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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended June 30, 2004.

For the transition period from              to             .

Commission file number 001-16009

SPINNAKER EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

(713) 759-1770

(Registrant’s telephone number, including area code)

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 August 5, 2004 was 33,898,340.

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SPINNAKER EXPLORATION COMPANY

Form 10-Q

For the Three and Six Months Ended June 30, 2004

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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 “Exchange Act”). 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, 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 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)

June 30, 2004

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, 2003.

2. Summary of Significant Accounting Policies

Stock-Based Compensation

Statement of Financial Accounting Standards (“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 Accounting Principles Board (“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, par value $0.01 per share (“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 $0.2 million and $0 in the second quarter of 2004 and 2003, respectively, and $0.2 million and $0 in the first six months of 2004 and 2003, 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 share of Common Stock would have been as follows (in thousands, except per share amounts):

Leasehold Costs

In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141, “Business Combinations,” which requires the use of 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

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an annual review of impairment. The new standard also requires that, at a minimum, all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no impact on the Company’s financial position or results of operations.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company and the extractive industries have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 141 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify approximately $85.8 million and $72.2 million as of June 30, 2004 and December 31, 2003, respectively, from oil and gas properties to a separate intangible assets line item. These costs include those to acquire contract-based drilling and mineral use rights such as delay rentals, lease bonuses, commission fees and other leasehold costs. The Company’s cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. Spinnaker will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided.

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 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, after taxes of $2.0 million.

The reconciliation of the beginning and ending asset retirement obligations for the three and six months ended June 30, 2004 and 2003 was as follows (in thousands):

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4. Earnings Per Share

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

5. Debt

On December 19, 2003, Spinnaker revised and renewed the $200.0 million revolving credit agreement (the “Revolver”) with a group of eight banks. The Revolver consists of two tranches, Tranche A and Tranche B, and matures on December 19, 2006. Borrowings under each tranche constitute senior indebtedness.

Tranche A is available on a revolving basis through the maturity of the Revolver, and availability is subject to the borrowing base, currently $140.0 million, as determined by the banks. Tranche B is $50.0 million, is available in multiple advances through April 1, 2005 and is not subject to the borrowing base. The Company has made no borrowings under Tranche B. Borrowings under Tranche B cannot be reborrowed once repaid. Total availability under Tranche A and Tranche B cannot exceed $200.0 million. Should the borrowing base exceed $150.0 million, Tranche B would be reduced by a like amount for the period the borrowing base exceeds $150.0 million until the maturity of Tranche B. At such time Tranche B is utilized, the banks are to be provided with security interests in virtually all of Spinnaker’s reserve base. Upon repayment of Tranche B, the security interests are to be released.

The borrowing base is re-determined semi-annually by the banks in their sole discretion and in their usual and customary manner. The banks and the Company also have the right to request one additional re-determination annually. The amount of the borrowing base is a function of the banks’ view of Spinnaker’s reserve profile, future commodity prices and projected cash flows. In addition to the semi-annual re-determinations, the banks have the right to re-determine the borrowing base in the event of the sale, transfer or disposition of assets included in the borrowing base exceeding $25.0 million, or $10.0 million when Tranche B is utilized.

The Company has the option to elect to use a base interest rate as described below or London Interbank Offered Rate (“LIBOR”) plus, for each such rate, a spread based on the percentage of the borrowing base used at that time. The base interest rate spread ranges from 0.0% to 0.5% for Tranche A borrowings and from 2.0% to 2.75% for Tranche B borrowings. The LIBOR spread ranges from 1.25% to 2.0% for Tranche A borrowings and from 3.0% to 3.75% for Tranche B

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borrowings. The base interest rate under the Revolver is a fluctuating rate of interest equal to the higher of either (i) The 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 0.375% to 0.5%, depending on the borrowing base usage for Tranche A, and is 0.625% for Tranche B. The Revolver contains various restrictions and covenants.

On June 30, 2004, the Company had outstanding borrowings under Tranche A of $93.0 million and was in compliance with the covenants and restrictive provisions under the Revolver. Subsequent to June 30, 2004, the Company had no additional borrowings; however, the Company expects to incur additional borrowings under Tranche A of the Revolver in the remainder of 2004.

6. Commodity Price Risk Management Activities:

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 June 30, 2004, 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 and ceiling price. As of June 30, 2004, Spinnaker’s commodity price risk management positions in natural gas collar arrangements and related fair values were as follows:

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The Company reported net liabilities of $6.3 million and $2.7 million related to its financial derivative contracts as of June 30, 2004 and December 31, 2003, respectively. Amounts related to hedging activities were as follows (in thousands):

The Company recognized no ineffective component of the derivatives in the three and six months ended June 30, 2004 and 2003. The Company recognized a net hedging loss in revenues in the three and six months ended June 30, 2004 and 2003 as follows (in thousands):

Based on future natural gas prices as of June 30, 2004, the Company would reclassify a net loss of $6.4 million from accumulated other comprehensive loss to earnings in the remainder of 2004 and a gain of $0.1 million from accumulated other comprehensive loss to earnings in the first quarter of 2005. The amounts ultimately reclassified into earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement.

7. Comprehensive Income

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

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

Executive Overview

Our objective since inception has been to assemble a large 3-D seismic database and focus on exploration activities exclusively in the Gulf of Mexico because we believe this area represents one of the most attractive exploration regions in North America. We also believe a geographic focus provides an excellent opportunity to develop and maintain competitive advantages through our regional exploration and operating expertise. We try to maintain balance and diversity in our exploration approach by drilling both shallow water and deepwater prospects, ranging from lower-risk prospects to higher-risk, higher-potential prospects.

We recognized net income of $17.6 million, or $0.51 per diluted share, in the second quarter of 2004 compared to net income of $10.0 million, or $0.30 per diluted share, in the second quarter of 2003. These financial results were impacted by 11% higher production and a 30% higher realized commodity price in the second quarter of 2004 compared to the second quarter of 2003. Our lease operating expense (“LOE”) rate per Mcfe in the second quarter of 2004 increased 14% to $0.48 compared to the same period in 2003, primarily due to higher LOE rates on new wells. The depreciation, depletion and amortization (“DD&A”) expense rate per Mcfe increased 17% in the second quarter of 2004 to $2.97 compared to the same period in 2003 primarily due to costs associated with unsuccessful drilling operations, higher finding costs and the timing of reserve recognition, as more reservoir and production information becomes available, compared to the related amortized costs. Of the total increase in the DD&A rate from the first quarter of 2004, $0.12 per Mcfe resulted from the retraction of royalty suspension volumes of 2.4 million barrels of oil (“MMBbls”), or 14.3 Bcfe, on Green Canyon 338/339/382 (“Front Runner”).

We had $16.0 million in cash and cash equivalents and outstanding borrowings under the Revolver of $93.0 million as of June 30, 2004. We have experienced and expect to continue to experience substantial capital requirements. We have incurred capital costs of approximately $1.0 billion in the past three years. Additionally, we have had negative working capital at the end of each of the last three years. Our working capital deficit decreased to $5.5 million as of June 30, 2004 compared to $33.2 million as of December 31, 2003. We have capital expenditure plans for 2004 totaling approximately $270.0 million. We believe that cash flows from operations, proceeds from available borrowings under the Revolver and Front Runner spar production facility financing opportunities will be sufficient to meet our capital requirements in the next twelve months.

Although we have been able to maintain a drilling success rate of approximately 60% since inception, our exploratory drilling successes on the shelf and deep shelf since the second half of 2001 have been smaller in size and had less impact on our operating results than those prior to that time, resulting in a negative impact on our subsequent production and reserve growth. Additionally, several of our discoveries since mid-2001 were in the deep water, and we do not expect to see the full impact on production and reserve recognition from these projects until after 2004.

Production

Since inception, approximately 90% of our total production has consisted of natural gas. Approximately 74% of our total production in the second quarter of 2004 was natural gas. Considering oil and condensate production from deepwater projects in 2004 and 2005, we anticipate that this concentration in natural gas production will be approximately 75% of total production in 2004 and approximately 50% of total production in 2005. As a result, we believe our revenues, profitability and cash flows will be less sensitive to natural gas prices and more sensitive to oil and condensate prices.

Generally, our producing properties on the shelf have high initial production rates followed by steep declines. As a result, we must continually drill for and develop new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find and develop these reserves. Our challenge is to find and develop reserves at economic rates and commence production of these reserves as quickly and efficiently as possible.

Oil and Gas Property Costs

Spinnaker participated in three successful wells in six attempts in the second quarter of 2004. Property and equipment additions of $68.1 million in the second quarter of 2004 included leasehold and other acquisition costs of approximately $9.9 million, exploration costs of $39.0 million, development costs of $19.0 million and other property and equipment costs of $0.2 million. We currently plan to drill approximately 12 wells on the shelf and 8 wells in the deep water in the second half of 2004. We expect more than 50% of our 2004 capital expenditure budget to be used for exploration activities, up from 34% in 2003.

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Finding and Development Costs

We believe that the DD&A rate is the best measure for evaluating finding and development costs per Mcfe since the rate generally considers all acquisition, exploration and development costs. The rate also considers any additional development costs associated with proved reserves, such as costs for drilling new wells, sidetracks and recompletions, which a company will incur in the future to produce the oil and gas reserves and an estimate of the costs to abandon wells, platforms, facilities and pipelines after reservoirs are depleted. However, other factors must also be considered when relying on the DD&A rate as a measure for evaluating a company’s finding and development costs per Mcfe. In most cases, the total estimated resource of a reservoir is not usually proved with only one well, and the initial proved reserves are generally burdened with 100% of all future development costs. The DD&A rate increases due to costs incurred without related reserve additions and the timing of reserve recognition, as more reservoir and production information becomes available, compared to the related amortized costs.

The DD&A rate per Mcfe is calculated quarterly and increased 5% to $2.97 in the second quarter of 2004 from $2.82 in the first quarter of 2004. The increase in the DD&A rate was primarily due to the retraction of royalty suspension volumes of 2.4 MMBbls, or 14.3 Bcfe, on Front Runner.

Oil and Gas Reserves

We have achieved reserve growth through exploration activities. We have not acquired reserves through acquisition activities. Ryder Scott Company, L.P. (“Ryder Scott”) prepares estimates of our proved oil and gas reserves as of June 30 and December 31 each year. As of June 30, 2004, Ryder Scott estimated net proved reserves at approximately 319.0 Bcfe, with a present value, discounted at 10% per annum, of pre-tax future net cash flows of approximately $1.1 billion. The discovery of the Front Runner field in 2001 significantly changed our reserve profile. Proved oil and condensate reserves were 50% of total proved reserves as of June 30, 2004 compared to 10% as of December 31, 2000. Proved undeveloped reserves were approximately 64% of total proved reserves as of June 30, 2004. Reserves associated with Front Runner represented approximately 72% of total proved undeveloped reserves. As each Front Runner well is completed over the next 12 months, the majority of these proved undeveloped reserves will be reclassified as proved developed reserves.

Natural Gas and Oil Prices and Hedging Activities

Prices for natural gas and oil fluctuate widely, primarily affecting the amount of cash flow available for capital expenditures, our ability to borrow and raise additional capital and the amount of natural gas and oil that we can economically produce. Natural gas prices have been extremely volatile recently as a result of various factors, including weather, industrial demand and uncertainty related to the ability of the energy industry to provide supply to meet future demand.

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these contracts also limit the benefits we would realize if prices increase. We recorded a net hedging loss of $3.3 million in the second quarter of 2004 compared to a net hedging loss of $9.2 million in the second quarter of 2003. The net hedging loss in the first six months of 2004 was $1.5 million compared to $26.9 million in the same period of 2003. Major challenges related to our hedging activities include a determination of the proper production volumes to hedge and acceptable commodity price levels for each hedge transaction.

Revenues, profitability, cash flow and future growth depend substantially on prevailing oil and gas prices and our ability to find and develop oil and gas reserves that are economically recoverable. A substantial or extended decline in the prices for oil and gas could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and ability to access capital.

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Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us 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 oil and gas properties. Oil and gas 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. Our critical accounting policies are as follows:

Full Cost Method of Accounting

The accounting for oil and gas exploration and production is subject to special accounting rules that are specific to the industry. Two allowable methods exist for these activities: the successful efforts method and the full cost method. Several significant differences exist between the two methods. The major difference is under the successful efforts method, costs such as geological and geophysical, exploratory dry holes and delay rentals are expensed as incurred whereas under the full cost method, these types of charges are capitalized into the full cost pool.

We use the full cost method of accounting for investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and gas properties 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, completions, platforms, facilities, pipelines and the costs related to the retirement of these assets. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas 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 oil and gas reserves.

Application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs, no exploration expenses and higher DD&A rates than the application of the successful efforts method of accounting. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. As a result, we believe that the full cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas investments.

Oil and Gas Reserve Estimates

Ryder Scott prepares estimates of our proved oil and gas reserves as of June 30 and December 31 each year. These estimates of proved reserves are based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate, among others, the amount and timing of future production, operating, workover and transportation expenses and development and abandonment costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our oil and gas reserves.

The Minerals Management Service (“MMS”) allows royalty relief under the Deep Water Royalty Relief Act subject to certain oil and gas price thresholds on eligible leases in the Gulf of Mexico. If the average annual NYMEX oil and gas prices exceed the price thresholds, royalty suspension volumes are retracted in that year. Average natural gas and oil prices have exceeded these thresholds in recent years for certain leases. At or near current levels, average annual NYMEX oil and gas prices in 2004 may exceed these thresholds.

Front Runner area reserves are subject to royalty relief on the first 87.5 million equivalent barrels of oil produced. At the end of each period, reserves are estimated based on oil and gas prices then in effect. Prior to June 30, 2004, our share of gross Front Runner reserves excluded royalty relief volumes for future natural gas production and included royalty relief volumes for future oil production. The MMS has estimated a 2004 oil price threshold of $33.29 per barrel that is applicable to Green Canyon Blocks 338 and 339 and $29.86 per barrel that is applicable to Green Canyon Block 382. Based on the average oil price as of June 30, 2004, we believe the thresholds will be exceeded and the leases will not qualify for royalty relief. As a result, we incurred a downward reserve revision of approximately 2.4 million barrels, or 14.3 Bcfe, in the second quarter of 2004.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, we use the units-of-production method to amortize our oil and gas properties, and the quantity of reserves could significantly impact our DD&A rate and related expense. Our oil and gas properties are also subject to a ceiling limitation based in part on the quantity of our proved reserves. Finally, these proved reserves are the basis for our supplemental oil and gas disclosures included in our annual report on Form 10-K.

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Depreciation, Depletion & Amortization

Our DD&A expense is comprised of many factors, including costs incurred in the acquisition, exploration and development of proved oil and gas reserves, production levels, estimates of proved reserve quantities and future development and abandonment costs. We compute the provision for DD&A of oil and gas 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 future asset retirement obligations.

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 June 30, 2004, we excluded from the amortization base estimated future expenditures of $29.5 million associated with common development costs for the deepwater discovery at 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 $29.5 million had been included in the amortization base as of June 30, 2004, and no additional reserves were assigned to the Front Runner project, the DD&A rate in the second quarter of 2004 would have been $3.06 per Mcfe, or an increase of $0.09 over the actual DD&A rate of $2.97 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 oil and gas reserves used in the full cost ceiling calculation, as discussed below.

Full Cost Ceiling

Capitalized costs of oil and gas properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effects of hedging activities in place as of end of the quarter, discounted at 10%, plus the lower of cost or fair value of 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 June 30, 2004, Spinnaker’s full cost ceiling, including estimated future net cash flows calculated using commodity prices of $6.45 per Mcf of natural gas and $32.95 per barrel of oil and condensate, exceeded capitalized costs of oil and gas properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, by approximately $194.6 million. Considering the volatility of natural gas and oil prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If natural gas or oil prices decline, even if for only a short period of time, if we incur significant costs associated with unsuccessful drilling operations or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.

Unproved Properties

The costs associated with unproved properties and properties under development are not initially included in the amortization base and primarily 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.

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Leasehold Costs

In June 2001, the FASB issued SFAS No. 141, “Business Combinations,” which requires the use of 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 of impairment. The new standard also requires that, at a minimum, all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no impact on Spinnaker’s financial position or results of operations.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, we and the extractive industries have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 141 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $85.8 million and $72.2 million as of June 30, 2004 and December 31, 2003, respectively, from oil and gas properties to a separate intangible assets line item. These costs include those to acquire contract-based drilling and mineral use rights such as delay rentals, lease bonuses, commission fees and other leasehold costs. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. Spinnaker will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided.

Asset Retirement Obligations

We recognize 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 which that liability could be settled in a current transaction between willing parties. We use 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.

Financial Instruments and Price Risk Management Activities

As of June 30, 2004, our financial instruments consisted of cash and cash equivalents, receivables, payables and derivative instruments. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value because of the short-term nature of these items. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. These hedging arrangements take the form of swap contracts or cashless collars and are placed with major financial institutions. We recorded a net hedging loss of $3.3 million and a net hedging loss of $1.5 million in the three and six months ended June 30, 2004, 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. We have 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 $0.2 million and $0 in the second quarter of 2004 and 2003, respectively, and $0.2 million and $0 in the first six months of 2004 and 2003, respectively. For further information concerning SFAS 123 see Note 2 of the Notes to Consolidated Financial Statements.

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Related Parties

We purchase oilfield goods, equipment and services from Baker Hughes Incorporated (“Baker Hughes”), Cooper Cameron Corporation (“Cooper Cameron”), National-Oilwell, Inc. (“National-Oilwell”) and other oilfield services companies in the ordinary course of business. Spinnaker incurred charges of $6.4 million in the first six months of 2004 from affiliates of Baker Hughes. Mr. Michael E. Wiley, a director of Spinnaker, serves as Chairman of the Board and Chief Executive Officer of Baker Hughes. Spinnaker incurred charges of less than $0.1 million in the first six months of 2004 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 incurred charges of less than $0.1 million in the first six months of 2004 from National-Oilwell. Mr. Roger L. Jarvis, Chairman of the Board, Chief Executive Officer and President of Spinnaker, serves as a director of National-Oilwell. These amounts represent less than 1% of Baker Hughes’, Cooper Cameron’s and National-Oilwell’s total revenues in the six months ended June 30, 2004 and only reflect charges directly incurred by us. Our partners may incur charges from these related parties that are not included above.

We believe that these transactions are at arm’s-length and the charges we pay 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. Each of these companies is a leader in their respective segments of the oilfield services sector. Spinnaker could be at a disadvantage if it were to discontinue using these companies as vendors.

Oil and Gas Reserves

The following table presents estimated net proved oil and gas reserves and the related present value of future net cash flows of the reserves as of June 30, 2004 as prepared by Ryder Scott. The present value of future net cash flows (before income taxes) discounted at 10% shown in the table are not intended to represent the current market value of the estimated oil and gas reserves we own.

The present value of future net cash flows as of June 30, 2004 was determined by using prices of $6.45 per Mcf of natural gas and $32.95 per barrel of oil as of June 30, 2004.

The process of estimating oil and gas reserves is complex. Ryder Scott prepares our reserve estimates as of June 30 and December 31 each year. In order to assist in the preparation of these estimates, we must project production rates and timing of development expenditures. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. As of June 30, 2004, approximately 80% of our proved reserves were either undeveloped or non-producing. 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.

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As of June 30, 2004, approximately 64% of our proved reserves were undeveloped and primarily related to Front Runner. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make these expenditures. Although the estimates of our reserves and the costs associated with developing them are prepared in accordance with industry standards, the estimated costs may be inaccurate, development may not occur as scheduled and the results may not be as estimated.

It should not be assumed that the present value of future net cash flows from our proved reserves is the current market value of our estimated oil and gas reserves. In accordance with Securities and Exchange Commission requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value of future net cash flows estimate.

Results of Operations