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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

Commission file number 001-16009

SPINNAKER EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

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  ¨

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, on May 14, 2003 was 33,200,836.

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SPINNAKER EXPLORATION COMPANY

Form 10-Q

For the Three Months Ended March 31, 2003

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SPINNAKER EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)

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

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SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)

(Unaudited)

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

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SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

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

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SPINNAKER EXPLORATION COMPANY

Notes to Interim Consolidated Financial Statements (Unaudited)

March 31, 2003

1. Basis of Presentation

The accompanying unaudited consolidated financial statements of Spinnaker Exploration Company (“Spinnaker” or the “Company”) have been prepared in accordance with generally accepted accounting principles for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In the opinion of management, all adjustments (consisting only of normal and recurring adjustments) necessary to present a fair statement of the results for the periods included herein have been made and the disclosures contained herein are adequate to make the information presented not misleading. Interim period results are not necessarily indicative of results of operations or cash flows for a full year. These consolidated financial statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

2. Summary of Significant Accounting Policies

Statement of Financial Accounting Standards (“SFAS”) No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure,” amends SFAS No. 123 to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. SFAS No. 148 amends Accounting Principles Board (“APB”) Opinion No. 28, “Interim Financial Reporting,” to require disclosure about those effects in interim financial information.

SFAS No. 123, “Accounting for Stock-Based Compensation,” encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to account for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the fair value of the Common Stock at the date of the grant over the amount an employee must pay to acquire the Common Stock. In accordance with APB Opinion No. 25, compensation expense related to stock-based compensation was $0 and $0.1 million in the first quarter of 2003 and the first quarter of 2002, respectively. Had compensation cost for the Company’s stock option compensation plans been determined based on the fair value at the grant dates for awards under these plans consistent with the method of SFAS No. 123, the Company’s pro forma net income and pro forma net income per common share would have been as follows (in thousands, except per share amounts):

3. Asset Retirement Obligations

Effective January 1, 2003, Spinnaker adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record a liability for asset retirement

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obligations at fair value in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. As of January 1, 2003, the Company recorded asset retirement costs of $21.4 million and asset retirement obligations of $26.0 million. The cumulative effect of change in accounting principle was $3.5 million, net of taxes of $2.0 million.

The reconciliation of the beginning and ending asset retirement obligations as of March 31, 2003 was as follows (in thousands):

The following table summarizes the pro forma net income and earnings per share for the three months ended March 31, 2002 and for the years ended December 31, 2002, 2001 and 2000 as if SFAS No. 143 had been adopted on January 1, 2000 (in thousands, except per share amounts):

The following table summarizes pro forma asset retirement obligations as of March 31, 2002 and December 31, 2002, 2001 and 2000 as if SFAS No. 143 had been adopted on January 1, 2000 (in thousands):

4. Earnings Per Share

Basic and diluted net income per common share were computed based on the following information (in thousands, except per share amounts):

5. Credit Facility

On December 28, 2001, the Company replaced its $75.0 million credit facility with an unsecured $200.0 million credit facility (“Credit Facility”) with a group of seven banks. The borrowing base of the three-year Credit Facility is re-determined on a semi-annual basis each year. The banks and Spinnaker also have the option to request one additional re-determination each year. The banks determine the borrowing base in their sole discretion and in their usual and customary manner. The amount of the borrowing base is a function of the banks’ view of the Company’s reserve profile as well as commodity prices. The current borrowing base is $100.0 million. The Company has the option to elect to use a base interest rate as described below or the LIBOR rate plus, for each such rate, a spread based on the percentage of the borrowing base used at that time. The base interest rate under the Credit Facility is a fluctuating rate of interest equal to the higher of either (i) Toronto-Dominion Bank’s base rate for dollar advances made in the United States or (ii) the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranges from 0.3% to 0.5%, depending on the borrowing base usage. The Credit Facility

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contains various covenants and restrictive provisions. At March 31, 2003, the Company was in compliance with the covenants and restrictive provisions.

6. Derivatives and Hedging

The Company enters into New York Mercantile Exchange (“NYMEX”) related swap contracts and collar arrangements from time to time. These swap contracts and collar arrangements will settle based on the reported settlement price on the NYMEX for the last trading day of each month for natural gas.

In a swap transaction, the counterparty is required to make a payment to the Company for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. The Company is required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. As of March 31, 2003, Spinnaker’s commodity price risk management positions in fixed price natural gas swap contracts and related fair values were as follows:

In a collar arrangement, the counterparty is required to make a payment to the Company for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. The Company is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. Neither party is required to make a payment if the settlement price falls between the fixed floor price and the fixed ceiling price. As of March 31, 2003, Spinnaker’s commodity price risk management positions in natural gas collar arrangements and related fair values were as follows:

The Company reported net liabilities of $23.5 million and $19.9 million related to its financial derivative contracts as of March 31, 2003 and December 31, 2002, respectively. Amounts related to hedging activities were as follows (in thousands):

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The Company recognized a net hedging loss of $17.7 million and a net hedging gain of $8.3 million in revenues in the first quarter of 2003 and the first quarter of 2002, respectively. Based on future natural gas prices as of March 31, 2003, the Company would reclassify a net loss of $15.1 million from accumulated other comprehensive loss to earnings within the next twelve months. The amounts ultimately reclassified into earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement. There was no ineffective component of the derivatives recognized in earnings during the first quarter of 2003 and $0.1 million in the first quarter of 2002.

7. Comprehensive Income

The following are components of comprehensive income (loss) (in thousands):

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Cautionary Statement About Forward-Looking Statements

Some of the information in this quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The forward-looking statements speak only as of the date made, and the Company undertakes no obligation to update such forward-looking statements. These forward-looking statements may be identified by the use of the words “believe,” “expect,” “anticipate,” “will,” “contemplate,” “would” and similar expressions that contemplate future events. These future events include the following matters:

Numerous important factors, risks and uncertainties may affect the Company’s operating results, including:

Any of the factors listed above and other factors contained in this quarterly report could cause the Company’s actual results to differ materially from the results implied by these or any other forward-looking statements made by the Company or on its behalf. The Company cannot provide assurance that future results will meet its expectations. You should pay particular attention to the risk factors and cautionary statements described in the Company’s annual report on Form 10-K for the year ended December 31, 2002.

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Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include DD&A of proved natural gas and oil properties. Natural gas and oil reserve estimates, which are the basis for unit-of-production DD&A and the full cost ceiling test, are inherently imprecise and are expected to change as future information becomes available. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts. The Company’s critical accounting policies are as follows:

Full Cost Method of Accounting

The Company uses the full cost method of accounting for its investments in natural gas and oil properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing natural gas and oil are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress, geological and geophysical service costs and depreciation of support equipment used in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of natural gas and oil properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil. Application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs, no exploration costs and higher DD&A rates than the application of the successful efforts method of accounting.

DD&A

The Company computes the provision for DD&A of natural gas and oil properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs and estimated salvage values associated with asset retirement costs.

Certain future development costs may be excluded from amortization when incurred in connection with major development projects expected to entail significant costs to ascertain the quantities of proved reserves attributable to the properties under development. The amounts that may be excluded are portions of the costs that relate to the major development project and have not previously been included in the amortization base and the estimated future expenditures associated with the development project. Such costs may be excluded from costs to be amortized until the earlier determination of whether additional reserves are proved or impairment occurs.

As of March 31, 2003, the Company excluded from the amortization base estimated future expenditures of $29.3 million associated with common development costs for its deepwater discovery on Green Canyon Blocks 338/339 (“Front Runner”). This estimate of future expenditures associated with common development costs is based on existing proved reserves to total proved reserves expected to be established upon completion of the Front Runner project.

If the $29.3 million had been included in the amortization base as of March 31, 2003, and no additional reserves were assigned to the Front Runner project, the DD&A rate as of March 31, 2003 would have been $2.49 per Mcfe, or an increase of $0.09 over the actual DD&A rate of $2.40 per Mcfe. All future development costs associated with the deepwater discovery at Front Runner are included in the determination of estimated future net cash flows from proved natural gas and oil reserves used in the full cost ceiling calculation, as discussed below.

Full Cost Ceiling

Capitalized costs of natural gas and oil properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, are limited to the estimated future net cash flows from proved natural gas and oil reserves, including the effects of hedging activities in place as of March 31, 2003, discounted at 10%, plus the lower of cost or fair value of

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unproved properties, as adjusted for related income tax effects (full cost ceiling). If capitalized costs of the full cost pool exceed the ceiling limitation, the excess is charged to expense.

As of March 31, 2003, the Company’s full cost ceiling, including estimated future net cash flows calculated using commodity prices of $5.52 per Mcf of natural gas and $28.93 per barrel of oil and condensate, exceeded capitalized costs of natural gas and oil properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, by approximately $161.5 million. Considering the volatility of natural gas and oil prices, it is probable that the Company’s estimate of discounted future net cash flows from proved natural gas and oil reserves will change in the near term. If natural gas or oil prices decline, even if for only a short period of time, or if the Company has downward revisions to its estimated proved reserves, it is possible that write-downs of natural gas and oil properties could occur in the future.

Capitalized Employee and Other General and Administrative Costs

Under the full cost method of accounting, certain costs are capitalized that are directly identified with acquisition, exploration and development activities. These capitalized costs include salaries, employee benefits, costs of consulting services and other related costs and do not include costs related to production, general corporate overhead or similar activities. Spinnaker capitalized employee and other general and administrative costs of $1.8 million and $1.5 million in the first quarter of 2003 and 2002, respectively.

Unproved Properties

The costs associated with unproved properties and properties under development are not initially included in the amortization base and relate to unevaluated leasehold acreage and delay rentals, seismic data, wells in-progress and wells pending determination. Unevaluated leasehold costs and delay rentals are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value. Unevaluated leasehold costs and delay rentals are transferred to the amortization base if a reduction in value has occurred. The costs of seismic data are transferred to the amortization base using the sum-of-the-year’s-digits method over a period of six years. The costs associated with wells in-progress and wells pending determination are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. The costs of drilling exploratory dry holes and associated leasehold costs are included in the amortization base immediately upon determination that the well is unsuccessful.

Asset Retirement Obligations

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the asset. The fair value of a liability for an asset retirement obligation is the amount at which that liability could be settled in a current transaction between willing parties. The Company uses the expected cash flow approach for calculating asset retirement obligations. The liability is discounted using the credit-adjusted risk-free interest rate in effect when the liability is initially recognized. The changes in the liability for an asset retirement obligation due to the passage of time are measured by applying an interest method of allocation to the amount of the liability at the beginning of the period. This amount is recognized as an increase in the carrying amount of the liability and as accretion expense classified as an operating item in the statement of operations.

Natural Gas and Oil Reserves

The process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The Company must project production rates and timing of development expenditures. The Company analyzes available geological, geophysical,

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production and engineering data, and the extent, quality and reliability of this data can vary. Therefore, estimates of natural gas and oil reserves are inherently imprecise.

Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, the Company may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond the Company’s control. A significant percentage of the Company’s proved reserves are either undeveloped or non-producing. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assumes that the Company will make these expenditures. Although the Company estimates its reserves and the costs associated with developing them in accordance with industry standards, the estimated costs may be inaccurate, development may not occur as scheduled and results may not be as estimated. Because most of the reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a lengthy production history.

Other Property and Equipment

The costs associated with seismic hardware and software are included in other property and equipment. These costs are amortized into the full cost pool using the straight-line method over three years. Amortization was $0.5 million and $0.2 million in the first quarter of 2003 and the first quarter of 2002, respectively.

Stock-Based Compensation

SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure,” amends SFAS No. 123 to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. SFAS No. 148 amends APB Opinion No. 28, “Interim Financial Reporting,” to require disclosure about those effects in interim financial information.

SFAS No. 123, “Accounting for Stock-Based Compensation,” encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to account for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the fair value of the Common Stock at the date of the grant over the amount an employee must pay to acquire the Common Stock. In accordance with APB Opinion No. 25, compensation expense related to stock-based compensation was $0 and $0.1 million in the first quarter of 2003 and the first quarter of 2002, respectively.

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Related Parties

The Company purchases oilfield goods, equipment and services from Baker Hughes Incorporated (“Baker Hughes”), Cooper Cameron Corporation (“Cooper Cameron”) and other oilfield services companies in the ordinary course of business. The Company incurred charges of approximately $2.2 million in the first quarter of 2003 from affiliates of Baker Hughes. Mr. Michael E. Wiley, a director of Spinnaker, serves as Chairman of the Board, Chief Executive Officer and President of Baker Hughes. The Company incurred charges of less than $0.1 million in the first quarter of 2003 from Cooper Cameron. Mr. Sheldon R. Erikson, a director of Spinnaker, serves as Chairman of the Board, Chief Executive Officer and President of Cooper Cameron. Spinnaker believes that these transactions are at arm’s-length and the charges it pays for such goods, equipment and services are competitive with the charges and fees of other companies providing oilfield goods, equipment and services to the oil and gas exploration and production industry.

Overview

Financial and operating results in the first quarter of 2003 compared to the first quarter of 2002 included:

Net cash provided by operating activities before changes in operating assets and liabilities is presented because of its acceptance as an indicator of the ability of an oil and gas exploration and production company to internally fund exploration and development activities. This measure should not be considered as an alternative to net cash provided by operating activities as defined by generally accepted accounting principles. A reconciliation of net cash provided by operating activities before changes in operating assets and liabilities to net cash provided by operating activities is shown below:

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Results of Operations

The following table sets forth certain operating information with respect to the natural gas and oil operations of the Company:

Three Months Ended March 31, 2003 as Compared to the Three Months Ended March 31, 2002

Revenues, including the effects of hedging activities, increased $39.1 million in the first quarter of 2003 compared to the first quarter of 2002. The increase in revenues was primarily due to higher production and natural gas and oil prices in the first quarter of 2003 compared to the first quarter of 2002. Excluding the effects of hedging activities, natural gas revenues increased $54.5 million and oil and condensate revenues increased $10.7 million. Revenues from natural gas hedging activities and other decreased $26.1 million in the first quarter of 2003 compared to the first quarter of 2002.

Production increased approximately 3.9 Bcfe in the first quarter of 2003 compared to the first quarter of 2002. Average daily production in the first quarter of 2003 was 152 million cubic feet gas equivalent (“MMcfe”) compared to 109 MMcfe in the same period of 2002. Natural gas revenues increased $54.5 million due to higher production and prices in the first quarter of 2003. Natural gas production increased 2.2 Bcfe in the first quarter of 2003 compared to the same period in 2002. Excluding the effects of hedging activities, first quarter 2003 natural gas prices averaged $6.69 per Mcf compared to $2.46 per Mcf in the first quarter of 2002. Oil and condensate revenues increased $10.7 million due to higher production and prices in the first quarter of 2003. Oil and condensate production increased 279 thousand barrels (“MBbls”) compared to the same period in 2002. First quarter 2003 oil and condensate prices averaged $34.28 per barrel compared to $18.60 per barrel in the same period of 2002.

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Lease operating expenses increased $2.1 million in the first quarter of 2003 compared to the first quarter of 2002. Of the total increase in lease operating expenses, approximately $1.6 million was attributable to wells on five new blocks that commenced production subsequent to March 31, 2002 and $1.1 million was attributable to higher operating costs on existing wells, offset in part by a decrease of $0.6 million in workover expenses. The overall increase in the lease operating expense rate per Mcfe in the first quarter of 2003 compared to the same period in 2002 resulted from higher lease operating rates associated with new wells compared to historical average lease operating rates due to well locations, transportation and gathering agreements, processing requirements and the addition of compression facilities at several locations.

DD&A increased $15.6 million in the first quarter of 2003 compared to the first quarter of 2002. Of the total increase in DD&A, $9.4 million related to higher production volumes of 3.9 Bcfe, $6.1 million related to an increase in the DD&A rate per Mcfe in the first quarter of 2003 and $0.1 million related to increased depreciation of other property and equipment compared to the same period in 2002. The increase in the DD&A rate was primarily due to unsuccessful wells and higher finding costs associated with discoveries since March 31, 2002.

General and administrative expenses increased $0.4 million in the first quarter of 2003 compared to the first quarter of 2002. The increase in general and administrative expenses was primarily due to higher employment-related costs associated with an increase in the number of employees during 2002.

Interest income increased less than $0.1 million in the first quarter of 2003 compared to the first quarter of 2002. Interest expense decreased $0.1 million in the first quarter of 2003 compared to the first quarter of 2002 primarily due to interest associated with borrowings of $37.0 million in the first quarter of 2002.

Income tax expense increased $7.5 million in the first quarter of 2003 compared to the first quarter of 2002 due to higher earnings in the first quarter of 2003. Income taxes were accrued at a 36% effective tax rate in the first quarter of 2003 and 2002.

The Company recognized net income of $15.3 million, or $0.46 per basic share and $0.45 per diluted share, in the first quarter of 2003 compared to net income of $5.6 million, or $0.20 per basic share and $0.20 per diluted share, in the first quarter of 2002.

Liquidity and Capital Resources

The Company has experienced and expects to continue to experience substantial capital requirements, primarily due to its active exploration and development programs in the Gulf of Mexico. Spinnaker has capital expenditure plans for 2003 totaling approximately $260.0 million. Additions to property and equipment of $77.7 million in the first quarter of 2003 included asset retirement costs of $22.2 million. Spinnaker has participated in a significant deepwater oil discovery, Front Runner, with a 25% non-operator working interest. Spinnaker has incurred inception-to-date capital expenditures associated with Front Runner of $93.0 million. As of March 31, 2003, the Company expects to incur approximately $67.5 million in future development costs related to Front Runner, including approximately $27.5 million in the remainder of 2003, $21.0 million in 2004 and $19.0 million thereafter.

Natural gas and oil prices have a significant impact on the Company’s cash flows available for capital expenditures and its ability to borrow and raise additional capital. The amount the Company can borrow under its Credit Facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil that the Company can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the Credit Facility, thus reducing the amount of financial resources available to meet the Company’s capital requirements. The Company believes that working capital, cash flows from operations and proceeds from available borrowings under its Credit Facility will be sufficient to meet its capital requirements in the next twelve months. However, additional debt or equity financing may be required in the future to fund growth and exploration and development programs. In the event additional capital resources are unavailable, the Company may curtail its drilling, development and other activities or be forced to sell some of its assets on an untimely or unfavorable basis.

Spinnaker has an effective shelf registration statement relating to the potential public offer and sale by the Company or certain of its affiliates of up to $500.0 million of any combination of debt securities, preferred stock, common stock, warrants, stock purchase contracts and trust preferred securities from time to time or when financing needs arise. The registration statement does not provide assurance that the Company will or could sell any such securities.

Cash and cash equivalents decreased $9.4 million to $23.2 million at March 31, 2003. The components of the decrease in cash and cash equivalents include $59.1 million used in investing activities, $49.5 million provided by operating activities and $0.2 million provided by financing activities.

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Operating Activities

Net cash provided by operating activities in the first quarter of 2003 increased 55% to $49.5 million primarily due to higher commodity prices and production. Cash flow from operations is dependent upon the Company’s ability to increase production through its exploration and development programs and the prices of natural gas and oil. The Company has made significant investments to expand its operations in the Gulf of Mexico.

The Company sells its natural gas and oil production under fixed or floating market price contracts. Spinnaker enters into hedging arrangements from time to time to reduce its exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these contracts also limit the benefits the Company would realize if prices increase. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

The Company’s cash flow from operations also depends on its ability to manage working capital, including accounts receivable, accounts payable and accrued liabilities. The net increase of $8.4 million in accounts receivable was primarily related to an increase of $13.9 million in the natural gas and oil revenue accrual at March 31, 2003 due to higher production and commodity prices in March 2003 compared to December 2002, offset by a decrease of $5.5 million in joint interest billings and other receivables. The net decrease of $4.6 million in accounts payable and accrued liabilities was primarily due to the level of drilling and development activities as of March 31, 2003 compared to December 31, 2002.

Investing Activities

Net cash used in investing activities was $59.1 million in the first quarter of 2003 and included oil and gas property capital expenditures of $59.8 million and purchases of other property and equipment of $0.4 million. The Company received proceeds of $1.1 million from the sale of natural gas and oil assets in the first quarter of 2003.

As part of its strategy, the Company explores for natural gas and oil at deeper drilling depths and in the deep waters of the Gulf of Mexico, where operations are more difficult and costly than at shallower drilling depths and in shallower waters. Along with higher risks and costs associated with these areas, greater opportunity exists for reserve additions. The Company has experienced and will continue to experience significantly higher drilling costs for its deep shelf and deepwater projects relative to the drilling costs on shallower depth shelf projects in the Gulf of Mexico. The Company drilled four wells in the first quarter of 2003, three of which were successful. The Company drilled 26 wells in 2002, 14 of which were successful. Since inception and through March 31, 2003, the Company has drilled 124 wells, 73 of which were successful, representing a success rate of 59%. Dry hole costs, including associated leasehold costs, were $5.4 million in the first quarter of 2003.

The Company has capital expenditure plans for 2003 totaling approximately $260.0 million, primarily for costs related to exploration and development programs. The Company does not anticipate any significant abandonment or dismantlement expenditures in 2003. Actual levels of capital expenditures may vary due to many factors, including drilling results, natural gas and oil prices, the availability of capital, industry conditions, acquisitions, decisions of operators and other prospect owners and the prices of drilling rig dayrates and other oilfield goods and services. The costs associated with unproved properties and properties under development not included in the amortization base were as follows (in thousands):

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Financing Activities

Net cash provided by financing activities of $0.2 million in the first quarter of 2003 related to proceeds from stock option exercises.

On December 28, 2001, the Company replaced its $75.0 million credit facility with an unsecured $200.0 million Credit Facility with a group of seven banks. The borrowing base of the three-year Credit Facility is re-determined on a semi-annual basis each year. The banks and Spinnaker also have the option to request one additional re-determination each year. The banks determine the borrowing base in their sole discretion and in their usual and customary manner. The amount of the borrowing base is a function of the banks’ view of the Company’s reserve profile as well as commodity prices. The current borrowing base is $100.0 million. The Company has the option to elect to use a base interest rate as described below or the LIBOR rate plus, for each such rate, a spread based on the percentage of the borrowing base used at that time. The base interest rate under the Credit Facility is a fluctuating rate of interest equal to the higher of either (i) Toronto-Dominion Bank’s base rate for dollar advances made in the United States or (ii) the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranges from 0.3% to 0.5%, depending on the borrowing base usage.

The Credit Facility contains various covenants and restrictive provisions, including the following limitations, subject to some exceptions, where the Company:

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At March 31, 2003, the Company was in compliance with the covenants and restrictive provisions and had no outstanding borrowings under the Credit Facility. The Company expects to borrow under the Credit Facility in the second quarter of 2003 and to be in compliance with the covenants and restrictive provisions for the next twelve months.

Contractual Obligations

The Company leases administrative offices, office equipment and oil and gas equipment under non-cancelable operating leases. The Company had no long-term debt, capital lease or purchase obligations or other contractual long-term liabilities as of March 31, 2003.

Interest Rate Risk

The Company is exposed to changes in interest rates. Changes in interest rates affect the interest earned on cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility. The Company does not currently use interest rate derivative financial instruments to manage exposure to interest rate changes, but may do so in the future.

Commodity Price Risk

The Company’s revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. Prices also affect the amount of cash flow available for capital expenditures and the Company’s ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas and oil that the Company can economically produce. The Company sells its natural gas and oil production under fixed or floating market price contracts. Spinnaker enters into hedging arrangements from time to time to reduce its exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. Spinnaker does not enter into such hedging arrangements for trading purposes. However, these contracts also limit the benefits the Company would realize if prices increase. The Company’s current financial derivative contracts include fixed price swap contracts and cashless collar arrangements that have been placed with major trading counterparties the Company believes represent minimum credit risks. Spinnaker cannot provide assurance that these trading counterparties will not become credit risks in the future. Under its current hedging practice, the Company generally does not hedge more than 66 ²/3% of its estimated twelve-month production quantities without the prior approval of the risk management committee of the board of directors.

The Company enters into NYMEX related swap contracts and collar arrangements from time to time. These swap contracts and collar arrangements will settle based on the reported settlement price on the NYMEX for the last trading day of each month for natural gas.

In a swap transaction, the counterparty is required to make a payment to the Company for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. The Company is required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. As of March 31, 2003, Spinnaker’s commodity price risk management positions in fixed price natural gas swap contracts and related fair values were as follows:

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