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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to             

Commission file number: 001-14837

Quicksilver Resources Inc.

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of incorporation or organization)

75-2756163

(I.R.S. Employer Identification No.)

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

(Address of principal executive offices) (Zip Code)

(817) 665-5000

(Registrant’s telephone number, including area code)

None

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

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

As of May 9, 2003, the registrant had 21,179,759 outstanding shares of its common stock, $0.01 par value.

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QUICKSILVER RESOURCES INC.

INDEX TOFORM 10-Q

For the Period Ending March 31, 2003

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PART I. FINANCIAL INFORMATION

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, 2003, and the related condensed consolidated statements of income, comprehensive income and cash flows for the three month periods ended March 31, 2003 and 2002. These financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of the Company as of December 31, 2002, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for the year then ended (not presented herein); and in our report dated March 14, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2002, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

As discussed in Note 2 to the condensed consolidated 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 9, 2003

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

In thousands, except for share data

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

In thousands, except for per share data – Unaudited

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

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QUICKSILVER RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

In thousands – Unaudited

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

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QUICKSILVER RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ACCOUNTING POLICIES AND DISCLOSURES

The accompanying condensed consolidated financial statements of Quicksilver Resources Inc. (“Quicksilver” or the “Company”), with the exception of the consolidated balance sheet as of December 31, 2002, have not been audited by independent public accountants. In the opinion of Company management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly the financial position of the Company as of March 31, 2003, and its income and cash flows for the three months ended March 31, 2003 and 2002. All such adjustments are of a normal recurring nature. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results.

Certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2002.

Net Income per Common Share

Basic net income per common share is computed by dividing the net income by the weighted average number of shares of common stock outstanding during the period. Diluted net income per common share is calculated in the same manner but also considers the impact to net income and common shares for the potential dilution from stock options, stock warrants, and any other convertible securities outstanding. For the three months ended March 31, 2003 and 2002 there were no adjustments to net income for purposes of calculating diluted net income per common share. The following is a reconciliation of the weighted average common shares used in the basic and diluted net income per common share calculations for the three months ended March 31, 2003 and 2002.

For the period ended March 31, 2002, warrants representing 550,000 shares of common stock were excluded from the diluted net income per share calculation for the period prior to their exercise as the exercise price exceeded the average market price of the Company’s common stock.

Recently Issued Accounting Standards

The Financial Accounting Standards Boards (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, in April 2004. The statement clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The statement is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003.

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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 to 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.

All asset retirement obligations of the Company have been 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 $13.3 million, of which $0.9 million has been classified as current. The cumulative-effect adjustment of $2.3 million includes $1.3 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. During the three months ended March 31, 2003, $0.2 million of accretion expense was recognized and included in the $7.8 million of depletion, depreciation and accretion expense reported in the statement of income for the period. Asset retirement obligations at March 31, 2003 are $13.6 million, of which $0.9 million has been classified as current. No abandonment and retirement costs have been incurred in 2003.

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

3. HEDGING

The estimated fair values of all hedge derivatives and the associated fixed price firm sales and purchase commitments as of March 31, 2003 and December 31, 2002 are provided below. The associated carrying values of these financial instruments and firm commitments are equal to the estimated fair values for each period presented.

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The fair values of all natural gas and crude oil financial instruments and firm sale and purchase commitments as of March 31, 2003 and December 31, 2002 were estimated based on market prices of natural gas and crude oil for the periods covered by the hedge derivatives. The net differential between the contractual prices in each hedge derivative and commitment and market prices for future periods, as adjusted for estimated basis, has been applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the fair value of the Company’s hedge derivatives and commitments does not necessarily represent the value a third party would pay to assume the Company’s contract positions. The fair value of the interest rate swap was based upon third-party estimates of the fair value of the swap.

At March 31, 2003, derivative assets of $276,000 and derivative liabilities of $33,007,000 have been classified as current based on the maturity of the derivative instruments resulting in $21,253,000 of after-tax losses to be reclassified from other comprehensive income over the next twelve months.

3. LONG-TERM DEBT

On March 12, 2003, the holders of the subordinated notes were notified that the Company intends to exercise its prepayment option for all of the subordinated notes outstanding. In addition to the principal and interest, the Company will pay a premium of $3,180,000 on June 27, 2003. The Company plans to finance the repayment with issuance of $60 million of term debt to be repaid over three and one half years at an interest rate of approximately 7.5%. At the time of the refinancing, the premium of $3,180,000 and the remaining deferred finance costs of approximately $1,485,000 will be expensed. The remainder of a deferred hedging gain of approximately $875,000 will be recognized as well. The gain resulted from the settlement of an associated interest rate hedge in 2002 and is currently being recognized through the original termination date of the hedge, March 30, 2009.

As of March 31, 2003, the Company’s borrowing base under its credit facility was $250 million of which $40,055,432 was available. On May 6, 2003, the borrowing base of $250 million was reaffirmed. The loan agreements for the credit facility prohibit the declaration or payments of dividends by the Company and contain certain other restrictive covenants, which, among other things, require the maintenance of a minimum current ratio. Additionally, the subordinated notes contain restrictive covenants, which, among other things, require maintenance of working capital, a collateral coverage ratio and an earnings ratio before interest, taxes, depreciation and amortization and costs associated with seismic and geological services in connection and attributable to oil and gas exploration. The Company currently is in compliance with all such restrictions.

4. TAX CREDIT SALES

On March 31, 2000, the Company conveyed to a bank Internal Revenue Code Section 29 credits for 99.5% of the interests acquired from CMS Oil and Gas Company, including the interests in Terra Energy Ltd., in Devonian shale gas production from certain wells located in Michigan. Cash proceeds received from the sale were $25,000,000 and were recorded as unearned revenue. Revenue was recognized as reserves were produced. Revenue of $2,441,000 was recognized in the first quarter of 2002 in other revenue.

During 1997, other tax credits were conveyed through the sale of certain working interests to a bank. Revenue of $386,000 related to that conveyance was recognized in the first quarter of 2002 in other revenue.

In May 2003, Quicksilver completed negotiations to purchase interests owned by the bank as a result of the Company’s tax credit sales. Quicksilver will pay $6.3 million to acquire all such interests in the Section 29 tax-eligible properties. As a result of the agreement, the Company recorded, in the first quarter of 2003, a $507,000 reduction of deferred revenue previously recognized.

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5. COMMITMENTS AND CONTINGENCIES

In August 2001, a group of royalty owners (Athel E. Williams et al.) brought suit against Quicksilver and three of its subsidiaries in the Circuit Court of Otsego County, Michigan. The suit alleges that Terra Energy Ltd., one of Quicksilver’s subsidiaries acquired in 2000, underpaid royalties or overriding royalties to the 13 named plaintiffs and to a class of plaintiffs who have yet to be determined. The pleadings of the plaintiffs seek damages in an unspecified amount and injunctive relief against future underpayments. Due to administrative oversight an answer was not timely filed and a default was entered against Quicksilver in December 2001. On October 24, 2002, the trial court granted Terra’s motion to set aside the default. The court heard arguments on class certification on November 8, 2002; on December 6, 2002, the court issued a memorandum opinion granting class certification in part and denying it in part. The court stated that those portions of the royalty owner’s complaint against the Company, which alleged that the Company deducted excessive post production costs from royalty payments should not be certified as class action. The court certified the remainder of the complaint for class action status. On December 20, 2002, the Company filed a motion for clarification and reconsideration of the court’s order. That motion was denied on March 9, 2003. Based on information currently available to the Company, Quicksilver believes that the final resolution of this matter will not have a material effect on its operations, equity or cash flows.

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 February 11 2003, the Company granted stock options covering 31,884 shares of common stock to the Company’s officers. These options were granted at an exercise price of $22.08. Non-employee directors were granted stock options on March 10, 2003 covering 20,210 shares of stock in lieu of compensation for 2003. These options were granted at an exercise price of $24.10 and vest one year from the date of grant. No compensation expense was recognized at the dates of grant, as the exercise price was equal to the market value of the common stock at the dates of grant.

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

7. RELATED PARTY TRANSACTIONS

The Darden family has effective ownership of approximately 47% of Quicksilver’s shares outstanding including shares owned by Mercury Exploration Company (“Mercury”) and Quicksilver Energy L.C. Thomas Darden, Glenn Darden and Anne Darden Self are officers and directors of the Company.

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During the first quarter of 2003, Quicksilver paid $203,000 for principal and interest on a note payable to Mercury associated with an acquisition of assets from Mercury. At March 31, 2003, the balance of the note was $1,760,000. Quicksilver and its associated entities paid $187,000 and $183,000 during the three-months ending March 31, 2003 and 2002, respectively, for rent on buildings, which are owned by a Mercury affiliate.

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

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

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

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

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

The statements contained in this quarterly report on Form 10-Q that are not historical facts, including, but not limited to, statements found in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements, as that term is defined in Section 21E of the Securities and Exchange Act of 1934, as amended. Forward-looking statements may relate to a variety of matters not currently ascertainable, such as future capital expenditures, drilling activity, acquisitions and dispositions, development or exploratory activities, cost savings efforts, production activities and volumes, hydrocarbon reserves, hydrocarbon prices, hedging activities and the results thereof, financing plans, liquidity, competition and our ability to realize efficiencies related to certain transactions or organizational changes. Such forward-looking statements generally are accompanied by words such as “anticipate,” “believe,” “budgeted,” “expect,” “intend,” “plan,” “project,” “potential” or similar statements. Such forward-looking information is based upon our current plans, expectations, estimates and assumptions and is subject to a number of risks and uncertainties that could significantly affect current plans, anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or assumptions expressed in or implied by any forward-looking statements made by or on our behalf. Among the factors that could cause actual results to differ materially are: fluctuations of the prices received or demand for our oil and natural gas, the uncertainty of drilling results and reserve estimates, operating hazards, acquisition risks, requirements for capital, general economic conditions, competition and government regulations, as well as the risks and uncertainties discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and public statements.

RESULTS OF OPERATIONS

Summary Financial Data

Three Month Periods Ended March 31, 2003 and 2002

We recorded net income of approximately $4.1 million ($0.19 per diluted share) in the three months ended March 31, 2003, compared to net income of approximately $2.2 million ($0.11 per diluted share) in the first quarter of 2002. Included in the 2003 period was a $2.3 million charge, net of tax, ($0.11 per diluted share) for the adoption of Statement of Financial Accounting Standard (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003.

Operating Revenues

Revenues for the first quarter of 2003 were $37.5 million; an $8.6 million increase from the $28.9 million reported for the three months ended March 31, 2002. Higher prices increased revenue $10.0 million while additional sales volumes further increased revenue $2.1 million. Volume increases were primarily the result of production from natural gas interests purchased from Enogex Exploration Company on December 2, 2002 and initial production from our Canadian CBM properties. Other revenue decreased $3.5 million from the prior year period primarily as a result of the expiration of Section 29 tax credits in 2002. Revenue for the first quarter of 2002 from tax credit sales was $2.8 million. During the first quarter of 2003, the completion of our negotiations to purchase the tax credit properties resulted in a $0.5 million reduction of other revenue.

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Gas, Oil and Related Product Sales

Sales volumes, revenues and average prices for the three months ended March 31, 2003 and 2002 are as follows:

Natural gas sales of $31.0 million for the first quarter of 2003 were 51% higher than the $20.5 million for the comparable 2002 period. Revenue increased $7.9 million from the 2002 first quarter as a result of a $1.00 increase in realized average natural gas prices. Prices were approximately $0.23 per Mcf lower than expected as a result of pipeline delivery imbalances. These imbalances were the result of a pipeline meter calibration problem and an approximate 260,000 Mcf decrease in first quarter 2003 production due to extreme weather conditions in Michigan. Additional sales volumes increased revenue $2.6 million compared to the first quarter of 2002. Additional natural gas volumes in Michigan included 685,000 Mcf from interests acquired from Enogex, 341,000 Mcf of Prairie du Chien production from wells fracture stimulated during the first half of 2002, 56,000 Mcf from Antrim wells drilled since March 31, 2002 and 38,000 Mcf as a result of an increase in our interests in properties where payout occurred. Initial production from our coal bed methane wells in Canada was 161,000 Mcf during the first three months of 2003 while Indiana production increased 20,000 Mcf from the first quarter of 2002.

Crude oil sales were $5.4 million for the three months ended March 31, 2003 compared to $4.2 million in the first quarter of 2002. The 2003 first quarter average crude oil sales price increased to $25.16 from $17.31. This increase improved revenue $1.9 million from the 2002 first quarter. Lower sales volumes reduced revenue $0.7 million from the prior year quarter. Decreased volumes were primarily due to natural production declines

NGL sales were $0.7 million for the first quarter of 2003. The $0.4 million increase was the result of both higher prices and slightly higher sales volumes.

Other Revenues

Other revenue of $0.4 million was $3.5 million lower when compared to the first quarter of 2002. Section 29 tax credit revenue was $2.8 million in the first quarter of 2002. The tax credits expired at the end of 2002. As a result, we have completed negotiations to repurchase the tax credit properties and reduced other revenue $0.5 million. Revenue from the Company’s marketing and gas processing subsidiaries was $1.0 million, a decrease of $0.1 million for the prior year quarter.

Operating Expenses

First quarter operating expenses for 2003 were $22.9 million, an increase of $1.9 million over the expenses $20.9 million incurred in the first quarter of 2002.

Oil and Gas Production Costs

Oil and gas production costs were $12.6 million. The $1.5 million dollar increase over the 2002 first quarter was primarily the result of increased severance tax expense. Increased sales prices and volumes in 2003 for natural gas increased severance tax expense $1.4 million from the first quarter of 2002. Although sales volumes increased 629,000 Mcfe, lease operating expenses increased only $0.1 million from the 2002 period. Cost cutting measures instituted in 2002 reduced lease operating expenses $0.05 per Mcf as compared to the first quarter of 2002.

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Depletion, Depreciation and Accretion

First quarter 2003 depletion of $6.7 million was slightly higher than first quarter of 2002 depletion. An increase in depletion was a result of higher sales volumes that was almost offset by a decrease in the depletion rate. Accretion expense of $0.2 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 costs incurred during the three months ended March 31, 2003 were $2.0 million; slightly lower than the expense incurred in the first quarter of 2002. While the royalty lawsuit filed against us in 2001 continues, legal costs have decreased $0.3 million from the first quarter of 2002. The decrease was partially offset by a net increase in several expense categories.

Income Tax Expense

The income tax provision of $3.6 million was established using an effective U.S. Federal tax rate of 35%. The provision also included $0.4 million for Canadian and state income tax expense. Income tax expense increased over the prior year period as a result of higher pretax income for the first quarter of 2003.

As of March 31, 2003, the Company had a deferred tax liability of $59.0 million. Deferred income tax expense of $3.5 million was partially offset by deferred income tax benefits of $1.2 million included in the cumulative effect of adopting SFAS No. 143 and $0.3 million associated with the equity distribution recorded as a result of the acquisition of the service contracts from our affiliate, Voyager Compression Services.

CAPITAL RESOURCES AND LIQUIDITY

Net cash from operations for the three months ended March 31, 2003 of $3.1 million was $8.8 million more than the same period in 2002. The increase resulted from higher earnings driven by higher revenues. Higher revenues were due to both additional sales volumes and higher prices for the 2003 first quarter.

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 2003, we sold approximately 29% of our natural gas production under fixed-price long-term contracts and an additional 40% of natural gas production was sold under fixed-price swap agreements. We also sold 21% of our crude oil production under fixed-price swap agreements. In addition, price collars covered 63% of our crude oil production. As a result of our hedging activities, we benefit from significant predictability of our natural gas and crude oil revenues. However, when natural gas and crude oil market prices exceed our financial hedge swap prices, we are required to make payment for the settlement of our hedge derivatives on the fifth day of the production month for natural gas hedges and the fifth day after the production month for crude oil hedges. We do not receive market price cash payment from our customers until 25 to 60 days after the month of production. Additionally, in the event of a significant production curtailment, we are required contractually to fulfill our commitments under our long-term sales contracts by purchasing natural gas volumes at market prices. During the first quarter of 2003, we increased borrowings under our credit facility in part as the result of settlement of our hedge derivatives for the months of January through March.

Net cash used for investing activities for the three months ended March 31, 2003 was $21.6 million. Investing activities were comprised of $16.8 million expended for drilling of oil and gas properties and $4.6 million for construction of gathering and processing facilities. In addition, we purchased compression maintenance service contracts and associated fixed assets from our affiliate, Voyager Compression Services, in February of 2003 for $0.7 million.

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Capital expenditures

Net cash provided by financing activities for the three months ended March 31, 2003 was $16.8 million. We received $17.0 million under our credit facility during the first quarter of 2003. The increase was the result of capital additions for the quarter and payments required under our natural gas and crude oil fixed-price swap agreements as described above.

As of March 31, 2003 and December 31, 2002, 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 downside 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 various financial contracts to hedge our exposure to commodity price risk associated with anticipated future natural gas production. These contracts have included price ceilings and floors, no-cost collars and fixed price swaps. We sell approximately 25,000 Mcfd and 10,000 Mcfd of natural gas under long-term fixed price contracts at $2.49/Mcf and $2.47/Mcf, respectively through March 2009. Approximately 6,900 Mcfd sold under these contracts are third party volumes controlled by us. Approximately 38,028 Mcfd of our equity natural gas is hedged using fixed price swap agreements and an additional 5,000 Mcfd is hedged with price collars. Additionally, our crude oil production is hedged by a 500 Bbld fixed price swap and price collars for 1,500 Bbld. As a result, we benefit from significant predictability of our natural gas and crude oil revenues.

Commodity price fluctuations affect the remaining natural gas and crude oil volumes as well as our NGL volumes. Up to 4,500 Mcfd of natural gas is committed at market price through May 2004. Additional gas volumes of 16,500 Mcfd are committed at market price through September 2008. Approximately 15,600 Mcfd sold under these contracts are third party volumes controlled by us.

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The following table summarizes our open financial hedge positions as of March 31, 2003 related to natural gas and crude oil production.

Cinnabar Energy Services & Trading, LLC, our wholly owned marketing company, also enters into various financial contracts to hedge its exposure to commodity price risk associated with future contractual natural gas sales and purchases. These contracts consist of fixed price sales or purchases from third parties. As a result of these firm sale and purchase commitments and associated financial price swaps, the hedge derivatives have qualified as fair value hedges. At March 31, 2003, we recorded assets and liabilities of $102,000 and $86,000, respectively, for the fair value of firm purchase and sale commitments. Additionally, we have recorded current assets and liabilities of $93,000 and $154,000, respectively, associated with the fair value of the financial floating price swaps.

The following table summarizes Cinnabar’s open financial derivative positions and hedged firm commitments as of March 31, 2003 related to natural gas marketing.

Utilization of our hedging program may result in natural gas and crude oil realized prices varying from market prices that we receive from the sale of natural gas and crude oil. Our revenue from oil and gas production was $14,740,000 lower as a result of the hedging programs in the first quarter of 2003. First quarter 2002 production revenue was

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$1,243,000 higher than if the hedging program had not been in effect. Marketing revenue was $517,000 higher and $1,939,000 lower as a result of hedging activities in the first quarter of 2003 and 2002, respectively.

The fair value of all natural gas financial contracts and associated firm sale and purchase commitments as of March 31, 2003 was estimated based on published market prices of natural gas for the periods covered by the contracts. The net differential between the prices in each contract and market prices for future periods, as adjusted for estimated basis, was applied to the volumes stipulated in each contract to arrive at an estimated future value. This estimated future value was discounted on each contract at rates commensurate with federal treasury instruments with similar contractual lives. As a result, the fixed price natural gas financial contract value does not necessarily represent the value a third party would pay to assume our contract positions.

Interest Rate Risk

As of March 31, 2003, $75,000,000 of our variable-rate debt is hedged with an interest rate swap that converts the debt’s floating LIBOR base to a 3.74% fixed-rate through March 31, 2005. Our liability associated with the swap is $2,971,000 at March 31, 2003.

Interest expense for the first quarter of 2003 and 2002 was $877,000 and $462,000 higher, respectively, as a result of the interest rate swaps.

ITEM 4. Controls and Procedures

Within the 90-day period prior to the filing of this report, an evaluation was carried out under supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-14(c) under the Securities Exchange Act of 1934). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the design and operation of these disclosure controls and procedures are effective in bringing to their attention on a timely basis material information required to be included in our periodic filings under the Exchange Act.

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

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PART II - OTHER INFORMATION

ITEM 6. Exhibits and Reports on Form 8-K: