STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
(Unaudited)

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Interim Financial Statements

        The condensed consolidated financial statements of Stone Energy Corporation and subsidiary as of June 30, 2003 and for the three- and six-month periods then ended are unaudited and reflect all adjustments (consisting only of normal recurring adjustments) which are, in the opinion of management, necessary for a fair presentation of the financial position and operating results for the interim periods. The condensed consolidated balance sheet at December 31, 2002 has been derived from the audited financial statements at that date. The consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto, together with management’s discussion and analysis of financial condition and results of operations, contained in our Annual Report on Form 10-K for the year ended December 31, 2002. The results of operations for the three- and six-month periods ended June 30, 2003 are not necessarily indicative of future financial results.

Note 2 – Earnings Per Share

        Basic net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the periods. Diluted net income per share of common stock was calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the periods plus the weighted-average number of dilutive stock options granted to outside directors and employees. There were approximately 230,000 and 215,000 dilutive shares for the three months ended June 30, 2003 and 2002, respectively, and 185,000 and 198,000 dilutive shares for the first six months of 2003 and 2002, respectively.

        Options that were considered antidilutive because the exercise price of the option exceeded the average price of our stock for the applicable periods totaled approximately 971,000 and 781,000 shares in the three months ended June 30, 2003 and 2002, respectively, and 1,063,000 and 952,000 shares in the first six months of 2003 and 2002, respectively.

Note 3 – Hedging Activities

        We enter into hedging transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. The primary objective of these activities is to reduce our exposure to the possibility of declining oil and natural gas prices during the term of the hedge. We do not enter into hedging transactions for trading purposes. We currently utilize two forms of hedging contracts: fixed-price swap and put contracts.

        During the three months ended June 30, 2003 and 2002, we recognized non-cash expenses of $2.1 million and $3.5 million, respectively, related to commodity derivatives, of which $1.3 million and $3.3 million represent the cost associated with put contracts that settled during the respective periods. For the six months ended June 30, 2003 and 2002, we recognized non-cash derivative expenses of $4.3 million and $8.5 million, respectively, of which $2.5 million and $5.3 million represent the cost associated with put contracts that settled during the respective periods. At June 30, 2003, the unsettled put contracts were recorded as assets totaling $0.1 million and the unsettled gas swaps were recorded as a liability totaling $11.7 million.

        The following table illustrates our hedging positions as of July 1, 2003.

        During the three months ended June 30, 2003 and 2002, we realized net decreases in oil and gas revenue related to hedging transactions of $0.5 million and $0.4 million, respectively. For the six months ended June 30, 2003 and 2002, we realized a net increase (decrease) in oil and gas revenue related to hedging transactions of ($0.5) million and $6.1 million, respectively.

Note 4 – Long-Term Debt

        Long-term debt consisted of the following:

        Borrowings outstanding at June 30, 2003 under our bank credit facility totaled $76.0 million, and letters of credit totaling $13.1 million have been issued under the facility. Effective June 9, 2003, the borrowing base under the credit facility was increased to $325 million. At June 30, 2003, we had $235.9 million of borrowings available under the credit facility and the weighted average interest rate under the credit facility was approximately 2.4%. The credit facility matures on December 20, 2004. The borrowing base under the credit facility, which is redetermined periodically, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values.

Note 5 – Comprehensive Income

        Comprehensive income consisted of the following:

Note 6 – Adoption of New Accounting Standard – SFAS No. 143

        In July 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 143, “Accounting for Asset Retirement Obligations,” effective for fiscal years beginning after June 15, 2002. This statement requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the termination of operating assets at the end of an oil and gas property’s useful life. The adoption of SFAS No. 143 requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital.

        We adopted SFAS No. 143 on January 1, 2003. Upon adoption, we recognized a credit for a cumulative transition adjustment of $5.3 million, net of tax, for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. In addition, we recorded a $32.1 million increase in the capitalized costs of our oil and gas properties, net of accumulated depreciation, and recognized $76.3 million in additional liabilities related to asset retirement obligations. During the first six months of 2003, we recognized a non-cash expense of $3.1 million related to the accretion of our asset retirement obligation and recorded $1.0 million of additional liabilities and capital costs associated with new retirement obligations, net of abandonment costs incurred during the period. As required by SFAS No. 143, our estimate of our asset retirement obligation does not give consideration to the value that the related assets could have to other parties.

        Assuming SFAS No. 143 was adopted as of the beginning of the earliest period presented, the liability for our asset retirement obligation would have been $70.5 million as of January 1, 2002. The following table illustrates the estimated impact SFAS No. 143 would have had on our earnings and earnings per share assuming adoption at the beginning of the earliest period presented:

Note 7 – Changes in Accounting Principles

        Units of Production Method.  Effective January 1, 2003, management elected to change to the Units of Production (UOP) method of amortizing proved oil and gas property costs versus the formerly used Future Gross Revenue (FGR) method. Under the UOP method, the quarterly provision for depreciation, depletion and amortization (DD&A) is computed by dividing production volumes for the period by the total proved reserves, and applying the respective rate to the net cost of proved oil and gas properties, including future development costs. Under the FGR method, the DD&A rate was calculated by dividing revenue for the period by future gross revenue. Management believes that this change in method is preferable because it removes fluctuations in DD&A expense caused by product pricing volatility within a reporting period and is a method more widely used in the oil and gas industry. The cumulative effect of the change in accounting principle was $4.0 million, net of tax, and was recorded as a non-cash charge during the first quarter of 2003. The following table illustrates the impact of the change in accounting principle, assuming adoption as of the beginning of the earliest period presented:

        Entitlement Method.  Management elected to begin recognizing production revenue under the Entitlement method of accounting effective January 1, 2003. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. Management believes that this method is preferable because revenues and production are accounted for in the period in which the earnings process is complete. The cumulative effect of the change to the Entitlement method was immaterial.

Note 8 – Stock-Based Compensation

        In October 1995, the FASB issued SFAS No. 123, “Accounting for Stock-Based Compensation,” which became effective with respect to us in 1996. Under SFAS No. 123, companies can either record expense based on the fair value of stock-based compensation upon issuance or elect to remain under the current method prescribed by Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” whereby no compensation cost is recognized upon grant if certain requirements are met. The FASB has issued SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure,” which has amended APB Opinion 28, Interim Financial Reporting, to require that public companies provide a tabular presentation similar to that called for in annual statements in condensed quarterly statements if, for any period presented, the intrinsic value method is used. We have continued to account for our stock-based compensation under APB 25. However, we have adopted the disclosure provisions of SFAS No. 148 as presented below.

        If the compensation expense for stock-based compensation plans had been determined consistent with the expense recognition provisions under SFAS No. 123, our net income and basic and diluted earnings per common share for the three and six months ended June 30, 2003 and 2002 would have approximated the pro forma amounts below:

Note 9 – New Accounting Principle

        In January 2003, the FASB issued Financial Interpretation 46, “Consolidation of Variable Interest Entities — An Interpretation of Accounting Research Bulletin (ARB) 51” (FIN 46 or Interpretation). FIN 46 addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. For the Company this guidance applies immediately to VIEs created after January 31, 2003, and July 1, 2003 for VIEs existing prior to February 1,2003. The company believes there will be no material impact on the financial statements from the adoption of FIN 46.

INDEPENDENT ACCOUNTANTS’ REVIEW REPORT

TO THE STOCKHOLDERS OF
STONE ENERGY CORPORATION:

We have reviewed the accompanying condensed consolidated balance sheet of Stone Energy Corporation (a Delaware corporation) as of June 30, 2003, and the related condensed consolidated statements of operations for the three- and six-month periods ended June 30, 2003 and 2002 and the condensed consolidated statements of cash flows for the six-month periods ended June 30, 2003 and 2002. These financial statements are the responsibility of the Company’s management.

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

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

We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet of Stone Energy Corporation as of December 31, 2002, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year then ended (not presented herein) and in our report dated February 28, 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.

New Orleans, Louisiana
July 29, 2003

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

        The information in this Form 10-Q and the information referenced herein includes “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. All statements, other than statements of historical or present facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering any forward-looking statement, you should keep in mind the risk factors and other cautionary statements as described in our 2002 Annual Report on Form 10-K as filed with the Securities and Exchange Commission. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Stone Energy Corporation are expressly qualified in their entirety by this cautionary statement. We use the terms “Stone,” “Stone Energy,” “Company,” “we,” “us” and “our” to refer to Stone Energy Corporation.

Overview

        Stone Energy Corporation is an independent oil and gas company focused primarily in the Gulf Coast Basin and is engaged in the acquisition and subsequent exploration, development, production and operation of oil and gas properties.

        Our business strategy, which has remained consistent since 1990, is to increase production, cash flow and reserves through the acquisition, exploitation and development of principally mature oil and gas properties. Currently, our property base consists of 91 active properties, 57 in the Gulf Coast Basin and 34 in the Rocky Mountains, and 29 primary term leases in the Gulf of Mexico. We serve as operator on 54 of our active properties, which enables us to better control the timing and cost of rejuvenation activities. We believe that there will continue to be opportunities to acquire properties in the Gulf Coast Basin due to the increased focus by major and large independent companies on projects away from the onshore and shallow water shelf regions of the Gulf of Mexico.

Critical Accounting Policies

        Our 2002 Annual Report on Form 10-K describes the accounting policies that we believe are critical to the reporting of our financial position and operating results and that require management’s most difficult, subjective or complex judgments. Our most significant estimates are:

• remaining proved oil and gas reserves;
• timing of our future drilling activities;
• future costs to develop and abandon our oil and gas properties;
• the fair value of derivative positions; and
• classification of unevaluated property costs.

        This Quarterly Report on Form 10-Q should be read together with the discussion contained in our 2002 Annual Report on Form 10-K regarding these critical accounting policies.

Other Factors Affecting Our Business and Financial Results

        In addition to the matters discussed above, our business, financial condition and results of operations are affected by a number of other factors. This report on Form 10-Q should be read in conjunction with the discussion in our 2002 Annual Report on Form 10-K regarding these other risk factors.

Results of Operations

        The following table sets forth certain operating information with respect to our oil and gas operations.

        Net Income.  For the second quarter of 2003, we reported net income totaling $28.6 million, or $1.08 per share, compared to net income reported for the second quarter of 2002 of $16.0 million, or $0.60 per share. Net income for the first six months of 2003 and 2002 totaled $84.5 million, or $3.18 per share, and $22.2 million, or $0.84 per share, respectively.

        Oil and Gas Revenue.  During the second quarter of 2003, oil and gas revenue totaled $117.2 million, compared to $100.4 million for the second quarter of 2002. Year-to-date 2003 oil and gas revenue totaled $274.8 million compared to $181.0 million during the comparable 2002 period. The increase in 2003 revenue was due to higher average realized oil and natural gas prices on an equivalent basis, partially offset by decreased production volumes.

        Prices.   Prices realized during the second quarter of 2003 averaged $28.34 per Bbl of oil and $5.05 per Mcf of natural gas. This represents a 36% increase, on an Mcfe basis, over second quarter 2002 average realized prices of $25.10 per Bbl of oil and $3.33 per Mcf of natural gas. Average realized prices during the first half of 2003 were $30.96 per Bbl of oil and $5.88 per Mcf of natural gas compared to $23.04 per Bbl of oil and $3.06 per Mcf of natural gas realized during the first half of 2002. All unit pricing amounts include the cash effects of hedging.

        During the second quarters of 2003 and 2002, hedging transactions reduced the average price we received for natural gas by $0.03 per Mcf. Hedging transactions for natural gas during the first half of 2003 decreased the average price we received for natural gas by $0.01 per Mcf compared to a net increase of $0.16 per Mcf for the comparable 2002 period. Hedging transactions during the first half of 2002 increased the average price received for oil by $0.24 per barrel.

         Production.  Natural gas production during the second quarter of 2003 totaled 15.4 Bcf compared to 18.0 Bcf produced during the second quarter of 2002. Oil production during the second quarter of 2003 totaled approximately 1.4 million barrels compared to 1.6 million barrels produced during the second quarter of 2002. Year-to-date 2003 production totaled 2.8 million barrels of oil and 31.9 Bcf of gas while six-month 2002 production totaled 3.2 million barrels of oil and 34.8 Bcf of gas. Production for the second quarter of 2003 of 23.8 Bcfe was down five percent from the first quarter of 2003 due primarily to the loss of four producing wells during the quarter, three of which have been restored to production. Also contributing to the decline were shut-ins related to unscheduled repair work on three pipelines, precautionary downtime for tropical storm Bill and shut-ins for rig mobilization on platforms during the quarter.

        Expenses.   Normal lease operating expenses during the second quarter of 2003 totaled $15.7 million, or $0.66 per Mcfe, compared to $15.8 million, or $0.57 per Mcfe, for the comparable quarter in 2002. For the first six months of 2003, normal lease operating expenses totaled $30.7 million, or $0.63 per Mcfe, compared to $30.4 million, or $0.56 per Mcfe, during the comparable period of 2002. The increase in normal lease operating expenses per Mcfe is the result of the decline in 2003 production volumes, discussed above.

        Major maintenance expenses, which represent major repair and workover operations, totaled $2.5 million during the second quarter of 2003 compared to $4.7 million in the second quarter of 2002. Second quarter 2003 major maintenance expenses consist primarily of workover costs for wells on West Cameron Block 45, South Marsh Island Block 288 and Eugene Island Block 113 and platform repairs at Main Pass Block 288. During the six months ended June 30, 2003 and 2002, major maintenance expenses totaled $5.2 million and $6.0 million, respectively.

        Effective January 1, 2003, management elected to change to the Units of Production (UOP) method of amortizing proved oil and gas property costs from the formerly used Future Gross Revenue (FGR) method. Under the UOP method, the quarterly provision for depreciation, depletion and amortization (DD&A) is computed by dividing production volumes for the period by the total proved reserves, and applying the respective rate to the net cost of proved oil and gas properties, including future development costs. Under the FGR method, the DD&A rate was calculated by dividing revenue for the period by future gross revenue. Management believes that this change in method is preferable because it removes fluctuations in DD&A expense caused by product pricing volatility within a reporting period and is a method more widely used in the oil and gas industry. The cumulative effect of the change in accounting principle was $4.0 million, net of tax, and was recorded as a non-cash charge during the first quarter of 2003.

        DD&A expense on oil and gas properties under the UOP method for the second quarter of 2003 totaled $40.4 million, or $1.70 per Mcfe. Under the FGR method, DD&A expense during the second quarter of 2002 was $41.5 million, or $1.50 per Mcfe. The increase in DD&A per Mcfe is attributable to $40.6 million increase in forecasted future development costs primarily related to production facilities and completion operations of discoveries made during second quarter of 2003, combined with initial reserve bookings limited by SEC guidelines to low known productive limits in newly discovered reservoirs. DD&A expense, as adjusted for the new method of accounting, would have been $43.5 million, or $1.57 per Mcfe, for the second quarter of 2002. Year-to-date 2003 DD&A expense on oil and gas properties totaled $81.3 million, or $1.67 per Mcfe, compared to $81.7 million, or $1.51 per Mcfe, for the comparable period in 2002. See Note 7 – Changes in Accounting Principle.

        Interest expense for the second quarter of 2003 was $5.2 million, net of $2.2 million of capitalized interest, compared to interest of $6.0 million, net of $2.1 million of capitalized interest, during the second quarter of 2002. Interest expense for the first six months of 2003 was $10.7 million, net of $4.2 million of capitalized interest, compared to interest of $11.5 million, net of $4.2 million of capitalized interest, during the first six months of 2002.

        Salaries, general and administrative expenses for the second quarter of 2003 totaled $3.6 million, or $0.15 per Mcfe, compared to $3.2 million, or $0.11 per Mcfe, during the second quarter of 2002. For the six months ended June 30, 2003, salaries, general and administrative expenses totaled $6.9 million, or $0.14 per Mcfe, compared to $6.6 million, or $0.12 per Mcfe, during the comparable period of 2002. Due to Stone’s progress to date toward our annual goals, incentive compensation expense increased to $0.7 million during the second quarter of 2003 compared to $0.2 million recognized during the second quarter of 2002. For the six months ended June 30, 2003 and 2002, incentive compensation expense totaled $1.3 million and $0.4 million, respectively.

        We recognized non-cash expenses of $1.6 million and $3.1 million during the three- and six-month periods ended June 30, 2003, respectively, related to the accretion of our asset retirement obligation in accordance with SFAS No. 143, which was adopted on January 1, 2003.

New Accounting Standard

        SFAS No. 143.   In July 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” effective for fiscal years beginning after June 15, 2002. This statement requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the termination of operating assets at the end of an oil and gas property’s useful life. The adoption of SFAS No. 143 requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital.

        We adopted SFAS No. 143 on January 1, 2003. Upon adoption, we recognized a credit for a cumulative transition adjustment of $5.3 million, net of tax, for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. In addition, we recorded a $32.1 million increase in the capitalized costs of our oil and gas properties, net of accumulated depreciation, and recognized $76.3 million in additional liabilities related to asset retirement obligations. During the first six months of 2003, we recognized a non-cash expense of $3.1 million related to the accretion of our asset retirement obligation and recorded $1.0 million of additional liabilities and capital costs associated with new retirement obligations, net of abandonment costs incurred during the period. As required by SFAS No. 143, our estimate of our asset retirement obligation does not give consideration to the value that the related assets could have to other parties.

        FIN 46.  In January 2003, the FASB issued Financial Interpretation 46, “Consolidation of Variable Interest Entities — An Interpretation of Accounting Research Bulletin (ARB) 51” (FIN 46 or Interpretation). FIN 46 addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. For the Company this guidance applies immediately to VIEs created after January 31, 2003, and July 1, 2003 for VIEs existing prior to February 1,2003. The company believes there will be no material impact on the financial statements from the adoption of FIN 46.

Hedging Activities

        The following is a breakdown of non-cash derivative expenses for the respective periods:

Liquidity and Capital Resources

        Cash Flow.   Net cash flow provided by operating activities for the six months ended June 30, 2003 was $213.1 million compared to $108.0 million reported in the comparable period in 2002. The increase in net cash flow provided by operating activities was primarily attributable to higher oil and gas revenue generated from 69% higher average realized prices on a gas equivalent basis offset by 10% lower production volumes during 2003. Net cash flow used in investing activities totaled $157.4 million and $119.1 million during 2003 and 2002, respectively, which primarily represents our investment in oil and gas properties. Net cash flow provided by (used in) financing activities totaled ($54.7) million and $22.4 million for the six months ended June 30, 2003 and 2002, respectively. During the first half of 2003, Stone repaid $55.0 million of borrowings under the bank credit facility. As a result of these activities, cash and cash equivalents increased from $27.6 million as of December 31, 2002 to $28.7 million as of June 30, 2003.

        We had working capital at June 30, 2003 of $4.2 million. We believe that our working capital balance is not a good indication of our liquidity because it fluctuates as a result of borrowings or repayments under our credit facility and the timing of capital expenditures.

        Capital Expenditures.  Capital expenditures during the three months ended June 30, 2003 totaled $87.5 million, including $14.5 million of acquisition costs, $3.7 million of capitalized salaries, general and administrative expenses, $2.2 million of capitalized interest and $1.0 million of non-cash asset retirement costs. During the first six months of 2003, additions to oil and gas property costs of $206.6 million included $53.0 million of non-cash asset retirement costs in connection with SFAS No. 143. Capital expenditures incurred during the first six months also included $26.8 million of acquisition costs, $7.2 million of capitalized salaries, general and administrative expenses and $4.2 million of capitalized interest. These investments were financed by cash flow from operating activities and working capital.

        Budgeted Capital Expenditures.   Our current estimated 2003 capital expenditures budget of approximately $270 million is allocated 89% to Gulf Coast operations and 11% to Rocky Mountain activities. We expect to drill 54 gross wells during 2003, 41 in the onshore and shallow water offshore regions of the Gulf Coast Basin and 13 in the Rocky Mountains. While the 2003 capital expenditures budget does not include any projected acquisitions, we continue to seek growth opportunities that fit our specific acquisition profile.

        Based upon our outlook on oil and gas prices and production rates, we expect cash flow from operations to be more than sufficient to fund the remaining 2003 capital expenditures budget. However, if oil and gas prices or production rates fall below our current expectations, we believe that the available borrowings under our bank credit facility will be sufficient to fund the capital expenditures in excess of operating cash flow.

        Bank Credit Facility.   At June 30, 2003, we had $76.0 million of borrowings outstanding under our bank credit facility. Letters of credit totaling $13.1 million have been issued pursuant to the facility. During 2003, we repaid $55.0 million of borrowings under the credit facility. Effective June 9, 2003, the borrowing base under the credit facility was increased to $325 million. At August 1, 2003, we had $235.9 million of borrowings available under the credit facility and the weighted average interest rate under the credit facility was approximately 2.4%. The credit facility matures on December 20, 2004. Our borrowing base under the credit facility, which is redetermined periodically, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values.

        Production Marketing Risk.   The publicly disclosed deteriorating financial conditions and recently reduced credit ratings of certain purchasers of production increase the possibility that we may not receive payment for a portion of our future production. We have attempted to diversify our sales and obtain credit protections such as letters of credit, guarantees and prepayments from certain of our purchasers. We are unable to predict, however, what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

        Operating Risk.   The exploration for and development of oil and gas properties involves a variety of operating risks as described in our 2002 Annual Report on Form 10-K. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include, but are not limited to, unexpected drilling conditions, equipment failures, shortages or delays in the deliver of equipment and weather conditions. Production for the second quarter of 2003 of 23.8 Bcfe was down five percent from the first quarter of 2003 due primarily to the loss of four producing wells during the quarter, three of which have been restored to production. Also contributing to the decline were the shut-ins related to unscheduled repair work on three pipelines, precautionary downtime for tropical storm Bill and shut-ins for rig mobilization on platforms during the second quarter. The result of these events, combined with delays of initial production from a number of 2003 discoveries to 2004, has led management to revise full-year 2003 production estimates to approximate 2002 production volumes.

        In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks inherent in our business. During 2002, we experienced two separate production interruptions resulting from the two named Gulf of Mexico storms. At the time, we maintained loss of production insurance to protect us against uncontrollable disruptions in production operations from events of this nature. However, we have decided not to renew loss of production coverage effective May 1, 2003, based on our assessment of the cost to retain this policy as compared to the benefits we received as a result of production interruptions caused by these storms.

Environmental

        Compliance with applicable federal, state and local environmental and safety regulations has not required any significant capital expenditures or materially affected our business or earnings. We believe we are in substantial compliance with environmental and safety regulations and foresee no material expenditures in the future; however, we are unable to predict the impact that compliance with future regulations may have on our capital expenditures, earnings, results of operations, financial condition or competitive position.

Defined Terms

        Oil and condensate are stated in barrels (“Bbl”) or thousand barrels (“MBbl”). Natural gas is stated herein in billion cubic feet (“Bcf”), million cubic feet (“MMcf”) or thousand cubic feet (“Mcf”). Oil and condensate are converted to natural gas at a ratio of one barrel of liquids per six Mcf of gas. Bcfe, MMcfe, and Mcfe represent one billion cubic feet, one million cubic feet and one thousand cubic feet of gas equivalent, respectively. MMBtu represents one million British Thermal Units and BBtu represents one billion British Thermal Units. An active property is an oil and gas property with existing production. A primary term lease is an oil and gas property with no existing production, in which we have a specific time frame to establish production without losing the rights to explore the property.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

        Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. In order to manage our exposure to oil and natural gas price declines, we occasionally enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production. We do not enter into hedging transactions for trading purposes.

        Our hedging policy provides that not more than one-half of our estimated production quantities can be hedged without the consent of the Board of Directors. See Note 3 – Hedging Activities for a detailed discussion of hedges in place to manage our exposure to oil and gas price declines.

Interest Rate Risk

        At June 30, 2003, Stone had long-term debt outstanding of $376.0 million. Of this amount, $300 million, or approximately 80%, bears interest at fixed rates averaging 8.4%. The remaining $76.0 million of debt outstanding at June 30, 2003 bears interest at a floating rate. At June 30, 2003, the weighted average interest rate under our floating-rate debt was approximately 2.4%. Because the majority of our long-term debt at June 30, 2003 was at fixed rates, we consider our interest rate exposure at such date to be minimal. At June 30, 2003, we had no open interest rate hedge positions to reduce our exposure to changes in interest rates.

        Since the filing of our Annual Report on Form 10-K, there have been no material changes in reported market risk as it relates to interest rates and commodity prices.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        Our chief executive officer and our chief financial officer, with the participation of other members of our senior management, reviewed and evaluated the effectiveness of Stone’s disclosure controls and procedures as of the end of the quarterly period ended June 30, 2003. Based on this evaluation, our chief executive officer and chief financial officer believe:

• Stone’s disclosure controls and procedures are designed to ensure that information required to be disclosed by Stone in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and
   
• Stone’s disclosure controls and procedures were effective to ensure that material information was accumulated and communicated to Stone’s management, including Stone’s chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Controls Over Financial Reporting

        There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended June 30, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 4. Submission of Matters to a Vote of Security Holders

        At the annual meeting of stockholders held on May 21, 2003, four Class I Directors, Peter K. Barker, D. Peter Canty, Raymond B. Gary and David R. Voelker, were elected to serve as Directors of the Company until the annual meeting of stockholders in the year 2006. Peter K. Barker received the vote of 21,020,343 shares with the vote of 452,197 shares withheld, D. Peter Canty received the vote of 21,239,341 shares with the vote of 233,199 shares withheld, Raymond B. Gary received the vote of 21,002,208 shares with the vote of 470,332 shares withheld, and David R. Voelker received the vote of 21,023,126 shares with the vote of 449,414 shares withheld. No other Director was standing for election. George R. Christmas, B. J. Duplantis, John P. Laborde and Richard A. Pattarozzi are Class II Directors whose terms expire with the 2004 annual meeting of stockholders. James H. Stone, Joe R. Klutts, and Robert A. Bernhard are Class III Directors whose terms expire with the 2005 annual meeting of stockholders.

        A management proposal to ratify the appointment of Ernst & Young LLP by the Board of Directors as independent auditors to the Company for the year 2003 was approved. The vote was 21,413,735 shares for, 43,345 shares against, and 15,460 shares abstained.

        A management proposal to approve and adopt the amendment to the 2001 Amended and Restated Stock Option Plan, increasing the number of shares subject to the plan by one million shares, was approved. The vote was 19,169,206 shares for, 2,207,080 shares against, and 96,254 shares abstained.

Item 6.      Exhibits and Reports on Form 8-K

SIGNATURE

         Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.