cash flow provided by operating activities	$	82,798	$	48,687	$	41,650

Cash flows from operating activities increased $34.1 million, or 70%, for 2004 compared to 2003. The principal factor in the increase was a $12.2 million increase in operating income for 2004, together with increases in accounts receivable and payable, accrued liabilities and depletion, depreciation and amortization. In addition, 2003 income included a $3.2 million prepayment premium incurred when the $53 million of subordinated notes were redeemed. Operating cash flows were also higher because of MGV’s use of cash calls on other working interest owners prior to incurring capital expenditures on various CBM exploration and development projects. A reduction in QRI’s third party marketing activities further increased operating cash flows about $2.0 million.

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Cash flows from operating activities were $7.0 million, or 17%, higher for 2003 compared to 2002. A 19% increase in operating income for 2003 as compared to 2002 was the principal factor. The $7.8 million increase in operating income was largely due to a 21% increase in realized average prices and a 3% increase in sales volumes. Operating income for 2002 included $5.1 million of deferred revenue that was offset by additional oil, gas and NGL revenue for 2003, which effectively increased operating cash flows by $5.1 million for 2003.

Our principal operating sources of cash include sales of natural gas, crude oil and NGLs and revenues from natural gas transportation and processing. We sold approximately 74% and 85% of our 2004 and 2003 natural gas and crude oil production, respectively, under long-term contracts with price floors and financial hedges. As a result, we benefit from significant predictability of our natural gas and crude oil revenues. However, when natural gas and crude oil market prices exceed our financial hedge swap prices, we are required to make payment for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payment from our customers until 25 to 60 days after the month of production. Additionally, in the event of a significant production curtailment, we are required contractually to fulfill our commitments under our long-term sales contracts by purchasing natural gas volumes at market prices.

	Year ended December 31,
	2004			2003			2002
	(in thousands)
Cash flow (used in) provided by investing activities:
Purchases of property, plant and equipment	$	(215,106	)	$	(138,579	)	$	(86,417	)
Distributions and advances from equity affiliates - net		2,097			1,649			4,043
Proceeds from sale of properties and equipment		9,160			101			1,263
Net cash used in investing activities:	$	(203,849	)	$	(136,829	)	$	(81,111	)
Net working capital changes related to acquisition of property, plant and equipment	$	(16,651	)	$	(10,593	)	$	(2,548	)

Purchases of property, plant and equipment accounted for the most significant cash outlays for investing activities in each of the three years ended December 31, 2004. We currently estimate that our spending for property, plant and equipment in 2005 will be as much as $261 million. Total property and equipment costs incurred (purchases of property and equipment plus net working capital changes related to acquisition of property and equipment) by operating segment for 2004, 2003 and 2002 are as follows:

Property and equipment costs incurred

	United States		Canada		Consolidated
	(in thousands)
2004
Proved acreage	$	11,907	$	2,942	$	14,849
Unproved acreage		31,857		7,144		39,001
Development costs		45,213		71,094		116,307
Exploration costs		25,673		22,631		48,304
Gas processing, transportation and administrative		12,527		769		13,296
Total	$	127,177	$	104,580	$	231,757
2003
Proved acreage	$	3,215	$	3,388	$	6,603
Unproved acreage		24,063		6,739		30,802
Development costs		37,682		41,820		79,502
Exploration costs		9,411		17,066		26,477
Gas processing, transportation and administrative		4,820		284		5,104
Total	$	79,191	$	69,297	$	148,488
2002
Proved acreage	$	32,199	$	—	$	32,199
Unproved acreage		550		5,422		5,972
Development costs		34,178		938		35,116
Exploration costs		5,925		8,659		14,584
Gas processing, transportation and administrative		952		142		1,094
Total	$	73,804	$	15,161	$	88,965

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Our 2004 property and equipment costs incurred for exploration and development activities were focused in four areas. Capital costs incurred for Canadian exploration and development projects were approximately $104.6 million. Those expenditures continued exploration and development of our initial CBM projects as well as exploration of several additional CBM projects. Included in the $104.6 million of Canadian expenditures was $7.1 million for acquisition of additional acreage in several areas of Alberta. Expenditures for Texas exploration and development activities were approximately $55.1 million, including approximately $29.3 million for additional acreage in north Texas. An additional $6.0 million was expended for the first phase of the Cowtown Pipeline. We spent approximately $31.5 million for continued development of our Michigan properties and an additional $2.1 million was spent on transportation and processing infrastructure. New wells and associated infrastructure in southern Indiana and northern Kentucky accounted for approximately $20.6 million of our expenditures for exploration and development activities. An additional $1.1 million was expended for the construction of plant and pipeline infrastructure in the Indiana/Kentucky area.

Capital costs incurred in 2003 of $148.5 million included $69.0 million for development and exploration of our Canadian CBM projects and acreage. We spent $31.8 million for further development of our Indiana/Kentucky properties and additional acreage positions. Our pipeline in the area, Cardinal Pipeline, accounted for $4.0 million of our capital expenditures. Michigan capital expenditures of $24.6 million focused on continued development and exploitation of the Antrim Shale. A significant acreage position in north Texas was acquired for approximately $12.6 million in 2003.

We acquired Michigan natural gas interests from Enogex Exploration Corporation in December 2002 for approximately $32.0 million. Canadian capital costs incurred were $15.0 million associated with CBM exploration costs and acreage acquisition. The remaining $42.0 million was spent on exploration and development costs incurred primarily in Michigan and Indiana.

	Year ended December 31,
	2004			2003			2002
	(in thousands)
Cash flow provided by financing activities:
Issuance of debt	$	511,091		$	114,000		$	16,000
Repayment of debt		(371,178	)		(113,116	)		(14,912	)
Issuance of common stock, net of issuance costs		2,499			79,926			40,640
Purchase of treasury stock		—			—			(316	)
Debt issuance costs		(8,023	)		(1,441	)		(1,362	)
Net cash provided by financing activities:	$	134,389		$	79,369		$	40,050

During 2004, we extended and increased our senior secured credit facility. Currently, our credit facility is a revolving facility that matures on July 28, 2009 and permits us to obtain revolving credit loans and letters of credit from time to time in an aggregate amount not to exceed the lesser of the borrowing base or $600 million. The current borrowing base is $300 million and is subject to annual redetermination and certain other redeterminations based upon several factors. Scheduled redeterminations occur on May 1 of each year. Our borrowing base is impacted primarily by the fair value of our oil and gas reserves. Changes in the fair value of our oil and gas reserves are affected by prices for natural gas and crude oil, operating expenses and the results of our drilling activity. A significant decline in the fair value of our reserves could reduce our borrowing base. A borrowing base reduction could limit our ability to carry out our capital expenditure programs and, in some circumstances, require the repayment of a portion of our outstanding borrowings under the facility.

At our option, loans may be prepaid, and revolving credit commitments may be reduced, in whole or in part at any time in minimum amounts. As of year-end, we can designate the interest rate on amounts outstanding at either the London Interbank Offered Rate (LIBOR) +1.375% or specified bank rates. The collateral for the credit facility consists of substantially all of our existing assets and any future reserves acquired. The loan agreements prohibit the declaration or payment of dividends by us and contain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio (calculated in accordance with provisions of the loan agreements) of at least 1.0. At December 31, 2004, we were in compliance with all such restrictions and we had $119.1 million available under the credit facility.

On November 1, 2004, we sold $150 million of 1.875% convertible subordinated debentures due in 2024 for gross proceeds of approximately $147.8 million. Holders of the debentures may require us to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 21.8139 shares for each $1,000 debenture, subject to adjustment. This results in an initial conversion price of approximately $45.84 per share and represents a premium of 42.5 percent over the closing sale price of $32.17 per share on October 26, 2004. Generally, except upon the occurrence of

17

specified events, holders of the debentures are not entitled to exercise their conversion rights until the Company’s stock price is $55.01 (120 % of the conversion price per share). Upon conversion, we have the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock.

On December 31, 2004, we had outstanding $70 million of Second Mortgage Notes due 2006, of which $40 million bore interest at a fixed rate of 7.5% and $30 million bore interest at a variable rate based upon three-month LIBOR plus 5.48%. The Second Mortgage Notes contain restrictive covenants that, among other things, require maintenance of a minimum current ratio of at least 1.0, a ratio of net present value of proved reserves to total debt of at least 1.8 to 1.0; and a ratio of earnings before interest, taxes, depreciation and amortization and non-cash income and expense to interest expense of at least 1.25 (calculated in each case in accordance with the provisions of the Second Mortgage Notes). At December 31, 2004, we were in compliance with such restrictions.

As of December 31, 2004, 2003 and 2002, our total capitalization was as follows:

	Year ended December 31,
	2004		2003		2002
	(in thousands)
Long-term and short-term debt:
Senior secured credit facility	$	180,422	$	178,000	$	192,000
Convertible subordinated debentures		147,769		—		—
Second mortgage notes payable		70,000		70,000		—
Subordinated notes payable		—		—		53,000
Mercury note payable		—		—		1,920
Various loans		1,073		1,386		1,582
Deferred gain – fair value interest hedge		226		—		—
Fair value interest hedge		—		50		942
Total debt		399,490		249,436		249,444
Stockholders’ equity		304,276		241,816		128,905
Total capitalization	$	703,766	$	491,252	$	378,349

We believe that our capital resources are adequate to meet the requirements of our existing business. We anticipate that our 2005 capital expenditure budget of approximately $261 million will be funded by cash flow from operations, credit facility utilization and the possible issuance of debt or equity securities.

Financial Position

The following impacted our balance sheet as of December 31, 2004, as compared to our balance sheet as of December 31, 2003:

• A $150.0 million increase in our debt used to finance the exploration and development of our oil and gas properties in 2004.

• A $198.0 million increase in our net property, plant and equipment balances resulting from capital expenditures for exploration and development of our oil and gas properties.

• A $21.8 million and $9.7 million decrease in our current and deferred derivative obligations, respectively, reflecting the four-month remaining term on our $2.79 per Mcf natural gas swaps as of December 31, 2004.

Contractual Obligations and Commercial Commitments

Information regarding our contractual obligations (within the scope of Item 303(a)(5) of Regulations S-K) as of December 31, 2004 is set forth in the following table. At December 31, 2004, we did not have any capital lease obligations or material purchase obligations that were binding on us and that specified all significant terms. Other long-term liabilities constituting contractual obligations reflected on our balance sheet at December 31, 2004 consisted of derivative obligations and asset retirement obligations.

	Payments Due by Period
Contractual Obligations	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
	(in thousands)
Long-Term Debt	$	401,495	$	356	$	70,718	$	180,421	$	150,000
Derivative Obligations		13,090		13,090		—		—		—
Asset Retirement Obligations		18,471		504		168		112		17,687
Gas Purchase Obligations		1,803		1,803		—		—		—
Operating Lease Obligations		6,894		2,160		4,059		675
Total Obligations	$	441,753	$	17,913	$	74,945	$	181,208	$	167,687

18

• Long-Term Debt – As of December 31, 2004, we had $180.4 million outstanding under our credit facility, $150.0 million of contingently convertible debentures (before discount), $70 million of second mortgage notes and $1.1 million of other debt. Based upon our debt outstanding at December 31, 2004, we anticipate interest payments to be approximately $15.7 million in 2005. We expect to increase borrowings under our credit facility to fund our capital program throughout 2005. For each additional $10 million in borrowings, annual interest payments will increase by approximately $0.4 million. If our borrowing base were to be fully utilized by year-end 2005, we estimate that interest payments would increase by approximately $4.0 million. If interest rates on our variable interest-rate debt of $112.8 million, as of February 28, 2005, and $75 million of variable rate debt hedged through March 31, 2005 increase or decrease by one percentage point, our annual pretax income will decrease or increase by $1.7 million. Interest payments would increase by a further $2.8 million annually should we utilize all of the $119.1 million available under our senior credit facility at December 31, 2004.

• Derivative Obligations – We utilize financial derivatives to manage price risk associated with our natural gas and crude oil product revenue. We also manage interest rate risk associated with our long-term debt. The recorded assets and liabilities associated with our derivative obligations were estimated based on published market prices of natural gas and crude oil for the periods covered by the contracts. Estimates of the liability associated with our interest rate derivative obligations are based upon estimates prepared by our counterparties. These amounts do not necessarily reflect what payments will be made to settle these obligations.

• Asset Retirement Obligations – Our liabilities include the fair value, $18.5 million, of asset retirement obligations that result from the acquisition, construction or development and the normal operation of our long-lived assets.

• Gas Purchase Obligations – Cinnabar, our subsidiary that ceased operations January 1, 2004, previously contracted to purchase gas through May 2005 for resale to the open market. Quicksilver has assumed the obligation.

• Operating Leases – We lease office buildings and other property under operating leases. $3.6 million of our operating lease obligations are with an affiliate of Mercury, which is owned by members of the Darden family.

We have the following commercial commitments as of December 31, 2004.

	Amounts of Commitments Expiration per Period
Commercial Commitments	Total Committed		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
	(in thousands)
Standby Letters of Credit	$	637	$	637	$	—	$	—	$	—
Total Commitments	$	637	$	637	$	—	$	—	$	—

Standby Letters Of Credit – Our letters of credit have been issued to fulfill contractual or regulatory requirements. The majority of these letters of credit were issued under our senior credit facility. All letters have an annual renewal option.

Forward-Looking Information

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

• changes in general economic conditions;

• fluctuations in natural gas and crude oil prices;

19

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

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

• competitive conditions in our industry;

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

• changes in the availability and cost of capital;

• operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

• the effects of existing and future laws and governmental regulations;

• the effects of existing or future litigation; and

• certain factors discussed elsewhere in this annual report.

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

RECENTLY ISSUED ACCOUNTING STANDARDS

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

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

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

Management has commenced analysis of the impact of SFAS No. 123(R), but has not yet decided: (1) whether to elect early adoption, (2) if early adoption is elected, at what date to adopt the standard, (3) whether to use the modified prospective method or elect to use the modified retrospective method, and (4) whether to use straight-line amortization or an accelerated method. Additionally we cannot predict with reasonable certainty the number of options that will be unvested and outstanding on December 31, 2005. Accordingly, management cannot currently quantify with precision the effect this standard would have on the Company’s financial position or results of operations in the future, except that a greater expense will probably be recognized for any awards that we may grant in the future.

In November 2004, the FASB issued SFAS No. 151,Inventory Costs, an amendment of ARB No. 43, Chapter 4, which amends Chapter 4 of ARB No. 43 that deals with inventory pricing. The statement clarifies the accounting for abnormal amounts of idle facility expenses, freight, handling costs and spoilage. Under paragraph 5 of ARB No. 43, such items might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. SFAS No. 151 eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. The statement also requires allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, although earlier application is permitted for fiscal years beginning after the issuance date of the statement.

20

Retroactive application is not permitted. Management is analyzing the requirements of SFAS No. 151 and believes that its adoption will not have any significant impact on the financial position, results of operations or cash flows of the Company.

The FASB issued SFAS No. 153,Exchanges of Nonmonetary Assets, an amendment of APB No. 29 in December 2004. The statement amends Opinion 29 by eliminating the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 provides that a nonmonetary exchange has commercial substance if future cash flows of the entity are expected to change significantly as a result of the exchange. The statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date of the issuance of the statement. Retroactive application is not permitted. Management is analyzing the requirements of SFAS No. 151 and believes that its adoption will not have any significant impact on the financial position, results of operations or cash flows of the Company.

FASB Staff Position (“FSP”) No. 109-2,Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004, was issued in December 2004. This FSP provides guidance on accounting for special reductions in taxes included in the American Jobs Creation Act of 2004. In particular, the Act allows a one-time decrease in U.S. Federal taxes on repatriated foreign earnings. FSP No. 109-2 clarifies that a company’s consideration of the Act does not overrule their prior contention that the foreign earnings were permanently reinvested. Also, this FSP indicates that companies should provide tax expense when a decision is made to repatriate some or all foreign earnings, and provide disclosure about the possible range of repatriation if the analysis is not yet complete. We repatriated $86.5 million through a Canadian divdend distribution in 2004 and provided approximately $0.8 million of current income tax expense in 2004.

In September 2004, the SEC issued Staff Accounting Bulletin (“SAB”) No. 106. This pronouncement requires companies that use the full cost method of accounting for oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. It also requires full cost companies to exclude any cash outflows associated with settling asset retirement obligations from their full cost ceiling test calculation. In addition, it requires specific disclosures regarding the impact of asset retirement obligations on oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. We will adopt the provisions of this pronouncement in the first quarter of 2005. We believe the adoption of SAB No. 106 will have no immediate effect on our consolidated financial statements.

21

ITEM 8. Financial Statements and Supplementary Data

QUICKSILVER RESOURCES INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Management’s Statement of Responsibilities	23
Report of Independent Registered Public Accounting Firm	24
Consolidated Balance Sheets as of December 31, 2004 and 2003	25
Consolidated Statements of Income and Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002	26
Consolidated Statements of Stockholders’ Equity for the Years ended December 31, 2004, 2003 and 2002	27
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002	28
Notes to Consolidated Financial Statements for the Years Ended December 31, 2004, 2003 and 2002	29

22

MANAGEMENT’S STATEMENT OF RESPONSIBILITIES

To the Stockholders of Quicksilver Resources Inc.:

Management of Quicksilver Resources Inc. is responsible for the preparation, integrity and fair presentation of its published consolidated financial statements. The financial statements have been prepared in accordance with U.S. generally accepted accounting principles and, as such, include amounts based on judgments and estimates made by management. The Company also prepared the other information included in the annual report and is responsible for its accuracy and consistency with the consolidated financial statements.

Management is also responsible for establishing and maintaining effective internal control over financial reporting. The Company’s internal control over financial reporting includes those policies and procedures that pertain to the Company’s ability to record, process, summarize and report reliable financial data. The Company maintains a system of internal control over financial reporting, which is designed to provide reasonable assurance to the Company’s management and board of directors regarding the preparation of reliable published financial statements and safeguarding of the Company’s assets. The system includes a documented organizational structure and division of responsibility, established policies and procedures, including a code of conduct to foster a strong ethical climate, which are communicated throughout the Company, and the careful selection, training and development of our people.

The Board of Directors, acting through its Audit Committee, is responsible for the oversight of the Company’s accounting policies, financial reporting and internal control. The Audit Committee of the Board of Directors is comprised entirely of outside directors who are independent of management. The Audit Committee is responsible for the appointment and compensation of the independent registered public accounting firm. It meets periodically with management, the independent registered public accounting firm and the internal auditors to ensure that they are carrying out their responsibilities. The Audit Committee is also responsible for performing an oversight role by reviewing and monitoring the financial, accounting and auditing procedures of the Company in addition to reviewing the Company’s financial reports. Internal auditors monitor the operation of the internal control system and report findings and recommendations to management and the Audit Committee. Corrective actions are taken to address control deficiencies and other opportunities for improving the system as they are identified. The independent registered public accounting firm and the internal auditors have full and unlimited access to the Audit Committee, with or without management, to discuss the adequacy of internal control over financial reporting, and any other matters which they believe should be brought to the attention of the Audit Committee.

Management recognizes that there are inherent limitations in the effectiveness of any system of internal control over financial reporting, including the possibility of human error and the circumvention or overriding of internal control. Accordingly, even effective internal control over financial reporting can provide only reasonable assurance with respect to financial statement preparation and may not prevent or detect misstatements. Further, because of changes in conditions, the effectiveness of internal control over financial reporting may vary over time.

Management assessed the Company’s internal control system as of December 31, 2004 in relation to criteria for effective internal control over financial reporting described in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, the Company has determined that, as of December 31, 2004, the Company’s system of internal control over financial reporting was effective.

The consolidated financial statements have been audited by the independent registered public accounting firm, Deloitte & Touche LLP, which was given unrestricted access to all financial records and related data, including minutes of all meetings of stockholders, the Board of Directors and committees of the Board. Reports of the independent registered public accounting firm, which includes the independent registered public accounting firm’s attestation of management’s assessment of internal controls, are also presented within this document.

/s/ Glenn Darden	/s/ Bill Lamkin
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer
Fort Worth, Texas March 16, 2005

23

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Quicksilver Resources Inc.

Fort Worth, Texas

We have audited the accompanying consolidated balance sheets of Quicksilver Resources Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003 and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standard No. 143,Accounting for Asset Retirement Obligations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 16, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Fort Worth, Texas

March 16, 2005 (August 8, 2005 as to the effects of the reclassifications described in Note 21)

24

QUICKSILVER RESOURCES INC.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31, 2004 AND 2003

In thousands, except for share data

	2004			2003(1)
ASSETS
Current assets
Cash and cash equivalents	$	15,947		$	4,116
Accounts receivable		38,037			26,247
Current deferred income taxes		3,523			11,760
Inventories and other current assets		8,689			7,588
Total current assets		66,196			49,711
Investments in and advances to equity affiliates		8,254			9,173
Property, plant and equipment
Oil and gas properties, full-cost method
Subject to depletion		838,134			665,457
Unevaluated costs		97,168			49,919
Pipelines and processing facilities		70,851			56,980
General properties		12,597			7,645
Accumulated depletion and depreciation		(216,140	)		(175,425	)
Property, plant and equipment – net		802,610			604,576
Other assets		11,274			3,474
	$	888,334		$	666,934
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of long-term debt	$	356		$	339
Accounts payable		28,407			17,954
Accrued derivative obligations		12,784			34,577
Accrued liabilities		41,904			27,644
Total current liabilities		83,451			80,514
Long-term debt		399,134			249,097
Deferred derivative obligations		—			9,662
Asset retirement obligations		17,967			15,135
Deferred income taxes		83,506			70,710
Commitments and contingencies (Note 13)		—			—
Stockholders’ equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 1 share issued as of December 31, 2004 and 2003		—			—
Common stock, $0.01 par value, 100,000,000 and 80,000,000 shares authorized, and 52,690,971 and 52,045,726 shares issued as of December 31, 2004 and 2003, respectively		527			520
Paid in capital in excess of par value		200,941			194,246
Treasury stock of 2,568,611 and 2,578,904 shares as of December 31, 2004 and 2003, respectively		(10,258	)		(10,299	)
Accumulated other comprehensive income (loss)		6,762			(17,683	)
Retained earnings		106,304			75,032
Total stockholders’ equity		304,276			241,816
	$	888,334		$	666,934

⁽¹⁾ Share and per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in June 2004. The split did not affect treasury shares.

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

25

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

In thousands, except for per share data

	2004			2003(1)			2002(1)
Revenues
Oil, gas and NGL sales	$	177,173		$	139,037		$	112,296
Other revenue		2,556			1,912			9,683
Total revenues		179,729			140,949			121,979
Expenses
Oil and gas production costs		65,186			52,194			42,228
Other operating costs		1,250			1,301			1,538
Depletion, depreciation and amortization		40,691			32,067			30,159
Provision for doubtful accounts		153			87			—
General and administrative		12,934			8,133			7,552
Total expenses		120,214			93,782			81,477
Income from equity affiliates		1,178			1,331			200
Operating income		60,693			48,498			40,702
Other income-net		(415	)		(186	)		(470	)
Interest expense		15,662			20,182			19,839
Income before income taxes		45,446			28,502			21,333
Income tax expense		14,174			9,997			7,498
Income before cumulative effect of change in accounting principle		31,272			18,505			13,835
Cumulative effect of change in accounting principle, net of tax		—			2,297			—
Net income	$	31,272		$	16,208		$	13,835
Other comprehensive income (loss) – net of taxes
Net derivative settlements		26,875			27,037			7,114
Net change in derivative fair value		(5,174	)		(20,939	)		(27,237	)
Foreign currency translation adjustment		2,744			10,389			(40	)
Comprehensive income (loss)	$	55,717		$	32,695		$	(6,328	)
Basic net income per common share:
Income before cumulative effect of change in accounting principle	$	0.63		$	0.41		$	0.35
Cumulative effect of change in accounting principle, net of tax		—			(0.05	)		—
Net income	$	0.63		$	0.36		$	0.35
Diluted net income per common share:
Income before cumulative effect of change in accounting principle	$	0.62		$	0.41		$	0.34
Cumulative effect of change in accounting principle, net of tax		—			(0.06	)		—
Net income	$	0.62		$	0.35		$	0.34
Basic weighted average shares outstanding		49,769			44,789			39,613
Diluted weighted average shares outstanding		51,343			45,689			40,789

⁽¹⁾ Share and per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in June 2004. The split did not affect treasury shares.

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

26

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

In thousands, except for share and per share data

	2004			2003(1)			2002(1)
Preferred stock, $0.01 par value, 10,000,000 shares authorized
Balance at beginning of year	$	—		$	—		$	—
Issuance of 1 share special voting preferred		—			—			—
Balance at end of year: 1 share issued at December 31, 2004, 2003 and 2002		—			—			—
Common stock, $0.01 par value, 100,000,000 shares authorized
Balance at beginning of year		520			448			413
Issuance of common stock		7			72			35
Balance at end of year: 52,690,971; 52,045,726 and 44,756,392 shares issued at December 31, 2004, 2003 and 2002, respectively		527			520			448
Paid in capital in excess of par value
Balance at beginning of year		194,246			113,902			77,627
Acquisition of minority interest		—			—			(189	)
Acquisition of Voyager Compression Services assets		—			(515	)		—
Warrants exercised		—			—			16,355
Treasury stock reissued		148			—			19,459
Issuance of common stock		—			79,205			—
Stock options exercised		2,304			1,014			842
Tax benefit related to stock options exercised		4,243			739			—
Fair value of options issued		—			—			229
Stock issuance costs		—			(99	)		(421	)
Balance at end of year		200,941			194,246			113,902
Treasury stock, at cost
Balance at beginning of year		(10,299	)		(10,099	)		(14,634	)
(Acquisition) reissuance of treasury stock-net		41			(200	)		4,535
Balance at end of year: 2,568,611; 2,578,904 and 2,570,502 shares at December 31, 2004, 2003, and 2002, respectively		(10,258	)		(10,299	)		(10,099	)
Accumulated other comprehensive loss
Deferred losses on hedge derivatives
Balance at beginning of year		(27,359	)		(33,457	)		(13,334	)
Net change during the year related to cash flow hedges		21,701			6,098			(20,123	)
Balance at end of year		(5,658	)		(27,359	)		(33,457	)
Deferred foreign exchange adjustment
Balance at beginning of year		9,676			(713	)		(673	)
Foreign currency translation adjustment		2,744			10,389			(40	)
Balance at end of year		12,420			9,676			(713	)
Total accumulated other comprehensive income (loss)		6,762			(17,683	)		(34,170	)
Retained earnings
Balance at beginning of year		75,032			58,824			44,989
Net income		31,272			16,208			13,835
Balance at end of year		106,304			75,032			58,824
Total stockholders’ equity	$	304,276		$	241,816		$	128,905

⁽¹⁾ Share and per share amounts have been adjusted to reflect a two-for-one stock split effected in the form of a stock dividend in June 2004. The split did not affect treasury shares.

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

27

QUICKSILVER RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS END DECEMBER 31, 2004, 2003 AND 2002

In thousands

	2004			2003			2002
Operating activities:
Net income	$	31,272		$	16,208		$	13,835
Charges and credits to net income not affecting cash
Cumulative effect of accounting change, net of tax		—			2,297			—
Depletion, depreciation and amortization		40,691			32,067			30,159
Deferred income taxes		12,989			9,736			7,760
Recognition of unearned revenues		—			507			(3,678	)
Income from equity affiliates		(1,178	)		(1,331	)		(200	)
Amortization of deferred loan costs		1,249			2,637			1,239
Non-cash (gain) loss from hedging activities		(786	)		(678	)		842
Other		91			455			169
Changes in assets and liabilities
Accounts receivable		(11,562	)		(5,259	)		414
Inventory, prepaid expenses and other assets		2,364			(918	)		(852	)
Accounts payable		2,220			1,246			(1,497	)
Accrued and other liabilities		5,448			(8,280	)		(6,541	)
Net cash provided by operating activities		82,798			48,687			41,650
Investing activities:
Purchases of property, plant and equipment		(215,106	)		(137,895	)		(86,417	)
Acquisition of Voyager Compression Service assets		—			(684	)		—
Distributions and advances from equity affiliates-net		2,097			1,649			4,043
Proceeds from sale of properties		9,160			101			1,263
Net cash used for investing activities		(203,849	)		(136,829	)		(81,111	)
Financing activities:
Issuance of debt		511,091			114,000			16,000
Repayments of debt		(371,178	)		(113,116	)		(14,912	)
Proceeds from issuance of common stock, net of issuance costs		—			79,176			39,725
Proceeds from exercise of stock options		2,499			750			915
Purchases of treasury stock		—			—			(316	)
Debt issuance costs		(8,023	)		(1,441	)		(1,362	)
Net cash provided by financing activities		134,389			79,369			40,050
Effect of exchange rates on cash		(1,507	)		3,773			(199	)
Net increase (decrease) in cash and equivalents		11,831			(5,000	)		390
Cash and equivalents at beginning of period		4,116			9,116			8,726
Cash and equivalents at end of period	$	15,947		$	4,116		$	9,116

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

28

QUICKSILVER RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

1. NATURE OF OPERATIONS

Quicksilver Resources Inc. (“Quicksilver”) is an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. Quicksilver engages in the acquisition, development, exploration, production and sale of natural gas, crude oil and natural gas liquids as well as the marketing, processing and transmission of natural gas. Substantial portions of Quicksilver’s reserves are located in Michigan, Indiana, Kentucky, Texas, the Rocky Mountains and Alberta, Canada. Quicksilver has U.S. offices in Gaylord, Michigan; Corydon, Indiana; Cut Bank, Montana; Fort Worth, Texas; Granbury, Texas and a Canadian subsidiary, MGV Energy Inc. (“MGV”) located in Calgary, Alberta.

Quicksilver’s results of operations are largely dependent on the difference between the prices received for its natural gas and crude oil products and the cost to find, develop, produce and market such resources. Natural gas and crude oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of factors beyond Quicksilver’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of crude oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels. Quicksilver manages a portion of the operating risk relating to natural gas and crude oil price volatility through hedging and fixed price contracts.

2. SIGNIFICANT ACCOUNTING POLICIES

Stock Split

On June 1, 2004, Quicksilver announced that its Board of Directors declared a two-for-one stock split of Quicksilver’s outstanding common stock effected in the form of a stock dividend. The stock dividend was payable on June 30, 2004, to holders of record at the close of business on June 15, 2004. The split did not affect treasury shares.

The capital accounts, all share data and earnings per share data included in the accompanying Consolidated Financial Statements for all years presented have been adjusted to retroactively reflect the stock split.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of Quicksilver and its subsidiaries (collectively, the “Company”). The Company accounts for its ownership in unincorporated partnerships and companies under the equity method of accounting as it has significant influence over those entities, but because of terms of the ownership agreements Quicksilver does not meet the criteria for control which would require consolidation of the entities. The Company also consolidates its pro-rata share of oil and gas joint ventures. All significant inter-company transactions are eliminated.

Use of Estimates

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 and 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. Significant estimates underlying these financial statements include the estimated quantities of proved natural gas and crude oil reserves used to compute depletion of natural gas and crude oil properties and the related present value of estimated future net cash flows therefrom (see Supplemental Information beginning on page 87), estimates of current revenues based upon expectations for actual deliveries and prices received, the estimated fair value of financial derivative instruments and the estimated fair value of asset retirement obligations.

Cash and Cash Equivalents

Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less.

Accounts Receivable

The Company’s customers are natural gas and crude oil purchasers. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although the Company does not require collateral, appropriate credit ratings are required and, in some instances, parental guarantees are obtained. Receivables are generally due in 30-60 days. When collections of specific amounts due are no longer reasonably assured, an allowance for doubtful accounts is established. During 2004, two purchasers accounted for approximately 15% and 14%, respectively, of the Company’s total consolidated natural gas and crude oil sales.

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Hedging

The Company enters into financial derivative instruments to hedge price risk for its natural gas and crude oil sales and interest rate risk. Hedging is accounted for in accordance with Statements of Financial Accounting Standards (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedge Activities, and SFAS No. 138,Accounting for Certain Derivative Instruments and Certain Hedging Activities, which amended SFAS No. 133 (see note 4). The Company does not enter into financial derivatives for trading or speculative purposes.

All derivatives are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses that qualify as hedges are recognized in revenues or interest expense in the period in which the hedged transaction is recognized. Gains or losses on derivative instruments terminated prior to their original expiration date are deferred and recognized as income or expense in the period in which the hedged transaction is recognized. Fair value is determined by reference to published future market prices or interest rates. Ineffective portions of hedges are recognized currently in earnings.

The Company’s long-term contracts for delivery of 25,000 Mcfd and 10,000 Mcfd at a floor of $2.49 and $2.47, respectively, through March 2009 are not considered derivatives but rather normal sales contracts under SFAS No. 133. For 2004, approximately 5,300 Mcfd of these volumes were third-party volumes controlled by the Company.

Inventories

Inventories consist of well equipment, spare parts and supplies carried on a first-in, first-out basis at the lower of cost or market.

Investments in Equity Affiliates

Income from equity affiliates is included as a component of operating income as the operations of the affiliates are associated with processing and transportation of the Company’s natural gas production.

Properties, Plant, and Equipment

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, geological and geophysical expenses, dry holes, leasehold equipment and overhead charges directly related to acquisition, exploration and development activities, are capitalized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is recognized.

The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved oil and gas reserves as determined by independent petroleum engineers. Excluded from amounts subject to depletion are costs associated with unevaluated properties. Natural gas and crude oil are converted to equivalent units based upon the relative energy content, which is six thousand cubic feet of natural gas to one barrel of crude oil.

Net capitalized costs are limited to the lower of unamortized cost net of deferred tax or the cost center ceiling. The cost center ceiling is defined as the sum of (i) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on unescalated year-end prices and costs, adjusted for contract provisions, financial derivatives that hedge the Company’s oil and gas revenue and asset retirement obligations, (ii) the cost of properties not being amortized, (iii) the lower of cost or market value of unproved properties included in the cost being amortized less (iv) income tax effects related to differences between the book and tax basis of the natural gas and crude oil properties. Such limitations are imposed separately for the U.S. and Canadian cost centers.

All other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives from five to forty years.

Revenue Recognition

Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2004 and 2003, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

Environmental Compliance and Remediation

Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Environmental remediation costs, which improve the condition of a property, are capitalized.

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Income Taxes

Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in years in which the temporary differences are expected to reverse. MGV, the Company’s Canadian subsidiary, computes taxes at rates in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested by MGV and thus not considered available for distribution to the parent Company. Net operating loss carry forwards and other deferred tax assets, are reviewed annually for recoverability, and if necessary, are recorded net of a valuation allowance.

Disclosure of Fair Value of Financial Instruments

The Company’s financial instruments include cash, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated at the present value of future cash flows discounted at rates consistent with comparable maturities for credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments.

Foreign Currency Translation

The Company’s Canadian subsidiary, MGV, uses the Canadian dollar as its functional currency. All balance sheet accounts of Canadian operations are translated into U.S. dollars at the year-end rate of exchange and statement of income items are translated at the weighted average exchange rates for the year. The resulting translation adjustments are made directly to a separate component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated statement of income.

Earnings per share

Basic net income or loss per common share is computed by dividing the net income or loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted net income or loss per common share is computed using the treasury stock method, which also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants and outstanding convertible securities.

The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share.

	Years Ended December 31,
	2004		2003			2002
	(in thousands, except per share data)
Income before cumulative effect of change in accounting principle	$	31,272	$	18,505		$	13,835
Cumulative effect of change in accounting principle		—		2,297			—
Net income		31,272		16,208			13,835
Impact of assumed conversions – interest on 1.875% contingently convertible debentures, net of income taxes		317		—			—
Income available to stockholders assuming conversion of contingently convertible debentures	$	31,589	$	16,208		$	13,835
Weighted average common shares – basic		49,769		44,789			39,613
Effect of dilutive securities:
Stock options		1,029		900			1,117
Warrants		—		—			59
Contingently convertible debentures		545		—			—
Weighted average common shares – diluted		51,343		45,689			40,789
Basic:
Income before effect of change in accounting principle	$	0.63	$	0.41		$	0.35
Cumulative effect of change in accounting principle		—		(0.05	)		—
Net income	$	0.63	$	0.36		$	0.35
Diluted:
Income before effect of change in accounting principle	$	0.62	$	0.41		$	0.34
Cumulative effect of change in accounting principle		—		(0.06	)		—
Net income	$	0.62	$	0.35		$	0.34

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No outstanding options were excluded from the diluted net income per share calculation for either 2004 or 2003. Warrants representing 1,100,000 shares of common stock were excluded from the 2002 diluted net income per share computation for the period prior to their exercise as the exercise price exceeded the average market price of the Company’s common stock.

Stock-Based Employee Compensation

At December 31, 2004, the Company has two stock-based compensation plans, which are described more fully in Note 16. The Company accounts for its plans under the recognition and measurement principles of APB 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 the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and earnings per share if the Company had applied fair value recognition provisions of FASB Statement No. 123,Accounting for Stock-Based Compensation.

	Years Ended December 31,
	2004			2003			2002
	(in thousands, except per share data)
Net income, as reported	$	31,272		$	16,208		$	13,835
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of income taxes		(3,169	)		(436	)		(674	)
Pro forma net income	$	28,103		$	15,772		$	13,161
Earnings per share
Basic – as reported	$	0.63		$	0.36		$	0.35
Basic – pro forma	$	0.56		$	0.35		$	0.33
Diluted – as reported	$	0.62		$	0.35		$	0.34
Diluted – pro forma	$	0.55		$	0.35		$	0.32

Recently Issued Accounting Standards

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

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

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

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

In November 2004, the FASB issued SFAS No. 151,Inventory Costs, an amendment of ARB No. 43, Chapter 4, which amends Chapter 4 of ARB No. 43 that deals with inventory pricing. The statement clarifies the accounting for abnormal

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amounts of idle facility expenses, freight, handling costs and spoilage. Under paragraph 5 of ARB No. 43, such items might be considered to be so abnormal, under certain circumstances, as to require treatment as current period charges. SFAS No. 151 eliminates the criterion of “so abnormal” and requires that those items be recognized as current period charges. The statement also requires allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. This statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, although earlier application is permitted for fiscal years beginning after the issuance date of the statement. Retroactive application is not permitted. Management is analyzing the requirements of SFAS No. 151 and believes that its adoption will not have any significant impact on the financial position, results of operations or cash flows of the Company.

The FASB issued SFAS No. 153,Exchanges of Nonmonetary Assets, an amendment of APB No. 29 in December 2004. The statement amends Opinion 29 by eliminating the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. SFAS No. 153 provides that a nonmonetary exchange has commercial substance if future cash flows of the entity are expected to change significantly as a result of the exchange. The statement is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Earlier application is permitted for nonmonetary asset exchanges occurring in fiscal periods beginning after the date of the issuance of the statement. Retroactive application is not permitted. Management is analyzing the requirements of SFAS No. 151 and believes that its adoption will not have any significant impact on the financial position, results of operations or cash flows of the Company.

FASB Staff Position (“FSP”) No. 109-2,Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004, was issued in December 2004. This FSP provides guidance on accounting for special reductions in taxes included in the American Jobs Creation Act of 2004. In particular, the Act allows a one-time decrease in U.S. Federal taxes on repatriated foreign earnings. FSP No. 109-2 clarifies that a company’s consideration of the Act does not overrule their prior contention that the foreign earnings were permanently reinvested. Also, this FSP indicates that companies should provide tax expense when a decision is made to repatriate some or all foreign earnings, and provide disclosure about the possible range of repatriation if the analysis is not yet complete. Quicksilver repatriated $86.5 million as the result of a Canadian dividend distribution in 2004 and provided approximately $0.8 million of current income tax expense in 2004.

In September 2004, the SEC issued Staff Accounting Bulletin (“SAB”) No. 106. This pronouncement requires companies that use the full cost method of accounting for oil and gas producing activities to include an estimate of future asset retirement costs to be incurred as a result of future development activities on proved reserves in their calculation of depreciation, depletion and amortization. It also requires full cost companies to exclude any cash outflows associated with settling asset retirement obligations from their full cost ceiling test calculation. In addition, it requires specific disclosures regarding the impact of asset retirement obligations on oil and gas producing activities, ceiling test calculations and depreciation, depletion and amortization calculations. The Company will adopt the provisions of this pronouncement in the first quarter of 2005. Management believes there will be no immediate effect on the Company’s consolidated financial statements.

3. ASSET RETIREMENT OBLIGATIONS

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

In connection with adoption of SFAS No. 143, all asset retirement obligations of the Company were identified and the fair value of the retirement costs were estimated as of the date the long-lived assets were placed into service. The asset retirement obligations’ fair values were then estimated as of January 1, 2003. At January 1, 2003, the Company recognized asset retirement costs of $10.8 million and asset retirement obligations of $13.3 million, of which $0.9 million was classified as current. The cumulative-effect adjustment of $2.3 million included $1.3 million for additional depletion and depreciation of the asset retirement costs, $2.2 million for accretion of the fair value of the asset retirement obligations and $1.2 million for deferred tax benefits. The asset retirement obligation would have been $12.6 million at January 1, 2002 had FAS No. 143 then been in effect.

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

	For the Year Ended December 31,
	2004		2003		2002
	(in thousands)
Income before cumulative effect of change in accounting principle	$	31,272	$	18,505	$	13,835
Deduct: accretion of asset retirement obligation and depletion and depreciation of associated fixed assets, net of income taxes		—		—		(523	)
Pro forma net income before cumulative effect of change in accounting principle	$	31,272	$	18,505	$	13,312
Pro forma net income – per share
Basic	$	0.63	$	0.41	$	0.34
Diluted		0.62		0.41		0.33

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 December 31, 2004.

	2004			2003
	(in thousands)
Beginning asset retirement obligation	$	15,189		$	13,326
Additional liability incurred		2,538			999
Accretion expense		982			739
Sale of properties		(680	)		—
Asset retirement costs incurred		(267	)		(39	)
Loss on settlement of liability		143			—
Currency translation adjustment		566			164
Ending asset retirement obligation	$	18,471		$	15,189

During the years ended December 31, 2004 and 2003, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the statement of income for the year. There have not been any revisions to either the timing or the amount of the original estimate of undiscounted cash flows during 2003 or 2004. Asset retirement obligations at December 31, 2004 and 2003 are $18.5 million and $15.2 million, respectively, of which $504,000 and $54,000, respectively, has been classified as current.

4. HEDGING

The Company hedges a portion of its equity production of natural gas and crude oil using various financial derivatives. All derivatives are evaluated using the hedge criteria established under SFAS Nos. 133 and 138. If hedge criteria are met, the change in a derivative’s fair value (for a cash flow hedge) is deferred in stockholders’ equity as a component of accumulated other comprehensive income. These deferred gains and losses are recognized into income in the period in which the hedged transaction is recognized in revenues to the extent the hedge is effective. The ineffective portions of hedges are recognized currently in earnings.

During 2004, the Company entered into both fixed and floating price firm natural gas sale and purchase commitments and associated financial price swaps that extend through March 2005. The derivative transactions qualify as fair value hedges. Hedge ineffectiveness resulted in $118,000 of net losses, $188,000 of net gains and $26,000 of net losses in 2004, 2003 and 2002, respectively.

During 2002, the Company cancelled three interest rate swap agreements. The first, covering its $53 million of Second Mortgage Notes (“Subordinated Notes”), was cancelled on July 15, 2002 and the Company received a cash settlement of $1.0 million. The swap agreement converted the debt’s 14.75% fixed rate to a floating three-month LIBOR base rate and qualified as a fair value hedge. The Company deferred the $1.0 million gain resulting from the settlement, which was to be recognized through the original maturity date for the swap, March 30, 2009. The Company redeemed the $53 million in principal amount of Subordinated Notes in June 2003. At that time the remaining $0.9 million deferred gain was recognized.

In October 2002, the Company cancelled two fixed-rate interest rate swaps related to $75 million of the Company’s variable-rate debt and entered into a new fixed-rate interest swap that converted the interest rate to a fixed-rate of 3.74% through March 31, 2005. The fair value of the open swap at its inception was $1.9 million. The Company recognized the $1.9 million loss associated with the cancelled swaps through the original maturity date of the swaps, March 31, 2003. At December 31, 2004 and 2003, the fair value of the open interest swap was a liability of $0.2 million and $2.0 million, respectively.

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On September 11, 2003, the Company entered into a fair value interest swap covering $40 million of its fixed rate 2003 Second Mortgage Notes. The swap converted the debt’s 7.5% fixed rate to a floating six-month LIBOR base rate plus 4.07% through the termination of the notes. The fair value of the swap was $50,000 as of December 31, 2003. In January 2004, the swap position was cancelled and the Company received a cash settlement of $0.3 million that will be recognized over the original maturity date for the swap, December 31, 2006. At December 31, 2004, $0.2 million of the gain remains to be recognized.

The change in carrying value of the Company’s derivatives, firm sale and purchase commitments accounted for as hedges and interest rate swaps in the Company’s balance sheet since December 31, 2003 resulted from a decrease in the remaining hedged volumes partially offset by an increase in market prices for natural gas, crude oil and a decrease in the remaining period covered by the interest rate swap. The change in fair value of all cash flow hedges was reflected in accumulated other comprehensive income, net of deferred tax effects. Natural gas and crude oil derivative assets and liabilities reflected as current in the December 31, 2004 balance sheet represent the estimated fair value of contract settlements scheduled to occur over the subsequent twelve-month period based on market prices for natural gas and crude oil as of the balance sheet date. These settlement amounts are not due and payable until the monthly period in which the related underlying hedged gas or oil sales transaction occurs. Settlement of the underlying hedged transactions occurs in the following 20 to 85 days.

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

	As of December 31,
	2004		2003
	(in thousands)
Derivative assets:
Fixed price sale commitments	$	314	$	43
Natural gas financial collars		3,563		330
Crude oil financial collars		106		—
Floating price natural gas financial swaps		—		463
Fixed price natural gas financial swaps		—		336
Fixed to floating interest rate swap		—		50
	$	3,983	$	1,222
Derivative liabilities:
Fixed price natural gas financial swaps	$	12,066	$	41,363
Floating price natural gas financial swaps		322		42
Natural gas financial collars		158		—
Crude oil financial collars		5		448
Fixed price sale commitments		—		356
Floating to fixed interest rate swap		233		2,030
	$	12,784	$	44,239

The fair value of all natural gas and crude derivatives and firm sale and purchase commitments accounted for as hedges as of December 31, 2004 and 2003 was estimated based on market prices of natural gas and crude oil for the periods covered by the derivatives. The net differential between the prices in each derivative 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. The fair value of the interest rate swap was based upon counterparty estimates of the fair value of such swaps. As a result, the fair value of the Company’s derivatives and commitments does not necessarily represent the value a third party would pay to assume the Company’s contract positions. Of the $4.0 million of derivatives assets and $12.8 million of derivative liabilities, $2.4 million of assets and $12.8 million of liabilities have been classified as current at December 31, 2004 based on the maturity of the derivative instruments, resulting in $6.8 million of after-tax losses to be reclassified from accumulated other comprehensive income in 2005.

5. FINANCIAL INSTRUMENTS

The Company has established policies and procedures for managing risk within its organization, including internal controls. The level of risk assumed by the Company is based on its objectives and capacity to manage risk.

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Quicksilver’s primary risk exposure is related to natural gas and crude oil commodity prices. The Company has mitigated the downside risk of adverse price movements through the use of swaps, futures and forward contracts; however in doing so, it has also limited future gains from favorable price movements.

Commodity Price Risk

The Company enters into contracts to hedge its exposure to commodity price risk associated with anticipated future natural gas and crude oil production. These contracts have included physical sales contracts and derivatives including price ceilings and floors, no-cost collars and fixed price swaps. As of December 31, 2004, Quicksilver sells approximately 25,000 Mcfd and 10,000 Mcfd of natural gas under long-term contracts with a floor of $2.49 per Mcf and $2.47 per Mcf, respectively, through March 2009. Approximately 29,700 Mcfd of the Company’s natural gas production was sold under these contracts during 2004. The remaining 5,300 Mcfd sold under these contracts were third-party volumes controlled by the Company. These contracts are not considered derivatives, but rather normal sales contracts under SFAS No. 133.

The Company hedged 30,000 Mcfd natural gas production in May 2000 using fixed price swap agreements at prices averaging $2.79 per Mcf. These agreements expire in April 2005. Natural gas price collars hedge approximately 20,000 Mcfd of the Company’s budgeted natural gas sales volumes for the first quarter of 2005. Natural gas price collars of nearly 33,000 Mcfd hedge the Company’s budgeted natural gas sales volumes for the remainder of 2005. Additionally, the Company has used price collar agreements to hedge approximately 750 Bbld of its crude oil production for 2005. As a result of these various contracts, the Company benefits from significant predictability of its natural gas and crude oil revenues. The following table summarizes the Company’s open financial derivative positions as of December 31, 2004 related to its natural gas and crude oil production.

Product	Type	Contract Period	Volume	Weighted Avg Price Per Mcf or Bbl		Fair Value
						(in thousands)
Gas	Swap	Jan 2005-Apr 2005	10,000 Mcfd	$	2.79	$	(4,016	)
Gas	Swap	Jan 2005-Apr 2005	10,000 Mcfd		2.79		(4,025	)
Gas	Swap	Jan 2005-Apr 2005	10,000 Mcfd		2.79		(4,025	)
Gas	Collar	Jan 2005-Mar 2005	5,000 Mcfd		5.50-9.60		62
Gas	Collar	Jan 2005-Mar 2005	10,000 Mcfd		5.50-9.63		115
Gas	Collar	Jan 2005-Mar 2005	5,000 Mcfd		5.50-9.90		86
Gas	Collar	Apr 2005-Oct 2005	5,000 Mcfd		5.50-6.75		(109	)
Gas	Collar	Apr 2005-Oct 2005	10,000 Mcfd		5.50-6.75		(219	)
Gas	Collar	May 2005-Oct 2005	15,000 Mcfd		5.50-7.15		(15	)
Gas	Collar	May 2005-Oct 2005	5,000 Mcfd		6.50-8.15		624
Gas	Collar	May 2005-Oct 2005	5,000 Mcfd		6.50-8.22		632
Gas	Collar	Nov 2005-Mar 2006	10,000 Mcfd		6.50-11.20		779
Gas	Collar	Nov 2005-Mar 2006	10,000 Mcfd		6.50-11.20		779
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd		5.50-8.10		332
Gas	Collar	Apr 2006-Oct 2006	5,000 Mcfd		5.50-8.25		339
Oil	Collar	Jan 2005-Jun 2005	500 Bbld		40.00-52.80		93
Oil	Collar	Jan 2005-Jun 2005	500 Bbld		40.00-46.75		(5	)
Oil	Collar	Jul 2005-Dec 2005	250 Bbld		38.00-47.75		13
					Net open positions	$	(8,560	)

Utilization of the Company’s financial hedging program may result in natural gas and crude oil realized prices that vary from actual prices that the Company receives from the sale of natural gas and crude oil. As a result of the hedging programs, revenues from production in 2004, 2003 and 2002 were $43.9 million, $39.8 million and $7.4 million lower, respectively, than if the hedging programs had not been in effect.

Commodity price fluctuations affect the remaining natural gas and crude oil volumes as well as the Company’s NGL volumes. Natural gas volumes of 4,500 Mcfd are committed at market price through May 2005 and an additional 16,500 Mcfd of natural gas is committed at market price through September 2008. During 2004, almost 6,400 Mcfd of Quicksilver’s natural gas production was sold under these contracts. An additional 14,600 Mcfd sold under these contracts were third-party volumes controlled by the Company.

The Company entered into various financial contracts to hedge exposure to commodity price risk associated with future contractual natural gas sales and purchases with derivative instruments. These contracts include either fixed and floating price sales or purchases from third parties. As a result of the firm sale and purchase commitments and associated financial price swaps, the hedge derivatives qualified as fair value hedges. Marketing revenues were $0.5 million and $0.3 million higher and lower by $2.2 million as a result of its hedging activities in 2004, 2003 and 2002, respectively.

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The following table summarizes our open financial derivative positions and hedged firm commitments as of December 31, 2004 related to natural gas marketing.

Contract Period	Volume	Weighted Avg Price per Mcf		Fair Value
				(in thousands)
Natural Gas Sales Contracts
Jan 2005	2,262 Mcfd	$	7.74	$	104
Feb 2005	3,935 Mcfd	$	7.53		136
Mar 2005	1,935 Mcfd	$	7.58		74
				$	314
Natural Gas Financial Derivatives
Jan 2005-Mar 2005	1,333 Mcfd		Floating Price	$	(171	)
Jan 2005-Mar 2005	333 Mcfd		Floating Price		(44	)
Jan 2005	645 Mcfd		Floating Price		(35	)
Feb 2005	1,428 Mcfd		Floating Price		(43	)
Feb 2005	714 Mcfd		Floating Price		(17	)
Mar 2005	323 Mcfd		Floating Price		(12	)
					(322	)
			Total-net	$	(8	)

The fair values of fixed price and floating price natural gas and crude oil derivatives and associated firm commitments as of December 31, 2004 were estimated based on 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 natural gas and crude oil financial swap and firm commitment fair value does not necessarily represent the value a third party would pay to assume the Company’s contract positions.

Interest Rate Risk

The Company manages its exposure associated with interest rates by entering into interest rate swaps. As of December 31, 2004, the interest payments for $75.0 million notional variable-rate debt are hedged with an interest rate swap that converts a floating three-month LIBOR base to a 3.74% fixed-rate through March 31, 2005. The liability associated with the swap was $0.2 million at December 31, 2004 and $2.0 million at December 31, 2003.

On September 10, 2003, the Company 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 converted the debt’s 7.5% fixed-rate debt to a floating six-month LIBOR base. The asset associated with the swap was $50,000 at December 31, 2003. In January 2004, the swap position was cancelled and the Company received a cash settlement of $0.3 million that is being recognized over the original term of the swap, which ends December 31, 2006. The deferred gain remaining at December 31, 2004 is $0.2 million.

Credit Risk

Credit risk is the risk of loss as a result of non-performance by counterparties of their contractual obligations. The Company sells a portion of its natural gas production directly under long-term contracts, and the remainder of its natural gas and crude oil is sold to large trading companies and energy marketing companies, refineries and other users of petroleum products at spot or short-term contracts. Quicksilver also enters into hedge derivatives with financial counterparties. The Company monitors its exposure to counterparties by reviewing credit ratings, financial statements and credit service reports. Exposure levels are limited and parental guarantees are required according to Company policy. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. In this manner, the Company reduces credit risk.

While Quicksilver follows its credit policies at the time it enters into sales contracts, the credit worthiness of counter parties could change over time. The credit ratings of the parent companies of the two counter parties to the Company’s long-term gas contracts were downgraded in early 2003 and remain below the credit ratings required for the extension of credit to new customers.

Performance Risk

Performance risk results when a financial counterparty fails to fulfill its contractual obligations such as commodity pricing or volume commitments. Typically, such risk obligations are defined within the trading agreements. The Company manages performance risk through management of credit risk. Each customer and/or counterparty of the Company is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter.

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Foreign Currency Risk

The Company’s Canadian subsidiary uses the Canadian dollar as its functional currency. To the extent that business transactions in Canada are not denominated in Canadian dollars, the Company is exposed to foreign currency exchange rate risk. During October and November 2004, Quicksilver loaned MGV approximately $11.4 million. To reduce its exposure to exchange rate risk, MGV entered into a forward contract that fixed the Canadian-to-US exchange rate. The balance of the loan was repaid at the end of November and upon settlement of the forward contract, MGV recognized a gain of $0.2 million.

6. ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	As of December 31,
	2004			2003
	(in thousands)
Accrued production receivables	$	24,351		$	19,318
Joint interest receivables		13,247			6,478
Other receivables		753			552
Allowance for bad debts		(314	)		(101	)
	$	38,037		$	26,247

7. INVENTORIES AND OTHER CURRENT ASSETS

Inventories and other current assets consist of:

	As of December 31,
	2004		2003
	(in thousands)
Inventories	$	4,161	$	4,595
Hedge derivatives (see note 4)		2,383		1,172
Prepaid expenses and deposits		2,145		1,821
	$	8,689	$	7,588

8. PROPERTIES, PLANT AND EQUIPMENT

Property and equipment includes the following:

	As of December 31,
	2004			2003
	(in thousands)
Oil and gas properties
Subject to depletion	$	838,134		$	665,457
Unevaluated costs		97,168			49,919
Accumulated depletion		(195,415	)		(159,801	)
Net oil and gas properties		739,887			555,575
Other equipment
Pipelines and processing facilities		70,851			56,980
General properties		12,597			7,645
Accumulated depreciation		(20,725	)		(15,624	)
Net other property and equipment		62,723			49,001
Property and equipment, net of accumulated depreciation and depletion	$	802,610		$	604,576

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Unevaluated Natural Gas and Crude Oil Properties Excluded From Depletion

Under full cost accounting, the Company may exclude certain unevaluated costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties excluded from natural gas and crude oil properties being amortized at December 31, 2004 and 2003 and the year in which they were incurred as follows:

	December 31, 2004 Costs Incurred During										December 31, 2003 Costs Incurred During
	2004		2003		2002		Prior		Total		2003		2002		2001		Prior		Total
	(in thousands)										(in thousands)
Acquisition costs	$	38,051	$	31,972	$	8,809	$	1,258	$	80,090	$	31,834	$	11,658	$	903	$	1,307	$	45,702
Exploration costs		16,125		845		108		—		17,078		3,337		880		—		—		4,217
Total	$	54,176	$	32,817	$	8,917	$	1,258	$	97,168	$	35,171	$	12,538	$	903	$	1,307	$	49,919

Costs are transferred into the amortization base on an ongoing basis, as the projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. As of December 31, 2004, approximately $38.3 million and $39.2 million of the total unevaluated costs of $97.2 million related to the Company’s Texas Barnett Shale and Canadian coal bed methane projects, respectively. These costs will be transferred into the amortization base as the undeveloped projects and areas are evaluated. The Company anticipates that the majority of this activity should be completed over the next two to three years.

Capitalized Costs

Capitalized overhead costs that directly relate to exploration and development activities were $3.1 million, $2.2 million and $0.8 million for the years ended December 31, 2004, 2003 and 2002, respectively.

Depletion per Mcfe was $0.78, $0.68 and $0.69 for the years ended December 31, 2004, 2003 and 2002, respectively.

9. OTHER ASSETS

Other assets consist of:

	As of December 31,
	2004			2003
	(in thousands)
Deferred financing costs	$	15,018		$	6,995
Less accumulated amortization		(5,891	)		(4,634	)
Net deferred financing costs		9,127			2,361
Hedge derivatives (see note 4)		1,600			50
Other		547			1,063
	$	11,274		$	3,474

Costs related to the acquisition of debt are deferred and amortized over the term of the debt.

10. ACCRUED LIABILITIES

Accrued liabilities include the following:

	As of December 31,
	2004		2003
	(in thousands)
Accrued capital expenditures	$	18,597	$	10,179
Prepayments from partners		7,607		—
Accrued operating expenses		4,382		3,498
Suspended revenue		3,834		3,577
Accrued property and production taxes		2,430		1,981
Accrued product purchases		1,421		6,626
Interest payable		1,112		522
Environmental liabilities		972		923
Other		1,549		338
	$	41,904	$	27,644

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11. NOTES PAYABLE AND LONG-TERM DEBT

Long-term debt consists of:

	As of December 31,
	2004			2003
	(in thousands)
Senior secured credit facility	$	180,422		$	178,000
Contingently convertible debentures, net of unamortized discount of $2,231		147,769			—
Second mortgage notes payable		70,000			70,000
Other loans		1,073			1,386
Deferred gain – fair value interest hedge		226			—
Fair value interest hedge		—			50
		399,490			249,436
Less current maturities		(356	)		(339	)
	$	399,134		$	249,097

Maturities are as follows, in thousands of dollars:

2005	$	356
2006		70,367
2007		351
2008		—
2009		180,421
Thereafter		150,000
	$	401,495

On July 28, 2004, the Company entered into a senior secured credit facility. Currently, the credit facility is a revolving facility that matures on July 28, 2009 and permits the Company to obtain revolving credit loans and letters of credit from time to time in an aggregate amount outstanding not to exceed the lesser of the borrowing base or $600 million. The current borrowing base is $300 million and is subject to annual redeterminations and certain other redeterminations, based upon several factors. The lenders’ commitments under the facility are allocated between U.S. and Canadian funds, with the U.S. funds being available for borrowing by the Company and Canadian funds being available for borrowing by the Company’s Canadian subsidiary, MGV Energy Inc. The Company’s interest rate options under the facility include rates based on LIBOR and specified bank rates. As borrowings increase, LIBOR margins increase in specified increments from 1.125% to a maximum of 1.75%. The facility is secured by Quicksilver’s oil and gas properties, and the lenders annually re-determine the global borrowing base under the facility in accordance with their customary practices for oil and gas loans based upon the estimated value of the Company’s year-end proved reserves. The loan agreements for the credit facility prohibit the declaration or payment of dividends by the Company and contain certain financial covenants, which, among other things, require the maintenance of a minimum current ratio and a minimum earnings (before interest, taxes, depreciation, depletion and amortization, non-cash income and expense, and exploration costs) to interest expense ratio. The Company was in compliance with all such covenants at December 31, 2004. The senior credit facility was also used to issue letters of credit. At December 31, 2004, the Company had $0.6 million in letters of credit and $119.1 million available under the senior revolving credit facility.

On November 1, 2004, the Company sold $150 million $1.875% convertible subordinated debentures due November 1, 2024, which are contingently convertible into 3,272,085 shares of common stock (subject to adjustment). Each $1,000 debenture was issued at 98.5% of par and bears interest at an annual rate of 1.875% payable semi-annually on May 1 and November 1 of each year. Holders of the debentures can require the Company to repurchase all or a portion of their debentures on November 1, 2011, 2014 or 2019 at a price equal to the principal amount thereof plus accrued and unpaid interest. The debentures are convertible into Quicksilver common stock at a rate of 21.8139 shares for each $1,000 debenture, subject to adjustment. Generally, except upon the occurrence of specified events, holders of the debentures are not entitled to exercise their conversion rights until the Company’s stock price is $55.01 (120 % of the conversion price per share). Upon conversion, the Company has the option to deliver in lieu of Quicksilver common stock, cash or a combination of cash and Quicksilver common stock. At December 31, 2004, the fair value of the $150 million in principal amount of contingently convertible debentures was $162.3 million.

On June 27, 2003, the Company redeemed $53 million in principal amount of subordinated notes payable through the issuance of $70 million in principal amount of second mortgage notes due 2006 (“the Second Mortgage Notes”). As a result of the redemption, the Company recognized additional interest expense of $3.8 million, consisting of a prepayment premium of $3.2 million and write-off of the remaining deferred financing costs of $1.5 million, partially offset by an associated deferred hedging gain of $0.9 million. A portion ($30 million) of the $70 million Second Mortgage Notes bear interest at a variable annual rate based upon the three-month LIBOR rate plus 5.48%, and the remainder ($40 million) bear interest at the

40

fixed rate of 7.5% per annum. The Second Mortgage Notes contain restrictive covenants, which, among other things, require maintenance of a minimum current ratio of at least 1.0, a ratio of net present value of proved reserves to total debt of at least 1.8 to 1.0; and a ratio of earnings before interest, taxes, depreciation and amortization and non-cash income and expense to interest expense (consolidated net interest expense and current maturities of debt) of at least 1.25 (calculated in each case in accordance with the provisions of the Second Mortgage Notes). At December 31, 2004, the Company was in compliance with all such restrictions. At December 31, 2004, the fair value of the $70 million in principal amount of second mortgage notes approximated the face value of $70 million.

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

12. TAX CREDIT SALES

Until expiration of the tax credit at December 31, 2002, certain properties of the Company earned Internal Revenue Code Section 29 income tax credits. Code Section 29 allowed a credit against regular federal income tax liability for certain eligible gas production.

On March 31, 2000, the Company sold, to a bank, Section 29 tax credits relating to production from certain wells located in Michigan. Cash proceeds received from the sale were $25 million and were recorded as unearned revenue. Revenue was recognized as reserves were produced. The purchase and sale agreement and ancillary agreements with the bank included a production payment in favor of Quicksilver burdening future production on the properties. Revenue of $3.7 million and $9.4 million was recognized in 2002 and 2001, respectively, in other revenue. During 1997, other tax credits attributable to properties owned by the Company were conveyed through the sale of certain working interests to a bank by entities who contributed properties to the Company at the time of its formation. Revenue of $1.4 million and $1.5 million was recognized in 2002 and 2001, respectively, 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.

13. COMMITMENTS AND CONTINGENCIES

The Company leases office buildings and other property under operating leases. Future minimum lease payments, in thousands, for operating leases with initial non-cancelable lease terms in excess of one year as of December 31, 2004, were as follows:

2005	$	2,160
2006		1,845
2007		1,283
2008		931
2009		675
Thereafter		—
Total lease commitments	$	6,894

Rent expense for operating leases with terms exceeding one month was $1.5 million in 2004, $1.4 million in 2003 and $1.4 million in 2002.

As of December 31, 2004, the Company had approximately $0.6 million in letters of credit outstanding related to various state and federal bonding requirements.

On October 6, 2004, Quicksilver entered into an Incentive Arrangements Agreement (the “Agreement”) with three executives of MGV and one employee of Quicksilver. The Agreement provides for the amendment and restatement of employment agreements with two MGV executives and terminates incentive agreements with the other two individuals. In addition, the Agreement provides for awards of cash bonuses based upon the achievement of specified proved reserve targets, as well as options granted under the Company’s Amended and Restated 1999 Stock Option and Retention Stock Plan covering 1,183,422 shares of common stock at an exercise price of $31.27. The cash bonuses, in the aggregate, will be determined as a base amount of $5.0 million for achieving proved reserves of 400 billion cubic feet equivalent (Bcfe) at December 31, 2005. Proved reserves in excess of 400 Bcfe to but not exceeding 1,000 Bcfe will increase the cash bonuses earned by $0.05 per Mcfe. Presently, the Company has not recognized an obligation for the cash bonuses; however, the Company will continue to monitor its potential liability in respect of these matters, and will record accruals in respect of such liabilities when payment thereof becomes probable and estimable.

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

Defendants have sought leave to appeal the certification order by filing an Application for Leave to Appeal on February 11, 2005 with the Michigan Court of Appeals. Defendants have also requested that the Court of Appeals stay proceedings in the Circuit Court pending the consideration of its appeal, and have requested that the Court of Appeals consider all matters in an expedited manner. The Company is currently awaiting a ruling from that court on the application and the requests for stay and immediate consideration.

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

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

14. INCOME TAXES

Deferred income taxes are established for all temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. In addition, deferred tax balances must be adjusted to reflect tax rates that will be in effect in the years in which the temporary differences are expected to reverse. For years prior to 2004, the Company had accrued no U.S. deferred income taxes on MGV’s undistributed earnings or on the related translation adjustments pursuant to FAS No. 109,Accounting for Income Taxes, and APB No. 23,Accounting for Income Taxes – Special Areas as the Company expected that MGV’s undistributed earnings would be permanently reinvested for use in the development of its oil and gas reserves. In July 2004, however, a dividend distribution of $86.5 million was made by MGV to Quicksilver. The distribution represented the repayment of Quicksilver’s capital contributions that had been made to MGV for the period January 1, 2001 through July 27, 2004 in the amount of $114.4 million, Canadian. This dividend is to be reinvested in the U.S. under a qualified domestic reinvestment plan as defined under Internal Revenue Code Section 965 (b)(4). The funds are to be used for capital expenditures in the Barnett Shale exploration and development program. After application of the 85% dividend exclusion on estimated accumulated earnings and profits of approximately $15.5 million, a current U.S. federal income tax of approximately $0.8 million has been accrued on this dividend distribution. No other deferred taxes have been accrued on MGV’s undistributed earnings and the Company continues to expect that the balance of MGV’s undistributed earnings will be permanently reinvested for use in the development of its oil and gas reserves.

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Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2004 and 2003 are as follows:

	2004		2003
Current
Deferred tax asset
Deferred tax benefit on cash flow hedge losses	$	3,523	$	11,760
Non-current
Deferred tax assets
Deferred tax benefit on cash flow hedge losses	$	—	$	3,022
Tax credit sale and unearned income		—		—
Net operating loss carry forwards		18,118		18,920
Other		233		166
Total deferred tax assets		18,351		22,108
Deferred tax liabilities
Properties, plant, and equipment		100,845		92,818
Deferred tax liability on cash flow hedge gains		593		—
Deferred tax liability on convertible debenture interest		419		—
Total deferred tax liabilities		101,857		92,818
Net deferred tax liabilities	$	83,506	$	70,710

The provisions for income taxes for the years ended December 31, 2004, 2003 and 2002 are as follows:

	2004		2003		2002
	(in thousands)
Current state income tax expense (benefit)	$	70	$	79	$	(139	)
Current federal income tax expense (benefit)		814		—		(178	)
Current foreign income tax expense		301		182		55
Total current income tax expense (benefit)		1,185		261		(262	)
Deferred federal income tax expense		8,756		8,175		7,928
Deferred foreign income tax expense (benefit)		4,233		1,561		(168	)
Total deferred income tax expense		12,989		9,736		7,760
Total	$	14,174	$	9,997	$	7,498

A reconciliation of the statutory federal income tax rate and the effective tax rate for the years ended December 31, 2004, 2003 and 2002 are as follows:

	2004		2003		2002
U.S. federal statutory tax rate	35.00	%	35.00	%	35.00	%
Dividend income from Canadian subsidiary	1.79	%	—		—
Permanent differences	.12	%	.18	%	.86	%
State income taxes net of federal deduction	.10	%	.18	%	(.42	)%
Foreign income taxes	(5.77	)%	(.27	)%	—
Other	(.05	)%	(.02	)%	(.29	)%
Effective income tax rate	31.19	%	35.07	%	35.15	%

Income tax benefits recognized as additional paid-in capital for the years ended December 31, 2004, 2003 and 2002 are as follows:

	2004		2003		2002
	(in thousands)
Income tax benefit recognized on employee stock option exercises	$	4,243	$	739	$	—

Included in deferred tax assets are net operating losses of approximately $51.8 million that are available for carryover beginning in the year 2005 to reduce future U.S. taxable income. The net operating losses will expire in 2005 through 2024. These net operating losses have not been reduced by a valuation allowance, because management believes that future taxable income will more likely than not be sufficient to utilize substantially all of its tax carry forwards prior to their expirations. However, under Internal Revenue Code Section 382, a change of ownership was deemed to have occurred for our predecessor, MSR Exploration Ltd. (“MSR”) in 1998. Due to the limitations imposed by Section 382, a portion of MSR’s net operating losses could not be utilized and are not included in deferred tax assets.

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15. EMPLOYEE BENEFITS

Quicksilver has a 401(k) retirement plan available to all employees with three months of service and who are at least 21 years of age. The Company may make discretionary contributions to the plan. Company contributions were $0.3 million, $0.2 million and $0.2 million for the years ended December 31, 2004, 2003 and 2002, respectively.

The Company initiated a self-funded health benefit plan effective July 1, 2001. The plan has been reinsured on an individual claim and total group claim basis. Quicksilver is responsible for payment of the first $50,000 for each individual claim. The claim liability for the total group was $2.2 million, $1.1 million and $1.2 million for the plan years ended June 30, 2004, 2003 and 2002, respectively. Aggregate level reinsurance is in place for payment of claims up to $1 million over and above the estimated maximum claim liability of $2.1 million for the plan year ending June 30, 2005. Administrative expenses for the plan years ended June 30, 2004, 2003 and 2002 were $0.4 million, $0.4 million and $0.3 million, respectively.

16. STOCKHOLDERS’ EQUITY

Stock Split

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

The capital stock accounts, all share data and earnings per share data included in the consolidated financial statements and notes give effect to the stock split, applied retroactively, to all periods presented.

Common Stock, Preferred Stock and Treasury Stock

The Company is authorized to issue 100 million shares of common stock with a par value per share of one cent ($0.01) and 10 million shares of preferred stock with a par value per share of one cent ($0.01). At December 31, 2004, the Company had 50,122,360 shares of common stock outstanding (including 172,626 shares issuable upon exchange of the MGV exchangeable shares and excluding treasury shares) and one share of special voting preferred stock outstanding.

In connection with the December 2000 MGV minority interest acquisition, all issued and outstanding shares of MGV capital stock, other than those held by Quicksilver, were converted into 567,338 MGV exchangeable shares. Each MGV exchangeable share is a non-voting share of MGV’s capital stock exchangeable for one share of Quicksilver common stock. Redemption or exchange can occur as a result of (i) liquidation of MGV; (ii) exercise of a redemption right by an MGV shareholder requiring MGV to purchase exchangeable shares; or (iii) exercise of an exchange put right by an MGV shareholder requiring Quicksilver to exchange the exchangeable shares for Quicksilver common stock. Any MGV exchangeable shares still outstanding on December 31, 2005 will be treated as having been the subject of an exercise of an exchange put right on that date. Upon exchange, the holder of exchangeable shares is entitled to receive one share of Quicksilver common stock and the full amount of all cash dividends declared on a share of Quicksilver common stock from the date of issuance of the exchangeable share to the date of exchange. In order to provide voting rights to holders of MGV exchangeable shares equivalent to the voting rights of the Quicksilver common shares, Quicksilver created, on December 15, 2000, a series of its preferred stock designated as Special Voting Stock. Quicksilver issued a single share of Special Voting Stock to an appointee. Through December 31, 2004, 27,000 exchangeable shares of MGV have been presented to MGV for redemption for $248,343 and 394,712 MGV exchangeable shares have been exchanged for shares of Quicksilver common stock.

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The following table shows common share and treasury share activity since January 1, 2002:

	Common Shares Issued		Treasury Shares Held
Opening Balance January 1, 2002	41,317,898		3,751,852
Stock options exercised	299,894		—
Warrants exercised	1,971,500		—
MGV Class C Retraction	(20,000	)	—
Treasury stock purchased	—		5,750
Treasury stock issued	1,187,100		(1,187,100	)
Balance at December 31, 2002	44,756,392		2,570,502
Stock options exercised	289,334		8,402
Stock issuance	7,000,000		—
Balance at December 31, 2003	52,045,726		2,578,904
Stock options exercised	645,245		(10,293	)
Balance at December 31, 2004	52,690,971		2,568,611

Stockholder Rights Plan

On March 11, 2003, the Company’s board of directors declared a dividend distribution of one preferred share purchase right for each outstanding share of common stock of the Company outstanding on March 26, 2003. Each right, when it becomes exercisable, entitles stockholders to buy one one-thousandth of a share of the Company’s Series A Junior Participating Preferred Stock at an exercise price of $50.00.

The rights will be exercisable only if such a person or group acquires 15 percent or more of the common stock of Quicksilver or announces a tender offer the consummation of which would result in ownership by such a person or group (an “Acquiring Person”) of 15 percent or more of the common stock of the Company. This 15 percent threshold does not apply to certain members of the Darden family who collectively owned, directly or indirectly, approximately 37% of the Company’s common stock at December 31, 2004.

If an Acquiring Person acquires 15 percent or more of the outstanding common stock of the Company, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of common shares of the Company having a market value of twice such price. If Quicksilver is acquired in a merger or other business combination transaction after an Acquiring Person has acquired 15 percent or more of the outstanding common stock of the Company, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s common shares having a market value of twice such price.

Prior to the acquisition by an Acquiring Person of beneficial ownership of fifteen percent or more of the common stock of Quicksilver, the rights are redeemable for $0.005 per right at the option of the board of directors of the Company.

Stock Option Plans

On October 4, 1999, the Board of Directors adopted the Company’s 1999 Stock Option and Retention Stock Plan (the “1999 Plan”), which was approved at the annual stockholders’ meeting held in June 2000. Upon approval of the 1999 Plan, 2.6 million shares of common stock were reserved for issuance pursuant to grants of incentive stock options, non-qualified stock options, stock appreciation rights and retention stock awards. Pursuant to an amendment approved at the annual shareholders meeting held in May 2004, an additional 2.4 million shares were reserved for issuance pursuant to the 1999 Plan.

In April 2004, the Board of Directors adopted the Company’s 2004 Non-Employee Director Stock Option Plan (the “2004 Plan”), which was approved at the annual stockholders’ meeting held in May 2004. There were 500,000 shares reserved under the 2004 Plan, which provides for the grant of non-qualified options to Quicksilver’s outside directors.

45

Under terms of the 1999 Plan and 2004 Plan, options may be granted to officers, employees and non-employee directors at an exercise price that is not less than 100% of the fair market value on the date of grant. Incentive stock options and non-qualified options may not be exercised more than ten years from date of grant. A summary of stock option transactions under the plans is as follows:

	2004				2003				2002
	Shares		Wtd Avg Exercise Price		Shares		Wtd Avg Exercise Price		Shares		Wtd Avg Exercise Price
Outstanding at beginning of year	1,258,712		$	4.45	1,476,422		$	3.75	1,692,174		$	2.94
Granted	1,844,496			26.98	104,188			11.45	138,506			8.51
Exercised	(655,538	)		3.47	(297,736	)		3.18	(337,694	)		2.43
Cancelled	—			—	—			—	(12,564	)		3.56
Forfeited	(11,500	)		16.52	(24,162	)		8.46	(4,000	)		8.51
Outstanding at end of year	2,436,170		$	21.50	1,258,712		$	4.45	1,476,422		$	3.75
Exercisable at end of year	583,163		$	4.96	913,848		$	3.83	770,314		$	3.33
Weighted average fair value of options granted			$	9.93			$	6.18			$	3.69

Pro forma information regarding net income and earnings per share is required by SFAS No. 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that statement. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:

	2004		2003		2002
Wtd avg grant date	Jul 6, 2004		Feb 21, 2003		Feb 5, 2002
Risk-free interest rate	2.7	%	2.8	%	3.0	%
Expected life (in years)	4.1		6.0		3.5
Expected volatility	45.4	%	54.9	%	55.6	%
Dividend yield	—		—		—

The following table summarizes information about stock options outstanding at December 31, 2004.

	Options Outstanding				Options Exercisable
Range of Exercisable Prices	At 12/31/04	Wtd Avg Remaining Contractual Life	Wtd Avg Exercise Price		At 12/31/04	Wtd Avg Exercise Price
$ 1-2	325,424	0.1	$	1.84	325,424	$	1.84
4-7	47,536	1.1		4.90	47,536		4.90
8-10	145,392	2.0		8.22	145,392		8.22
11-13	87,822	3.1		11.41	55,837		11.62
16-24	576,814	4.0		16.71	8,974		23.75
31-36	1,253,182	3.1		31.52	—		—
	2,436,170	2.8	$	21.50	583,163	$	4.96

17. OTHER REVENUE

Other revenue consists of the following:

	For the Years Ended December 31,
	2004		2003			2002
	(in thousands)
Tax credit revenue	$	221	$	(582	)	$	5,129
Marketing		928		1,208			3,021
Processing and transportation		1,407		1,286			1,533
	$	2,556	$	1,912		$	9,683

18. SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for interest and income taxes is as follows:

	For the Years Ended December 31,
	2004		2003		2002
	(in thousands)
Interest	$	14,742	$	19,543	$	19,730
Income taxes		72		66		147

46

Other non-cash transactions are as follows:

	For the Years Ended December 31,
	2004			2003			2002
	(in thousands)
Noncash changes in working capital related to acquisition of property, plant and equipment	$	(16,651	)	$	(10,593	)	$	(2,548	)
Distribution of equity to Mercury Exploration Company	$	—		$	(515	)	$	—
Tax benefit recognized on employee stock option exercises		4,243			739			—
Treasury stock (acquired) reissued:
10,293 shares for non-employee director stock option exercise		189			—			—
8,402 shares for employee stock option exercise		—			(200	)		—
74,200 shares for payment of executives’ compensation		—			—			364

19. RELATED PARTY TRANSACTIONS

As of December 31, 2004, members of the Darden family, Mercury Exploration Company and Quicksilver Energy L.P., entities that are owned by members of the Darden family, beneficially owned approximately 37% of the Company’s outstanding common stock. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

During 2002, Quicksilver paid $0.85 million and $0.90 million, respectively, for principal and interest on the note payable to Mercury associated with the 2000 acquisition of assets from Mercury. During 2003, Quicksilver paid Mercury $2.05 million principal and interest to retire the note. Quicksilver and its associated entities paid $0.86 million, $0.78 million and $0.74 million for rent in 2004, 2003 and 2002, respectively, on buildings which are owned by a Mercury affiliate. Rental rates were determined based on comparable rates charged by third parties.

Effective July 1, 2000, Quicksilver purchased the natural gas producing, gathering, transmission and marketing assets of Mercury, including 65% of Voyager Compression Services, LLC (“Voyager”), a gas compression company, from Mercury for $18 million. An independent appraiser determined the fairness, from a financial point of view, of the $18 million purchase price and the disinterested members of the Board of Directors approved the purchase. Mercury continued to own 33% of Voyager, and Jeff Cook, an officer of the Company, 2%. Quicksilver accounted for its 65% holdings in Voyager under the equity method since control over Voyager was shared equally with Mercury.

During 2002, Quicksilver purchased compressors and equipment for $3.7 million and maintenance and related services for $1.8 million from Voyager at terms as favorable as those granted by Voyager to third parties. Also in 2002, Voyager recognized an impairment loss of $0.9 million related to its inventory, fixed assets and operating leases for facilities. Subsequently, Voyager sold, to a third party, its Michigan inventory and fixed assets and recognized a gain on the sale of $0.2 million. Quicksilver recognized its proportionate share of these items during 2002.

Voyager sold its compressor service fixed assets and the majority of its Texas inventory to Quicksilver for $1.6 million (its historical cost that approximated fair value) in February 2003. In addition, Quicksilver paid Voyager $2.2 million for the fair value of its compressor service contracts. After completion of the sale of the service contracts and other assets, Quicksilver received a $0.2 million cash distribution from Voyager and recorded a $0.5 million equity distribution to Mercury for its share of Voyager’s gain from the disposition of the Compressor service contracts to Quicksilver. The transaction was reviewed and approved by the disinterested members of the Board of Directors. Mercury’s portion of the gain on the sale of the service contracts was treated as an equity distribution by Quicksilver as Mercury and the Darden family are considered as having a controlling interest in Quicksilver. Quicksilver’s gain on the sale of the contracts was eliminated.

During 2003, Voyager also sold, to a Mercury affiliate, leasehold improvements on operating leases with that Mercury affiliate at historical cost, which approximates fair value, of approximately $0.8 million. The leases were cancelled, and Voyager’s lease cancellation costs were $0.4 million.

47

20. SEGMENT INFORMATION

The Company operates in two geographic segments, the United States and Canada. Both areas are engaged in the exploration and production segment of the oil and gas industry. The Company evaluates performance based on operating income and property and equipment costs incurred (purchases of property and equipment plus noncash changes in working capital related to acquisition of property and equipment).

	United States		Canada			Corporate			Consolidated
2004
Revenues	$	136,580	$	43,149		$	—		$	179,729
Depletion, depreciation and accretion		30,808		9,282			601			40,691
Operating income		50,763		23,465			(13,535	)		60,693
Fixed assets – net		581,575		219,369			1,666			802,610
Property and equipment costs incurred		126,512		104,580			665			231,757
2003
Revenues	$	129,235	$	11,714		$	—		$	140,949
Depletion, depreciation and accretion		29,036		2,562			469			32,067
Operating income (loss)		51,898		5,202			(8,602	)		48,498
Fixed assets – net		496,102		106,789			1,685			604,576
Property and equipment costs incurred		78,936		69,297			255			148,488
2002
Revenues	$	119,917	$	2,062		$	—		$	121,979
Depletion, depreciation and accretion		28,932		675			552			30,159
Operating income (loss)		49,143		(337	)		(8,104	)		40,702
Fixed assets – net		436,195		31,984			1,899			470,078
Property and equipment costs incurred		73,480		15,161			324			88,965

21. RECLASSIFICATION OF THE STATEMENTS OF CASH FLOWS

The Statements of Cash Flows for the years ended December 31, 2004, 2003, and 2002 have been adjusted to correct the classification of certain transactions between sections of the Statements of Cash Flows. The Company determined that it had incorrectly classified the increase in accounts payable related to acquisition of property, plant and equipment as an operating activity inflow and an investing activity outflow rather than a noncash investing activity. Management has concluded that the correction was not material to the consolidated financial statements. The effect of the adjustments to correct the misclassification is to decrease cash flows from operating activities and to increase cash flows from investing activities in the amounts of $16.7 million, $10.6 million, and $2.5 million for the years ended December 31, 2004, 2003, and 2002, respectively.

A summary of the effects of these reclassifications are as follows:

	Year Ended December 31, 2004
	As Previously Reported			Adjustments			As Adjusted
	(in thousands)
Net cash flows from operating activities	$	99,449		$	(16,651	)	$	82,798
Net cash flows from investing activities		(220,500	)		16,651			(203,849	)
Net cash flows from financing activities		134,389			—			134,389
Effect of exchange rates on cash		(1,507	)		—			(1,507	)
Change in cash and cash equivalents		11,831			—			11,831
Cash and cash equivalents at beginning of the year		4,116			—			4,116
Cash and cash equivalents at end of the year	$	15,947		$	—		$	15,947
Noncash changes to working capital related to the acquisition of property, plant and equipment	$	—		$	(16,651	)	$	(16,651	)

48

	Year Ended December 31, 2003
	As Previously Reported			Adjustments			As Adjusted
	(in thousands)
Net cash flows from operating activities	$	59,280		$	(10,593	)	$	48,687
Net cash flows from investing activities		(147,422	)		10,593			(136,829	)
Net cash flows from financing activities		79,369			—			79,369
Effect of exchange rates on cash		3,773			—			3,773
Change in cash and cash equivalents		(5,000	)		—			(5,000	)
Cash and cash equivalents at beginning of the year		9,116			—			9,116
Cash and cash equivalents at end of the year	$	4,116		$	—		$	4,116
Noncash changes to working capital related to the acquisition of property, plant and equipment	$	—		$	(10,593	)	$	(10,593	)
	Year Ended December 31, 2002
	As Previously Reported			Adjustments			As Adjusted
	(in thousands)
Net cash flows from operating activities	$	44,198		$	(2,548	)	$	41,650
Net cash flows from investing activities		(83,659	)		2,548			(81,111	)
Net cash flows from financing activities		40,050			—			40,050
Effect of exchange rates on cash		(199	)		—			(199	)
Change in cash and cash equivalents		390			—			390
Cash and cash equivalents at beginning of the year		8,726			—			8,726
Cash and cash equivalents at end of the year	$	9,116		$	—		$	9,116
Noncash changes to working capital related to the acquisition of property, plant and equipment	$	—		$	(2,548	)	$	(2,548	)

22. SUPPLEMENTAL INFORMATION (UNAUDITED)

Proved oil and gas reserves estimates were prepared by independent petroleum engineers with Schlumberger Data and Consulting Services, LaRoche Petroleum Consultants, Ltd. and Netherland, Sewell & Associates, Inc. The reserve reports were prepared in accordance with guidelines established by the Securities and Exchange Commission and, accordingly, were based on existing economic and operating conditions. Natural gas and crude oil prices in effect as of the date of the reserve reports were used without any escalation except in those instances where the sale of production was covered by contract, in which case the applicable contract prices, including fixed and determinable escalations, were used for the duration of the contract, and thereafter the year-end price was used (See “Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves” below for a discussion of the effect of the different prices on reserve quantities and values.) Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be

49

construed as being exact. Moreover, the present values should not be construed as the current market value of the Company’s natural gas and crude oil reserves or the costs that would be incurred to obtain equivalent reserves.

The changes in proved reserves for the years ended December 31, 2002, 2003 and 2004 were as follows:

	Natural Gas (MMcf)						Crude Oil (MBbl)						NGL (MBbl)
	United States		Canada		Total		United States		Canada		Total		United States		Canada		Total
December 31, 2001	535,009		16,513		551,522		13,344		—		13,344		1,538		—		1,538
Revisions	40,288		1,375		41,663		2,153		—		2,153		214		—		214
Extensions and discoveries	30,330		36,649		66,979		1,444		—		1,444		619		—		619
Purchases in place	64,267		—		64,267		25		—		25		1		—		1
Sales in place	—		—		—		(59	)	—		(59	)	—		—		—
Production	(31,910	)	(935	)	(32,845	)	(905	)	—		(905	)	(156	)	—		(156	)
December 31, 2002	637,984		53,602		691,586		16,002		—		16,002		2,216		—		2,216
Revisions	(9,137	)	2,363		(6,774	)	(2,022	)	1		(2,021	)	(165	)	2		(163	)
Extensions and discoveries	45,081		93,591		138,672		—		—		—		—		—		��
Purchases in place	1,204		—		1,204		—		—		—		—		—		—
Production	(31,612	)	(2,924	)	(34,536	)	(807	)	(1	)	(808	)	(133	)	(2	)	(135	)
December 31, 2003	643,520		146,632		790,152		13,173		—		13,173		1,918		—		1,918
Revisions	(18,350	)	(12,105	)	(30,455	)	(43	)	—		(43	)	(44	)	1		(43	)
Extensions and discoveries	28,752		131,796		160,548		3		—		3		2,447		—		2,447
Purchases in place	5,000		3,461		8,461		—		—		—		—		—		—
Sales in place	(602	)	—		(602	)	(3,377	)	—		(3,377	)	(6	)	—		(6	)
Production	(30,644	)	(8,707	)	(39,351	)	(689	)	—		(689	)	(128	)	(1	)	(129	)
December 31, 2004	627,676		261,077		888,753		9,067		—		9,067		4,187		—		4,187
Proved developed reserves
December 31, 2002	550,889		22,750		573,639		10,722		—		10,722		1,524		—		1,524
December 31, 2003	569,978		83,698		653,676		8,734		—		8,734		1,405		—		1,405
December 31, 2004	556,999		149,453		706,453		4,587		—		4,587		2,464		—		2,464

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The capitalized costs relating to oil and gas producing activities and the related accumulated depletion, depreciation and accretion as of December 31, 2004, 2003 and 2002 were as follows:

	United States			Canada			Consolidated
				(in thousands)
2004
Proved properties	$	644,527		$	193,607		$	838,134
Unevaluated properties		57,929			39,239			97,168
Accumulated DD&A		(180,975	)		(14,440	)		(195,415	)
Net capitalized costs	$	521,481		$	218,406		$	739,887
2003
Proved properties	$	577,322		$	88,135		$	665,457
Unevaluated properties		27,110			22,809			49,919
Accumulated DD&A		(155,183	)		(4,618	)		(159,801	)
Net capitalized costs	$	449,249		$	106,326		$	555,575
2002
Proved properties	$	524,947		$	20,431		$	545,378
Unevaluated properties		3,888			13,025			16,913
Accumulated DD&A		(129,194	)		(1,712	)		(130,906	)
Net capitalized costs	$	399,641		$	31,744		$	431,385

Costs incurred in oil and gas property acquisition, exploration and development activities during the years ended December 31, 2004, 2003 and 2002 were as follows:

	United States		Canada		Consolidated
			(in thousands)
2004
Proved acreage	$	11,907	$	2,942	$	14,849
Unproved acreage		31,857		7,144		39,001
Development costs		45,213		71,094		116,307
Exploration costs		25,673		22,631		48,304
Total	$	114,650	$	103,811	$	218,461
2003
Proved acreage	$	3,215	$	3,388	$	6,603
Unproved acreage		24,063		6,739		30,802
Development costs		37,682		41,820		79,502
Exploration costs		9,411		17,066		26,477
Total	$	74,371	$	69,013	$	143,384
2002
Proved acreage	$	32,199	$	—	$	32,199
Unproved acreage		550		5,422		5,972
Development costs		34,178		938		35,116
Exploration costs		5,925		8,659		14,584
Total	$	72,852	$	15,019	$	87,871

Results of operations from producing activities for the years ended December 31, 2004, 2003 and 2002 are set forth below:

	United States		Canada			Consolidated
	(in thousands)
2004
Natural gas, crude oil & NGL sales	$	134,268	$	42,905		$	177,173
Oil & gas production expense		54,784		10,402			65,186
Depletion expense		26,444		8,981			35,425
		53,040		23,522			76,562
Income tax expense		18,564		7,908			26,472
Results from producing activities	$	34,476	$	15,614		$	50,090
2003
Natural gas, crude oil & NGL sales	$	127,339	$	11,698		$	139,037
Oil & gas production expense		48,243		3,951			52,194
Depletion expense		25,600		2,428			28,028
		53,496		5,319			58,815
Income tax expense		18,724		1,788			20,512
Results from producing activities	$	34,772	$	3,531		$	38,303
2002
Natural gas, crude oil & NGL sales	$	110,291	$	2,005		$	112,296
Oil & gas production expense		40,505		1,723			42,228
Depletion expense		26,352		601			26,953
		43,434		(319	)		43,115
Income tax expense		15,199		(138	)		15,061
Results from producing activities	$	28,235	$	(181	)	$	28,054

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The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of the Company’s natural gas and crude oil properties. An estimate of such value should consider, among other factors, anticipated future prices of natural gas and crude oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.

Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for contracts with price floors but excluding hedges, to the estimated future production of the year-end reserves. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain proved undeveloped locations uneconomical, both of which reduce reserves. The following representative natural gas and crude oil year-end prices were used in the Standardized Measure. These prices were adjusted by field for appropriate regional differentials.

	At December 31,
	2004		2003		2002
Natural gas – Henry Hub-Spot	$	6.18	$	5.97	$	4.74
Natural gas – AECO		5.18		5.32		2.92
Crude oil – WTI Cushing		43.36		32.55		31.20

Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved natural gas and crude oil properties. Tax credits and net operating loss carry forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.

The standardized measure of discounted cash flows related to proved oil and gas reserves at December 31, 2004, 2003 and 2002 were as follows:

	United States			Canada			Consolidated
				(in thousands)
2004
Future revenues	$	4,241,385		$	1,306,819		$	5,548,204
Future production costs		(1,456,005	)		(295,443	)		(1,751,448	)
Future development costs		(116,559	)		(145,297	)		(261,856	)
Future income taxes		(836,557	)		(238,141	)		(1,074,698	)
Future net cash flows		1,832,264			627,938			2,460,202
10% discount - calculated difference		(1,133,990	)		(355,481	)		(1,489,471	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	698,274		$	272,457		$	970,731
2003
Future revenues	$	4,125,685		$	746,722		$	4,872,407
Future production costs		(1,342,167	)		(122,164	)		(1,464,331	)
Future development costs		(117,330	)		(60,696	)		(178,026	)
Future income taxes		(851,337	)		(162,636	)		(1,013,973	)
Future net cash flows		1,814,851			401,226			2,216,077
10% discount - calculated difference		(1,120,056	)		(247,280	)		(1,367,336	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	694,795		$	153,946		$	848,741
2002
Future revenues	$	3,354,927		$	206,602		$	3,561,529
Future production costs		(1,260,500	)		(40,504	)		(1,301,004	)
Future development costs		(96,748	)		(14,373	)		(111,121	)
Future income taxes		(616,865	)		(52,680	)		(669,545	)
Future net cash flows		1,380,814			99,045			1,479,859
10% discount - calculated difference		(802,968	)		(62,040	)		(865,008	)
Standardized measure of discounted future net cash flows relating to proved reserves	$	577,846		$	37,005		$	614,851

52

The primary changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2004, 2003 and 2002 were as follows:

	As of December 31,
	2004			2003			2002
				(in thousands)
Net changes in price and production costs	$	(82,974	)	$	140,623		$	358,878
Development costs incurred		61,069			44,167			35,116
Revision of estimates		(30,509	)		(27,901	)		63,866
Changes in estimated future development costs		3,183			(12,703	)		(63,980	)
Purchase and sale of reserves, net		(23,367	)		1,832			63,539
Extensions and discoveries		219,656			170,660			87,555
Net change in income taxes		(21,638	)		(99,013	)		(162,889	)
Sales of oil and gas net of production costs		(111,987	)		(86,843	)		(70,068	)
Accretion of discount		120,065			86,775			35,895
Other		(11,508	)		16,293			(2,003	)
Net increase	$	121,990		$	233,890		$	345,909

23. SELECTED QUARTERLY DATA (UNAUDITED)

	Mar 31		Jun 30		Sep 30		Dec 31
	(In thousands, except per share data)
2004
Operating revenues	$	39,777	$	41,980	$	45,544	$	52,428
Operating income		12,012		13,172		16,109		19,400
Net income		5,937		7,500		7,889		9,946
Basic net income per share	$	0.12	$	0.15	$	0.16	$	0.20
Diluted net income per share		0.12		0.15		0.16		0.19
2003
Operating revenues	$	37,516	$	33,095	$	33,513	$	36,825
Operating income		14,915		10,102		11,643		11,838
Income before effect of accounting change		6,412		1,109		5,229		5,755
Net income		4,115		1,109		5,229		5,755
Basic income per share before effect of accounting change	$	0.15	$	0.03	$	0.12	$	0.12
Basic net income per share		0.10		0.03		0.12		0.12
Diluted income per share before effect of accounting change		0.15		0.03		0.11		0.11
Diluted net income per share		0.10		0.03		0.11		0.11

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PART IV

ITEM 15. Exhibits and Financial Statement Schedules

(b) Exhibits

Exhibit No.	Description
*23.1	Consent of Deloitte & Touche LLP
*31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Filed herewith

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SIGNATURES

Pursuant to the requirements of Section 13 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.

	Quicksilver Resources Inc.
	(the “Registrant”)
	By:	/s/ Glenn Darden
		Glenn Darden
Dated: August 8, 2005		President and Chief Executive Officer

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