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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2004

OR

FOR THE TRANSITION PERIOD FROM              TO             

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)

777 West Rosedale, Suite 300, Fort Worth, Texas 76104

(Address of principal executive offices) (Zip Code)

(817) 665-5000

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

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

As of April 30, 2004, the registrant had 24,849,973 outstanding shares of its common stock, $0.01 par value.

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QUICKSILVER RESOURCES INC.

INDEX TO FORM 10-Q

For the Period Ending March 31, 2004

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

INDEPENDENT ACCOUNTANTS’ REPORT

To the Board of Directors and Stockholders of

Quicksilver Resources Inc.

Fort Worth, Texas

We have reviewed the accompanying condensed consolidated balance sheet of Quicksilver Resources Inc. (the Company) as of March 31, 2004, and the related condensed consolidated statements of income and comprehensive income and cash flows for the three-month periods ended March 31, 2004 and 2003. These interim financial statements are the responsibility of the Company’s management.

We conducted our reviews in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of the Company as of December 31, 2003, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated March 15, 2004, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2003, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

As discussed in Note 2 to the condensed consolidated interim financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standard No. 143, Accounting for Asset Retirement Obligations.

/s/ DELOITTE & TOUCHE LLP

Fort Worth, Texas

May 6, 2004

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data – Unaudited

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

In thousands, except for per share data – Unaudited

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

In thousands – Unaudited

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

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QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated interim financial statements of Quicksilver Resources Inc. (“Quicksilver” or the “Company”) have not been audited by independent public accountants. In the opinion of Company management, the accompanying condensed consolidated interim financial statements contain all adjustments necessary to present fairly the financial position of the Company as of March 31, 2004, and its income, comprehensive income and cash flows for the three month periods ended March 31, 2004 and 2003. All such adjustments are of a normal recurring nature. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Management believes its estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from the Company’s estimates.

Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2003.

Net Income per Common Share

Basic net income per common share is computed by dividing the net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants, and any other convertible securities outstanding. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three month periods ended March 31, 2004 and 2003.

No outstanding options were excluded from the diluted net income per share calculation for either of the periods presented.

Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141, Business Combinations, which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, Goodwill and Other Intangible Assets, which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life continue to be amortized over that period. The amortization provisions apply to goodwill and intangible assets acquired after June 30, 2001. SFAS Nos. 141 and 142 clarify that more assets should be distinguished and classified between tangible and intangible. The Company did not change or reclassify contractual mineral rights included in oil and gas properties on the balance sheet upon adoption of SFAS No. 142. The Company believes the treatment of such mineral rights as tangible assets under the full cost method of accounting for crude oil and natural gas properties is appropriate. An issue has arisen regarding whether contractual mineral rights should be classified as intangible rather than tangible assets. If it is determined that reclassification is necessary, the Company’s gross oil and gas properties would be reduced by $89.2 million and $74.9 million and intangible assets would be increased by like amounts at March 31, 2004 and December 31, 2003, respectively, representing cost incurred from the effective date of June 30, 2001. The provisions of SFAS Nos. 141 and 142 impact only the balance sheet and associated footnote disclosure. The reclassifications would not affect the Company’s cash flows or results of operations.

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2. ASSET RETIREMENT OBLIGATIONS

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

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

The following table provides a reconciliation of the changes in the estimated asset retirement obligation for the three month periods ended March 31, 2004 and 2003.

During the three month periods ended March 31, 2004 and 2003, accretion expense was recognized and included in depletion, depreciation and accretion expense reported in the statement of income for the period. There have not been any revisions to either the timing or the amount of the original estimate of undiscounted cash flows during 2004. At March 31, 2004 and December 31, 2003, retirement obligations classified as current were $54,000.

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3. HEDGING

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

The fair values of all natural gas and crude oil financial instruments and firm sale and purchase commitments as of March 31, 2004 and December 31, 2003 were estimated based on market prices of natural gas and crude oil for the periods covered by the hedge derivatives. The net differential between the contractual prices in each hedge derivative and commitment and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the fair value of the Company’s hedge derivatives and commitments does not necessarily represent the value a third party would pay to assume the Company’s contract positions. The fair values of the interest rate swaps were based upon third-party estimates of the fair values of the swaps.

At March 31, 2004, derivative assets of $0.3 million and derivative liabilities of $41.6 million have been classified as current based on the maturity of the derivative instruments. The Company estimates $26.3 million of after-tax losses will be reclassified from other comprehensive income over the next twelve months.

4. LONG-TERM DEBT

Long-term debt consists as follows:

As of March 31, 2004, the Company’s borrowing base under its senior credit facility was $250 million of which $46.4 million was available. The loan agreements for the senior credit facility prohibit the declaration or payments of dividends by the Company and contain certain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio and minimum earnings (before interest, taxes, depreciation, depletion, amortization, non-cash income and expense and exploration costs to interest ratio). Additionally, the Second Mortgage Notes contain restrictive covenants, which, among other things, require maintenance of a minimum current ratio, a minimum collateral coverage ratio and a minimum earnings (before interest, taxes, depreciation, depletion, accretion, amortization, non-cash income and expense and exploration costs) to fixed charges ratio. The Company currently is in compliance with all such restrictions.

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

5. COMMITMENTS AND CONTINGENCIES

Quicksilver has employment agreements in place for three executives of MGV. These agreements contain a formula for calculating bonuses with a determination date of December 31, 2005. The formula requires actual data with respect to, among other things, capital spending and proved reserve value for MGV from the last six months of 2005. The formula could result in bonuses being payable, but the amounts of such bonuses cannot be calculated at this time. The Company will continue to monitor its potential liability in respect of these bonuses, and will record accruals in respect of such liabilities when payment of the bonuses becomes probable and the amounts thereof become reasonably estimable.

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

6. STOCK BASED COMPENSATION

Quicksilver has one stock-based employee compensation plan, the 1999 Stock Option and Stock Retention Plan. The Company accounts for the plan under the recognition and measurement principles of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. No stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant.

On January 7, 2004, the Company granted stock options covering 287,965 shares of common stock to the Company’s officers and employees. These options were granted at an exercise price of $33.03. No compensation expense was recognized at the date of grant, as the exercise price was equal to the market value of the common stock at the dates of grant.

The following table reflects pro forma income before the cumulative effect of an accounting change and the associated earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-based Compensation, to stock-based employee compensation.

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7. RELATED PARTY TRANSACTIONS

The Darden family and associated entities, including Mercury Exploration Company (“Mercury”), Quicksilver Energy L.P., The Discovery Fund, Thomas Darden, Glenn Darden, Anne Darden Self, Lucy Darden and eight Darden family trusts beneficially own approximately 38% of Quicksilver’s shares outstanding. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

Quicksilver and its subsidiaries paid $0.2 million during each of the three-month periods ended March 31, 2004 and 2003 for rent on buildings owned by a Mercury affiliate. Rental rates were determined based on comparable rates charged by third parties.

8. GEOGRAPHIC INFORMATION

The Company operates in two geographic segments, the United States and Canada. Both areas are engaged in the exploration and production segment of the oil and gas industry. The Company evaluates performance based on operating income.

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

Certain statements contained in this quarterly report and other materials we file with the SEC, as well as information included in oral statements or other written statements made or to be made by us, other than statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements may relate to a variety of matters not currently ascertainable, such as future capital expenditures, drilling activity, acquisitions and dispositions, development or exploratory activities, cost savings efforts, production activities and volumes, hydrocarbon reserves, hydrocarbon prices, hedging activities and the results thereof, financing plans, liquidity, competition and our ability to realize efficiencies related to certain transactions or organizational changes. Forward-looking statements generally are accompanied by words such as “may,” “will,” “could,” “should,” “anticipate,” “believe,” “budgeted,” “expect,” “intend,” “plan,” “project,” “potential,” “estimate,” “continue,” or “future” or the negative, other variations thereof or other or similar statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include:

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements. In addition to the foregoing and any risks and uncertainties specifically identified in the text surrounding forward-looking statements, any statements in the reports and other documents filed by us with the Commission that warn of risks or uncertainties associated with future results, events or circumstances identify important factors that could cause actual results, events and circumstances to differ materially from those reflected in the forward-looking statements. The following discussion and analysis should be read in conjunction with our condensed consolidated interim financial statements contained herein and our annual report for the year ended December 31, 2003, along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in such annual report.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2004 Compared with Three Months Ended March 31, 2003

We recorded net income of $5.9 million ($0.24 per diluted share) for the three months ended March 31, 2004, compared to net income of $4.1 million ($0.19 per diluted share) for the first quarter of 2003. Included in the 2003 period was a $2.3 million charge ($0.11 per diluted share), net of tax, for the adoption of SFAS No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

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Operating Revenues

Revenues for the first quarter of 2004 were $39.8 million; a $2.3 million increase from the $37.5 million reported for the three months ended March 31, 2003. Production revenue increased $2.0 million as a result of a 4% increase in sales volumes and slightly higher realized sales prices.

Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the three months ended March 31, 2004 and 2003 are as follows:

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Natural gas sales of $33.0 million for the first quarter of 2004 were 7% higher than the $31.0 million for the 2003 first quarter. Revenue increased $2.0 million from the first quarter of 2003 as a result of a 7% increase in sales volumes for the 2004 quarter. Production from our coal bed methane (“CBM”) projects in Canada increased approximately 1,288,000 Mcf from the 2003 first quarter. New wells in Indiana added sales volumes of approximately 346,000 Mcf in the first quarter of 2004. Natural gas volumes in Michigan included 287,000 Mcf from Antrim wells drilled during 2003 and 2004. The U.S. production increases were more than offset by natural production declines.

Crude oil sales were $5.2 million for the three months ended March 31, 2004 compared to $5.4 million in the first quarter of 2003. Lower production reduced revenue $0.8 million from the prior year quarter. Natural production declines were only partially offset by production from new wells in the Michigan Beaver Creek Detroit River Zone 3 and Wyoming Derby Dome fields where production increased approximately 2,100 barrels from the first quarter of 2003. First quarter average crude oil sales price for 2004 increased to $27.94 per Bbl from $25.16 per Bbl in the first quarter of 2003 and increased revenue $0.6 million.

Other Revenue

Other revenue increased $0.2 million from the prior year period. The first quarter of 2003 included a $0.5 million reduction in other revenue that resulted from the completion of our repurchase of Section 29 tax credit properties. Marketing revenue for the first quarter of 2004 decreased $0.4 million as a result of the cessation of business of our marketing subsidiary, Cinnabar Energy Services & Trading, LLC, as of December 31, 2003.

Operating Expenses

First quarter operating expenses for 2004 were $28.1 million; an increase of $5.2 million over the $22.9 million of expenses incurred in the first quarter of 2003.

Oil and Gas Production Costs

Oil and gas production costs were $16.0 million for the 2004 first quarter. The $3.4 million increase over the prior year quarter included a $1.5 million increase in Canadian production costs. Canadian production increased 1,288,000 Mcfe primarily as a result of CBM wells drilled during the last half of 2003 and the first quarter of 2004. On a Mcfe-basis, Canadian production expenses decreased $0.30 to $1.22 per Mcfe as a result of the improving economies of scale.

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U.S. production expenses increased $1.9 million for the first quarter of 2004 compared to the prior year period. Initial operating expenses for new wells in Indiana increased production expenses approximately $0.9 million. During the first quarter, 12 new wells and 24 non-producing wells acquired in 2003 began production in addition to 47 wells that began production in the fourth quarter of 2003. Operating costs are expected to decrease as natural gas production increases after initial production that contains a high water concentration. Production overhead in Indiana increased approximately $0.3 million as a result of personnel added to operate and maintain these properties. Michigan operating expenses increased approximately $0.8 million as a result of the routine overhaul of several compressors. Similar overhaul expenses were not incurred in the first quarter of 2003, but are expected to continue into the second quarter of 2004. These items increased U.S. production expenses by $0.20 per Mcfe for the first quarter of 2004.

Depletion, Depreciation and Accretion

First quarter 2004 depletion of $7.7 million was $1.0 million higher than depletion for the 2003 first quarter primarily as a result of an increase in the depletion rate as well as additional sales volumes. Our depletion rate increased over the prior year period as a result of the significant capital expenditures and proved reserves added for our Canadian operations.

General and Administrative Expense

General and administrative costs incurred during the three months ended March 31, 2004 were $2.6 million. The $0.6 million increase over first quarter of 2003 expense was primarily the result of a $0.5 million increase in personnel costs for the 2004 quarter. Increased payroll and benefit costs are primarily the result of additional management and administrative personnel hired during the fourth quarter of 2003 and the first quarter of 2004.

Interest Expense

Interest expense for the first quarter of 2004 was $3.4 million, a decrease of $1.5 million compared to the first quarter of 2003. Interest expense decreased as a result of lower effective interest rates. The decrease in effective interest rates is primarily the result of refinancing our subordinated notes payable at lower interest rates in June of 2003.

Income Tax Expense

Income tax expense decreased $0.9 million over the prior year period as a result of lower pretax income for the first quarter of 2004. Our income tax provision of $2.7 million was established using an effective U.S. federal tax rate of 35% and an effective Canadian tax rate of 26%. The effective Canadian tax rate reflects adjustments for permanent and timing differences between the accounting and tax basis of assets and liabilities with consideration of enacted tax rate reductions in future years.

CAPITAL RESOURCES AND LIQUIDITY

Net cash from operations of $15.2 million for the three months ended March 31, 2004 was $12.1 million higher than the same period in 2003. The improvement was primarily due to changes in working capital from operations. Our principal operating sources of cash include sales of natural gas and crude oil and revenues from gas marketing, transportation and processing. During the first quarter of 2004, we sold approximately 28% of our natural gas production under long-term contracts with an average floor price of $2.48 per Mcf and an additional 42% of our natural gas production was sold under fixed-price swap agreements. Additionally, price collars covered 10% and 49% of our natural gas and crude oil production, respectively. As a result of our hedging activities, we benefit from enhanced predictability of our natural gas and crude oil revenues. However, when natural gas and crude oil market prices exceed our financial hedge swap prices, we are required to make payment for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payment from our customers until 25 to 60 days after the month of production. Additionally, in the event of a significant production curtailment, we are required contractually to fulfill our commitments under our long-term sales contracts by purchasing natural gas volumes at market prices.

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In the first quarter of 2004, we expended $39.9 million on additions of oil and gas properties and related equipment. Cash used for investing activities consisted of $37.2 million expended for exploration and development activities and $2.7 million expended for construction and acquisition of gathering and processing facilities and other fixed assets. Of the $37.2 million expended for exploration and development, $14.0 million was incurred in leasehold acquisitions. Those acquisitions included $7.5 million in Canada, $2.5 million in Indiana and Kentucky and $2.7 million in Texas.

Capital expenditures

Net cash provided by financing activities for the three months ended March 31, 2004 was $25.4 million. During the first quarter of 2004, we increased borrowings under our senior credit facility by $25 million. As of March 31, 2004, we had $46.4 million available under our $250 million senior credit facility.

The senior credit facility matures on May 13, 2005 and the Second Mortgage Notes mature on December 31, 2006. The Company is engaged in discussions with potential lenders regarding a new senior credit facility to replace the Company’s existing senior credit facility.

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.

Our primary risk exposure is related to natural gas and crude oil commodity prices. We have mitigated the risk of adverse price movements through the use of swaps and collars; however, we have also limited future gains from favorable movements.

Commodity Price Risk

We enter into financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. These contracts have included price ceilings and floors, no-cost collars and fixed price swaps. We sell approximately 25,000 Mcfd and 10,000 Mcfd of natural gas under long-term contracts with floor prices of $2.49 per Mcf and $2.47 per Mcf, respectively, through March 2009. Approximately 6,800 Mcfd sold under these contracts are third party volumes controlled by us.

Equity natural gas volumes of approximately 53,000 Mcfd, 50,500 Mcfd and 37,200 Mcfd are hedged for the second, third and fourth quarters of 2004, respectively, using fixed price swap agreements. The weighted averaged price for those natural gas volumes is $3.72 per Mcf, $3.79 per Mcf and $3.24 per Mcf, respectively. Additionally, our crude oil production is hedged by price collars for 1,000 Bbld for the second quarter of 2004 and 500 Bbld for the remainder of the year.

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

Commodity price fluctuations affect our remaining natural gas and crude oil volumes as well as our NGL volumes. Up to 4,500 Mcfd of natural gas is committed at market price through May 2005. Additional gas volumes of 16,500 Mcfd are committed at market price through September 2008. Approximately 15,200 Mcfd sold under these contracts are third party volumes controlled by us.

We also enter into financial contracts to hedge our exposure to commodity price risk associated with future contractual natural gas sales and purchases. These contracts consist of fixed price sales to third parties. As a result of these firm sale commitments the associated financial price swaps have qualified as fair value hedges. At March 31, 2004, we recorded assets and liabilities of $261,000 and $226,000, respectively, for the fair value of firm sale commitments and the associated financial price swaps.

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