UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003

or

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-12074

STONE ENERGY CORPORATION

Registrant’s Telephone Number, Including Area Code: (337) 237-0410

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

     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.

[x] Yes   [   ] No

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

[x] Yes   [  ] No

     The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $978,130,217 as of June 30, 2003 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

     As of March 1, 2004, the registrant had outstanding 26,480,434 shares of Common Stock, par value $.01 per share.

     Document incorporated by reference: Portions of the Definitive Proxy Statement of Stone Energy Corporation relating to the Annual Meeting of Stockholders to be held on May 20, 2004 are incorporated by reference into Part III of this Form 10-K.

Table of Contents

TABLE OF CONTENTS

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PART I

     This section highlights information that is discussed in more detail in the remainder of the document. Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section beginning on page 8 of this document for an explanation of these types of statements. We use the terms “Stone”, “Stone Energy”, “company”, “we”, “us” and “our” to refer to Stone Energy Corporation. Certain terms relating to the oil and gas industry are defined in “Glossary of Certain Industry Terms”, which begins on page G-1 of this Form 10-K.

ITEM 1. BUSINESS

The Company

     Stone Energy is a Gulf Coast Basin-focused independent oil and gas company engaged in the acquisition and subsequent exploration, exploitation, development, production and operation of oil and gas properties. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508.

Available Information

     We make available free of charge on our Internet Web site (www.stoneenergy.com) our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”). We also make available our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, respectively, which have been approved by our board of directors, on our Internet Web site. We will make immediate disclosure either by Form 8-K or on our Web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers.

Strategy and Operational Overview

     The Gulf of Mexico is a critical supply basin for the United States, traditionally accounting for approximately 25% of total U.S. oil and natural gas production. Properties located in the Gulf of Mexico are typically on 5,000-acre lease blocks and afford a substantial area to explore away from and beneath established production. We have established extensive geological, geophysical, technical and operational expertise in the Gulf Coast Basin. The application of these core strengths, combined with our detailed and thorough approach to evaluating mature fields and our utilization of new drilling, seismic and completion technologies, have enabled us to successfully exploit and derive significant value from mature Gulf Coast Basin properties. As of March 1, 2004, our property portfolio consisted of 60 active properties and 28 primary term leases in the Gulf Coast Basin and 33 active properties in the Rocky Mountains.

     Our business strategy, which has remained consistent since 1993, is to increase reserves, production and cash flow through the acquisition, exploitation and development of mature properties located primarily in the Gulf Coast Basin. Since going public in 1993, we have grown reserves, production and cash flow from operating activities at compounded annual rates of 24%, 24% and 40%, respectively. Approximately 91% of our estimated proved reserves at December 31, 2003 and 94% of our production during 2003 were associated with our Gulf Coast Basin properties. As of December 31, 2003, we had estimated proved reserves of approximately 816.3 billion cubic feet of gas equivalent (Bcfe), 75% of which were classified as proved developed and 57% of which were natural gas. For the year ended December 31, 2003, we produced an average of 265.5 million cubic feet of gas equivalent (MMcfe) per day. As a result of successful drilling and strategic acquisitions, our estimated total proved reserves at December 31, 2003 were 9% higher than the prior year. During 2003, we generated net cash flow from operating activities of $391.5 million.

     We apply the latest production techniques and geophysical interpretation tools to established fields with significant historical production that have been under-evaluated in recent years. We have grown our opportunity base through both the drillbit and strategic acquisitions, implementing a conservative financial strategy that incorporates a combination of operating cash flow, equity issuance and indebtedness to fund our acquisition and exploitation activities. While we have acquired substantially all of our properties from third parties, we have generated significant growth in reserves, production and prospect inventory subsequent to acquisition. We believe significant reserves remain to be discovered and exploited on properties that satisfy our acquisition criteria as the focus of oil and gas companies shifts over time. We also believe that we are well positioned to exploit these reserves by applying our technical expertise and our thorough, consistent and patient approach in the evaluation and acquisition of these properties.

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     We seek to acquire properties that have the following characteristics:

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primarily Gulf Coast Basin location;

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mature properties with an established production history and infrastructure;

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multiple productive sands and reservoirs;

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low production levels at acquisition with significant identified proven and potential reserves; and

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opportunity for us to obtain a controlling interest and serve as operator.

     Our approach to evaluating mature fields in the Gulf Coast Basin involves a combination of techniques designed to generate opportunities and unlock value. By using the extensive production history and data accumulated on properties in the Gulf Coast Basin, our experienced technical teams construct an interpretation of the unique geology of each field to gain a better understanding of the potential location of previously untested or unexploited oil and gas accumulations. Using our interpretations, we are frequently able to combine development and exploratory targets in a single well to improve the chance of investment success. Since 1993, 75% of the wells we drilled were productive.

     Prior to acquiring a property, we perform a thorough geological, geophysical and engineering analysis of the property to formulate a comprehensive development plan. To formulate this plan, we utilize the expertise of our technical team of 20 geologists, 19 geophysicists and 27 engineers. We also employ our extensive technical database, which includes both 3-D and 4-C seismic data. After we acquire a property, we seek to increase cash flow from existing reserves and establish additional proved reserves through the drilling of new wells, workovers and recompletions of existing wells and the application of other techniques designed to increase production.

     Effective April 1, 2004, D. Peter Canty will retire as President and Chief Executive Officer. The Board of Directors has elected David H. Welch as President, Chief Executive Officer and a Director of Stone effective April 1, 2004.

Financial Overview

     We were incorporated in Delaware in 1993. We completed our initial public offering of common stock in July 1993 and our shares are listed on the New York Stock Exchange under the ticker symbol “SGY.” Additional offerings of common stock were completed in November 1996 and July 1999. We have maintained consistent and profitable growth since our initial public offering in 1993. We have generated net income in all calendar quarters except the fourth quarter of 1998 and third quarter of 2001, both of which included non-cash ceiling test write-downs of our oil and gas properties due to depressed oil and gas prices.

     On September 30, 2003, we redeemed our outstanding $100 million aggregate principal amount of 8¾% Senior Subordinated Notes due 2007 at a call premium of 102.917%. The redemption was funded with available cash and borrowings under our bank credit facility. In December 2001, we issued $200 aggregate million principal amount of 8¼% Senior Subordinated Notes due 2011 to finance a portion of our acquisition of eight producing properties from Conoco, Inc.

     We have a borrowing base under our bank credit facility of $350 million, with availability of an additional $157.9 million of borrowings as of March 1, 2004. The borrowing base limitation is re-determined periodically and is based on a borrowing base amount established by the bank group after its evaluation of the value of our estimated proved oil and gas reserves.

Oil and Gas Marketing

     Our oil and natural gas production is sold at current market prices under short-term contracts providing for variable or market sensitive prices. We derived 12%, 13% and 10% of our total oil and natural gas revenue from Cinergy Marketing and Trading, Duke Energy Trading and Marketing LLC, and Equiva Trading Company, respectively, for the year ended December 31, 2003. No other purchaser accounted for 10% or more of our total oil and natural gas revenue during 2003. We believe that the loss of any of our major purchasers would not result in a material adverse effect on our ability to market future oil and gas production. From time to time, we may enter into transactions that hedge the price of oil and natural gas. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.”

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Competition and Markets

     Competition in the Gulf Coast Basin and the Rocky Mountains is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. See “Risk Factors – Competition within our industry may adversely affect our operations.”

     The availability of a ready market for and the price of any hydrocarbons produced will depend on many factors beyond our control, including but not limited to the amount of domestic production and imports of foreign oil and liquefied natural gas, the marketing of competitive fuels, the proximity and capacity of natural gas pipelines, the availability of transportation and other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of allowable rates of production, taxation and the conduct of drilling operations, and federal regulation of natural gas. In addition, the restructuring of the natural gas pipeline industry virtually eliminated the gas purchasing activity of traditional interstate gas transmission pipeline buyers. See “Regulation — Federal Regulation of Sales and Transportation of Natural Gas.” Producers of natural gas have therefore been required to develop new markets among gas marketing companies, end users of natural gas and local distribution companies. All of these factors, together with economic factors in the marketing arena, generally may affect the supply of and/or demand for oil and natural gas and thus the prices available for sales of oil and natural gas.

Regulation

     Our oil and natural gas operations are subject to numerous U.S. federal, state and local laws and regulations. See “Risk Factors — Our oil and gas operations are subject to various U.S. federal, state and local government regulations that materially affect our operations.”

     Regulation of Production. In all areas where we operate, there are statutory provisions regulating the production of oil and natural gas under which administrative agencies may enforce rules in connection with the location, spacing, drilling, operation and production of both oil and gas wells, determine the reasonable market demand for oil and gas and establish allowable rates of production. These regulatory orders can limit the number of wells or the location where wells may be drilled. Regulation can also restrict the rate of production below the rate that these wells would otherwise produce in the absence of such regulatory orders. Any of these actions could negatively impact the amount or timing of revenues.

     Federal Leases. We have oil and gas leases both onshore and in the Gulf of Mexico, which were granted by the federal government. Operations on onshore federal leases must be conducted in accordance with permits issued by the federal Bureau of Land Management and are subject to a number of other regulatory restrictions, such as restrictions on activities that might interfere with wildlife breeding and nesting and drilling limitations imposed by resource management plans. Moreover, on certain federal leases, prior approval of drillsite locations must be obtained from the U.S. Environmental Protection Agency (the “EPA”). On large-scale projects, lessees may be required to perform Environmental Impact Statements to assess the environmental effects of potential development, which can delay project implementation or result in the imposition of environmental restrictions that could have a material impact on the cost or scope of such project.

     Offshore leases are administered by the United States Department of the Interior Minerals Management Service (the “MMS”). Offshore lessees must obtain MMS approval of exploration, development and production plans prior to the commencement of these operations. In addition to permits required from other agencies (such as the U.S. Coast Guard, the Army Corps of Engineers and the EPA), lessees must obtain a permit from the MMS prior to the commencement of drilling. The MMS has enacted regulations requiring offshore production facilities located on the Outer Continental Shelf (“OCS”) to meet stringent engineering, construction and safety specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has enacted other regulations governing the plugging and abandoning of wells located offshore and the removal of all production facilities. Lessees must also comply with detailed MMS regulations governing the calculation of royalty payments and the valuation of production and permitted cost deductions for that purpose. In 2000, the MMS issued a final rule modifying the valuation procedures for the calculation of royalties owed for crude oil sales. When oil production sales are not in arms-length transactions, the royalties’ calculation will be based on the valuation of oil production on spot market prices instead of the posted prices that were previously utilized. We are currently selling our crude oil under arms-length transactions in a manner that we believe to be acceptable to the MMS under its 2000 rule. This rule has not had a material adverse effect on our results of operations. On August 20, 2003, the MMS issued a proposed rule that would change certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The proposed changes include changing the valuation basis for transactions not at arm’s-length from spot to New York Mercantile Exchange (“NYMEX”) prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. Final comments on the proposed rule were

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due on November 10, 2003. We have no way of knowing whether the MMS will implement the proposed changes in a final rule or what effect such changes, if implemented, will have on our results of operations.

     With respect to any operations conducted on offshore federal leases, liability may generally be imposed under the Outer Continental Shelf Lands Act (the “OCSLA”) for costs of clean-up and damages caused by pollution resulting from these operations, other than damages caused by acts of war or the negligence of third parties. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable financial assurances that these obligations will be met. The cost of bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases.

     Operators in the OCS waters of the Gulf of Mexico are also required to post area-wide bonds and individual lease bonds of $3 million and $1 million, respectively, unless the MMS allows exemptions or reduced amounts. We currently have an area-wide right-of-way bond for $0.3 million and an area-wide lessee’s and operator’s bond totaling $3 million issued in favor of the MMS for our existing offshore properties. The MMS also has discretionary authority to require supplemental bonding in addition to the foregoing required bonding amounts but this authority is only exercised on a case-by-case basis at the time of filing an assignment of record title interest for MMS approval. Based upon certain financial parameters, we have been granted exempt status by the MMS, which exempts us from the supplemental bonding requirements. There is no assurance, however, that such exemption will be maintained. Under certain circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

     Oil Price Controls and Transportation Rates. Sales of crude oil, condensate and gas liquids are not currently regulated and are made at negotiated prices. Effective January 1, 1995, the Federal Energy Regulatory Commission (the “FERC”) implemented regulations establishing an indexing system for transportation rates for oil that allowed oil pipelines to change rates yearly based on the change in an inflation index, the Producer Price Index for Finished Goods (“PPI-FG”), minus one percent. The implementation of these regulations did not have a material adverse effect on our results of operations. As required by its own regulations, in July 2000, the FERC reviewed its indexing methodology and concluded no change was needed. On judicial review, however, the Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) concluded that the FERC’s decision was not adequately supported and remanded the decision to the FERC. In February 2003, on remand, the FERC changed the rate indexing methodology to the PPI-FG, but without the subtraction of one percent as had been done previously. The FERC made the change prospective only, but did allow oil pipelines to recalculate their maximum ceiling rates as though the new rate indexing methodology had been in effect since July 1, 2000.

     Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (the “NGA”), the Natural Gas Policy Act of 1978 (the “NGPA”) and regulations promulgated thereunder by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

     Commencing in 1992, the FERC issued Order No. 636 and subsequent orders (collectively, “Order No. 636”), which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sales of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all shippers. Although Order No. 636 does not directly regulate our activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The implementation of these orders has not had a material adverse effect on our results of operations. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations.

     In 2000, the FERC issued Order No. 637 and subsequent orders (collectively, “Order No. 637”), which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 were upheld on judicial review, though certain issues, such as capacity segmentation and rights of first refusal, were remanded to the FERC, which issued a remand order in October of 2002. In January of 2004, the FERC denied rehearing of its October 2002 remand order. We cannot predict whether judicial review will be sought of the FERC’s remand order and, if so, whether and to what extent the FERC’s market reforms will survive such review and, if they do, whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that we will be affected by any action taken materially different than other natural gas producers and marketers with which we compete.

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     Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. The natural gas industry historically has been heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

     Environmental Regulations. Our operations are subject to numerous stringent and complex laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, the issuance of remedial requirements, and the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and gas industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, there is no assurance that this trend will continue in the future.

     The Oil Pollution Act, as amended (“OPA”), and regulations implemented thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters, including the OCS. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for onshore facilities is $350 million while for offshore facilities it is the payment of all removal costs, plus up to $75 million in other damages. Few defenses exist to the liability imposed by OPA.

     OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under OPA and a final rule adopted by the MMS in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10 million in specified state waters to at least $35 million in OCS waters, with higher amounts of up to $150 million in certain limited circumstances where the MMS believes such a level is justified by the risks posed by the operations, or if the worst case oil spill discharge volume possible at the facility may exceed the applicable threshold volume specified under the MMS’s final rule. We do not anticipate that we will experience any difficulty in continuing to satisfy the MMS’s requirements for demonstrating financial responsibility under OPA and the MMS’s regulations.

     The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

     The Resource Conservation and Recovery Act, as amended (“RCRA”), generally does not regulate most wastes generated by the exploration and production of oil and natural gas. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the oil and gas industry in general. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

     We currently own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or under other locations where such wastes have been taken for disposal. In addition, most of these properties have been operated by third parties whose treatment and disposal or release of wastes is not under our control. These properties and the

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wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

     The Federal Water Pollution Control Act, as amended (“FWPCA”), imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas waste into navigable waters. Permits must be obtained to discharge pollutants into waters and to conduct construction activities in waters and wetlands. The FWPCA and similar state laws provide for civil, criminal and administrative fines and penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into coastal waters. Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry is expected to experience similar costs and we believe that these costs will not have a material adverse impact on our results of operations or financial position. The EPA has adopted regulations requiring certain oil and gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

Employees

     At March 1, 2004, we had 215 full time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. From time to time we utilize the services of independent contractors to perform various field and other services.

Forward-Looking Statements

     The information in this Form 10-K 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 forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K.

     Forward-looking statements appear in a number of places and include statements with respect to, among other things:

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any expected results or benefits associated with our acquisitions;

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estimates of our future oil and natural gas production, including estimates of any increases in oil and gas production;

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planned capital expenditures and the availability of capital resources to fund capital expenditures;

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our outlook on oil and gas prices;

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estimates of our oil and gas reserves;

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any estimates of future earnings growth;

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the impact of political and regulatory developments;

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our outlook on the resolution of pending litigation;

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our future financial condition or results of operations and our future revenues and expenses; and

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our business strategy and other plans and objectives for future operations.

     We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, but are not limited to, commodity price volatility, third party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating proved oil and natural

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gas reserves and in projecting future rates of production and timing of development expenditures and the other risks described in this Form 10-K.

     Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered.

     Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. 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 us are expressly qualified in their entirety by this cautionary statement.

Risk Factors

     Our business is subject to a number of risks including, but not limited to, those described below:

Oil and gas price declines and volatility could adversely affect our revenues, cash flows and profitability.

     Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Factors that can cause this fluctuation include:

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relatively minor changes in the supply of and demand for oil and natural gas;

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market uncertainty;

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the level of consumer product demands;

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weather conditions;

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domestic and foreign governmental regulations;

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the price and availability of alternative fuels;

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political and economic conditions in oil producing countries, particularly those in the Middle East;

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the foreign supply of oil and natural gas;

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the price of oil and gas imports; and

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overall domestic and foreign economic conditions.

     We cannot predict future oil and natural gas prices. At various times, excess domestic and imported supplies have depressed oil and gas prices. Declines in oil and natural gas prices may adversely affect our financial condition, liquidity and results of operations. Lower prices may reduce the amount of oil and natural gas that we can produce economically and may also create ceiling test write-downs of our oil and gas properties. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices, not long-term fixed price contracts.

     In an attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition and results of operations.

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The marketability of our production depends mostly upon the availability, proximity and capacity of gas gathering systems, pipelines and processing facilities.

     The marketability of our production depends upon the availability, proximity, operation and capacity of gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors changed dramatically, the financial impact on us could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

We may not receive payment for a portion of our future production.

     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, parental 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.

Estimates of oil and gas reserves are uncertain and inherently imprecise.

     This Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

     Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this document and the information incorporated by reference. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

     At December 31, 2003, approximately 25% of our estimated proved reserves were proved undeveloped and 44% were proved developed non-producing. Proved undeveloped reserves and proved developed non-producing reserves, by their nature, are less certain than proved developed producing reserves. Estimation of these non-producing categories is nearly always based on volumetric calculations rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Recovery of proved developed non-producing reserves requires capital expenditures to recomplete into the zones above producing intervals and is subject to the risk of a successful recompletion. Production revenues from proved non-producing reserves will not be realized until sometime in the future, sometimes not for many years. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our oil and gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated.

     You should not assume that the present value of estimated future net cash flow referred to in this Form 10-K is the current fair value of our estimated oil and gas reserves. In accordance with SEC requirements, the present value of estimated future net cash flows from proved reserves is based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor for Stone.

Lower oil and gas prices may cause us to record ceiling test write-downs.

     We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties (net of related deferred taxes), including estimated capitalized abandonment costs, may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10% and excluding cash flows related to estimated abandonment costs, plus the lower of cost or fair value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” This charge does not

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impact cash flow from operating activities, but does reduce net income. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. We recorded an after-tax write-down of $154.5 million ($237.7 million pre-tax) at the end of the third quarter of 2001 due to low natural gas prices on the last day of that quarter. There was no loss of proved reserve volumes associated with the ceiling test write-down. We cannot assure you that we will not experience ceiling test write-downs in the future.

We may not be able to obtain adequate financing to execute our operating strategy.

     We have historically addressed our short and long-term liquidity needs through the use of bank credit facilities, the issuance of debt and equity securities and the use of cash flow provided by operating activities. We continue to examine the following alternative sources of capital:

•

bank borrowings or the issuance of debt securities;

•

the issuance of common stock, preferred stock or other equity securities;

•

joint venture financing; and

•

production payments.

     The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices and our market value and operating performance. We may be unable to fully execute our operating strategy if we cannot obtain capital from these sources.

We may not be able to fund our planned capital expenditures.

     We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. Our capital expenditures, including acquisitions and exclusive of estimated asset retirement costs, were $362.6 million during 2003, $215.6 million during 2002 and $641.3 million during 2001. We have budgeted total capital expenditures in 2004, excluding property acquisitions and capitalized salaries, general and administrative costs and interest, of approximately $280 million. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to spend the capital necessary to complete our capital expenditures program. In addition, if our borrowing base under our credit facility is re-determined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot assure you that additional debt or equity financing will be available or cash flows provided by operations will be sufficient to meet these requirements.

We may not be able to replace production with new reserves.

     In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. During 2003, 94% of our production and 91% of our estimated proved reserves were derived from Gulf of Mexico reservoirs, while the remaining portions of our production and reserves were derived from the Rocky Mountain region. Gulf of Mexico reservoirs tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves.

     Our recent growth is due in large part to acquisitions of producing properties. The successful acquisition of producing properties requires an assessment of a number of factors, some of which are beyond our control. These factors include recoverable reserves, future oil and gas prices, operating costs, and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties, which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, the review will not permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing oil and gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us.

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     Our strategy includes increasing our reserves, production and cash flow by the implementation of a carefully designed field-wide development plan. These development plans are formulated both prior to and after the acquisition of a property. However, we cannot assure you that our future development and exploration activities on the properties we acquire will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

There are uncertainties in successfully integrating our acquisitions.

     Integrating acquired businesses and properties involves a number of special risks. These risks include the possibility that management may be distracted from regular business concerns by the need to integrate operations and that unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results.

Our operations are subject to numerous risks of oil and gas drilling and production activities.

     Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be found. The cost of drilling and completing wells is often uncertain. 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:

•

unexpected drilling conditions;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

weather conditions;

•

shortages in experienced labor; and

•

shortages or delays in the delivery of equipment.

     The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services.

     We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenue after operating and other costs to recoup drilling costs.

Our industry experiences numerous operating risks.

     The exploration, development and operation of oil and gas properties involves a variety of operating risks including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. If any of these industry-operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above.

     We have begun to explore for natural gas and oil in the deep waters of the Gulf of Mexico (water depths greater than 2,000 feet) where operations are more difficult than in shallower waters. Our deepwater drilling and operations require the application of recently developed technologies that involve a higher risk of mechanical failure. The deep waters of the Gulf of Mexico often lack the physical and oilfield service infrastructure present in the shallower waters. As a result, deepwater operations may require a significant amount of time between a discovery and the time that we can market the natural gas or oil, increasing the risks involved with these operations.

     During 2002, we experienced two separate production interruptions resulting from two named storms in the Gulf of Mexico. 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 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.

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     We maintain insurance of various types to cover our operations, including maritime employer’s liability and comprehensive general liability. Coverage amounts are provided by primary and excess umbrella liability policies with ultimate limits of $100 million. In addition, we maintain up to $100 million in operator’s extra expense insurance, which provides coverage for the care, custody and control of wells drilled and/or completed plus re-drill and pollution coverage. The exact amount of coverage for each well is dependent upon its depth and location.

     We cannot assure you that our insurance will be adequate to cover losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse affect on our financial condition and operations.

Terrorist attacks aimed at our facilities could adversely affect our business.

     The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments have subjected our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers, could have a material adverse affect on our financial condition and operations.

A majority of our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a geographic area.

     Approximately 91% of our estimated proved reserves at December 31, 2003 and 94% of our production during 2003 were associated with our Gulf Coast Basin properties. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue.

Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, results of operations and business prospects.

     As of December 31, 2003, we had $370.0 million in outstanding indebtedness. We have a borrowing base under our bank credit facility of $350 million with availability of an additional $157.9 million of borrowings as of March 1, 2004.

     The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:

•

incurring additional debt;

•

paying dividends on stock, redeeming stock or redeeming subordinated debt;

•

making investments;

•

creating liens on our assets;

•

selling assets;

•

guaranteeing other indebtedness;

•

entering into agreements that restrict dividends from our subsidiary to us;

•

merging, consolidating or transferring all or substantially all of our assets; and

•

entering into transactions with affiliates.

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     Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences on our operations, including:

•

making it more difficult for us to satisfy our obligations under the indentures or other debt and increasing the risk that we may default on our debt obligations;

•

requiring us to dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

•

limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;

•

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•

detracting from our ability to successfully withstand a downturn in our business or the economy generally;

•

placing us at a competitive disadvantage against other less leveraged competitors; and

•

making us vulnerable to increases in interest rates, because debt under our credit facility will be at variable rates.

     We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of our repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Our borrowing base under the credit facility, which is re-determined periodically, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values. Upon a re-determination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to repay a portion of our bank debt.

     We may not have sufficient funds to make such repayments. If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flow from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt. The terms of our debt, including our credit facility and our indentures, may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure you that any such offering, refinancing or sale of assets can be successfully completed.

Competition within our industry may adversely affect our operations.

     Competition in the Gulf Coast Basin and the Rocky Mountains is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete.

Our oil and gas operations are subject to various U.S. federal, state and local governmental regulations that materially affect our operations.

     Our oil and gas operations are subject to various U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as wetlands and restrictions on the way we can release materials in the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; and taxation. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies have restricted the rates of flow of oil and gas wells below actual production capacity. In addition, the OPA requires operators of offshore facilities such as us to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under OPA and other federal and state environmental statutes, the CERCLA and the RCRA, owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other

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regulated substances, subject to certain limitations. Consequently, a substantial spill from one of our facilities subject to laws such as OPA, CERCLA and RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and gas, by-products from oil and gas and other substances, and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.

The loss of key personnel could adversely affect our ability to operate.

     Our operations are dependent upon a relatively small group of key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. We do not have employment contracts with any of these individuals. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us.

Hedging transactions may limit our potential gains.

     In order to manage our exposure to price risks in the marketing of our oil and natural gas, we periodically enter into oil and gas price hedging arrangements with respect to a portion of our expected production. Our hedging policy provides that, without prior approval of our board of directors, generally not more than 50% of our estimated production quantities may be hedged. These arrangements may include futures contracts on the NYMEX. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•

our production is less than expected;

•

there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

•

the counterparties to our futures contracts fail to perform the contracts; or

•

a sudden, unexpected event materially impacts oil or natural gas prices.

Ownership of working interests, net profits interests and overriding royalty interests in certain of our properties by certain of our officers and directors may create conflicts of interest.

     James H. Stone and Joe R. Klutts, both directors of Stone, collectively own 9% of the working interest in certain wells drilled on Section 19 on the east flank of the Weeks Island Field. These interests were acquired at the same time that our predecessor company acquired its interests in the Weeks Island Field. In their capacity as working interest owners, they are required to pay their proportional share of all costs and are entitled to receive their proportional share of revenue.

     D. Peter Canty, Stone’s Chief Executive Officer, and James H. Prince, Stone’s Chief Financial Officer, were granted net profit interests in some of Stone’s oil and gas properties acquired prior to our initial public offering in 1993. In addition, Michael E. Madden, Stone’s Vice President of Engineering, was granted an overriding royalty interest in some of Stone’s properties by an independent third party. At the time he was granted this interest, Mr. Madden was serving Stone as an independent engineering consultant. The recipients of net profits and overriding royalty interests are not required to pay capital costs incurred on the properties burdened by such interests.

     As a result of these transactions, a conflict of interest may exist between us and such directors and officers with respect to the drilling of additional wells or other development operations.

We do not pay dividends.

     We have never declared or paid any cash dividends on our common stock and have no intention to do so in the near future. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indenture executed in connection with our 81/4% Senior Subordinated Notes due 2011. In addition, we have entered into a credit facility that contains provisions that may have the effect of limiting or prohibiting the payment of dividends.

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Our Certificate of Incorporation and Bylaws have provisions that discourage corporate takeovers and could prevent stockholders from realizing a premium on their investment.

     Certain provisions of our Certificate of Incorporation, Bylaws and shareholders’ rights plan and the provisions of the Delaware General Corporation Law may encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. Our Bylaws provide for a classified board of directors. Also, our Certificate of Incorporation authorizes our board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as the board may determine. Additional provisions include restrictions on business combinations and the availability of authorized but unissued common stock. These provisions, alone or in combination with each other and with the rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.

     During 1998, our board of directors adopted a shareholder rights agreement, pursuant to which uncertificated stock purchase rights were distributed to our stockholders at a rate of one right for each share of common stock held of record as of October 26, 1998. The rights plan is designed to enhance the board’s ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect stockholders against attempts to acquire us by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover not supported by our board, including a takeover that may be desired by a majority of our stockholders or involving a premium over the prevailing stock price.

ITEM 2. PROPERTIES

     We have grown principally through the acquisition and subsequent development and exploitation of properties purchased from major and independent oil and gas companies. As of March 1, 2004, our property portfolio consisted of 60 active properties and 28 primary term leases in the Gulf Coast Basin and 33 active properties in the Rocky Mountains.

     As of January 1, 2004, we served as operator on 59% of our active properties, including a 67% operating percentage on our Gulf Coast Basin properties. The properties that we operate accounted for 78% of our year-end 2003 estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities.

Oil and Natural Gas Reserves

     The information in this annual report on Form 10-K relating to Stone’s estimated oil and gas reserves and the estimated future net cash flows attributable thereto is based upon the reserve reports (the “Reserve Reports”) prepared as of December 31, 2003 by Atwater Consultants, Ltd., Ryder Scott Company, L.P., and Cawley, Gillespie & Associates, Inc., all independent petroleum engineers. These independent petroleum engineers reviewed 100% of our total proved reserves as of December 31, 2003. All product pricing and cost estimates used in the Reserve Reports are in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, the reported amounts give no effect to federal or state income taxes otherwise attributable to estimated future cash flow from the sale of oil and natural gas. The present value of estimated future net cash flows has been calculated using a discount factor of 10%.

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     You should not assume that the estimated future net cash flows or the present value of estimated future net cash flows, referred to in the table below, represent the fair value of our estimated oil and gas reserves. As required by the SEC, we determine estimated future net cash flows using period-end market prices for oil and gas without considering hedge contracts in place at the end of the period. Using the information contained in the Reserve Reports, the average 2003 year-end product prices for all of our properties were $31.79 per barrel of oil and $6.30 per Mcf of gas. The following table sets forth our estimated net proved oil and natural gas reserves and the present value of estimated future net cash flows before income taxes related to such reserves as of December 31, 2003.

     There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein only represents estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. Results of drilling, testing and production subsequent to the date of an estimate may justify a revision of such estimates. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately produced. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geological success, prices, future production levels and costs that may not prove to be correct. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of these estimates depends on the accuracy of the assumptions upon which they are based.

     As an operator of domestic oil and gas properties, we have filed Department of Energy Form EIA-23, “Annual Survey of Oil and Gas Reserves,” as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported herein. The differences are attributable to the fact that Form EIA-23 requires that an operator report the total reserves attributable to wells that it operates, without regard to percentage ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis) or non-operated wells in which it owns an interest.

Acquisition, Production and Drilling Activity

     Acquisition and Development Costs. The following table sets forth certain information regarding the costs incurred in our acquisition, development and exploratory activities during the periods indicated.

     (1) Recorded in connection with the application of Statement of Financial Accounting Standards No. 143.

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     Productive Well and Acreage Data. The following table sets forth certain statistics regarding the number of productive wells and developed and undeveloped acreage as of December 31, 2003.

	(1)		15 gross wells each have dual completions.
	(2)		5 gross wells each have dual completions.
	(3)		Leases covering approximately 5% of our undeveloped gross acreage will expire in 2004, 5% in 2005, 2% in 2006, 1% in 2007 and 4% in 2008. Leases covering the remainder of our undeveloped gross acreage (83%) are held by production.

     Drilling Activity. The following table sets forth our drilling activity for the periods indicated.

Title to Properties

     We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Our properties are subject to customary royalty interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect the value of such properties. Prior to acquiring undeveloped properties, we perform a title investigation that is thorough but less vigorous than that conducted prior to drilling, which is consistent with standard practice in the oil and gas industry. Before we commence drilling operations, we conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations. We have performed a thorough title examination with respect to substantially all of our active properties.

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ITEM 3. LEGAL PROCEEDINGS

     Goodrich Petroleum Corporation, Goodrich Petroleum Company, L.L.C. and Goodrich Petroleum Company-Lafitte, L.L.C. filed civil action number 2000-06437, in Harris County, Texas, against Stone Energy Corporation, seeking seismic data at Lafitte Field and unspecified damages. On October 29, 2003, after a trial of this matter, the jury awarded Goodrich Petroleum Company-Lafitte, L.L.C. damages in the amount of approximately $0.5 million. As of March 1, 2004, the court had not entered a judgement in this case. There has been no indication whether the plaintiff will appeal this decision. We are evaluating whether an appeal will be filed by Stone.

     We are named as a defendant in certain lawsuits and are a party to certain regulatory proceedings arising in the ordinary course of business. We do not expect these matters, individually or in the aggregate, to have a material adverse effect on our financial condition.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matters were submitted for a vote of our stockholders during the fourth quarter of 2003.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

     We announced that effective April 1, 2004, D. Peter Canty will retire as President and Chief Executive Officer. Mr. Canty will continue to serve as one of our directors. Effective April 1, 2004, Mr. David H. Welch will become President, Chief Executive Officer and a director of Stone. Mr. Welch most recently served as Senior Vice President of BP America, Inc.

     The following table sets forth information regarding the names, ages (as of March 1, 2004) and positions held by each of our executive officers, followed by biographies describing the business experience of our executive officers for at least the past five years. Our executive officers serve at the discretion of the board of directors.

     D. Peter Canty was named Chief Executive Officer on January 1, 2001 and President in March 1994. He has also served as a Director since March 1993. Mr. Canty will resign as President and Chief Executive Officer effective April 1, 2004. He has been employed by Stone Energy since its inception in 1993.

     Andrew L. Gates, III has served as Vice President, General Counsel and Secretary since August 1995.

     Craig L. Glassinger was named Senior Vice President – Planning, Acquisitions and Analysis in April 2002. From December 1995 to February 2001 he served as Vice President – Acquisitions and from February 2001 until April 2002 as Vice President – Resources.

     E. J. Louviere has served as Vice President – Land since June 1995. He has been employed by Stone since its inception in 1993.

     Michael E. Madden was named Vice President – Engineering in March 2002. Previously, he served as the Lafayette District Manager from February 2001 to March 2002. He has been employed by Stone Energy since its inception in 1993 as a reservoir engineer.

     J. Kent Pierret was named Vice President and Chief Accounting Officer in June 1999. Mr. Pierret was named Treasurer in February 2004. Prior to June 1999, he was a partner in the firm of Pierret, Veazey & Co., CPAs (and its predecessors) from May 1988 to May 1999, which performed a substantial amount of our financial reporting, tax compliance and financial advisory services.

     James H. Prince was named Chief Financial Officer in August 1999. He previously served as Chief Accounting Officer and Controller from 1993 to June 1999 and Treasurer from June 1999 to February 2004. In April 2002, he became a Senior Vice President. He has been employed by Stone Energy since its inception in 1993.

     Gerald G. Yunker was named Vice President – Resources in March 2002. Previously, he served Stone Energy in various capacities as a geologist, a Development Manager, and the Planning, Acquisition & Analysis Manager from October 1994 to March 2002.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

     Since July 9, 1993, our common stock has been listed on the New York Stock Exchange under the symbol “SGY.” The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock.

     On March 1, 2004, the last reported sales price on the New York Stock Exchange Composite Tape was $46.38 per share. As of that date, there were 203 holders of record of our common stock.

Dividend Restrictions

     In the past, we have not paid cash dividends on our common stock, and we do not intend to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and development of our business. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indenture executed in connection with our 81/4% Senior Subordinated Notes due 2011. In addition, we have entered into a credit facility that contains provisions that may have the effect of limiting or prohibiting the payment of dividends.

Equity Compensation Plan Information

     Please refer to Item 12 of this Annual Report on Form 10-K for information concerning securities authorized under our equity compensation plan.

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ITEM 6. SELECTED FINANCIAL DATA

     The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2003. This information is derived from our Financial Statements and the notes thereto. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”

	(1)		Relates to 100% allowance for production receivable due from Enron North America.
	(2)		Cumulative effects of accounting changes related to the adoption of SFAS No. 143 and change to the Units of Production method of DD&A.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

     The following discussion is intended to assist in understanding our financial position and results of operations for each of the years in the three-year period ended December 31, 2003. Our Financial Statements and the notes thereto, which are found elsewhere in this Form 10-K contain detailed information that should be referred to in conjunction with the following discussion. See “Item 8. – Financial Statements and Supplementary Data.”

Executive Overview

     We are an independent oil and gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties onshore and in the Gulf of Mexico and in several basins in the Rocky Mountains. Our business strategy, which has remained consistent since 1993, is to increase reserves, production and cash flow through the acquisition, exploitation and development of mature properties located primarily in the Gulf Coast Basin. Our revenue, profitability and future rate of growth are dependent upon the prices of oil and natural gas. Over the last few years, the prices of oil and gas have been highly volatile. The increased volatility is attributable to a variety of factors impacting supply and demand, including weather conditions, political events and economic events we can neither control nor predict.

     Effective April 1, 2004, D. Peter Canty will retire as President and Chief Executive Officer. The Board of Directors has elected David H. Welch as President, Chief Executive Officer and a Director of Stone effective April 1, 2004.

     Over the last several years, we have financed our drilling budget primarily with cash flow from operating activities. We accessed the capital markets and issued debt securities to finance the $300 million property acquisition from Conoco, Inc. on December 31, 2001.

     2003 Highlights.

     Our primary 2003 goals were to grow production and reserves and lower debt levels. Although total production volumes during 2003 did not exceed volumes produced during 2002, we did achieve other goals indicated below:

•

Record Reserve Additions from Drilling – At December 31, 2003, our estimated total proved reserves were 816.3 Bcfe, which represents a 9% growth over prior year estimates and a 167% replacement of 2003 production volumes, 143% of which was achieved through drilling.

•

Drilling Success – During 2003, of the 52 wells we drilled 44 were productive, 85% rate of success.

•

Record Level of Revenue – Oil and gas revenue totaled $508.3 million, or 35% higher than 2002 revenue of $377.5 million.

•

Reduced Long-Term Debt –During 2003, we had net repayments of long-term debt of $61 million through the redemption of our 8¾% Senior Subordinated Notes and repayments on our bank credit facility. As a result of these repayments and a 143% increase in net income for 2003, our debt-to-book capital ratio at December 31, 2003 improved to 34% versus 43% on December 31, 2002.

•

MMS SAFE Award Finalist – Stone has been recognized by the MMS as one of five 2003 SAFE Award Finalists for “High Activity Operators.”

     2004 Outlook.

     Based on our outlook of commodity prices and our estimated production, we expect to finance our 2004 capital program with cash flow from operating activities. We have hedged a portion of our estimated 2004 Gulf Coast Basin production at prices of $3.50 per MMBtu of natural gas and $25.00 per barrel of oil. In addition, we have swap contracts for a portion of our estimated production from the Rocky Mountains at a price of $3.42 per MMBtu of natural gas.

     Our 2004 capital expenditures budget is approximately $280 million, excluding acquisitions and capitalized interest and general and administrative expenses. To the extent that 2004 cash flow from operating activities exceeds our estimated 2004 capital expenditures, we plan to pay down a portion of our existing debt. If cash flow from operating activities during 2004 is not sufficient to fund estimated 2004 capital expenditures, we believe that our bank credit facility, under which we have $157.9 million of available borrowings at March 1, 2004, will provide us with adequate liquidity.

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     We have begun to explore for natural gas and oil in the deep waters of the Gulf of Mexico (water depths greater than 2,000 feet) where operations are more difficult than in shallower waters. A team of experienced technical personnel has been established to evaluate potential prospects and opportunities with other operators. We have identified one prospect that we expect to drill during 2004 in the deep water.

Results of Operation

     The following table sets forth certain operating information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and gas reserves. See “Item 2. Properties – Oil and Gas Reserves.”

(1)

Includes the settlement of hedging contracts.

(2)

Excludes major maintenance expenses.

     2003 Compared to 2002. For the year 2003, we reported net income totaling $134.5 million, or $5.07 per share, compared to net income for the year ended December 31, 2002 of $55.4 million, or $2.09 per share. The variance in annual results was due to the following components:

     Production. During 2003, production volumes decreased 7% to 96.9 Bcfe compared to 104.4 Bcfe produced during 2002. Oil production during 2003 totaled approximately 5.7 million barrels compared to 2002 oil production of 6.2 million barrels, while natural gas production during 2003 totaled approximately 62.5 billion cubic feet compared to 67.0 billion cubic feet produced during 2002. The decrease in overall 2003 production, compared to 2002, was primarily the result of delays in initial production from certain discoveries made in 2003 combined with production shut-ins for weather and rig mobilization and from natural production declines.

     Prices. Prices realized during 2003 averaged $30.41 per barrel of oil and $5.34 per Mcf of gas compared to 2002 average realized prices of $25.00 per barrel of oil and $3.31 per Mcf of gas. On a gas equivalent basis, average 2003 prices were 45% higher than prices realized during 2002. All unit pricing amounts include the settlement of hedging contracts.

     From time to time, we enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During 2003, hedging transactions decreased the average price we received for natural gas by $0.03 per Mcf, compared to a net increase of $0.13 per barrel and a net increase of $0.08 per Mcf realized during 2002. We had no hedges in place for 2003 oil production.

     Oil and Gas Revenue. As a result of 45% higher realized prices on a gas equivalent basis, offset in part by a 7% decline in production, oil and gas revenue increased 35% to $508.3 million in 2003 from $377.5 million during 2002.

     Expenses. During 2003, we incurred normal lease operating expenses of $61.4 million, compared to $61.0 million incurred during 2002. On a unit of production basis, 2003 normal lease operating expenses were $0.63 per Mcfe as compared to $0.58 per Mcfe for 2002.

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     Major maintenance expenses, which represent unpredictable repairs and maintenance costs that vary from year to year, totaled $11.4 million in 2003 compared to $15.7 million in 2002.

     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 of $4.0 million, net of tax, was recorded as a charge during 2003.

     DD&A expense on oil and gas properties under the UOP method for 2003 totaled $168.0 million, or $1.73 per Mcfe. Under the FGR method, DD&A expense during 2002 was $158.3 million, or $1.52 per Mcfe. DD&A expense, as adjusted for the new method of accounting, would have been $166.9 million, or $1.60 per Mcfe, for 2002. The increase in DD&A per Mcfe is attributable to the unit cost of current year reserve additions, including increases in future development costs, exceeding the per unit amortizable base as of the beginning of the year. DD&A under the FGR method for the year ended December 31, 2002 was positively impacted by higher period-end oil and gas prices for 2002. See Accounting Matters and Critical Accounting Policies – Changes in Accounting Principles.

     During 2003, we incurred $6.3 million of accretion expense related to the January 1, 2003 adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.”

     Due to our progress in reaching certain of our annual performance goals, incentive compensation expense increased to $2.6 million during 2003 compared to $0.9 million during 2002.

     Derivative expenses represent primarily the cost of put contracts charged to earnings as the contracts settle during the respective periods. During 2003, we incurred derivative expenses of $8.7 million compared to $16.0 million in 2002. The decline in derivative expenses in 2003 is the result of no oil put contracts for 2003 production volumes and a lower cost of our natural gas put contracts.

     Effective September 30, 2003, we redeemed our outstanding $100 million aggregate principal amount of 8¾% Senior Subordinated Notes due 2007 with cash and borrowings available under our bank credit facility. As a result of the redemption of these Notes and repayments on the bank credit facility of $61.0 million, interest expense during 2003 was 17% lower than 2002. Interest expense for 2003 totaled $19.1 million, net of $8.6 million of capitalized interest, compared to interest of $23.1 million, net of $8.5 million of capitalized interest, during 2002.

     Reserves. At December 31, 2003, our estimated proved oil and gas reserves totaled 816.3 Bcfe, compared to December 31, 2002 reserves of 750.8 Bcfe. The 9% increase in estimated proved reserves during 2003 was the combined result of drilling results and acquisitions made during the year. Estimated proved natural gas reserves totaled 461.3 Bcf and estimated proved oil reserves totaled 59.2 MMBbls at the end of 2003. The reserve estimates were prepared by independent petroleum consultants in accordance with guidelines established by the SEC.

     Our present values of estimated future net cash flows before income taxes were $2.4 billion and $1.8 billion at December 31, 2003 and 2002, respectively. You should not assume that the present values of estimated future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine the present value of estimated future net cash flows using market prices for oil and gas on the last day of the fiscal period. The average year-end oil and gas prices on all of our properties used in determining these amounts, excluding the effects of hedges in place at year-end, were $31.79 per barrel and $6.30 per Mcf for 2003 and $30.41 per barrel and $4.86 per Mcf for 2002.

     2002 Compared to 2001. For the year 2002, we reported net income totaling $55.4 million, or $2.09 per share, compared to net loss for the year ended December 31, 2001 of $71.4 million, or $2.73 per share. The variance in annual results was due to the following components:

     Production. During 2002, production volumes increased 13% to 104.4 Bcfe compared to 92.4 Bcfe produced during 2001. Oil production during 2002 increased 55% to approximately 6.2 million barrels compared to 2001 oil production of 4.0 million barrels, while natural gas production during 2002 totaled approximately 67.0 billion cubic feet compared to 68.2 billion cubic feet produced during 2001. The increase in overall 2002 production, compared to 2001, was primarily the result of our December 31, 2001 acquisition of eight producing properties from Conoco, Inc.

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     Prices. Prices realized during 2002 averaged $25.00 per barrel of oil and $3.31 per Mcf of gas compared to 2001 average realized prices of $25.62 per barrel of oil and $4.29 per Mcf of gas. On a gas equivalent basis, average 2002 prices were 16% lower than prices realized during 2001. All unit pricing amounts include the cash effects of hedging.

     From time to time, we enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. Hedging transactions increased the average price we received during 2002 for oil by $0.13 per barrel and increased the average price we received for natural gas by $0.08 per Mcf, compared to a net increase of $0.37 per barrel and a net decrease of $0.04 per Mcf realized during 2001.

     Oil and Gas Revenue. As a result of lower realized prices, offset in part by a 13% growth in production, oil and gas revenue declined 5% to $377.5 million in 2002 from $395.5 million during 2001.

     Expenses. During 2002, we incurred normal lease operating expenses of $61.0 million, compared to $47.6 million incurred during 2001. On a unit of production basis, 2002 normal lease operating expenses were $0.58 per Mcfe as compared to $0.51 per Mcfe for 2001. Our December 2001 acquisition of eight producing properties increased the number of producing wells and significantly increased the volume of oil production from 2001 levels. The combination of these factors contributed to the increase in normal lease operating expenses during 2002.

     Production taxes for 2002 decreased to $5.0 million from $6.4 million in 2001 primarily due to decreased production volumes from onshore properties and a decrease in the Louisiana severance tax rate for natural gas effective July 1, 2002.

     Depreciation, depletion and amortization (DD&A) expense on oil and gas properties totaled $158.3 million, or $1.52 per Mcfe, during 2002 compared to $157.2 million, or $1.70 per Mcfe, for 2001. DD&A for the year ended December 31, 2002 was positively impacted by higher period-end oil and gas prices for 2002.

     We follow the full cost method of accounting for oil and gas properties. Based upon low oil and gas prices at the end of the third quarter of 2001, we recognized a ceiling test write-down of our oil and gas properties totaling $237.7 million, or $154.5 million after taxes. This expense did not impact our cash flow from operating activities, but did reduce net income.

     Interest expense for 2002 increased to $23.1 million, compared to $4.9 million during 2001 due to the issuance of the 81/4% Senior Subordinated Notes and borrowings under our bank credit facility to finance our $300 million acquisition in December 2001.

     Due to Enron Corp’s financial difficulties, during the fourth quarter of 2001, we recorded a 100% allowance for a production accounts receivable due from Enron North America Corp. This allowance resulted in a 2001 non-cash charge of approximately $2.3 million to bad debt expense.

     Our merger with Basin Exploration, Inc. was completed on February 1, 2001. In connection with the completion of the merger, we incurred expenses during 2001 totaling $25.8 million.

     Reserves. At December 31, 2002, our estimated proved oil and gas reserves totaled 750.8 Bcfe, compared to December 31, 2001 reserves of 775.0 Bcfe. The 3% decline in estimated proved reserves during 2002 was the combined result of 2002’s record production, the exploration portion of our drilling program providing less than expected reserve additions and the lack of a material acquisition during 2002. Estimated proved natural gas reserves totaled 438.7 Bcf and estimated proved oil reserves totaled 52.0 MMBbls at the end of 2002. The reserve estimates were prepared by independent petroleum consultants in accordance with guidelines established by the SEC.

     Our present values of estimated future net cash flows before income taxes were $1.8 billion and $1.0 billion at December 31, 2002 and 2001, respectively. You should not assume that the present values of estimated future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine the present value of estimated future net cash flows using market prices for oil and gas on the last day of the fiscal period. The average year-end oil and gas prices on all of our properties used in determining these amounts, excluding the effects of hedges in place at year-end, were $30.41 per barrel and $4.86 per Mcf for 2002 and $18.64 per barrel and $2.79 per Mcf for 2001.

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Liquidity and Capital Resources

     Cash Flow and Working Capital. Net cash flow provided by operating activities for 2003 was $391.5 million compared to $222.9 million and $315.6 million reported in 2002 and 2001, respectively. The increase in net cash flow provided by operating activities was primarily attributable to an increase oil and gas revenue generated from 45% higher average realized prices on a gas equivalent basis during 2003, offset in part by a 7% decrease in production volumes from the corresponding period. Based on our outlook of commodity prices and our estimated production, we expect to finance our 2004 capital expenditures program with cash flow from operating activities.

     Net cash flow used in investing activities totaled $341.9 million, $216.6 million and $656.8 million during 2003, 2002 and 2001, respectively, which primarily represents our investment in oil and gas properties. Net cash used in investing activities in 2001 includes the $300 million acquisition of eight producing properties from Conoco.

     Net cash flow provided by (used in) financing activities totaled ($60.1) million, $8.1 million and $275.8 million for the years ended December 31, 2003, 2002 and 2001, respectively. The cash flow used in financing activities during 2003 was the result of the $61.0 million of repayments under the amended credit facility. Net cash flow provided by financing activities in 2001 includes $200.0 million of proceeds from the issuance of 8¼% Senior Subordinated Notes in connection with the acquisition from Conoco. As a result of these activities, cash and cash equivalents decreased from $27.6 million as of December 31, 2002 to $17.1 million as of December 31, 2003.

     We had a working capital deficit at December 31, 2003 of $38.5 million. Working capital deficits are not unusual at the end of a period, and are usually the result of accounts payable related to exploration and development costs. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity. Liquidity is defined as the ability to obtain cash quickly either through the conversion of assets or incurrence of liabilities. See Bank Credit Facility.

     Capital Expenditures. Capital expenditures during 2003 totaled $412.3 million and included $49.7 million of asset retirement costs associated with SFAS No. 143, $14.2 million of capitalized general and administrative costs, net of overhead reimbursements, and $8.6 million of capitalized interest. These investments were financed by cash flows from operating activities, borrowings under our bank credit facility and working capital.

     Our 2004 capital expenditures budget, excluding acquisitions and capitalized interest and general and administrative expenses, is approximately $280.0 million, or 2% less than our 2003 capital expenditures, excluding acquisitions, asset retirement costs and capitalized interest and general and administrative expenses. Based on our outlook of commodity prices and our estimated production, we expect to finance our 2004 capital program with cash flow from operating activities.

     To the extent that 2004 cash flow from operating activities exceeds our estimated 2004 capital expenditures, we plan to pay down a portion of our existing debt. If cash flow from operating activities during 2004 is not sufficient to fund estimated 2004 capital expenditures, we believe that our bank credit facility will provide us with adequate liquidity.

     We do not budget acquisitions; however, we are currently evaluating opportunities that fit our specific acquisition profile. One or a combination of certain of these possible transactions could fully utilize our existing sources of capital. Although we have no plans to access the public markets for purposes of capital, if the opportunity arose, we would consider such funding sources to provide capital in excess of what is currently available to us.

     Production Marketing Risk. 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, parental 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.

     Reserve Replacement Risk. In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rate depends on reservoir characteristics. Our proved reserves are primarily derived from Gulf of Mexico reservoirs. Gulf of Mexico reserves tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production, and corresponding revenues and cash flows, are highly dependent upon our level of success in finding or acquiring additional reserves. During 2003, proved reserve additions replaced 167% of our total production volumes for the year.

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     Bank Credit Facility. At December 31, 2003, we had $170.0 million of borrowings outstanding under our credit facility and letters of credit totaling $13.1 million had been issued pursuant to the facility. We have a borrowing base under the credit facility of $350 million, with availability of an additional $157.9 million in borrowings as of March 1, 2004. Our borrowing base under the credit facility, which is re-determined periodically, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values.

     Under the financial covenants of our credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the amended credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a consolidated tangible net worth of at least $350 million, which is adjusted for future earnings and cash proceeds from equity offerings after September 30, 2001. In addition, the credit facility places certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends.

     Hedging. See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk – Commodity Price Risk.”

Contractual Obligations and Other Commitments

     The following table summarizes our significant contractual obligations and commitments, other than hedging contracts, by maturity as of December 31, 2003.

(1) The bank credit facility and related letters of credit mature on June 20, 2005.

Forward-Looking Statements

     Certain of the statements set forth under this item and elsewhere in this Form 10-K are forward-looking and are based upon assumptions and anticipated results that are subject to numerous risks and uncertainties. See “Item 1. Business — Forward-Looking Statements” and "— Risk Factors.”

Accounting Matters and Critical Accounting Policies

     Changes in Accounting Principles. 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 previously used future gross revenue method. Under the UOP method, the quarterly provision for DD&A is computed by dividing production volumes, instead of revenue, for the period by the total proved reserves, instead of future gross revenue, as of the beginning of the period, and similarly applying the respective rate to the net cost of proved oil and gas properties, including future development costs. 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. As a result of the change in accounting principle, we recognized a charge against our 2003 net income for the cumulative transition adjustment of $4.0 million, net of tax.

     In addition, 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. The cumulative effect of adoption of the Entitlement method is immaterial.

     Asset Retirement Obligations. In July 2001, the Financial Accounting Standards Board (“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 removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The

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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 gain 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. As required by SFAS No. 143, our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

     Full Cost Method. We use the full cost method of accounting for our oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee costs and general and administrative costs (less any reimbursements for such costs), incurred for the purpose of acquiring and finding oil and gas are capitalized. Unevaluated property costs are excluded from the amortization base until we have made a determination as to the existence of proved reserves on the respective property or impairment. We review our unevaluated properties at the end of each quarter to determine whether the costs should be reclassified to the full cost pool and thereby subject to amortization. Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

     We amortize our investment in oil and gas properties through DD&A using the UOP method. See “Changes in Accounting Principles” above.

     We capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property costs and our weighted-average borrowing rate. We also capitalize the portion of employee, general and administrative expenses that are attributable to our acquisition, exploration and development activities.

     Generally accepted accounting principles allow the choice of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs and in the computation of DD&A. Under the full cost method, all exploratory costs are capitalized while under the successful efforts method exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under full cost accounting, DD&A is computed on cost centers represented by entire countries while under successful efforts cost centers are represented by properties, fields or reservoirs.

     Under the full cost method of accounting, we are required to periodically compare the present value of estimated future net cash flows from proved reserves (based on period-end commodity prices and excluding cash flows related to estimated abandonment costs), net of related tax effect, to the net capitalized costs of proved oil and gas properties, including estimated capitalized abandonment costs, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows.

     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 Accounting Principles Board Opinion No. 25 (“APB 25”) method whereby no compensation cost is recognized upon grant if certain requirements are met. We have continued to account for our stock-based compensation under APB 25. The Notes to Consolidated Financial Statement provide pro forma information assuming compensation expense for stock-based compensation plans had been determined consistent with the expense recognition provisions under SFAS No. 123.

     Recent Accounting Developments. In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) 51” (“FIN 46”). FIN 46 addresses consolidation by business enterprises of variable interest entities (“VIEs”). The primary objective of FIN 46 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. The provisions of FIN 46 apply immediately to VIEs created after January 31, 2003. In December 2003, the FASB issued a revision to FIN 46, which among other things, deferred the effective date for certain variable interest created prior to January 31, 2003. The Company adopted FIN 46, as revised, as of December 31, 2003, which had no impact on the financial statements.

     We have taken note of a July 2003 inquiry to the Financial Accounting Standards Board regarding whether or not contract-based oil and gas mineral rights held by lease or contract (“mineral rights”) should be recorded or disclosed as intangible assets. The inquiry presents a view that these mineral rights are intangible assets as defined in SFAS No. 141, “Business Combinations,” and, therefore, should be classified separately on the balance sheet as intangible assets. SFAS No. 141, and SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective for transactions subsequent to June 30, 2001 with the disclosure requirements of SFAS No. 142

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required as of January 1, 2002. SFAS No. 141 requires that intangible assets be disaggregated and reported separately from goodwill. SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under the statement, intangible assets should be separately reported on the face of the balance sheet and accompanied by disclosure in the notes to financial statements. We do not believe that SFAS No. 141 or 142 changes the classification of oil and gas mineral rights and we continue to classify these assets as part of oil and gas properties. The Emerging Issues Task Force (“EITF”) has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how we classify these assets. Since June 2001, our only significant acquisition of mineral rights was the December 2001 acquisition from Conoco totaling approximately $300 million. We estimate that of the total purchase price, approximately 70% would be classified as intangible based upon our understanding of the issue before the EITF. Using our historical DD&A rate under the UOP method, the intangible asset would be approximately $160 million, net of accumulated DD&A, as of December 31, 2003.

     Based on our understanding of the issue before the EITF, if all mineral rights associated with unevaluated property and producing reserves were deemed to be intangible assets:

•

mineral rights with proved reserves that were acquired after June 30, 2001 and mineral rights with no proved reserves would be classified as intangible assets and would not be included in oil and gas properties on our consolidated balance sheet;

•

results of operations and cash flows would not be affected because developed mineral rights would continue to be amortized in accordance with full cost accounting rules; and

•

disclosures required by SFAS Nos. 141 and 142 relative to intangibles would be included in the notes to our financial statements.

     If the accounting for mineral rights is ultimately changed, transitional guidance for intangible assets permits the reclassification of only amounts acquired after the effective date of SFAS Nos. 141 and 142 if records were not previously maintained to track acquisition costs based on their intangible or tangible nature. Lack of these records prior to the effective date could result in the loss of comparability between historical balances of tangible and intangible asset balances and among companies in the industry.

     Use of Estimates. 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, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for DD&A, unevaluated property costs, estimated future net cash flow from proved reserves, taxes, costs to abandon oil and gas properties, reserves of accounts receivable, capitalized employee, general and administrative costs, fair value of financial instruments, the purchase price allocation on properties acquired and contingencies.

     Derivative Instruments and Hedging Activities. Under SFAS No. 133, as amended, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. We do not use derivative instruments for trading purposes. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in equity through other comprehensive income, net of related taxes, to the extent the hedge is effective. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings.

     Deferred Income Taxes. Deferred income taxes have been determined in accordance with SFAS No. 109, “Accounting for Income Taxes.” As of December 31, 2003, we had a net deferred tax liability of $127.5 million, which amount was calculated based on our assumption that it is more likely than not that we will have sufficient taxable income in future years to utilize certain tax attribute carryforwards.

     For a more complete discussion of our accounting policies and procedures see our Notes to Consolidated Financial Statements beginning on page F-8.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     We are exposed to market risk, including adverse changes in commodity prices and operating costs. Assuming a 10% decline in realized oil and natural gas prices, including the effects of hedging contracts, our diluted net income per share would have declined approximately 24%. Assuming the costs to operate our properties, including lease operating and major maintenance expenses, increased 10%, our diluted earnings per share would have declined approximately 4%. These results indicate our sensitivity to changes in market conditions as it relates to commodity prices and operating costs.

Commodity Price Risk

     Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and gas price declines and volatility could adversely affect our revenues, cash flow from operating activities and profitability. In order to manage our exposure to oil and gas price declines, we occasionally enter into oil and 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. While intended to reduce the effects of volatile oil and gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•

our production is less than expected;

•

there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

•

the counterparties to our hedging contracts fail to perform the contracts; or

•

a sudden, unexpected event materially impacts oil or natural gas prices.

     Our hedging policy provides that not more than 50% of our estimated production quantities can be hedged without the consent of the board of directors.

     Hedging. We realized a net decrease in revenue during 2003 from our hedging contracts of $1.6 million. During the year we hedged 37,775 BBtus of natural gas, which represented approximately 60% of our 2003 gas production. There were no oil hedges during 2003. During 2002, we realized a net increase in revenue from our hedging transactions of $6.0 million. Our contracts totaled 4,218 MBbls of oil and 24,940 BBtus of gas, which represented approximately 68% and 37%, respectively, of our oil and gas production for the year. During 2001, we realized a net decrease in revenue from our hedging transactions of $1.8 million. Our contracts totaled 1,278 MBbls of oil and 29,300 BBtus of gas, which represented approximately 32% and 43%, respectively, of our oil and gas production for the year.

     Our put contracts are with Bank of America, Bank of Montreal, Bank One and J. Aron & Company (a subsidiary of Goldman Sachs). Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contracts represents our maximum cash exposure. We are not obligated to make any further payments under the put contracts regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above that floor.

     In October 2002, we reached an agreement with Enron North America Corp. to purchase the natural gas swap contract settling subsequent to October 2002 for $5.9 million. We amortized $3.6 million of derivative expenses during 2003 related to previously recorded other comprehensive loss from the swap contract.

     During 2003, we recognized $8.7 million of derivative expenses, of which $5.1 million represents the historical cost charged to earnings associated with put contracts that settled during the year.

     Because over 90% of our production has historically been derived from the Gulf Coast Basin, we believe that fluctuations in prices will closely match changes in the market prices we receive for our production. Oil contracts typically settle using the average of the daily closing prices for a calendar month. Natural gas contracts typically settle using the average closing prices for near month NYMEX futures contracts for the three days prior to the settlement date.

     In addition to put contracts, we utilized fixed-price swaps to hedge a portion of our future gas production from the Rocky Mountains. Our swap contracts are with Bank of America. Swaps typically provide for monthly payments by us if prices rise above the swap price or to us if prices fall below the swap price.

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     The following tables show our hedging positions as of March 1, 2004:

     Interest Rate Risk

     On September 30, 2003, we redeemed our outstanding 8¾% Senior Subordinated Notes due 2007 with $90.0 million of borrowings under our bank credit facility and available cash. As a result, Stone had long-term debt outstanding of $370.0 million at December 31, 2003, of which $200.0 million, or approximately 54%, bears interest at a fixed rate of 8¼%. The remaining $170.0 million of debt outstanding at December 31, 2003 bears interest at a floating rate. At December 31, 2003, the weighted average interest rate under our floating-rate debt was approximately 2.6%. At December 31, 2003, we had no interest rate hedge positions in place to reduce our exposure to changes in interest rates. Assuming a 200 basis point increase in market interest rates during 2003, our interest expense, net of capitalization, would have increased approximately $1.0 million, net of taxes, resulting in a $0.01 per diluted share reduction in earnings.

     Fair Value of Financial Instruments

     The fair value of cash and cash equivalents, net accounts receivable, accounts payable and bank debt approximated book value at December 31, 2003. At December 31, 2003, the fair value of the 8¼% Senior Subordinated Notes due 2011 totaled $218.0 million. The fair value of the Notes has been estimated based on quotes from brokers. Our put and swap contracts are recorded on the balance sheet at fair value, which is obtained from counter-parties to the contracts.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Information concerning this Item begins on Page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

     There have been no disagreements with our independent accountants on our accounting or financial reporting that would require our independent accountants to qualify or disclaim their report on our financial statements, or otherwise require disclosure in this Annual Report on Form 10-K.

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ITEM 9A. 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 period covered by this report. Based on this evaluation, our chief executive officer and chief financial officer believe:

•

Stone’s disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports that 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 information required to be disclosed by Stone in the reports that it files or submits under the Securities Exchange Act of 1934 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 year ended December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     See Item 4A – Executive Officers of the Registrant for information regarding our executive officers.

     Additional information required by Item 10, including information regarding our audit committee financial experts, is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2004 Annual Meeting of Stockholders to be held on May 20, 2004. The Company has made available free of charge on its Internet Web Site (www.StoneEnergy.com) the Code of Business Conduct and Ethics applicable to all employees of the Company including the chief executive officer, chief financial officer and principal accounting officer.

ITEM 11. EXECUTIVE COMPENSATION

     The information required by Item 11 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2004 Annual Meeting of Stockholders to be held on May 20, 2004.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
                  STOCKHOLDER MATTERS

     The information required by Item 12 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2004 Annual Meeting of Stockholders to be held on May 20, 2004.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The information required by Item 13 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2004 Annual Meeting of Stockholders to be held on May 20, 2004.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

     The information required by Item 14 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2004 Annual Meeting of Stockholders to be held on May 20, 2004.

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PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. Financial Statements:

		The following consolidated financial statements, notes to the consolidated financial statements and the Report of Independent Auditors thereon are included on pages F-1 through F-25 of this Form 10-K:
		Report of Independent Auditors
		Consolidated Balance Sheet as of December 31, 2003 and 2002
		Consolidated Statement of Operations for the three years in the period ended December 31, 2003
		Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2003
		Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period ended December 31, 2003
		Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2003
		Notes to the Consolidated Financial Statements

     2. Financial Statement Schedules:

     All schedules are omitted because the required information is inapplicable or the information is presented in the Financial Statements or the
     notes thereto.

     3. Exhibits:

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(b)

Reports on Form 8-K

     Stone filed the following reports on Form 8-K during the fourth quarter of 2003:

*

The information in the Forms 8-K furnished pursuant to Items 9 & 12 is not considered to be “filed” for the purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities of that section except if Stone specifically states that the information is to be considered “filed” under the Exchange Act or incorporates it by reference into a filing under the Securities Act or the Exchange Act.

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SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

     Pursuant to the requirements of the Securities Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

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INDEX TO FINANCIAL STATEMENTS

F-1

REPORT OF INDEPENDENT AUDITORS

To the Stockholders of
Stone Energy Corporation:

We have audited the accompanying consolidated balance sheets of Stone Energy Corporation (a Delaware corporation) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity, comprehensive income and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Stone Energy Corporation as of December 31, 2003 and 2002, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2001, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” As also discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company elected to change to the units of production method of amortizing proved oil and gas property costs and elected to begin recognizing production revenue under the entitlement method.

Ernst & Young LLP

New Orleans, Louisiana
February 27, 2004

F-2

STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollar amounts in thousands, except per share amounts)

The accompanying notes are an integral part of this balance sheet.

F-3

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)

The accompanying notes are an integral part of this statement.

F-4

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollar amounts in thousands)