UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

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

For the fiscal year ended December 31, 2004

or

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

For the transition period from                      to                     

Commission File Number: 1-12074

STONE ENERGY CORPORATION

State of Incorporation: Delaware                     I.R.S. Employer Identification No. 72-1235413

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.

þ Yes       o 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. o

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

þ Yes       o No

     The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1,107,417,271 as of June 30, 2004 (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, 2005, the registrant had outstanding 26,681,912 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 18, 2005 are incorporated by reference into Part III of this Form 10-K.

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 an independent oil and gas company engaged in the acquisition and subsequent exploration, development, operation and production of oil and gas properties located in the conventional shelf of the Gulf of Mexico (the “GOM”), the deep shelf of the GOM, the deepwater of the GOM and several basins of the Rocky Mountains. 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 report 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 on our Internet web site 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. We will make immediate disclosure by a current report on Form 8-K and 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

     Since our public offering in 1993, we have increased reserves, production and cash flow primarily through the acquisition, exploration and development of mature oil and gas properties in the Gulf Coast Basin, which includes onshore Louisiana and offshore GOM. During this period, we have grown reserves, production and cash flow from operating activities at compounded annual rates of 22%, 21% and 35%, respectively. During 2004, we broadened our conventional shelf acquisition and exploitation strategy in order to diversify, extend reserve life and take advantage of a strong oil and gas market. This broadened growth strategy includes targeting reserves and production in the deep water of the GOM and furthering our position in the Rocky Mountains to complement our existing portfolio of properties in the Gulf Coast Basin (onshore, shelf and deep shelf). Our strategy is driven by increased availability of lease blocks in the deep water of the GOM, 3D seismic technology improvements in the deep shelf of the GOM and fracturing technology improvements in the Rocky Mountains. As of March 1, 2005, our property portfolio consisted of 59 active properties and 53 primary term leases in the Gulf Coast Basin and 13 active properties in the Rocky Mountains.

     As of December 31, 2004, we had estimated proved reserves of approximately 825 billion cubic feet of gas equivalent (Bcfe), 73% of which were classified as proved developed and 59% of which were natural gas. For the year ended December 31, 2004, we produced an average of 241 million cubic feet of gas equivalent (MMcfe) per day, which was curtailed due to extended production downtime associated with Hurricane Ivan. During 2004, we generated net cash flow from operating activities of $369.5 million.

     Gulf of Mexico — Conventional Shelf

     Our conventional shelf strategy is the same acquisition and exploitation combination that we adopted prior to our initial public offering in 1993. We apply the latest geophysical interpretation tools to identify underdeveloped properties and the latest production techniques to increase production attributable to these properties. We believe significant reserves remain to be discovered and exploited on properties that satisfy our acquisition criteria. We also believe that we are well positioned to exploit these reserves by applying our technical expertise in a thorough and consistent approach to the evaluation and acquisition of these properties.

     In the Gulf of Mexico, we seek to acquire properties that have the following characteristics:

	•	mature properties with an established production history and infrastructure;
	•	multiple productive sands and reservoirs;
	•	low production levels at acquisition with significant identified proven and potential reserves; and
	•	opportunity for us to obtain a controlling interest and serve as operator.

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     Using our 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. We also employ our extensive technical database, which includes both 3-Dimensional and 4-Component 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.

     Gulf of Mexico — Deep Water

     We believe that the deep water of the Gulf of Mexico is a compelling exploration area and have assembled a technical team with prior geological, geophysical and engineering experience in the deep water arena to evaluate potential opportunities. During 2004, we entered into an exploration agreement with Kerr-McGee Oil and Gas Corp. covering several undeveloped leases in the GOM. Under the agreement, we acquired varying interests in these deep water and deep shelf leases and will participate in five commitment wells to be drilled by the end of 2005, two of which have been drilled. In addition, we also intend to evaluate additional drilling opportunities on the respective leases through 2006.

     Gulf of Mexico — Deep Shelf

     Our current property base also contains multiple deep shelf exploration opportunities in the GOM, which are defined as prospects below 15,000 feet. The deep shelf presents higher risk with high potential opportunities that have existing infrastructure, which shortens the lead time to production. The exploration agreement with Kerr-McGee, noted above, combined with our existing property base creates the opportunity for a portfolio approach to the deep shelf.

     Rocky Mountains

     Although currently less than 11% of our total production and reserves, we consider the assets in the Rockies to be an important component of our continued growth and expect to increase our investment in this region. We are continuing to build a foundation for this business through large acreage acquisitions.

     We are currently active in the vicinity of the Howard Ranch Field in the northern Wind River Basin of Wyoming. This property was acquired by acreage acquisitions in 2002 and 2004. Processing of a 70 square mile seismic survey is currently underway that will allow for interpretation of well locations for our 2005 drilling program in this field. We have also acquired approximately 47,000 net acres of deep rights below the Monument Butte Field in the Uinta Basin of Utah. There is extensive ongoing industry activity in areas around this acreage block. We also operate in the Greater Green River Basin of Wyoming with continued success on the Pinedale Anticline.

     During 2004, we acquired the leasehold rights to approximately 27,000 net acres in Utah. We intend to test the coalbed methane potential of this acreage at depths of 2,000 to 4,000 feet with a three to five well exploratory program during 2005 followed by a development program if exploration is successful. This project, which is located approximately 40 miles southeast of our Monument Butte field, represents our first move into a coalbed methane play.

     On March 1, 2005, we completed the acquisition of approximately 35,000 net exploratory acres in the Williston Basin of North Dakota and Montana. The acquisition cost, net of purchase price adjustments, totaled approximately $85.7 million, of which $76.0 million was financed with borrowings under Stone’s bank credit facility. Approximately 75% of the net purchase price has been allocated to unevaluated costs. We expect to begin exploring the acreage with a multi-well drilling program in 2005.

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. BP Energy Company, Cinergy Marketing and Trading, Conoco, Inc., Equiva Trading Company and Total Gas & Power North America, Inc. each accounted for between 10%-13% of oil and natural gas revenue generated during the year ended December 31, 2004. No other purchaser accounted for 10% or more of our total oil and natural gas revenue during 2004. 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. 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 gas operations are subject to various U.S. federal, state and local laws and regulations.

     Various aspects of our oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted and by certain agencies of the Federal government for operations on Federal leases. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions requiring permits for the drilling of wells and maintaining bonding requirements in order to drill or operate wells, and provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the number of wells that may be drilled in an area and the unitization or pooling of oil and natural gas properties. In this regard, some states can order the pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

     Certain operations that we conduct are on federal oil and gas leases, which are administered by the Bureau of Land Management (the “BLM”) and the Minerals Management Service (the “MMS”). These leases contain relatively standardized terms and require compliance with detailed BLM and MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act (the “OCSLA”) (which are subject to change by the MMS). Many onshore leases contain stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the times during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban any surface activity. For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Environmental Protection Agency), lessees must obtain a permit from the BLM or the MMS, as applicable, prior to the commencement of drilling, and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on Outer Continental Shelf (the “OCS”) of the GOM, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the MMS exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. Under certain circumstances, the BLM or MMS, as applicable, may require 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.

     Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by Congress, states, the Federal Energy Regulatory Commission (the “FERC”) and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. We can give no assurance that the regulatory approach currently pursued by the FERC will continue indefinitely. We do not anticipate, however, that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect on our financial condition, results of operations or competitive position. No portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the Federal government.

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Environmental Regulation

     As a lessee and operator of onshore and offshore oil and gas properties in the United States, we are subject to stringent federal, state and local laws and regulations relating to environmental protection as well as controlling the manner in which various substances, including wastes generated in connection with oil and gas industry operations, are released into the environment. Compliance with these laws and regulations can affect the location or size of wells and facilities, limit or prohibit the extent to which exploration and development may be allowed, and require proper closure of wells and restoration of properties that are being abandoned. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial obligations, incurrence of capital costs to comply with governmental standards, and even injunctions that limit or prohibit exploration and production operations or the disposal of substances generated in connection with oil and gas industry operation.

     We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used for 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 operated or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws and regulations imposing joint and several, strict liability without regard to fault or the legality of the original conduct that could require us to remove or remediate previously disposed wastes or property contamination, or to perform remedial plugging or pit closure to prevent future contamination. We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

     We have made, and will continue to make, expenditures in efforts to comply with environmental laws and regulations. While we believe that we are in substantial compliance with applicable environmental laws and regulations in effect and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance that we will not be adversely affected in the future.

     We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the United States. We employ a safety department whose responsibilities include providing assurance that our operations are carried out in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance against the costs of cleanup operations, public liability and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will continue to be available in the future. To date we believe that compliance with existing requirements of such governmental bodies has not had a material effect on our operations.

Employees

     On March 1, 2005, we had 236 full time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. Under our supervision, we utilize the services of independent contractors to perform various daily operational duties for our offshore GOM properties.

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:

	•	any expected results or benefits associated with our acquisitions;
	•	estimates of our future oil and natural gas production, including estimates of any increases in oil and gas production;
	•	planned capital expenditures and the availability of capital resources to fund capital expenditures;
	•	our outlook on oil and gas prices;
	•	estimates of our oil and gas reserves;
	•	any estimates of future earnings growth;
	•	the impact of political and regulatory developments;
	•	our outlook on the resolution of pending litigation;
	•	our future financial condition or results of operations and our future revenues and expenses; and
	•	our business strategy and other plans and objectives for future operations.

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     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 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:

	•	relatively minor changes in the supply of and demand for oil and natural gas;
	•	market uncertainty;
	•	the level of consumer product demands;
	•	weather conditions;
	•	domestic and foreign governmental regulations;
	•	the price and availability of alternative fuels;
	•	political and economic conditions in oil producing countries, particularly those in the Middle East;
	•	the foreign supply of oil and natural gas;
	•	the price of oil and gas imports; and
	•	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, state and local 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 parental guarantees 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. Although 100% of our estimated proved reserves as of December 31, 2004 were determined by independent reserve engineers, 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, 2004, approximately 27% of our estimated proved reserves were proved undeveloped and 52% were proved developed non-producing. The increase in proved developed non-producing reserves as of December 31, 2004 is primarily the result of reserves associated with producing fields that were shut-in due to damage to downstream production facilities and pipelines owned by third parties, which impacted our ability to restore production to these fields. 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 estimate of proved reserve volumes and 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.

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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 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 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 $501.9 million during 2004, $362.6 million during 2003 and $215.6 million during 2002. We have budgeted total capital expenditures in 2005, excluding property acquisitions and capitalized salaries, general and administrative costs and interest, to be approximately $315 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 fund 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. 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. During 2004, 91% of our production and 89% 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. 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 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 production 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 deep water 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 infrastructure and availability of services present in the shallower waters. As a result, deep water operations may require a significant amount of time between a discovery and the time that we can market the oil and gas, increasing the risks involved with these operations.

     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 experienced Gulf of Mexico production interruption in 2004 from Hurricane Ivan for which we do not have any loss of production insurance.

     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.

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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 89% of our estimated proved reserves at December 31, 2004 and 91% of our production during 2004 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 March 1, 2005, we had $558.0 million in outstanding indebtedness. We have a borrowing base under our bank credit facility of $400 million with availability of an additional $228.9 million of borrowings as of March 1, 2005.

     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.

     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

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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. Failure to comply with these laws and regulations can result in the assessment of administrative, civil, or criminal penalties, the issuance of remedial obligations, and the imposition of injunctions limiting or prohibiting certain of our operations. 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 like CERCLA and RCRA, owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other 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.

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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, our chairman of the board of directors, owns up to 7.5% of the working interest in certain wells drilled on Section 19 on the east flank of the Weeks Island Field. This interest was acquired prior to our initial public offering in 1993. In his capacity as a working interest owner, he is required to pay a proportional share of all costs and is entitled to receive a proportional share of revenue.

     D. Peter Canty, a director and our former President and Chief Executive Officer, and James H. Prince, our Executive Vice President and 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, our Vice President of Exploration and Production Technology, 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 and 6³/4% senior subordinated notes due 2014. 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.

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. During 2004, we implemented an broadened growth strategy designed to diversify from the conventional shelf of the GOM by exploring opportunities in the deep water environment of the GOM and expanding our Rocky Mountain asset base. See “Item 1. Business – Strategy and Operational Overview.” As of March 1, 2005, our property portfolio consisted of 59 active properties and 53 primary term leases in the Gulf Coast Basin and 13 active properties in the Rocky Mountains.

     As of March 1, 2005, we served as operator on 61% of our active properties, including a 66% operating percentage on our Gulf Coast Basin properties. The properties that we operate accounted for 75% of our year-end 2004 estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities.

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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, 2004 by Atwater Consultants, Ltd., Ryder Scott Company, L.P., Netherland, Sewell & Associates, Inc. and Cawley, Gillespie & Associates, Inc., all independent petroleum engineers. These independent petroleum engineers determined 100% of our estimated total proved reserves as of December 31, 2004. All product pricing and cost estimates used in the Reserve Reports are in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”). The standardized measure of discounted future net cash flows has been calculated using a discount factor of 10%.

     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 2004 year-end product prices for all of our properties were $41.14 per barrel of oil and $6.58 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 related to such reserves as of December 31, 2004.

     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, operating costs, development costs and income taxes 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.

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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.

     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, 2004.

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     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.

ITEM 3. LEGAL PROCEEDINGS

     We are among the defendants included in a lawsuit filed in 2004 by the State of Louisiana and the Iberia Parish School Board in Case Number 101934, Iberia Parish, Louisiana, alleging contamination and damage to portions of Section 16, Township 12 South, Range 11 East in the Bayou Pigeon Field as a result of past oil and gas exploration and production activities. The Company believes it has been named as a defendant in error and intends to vigorously defend this matter.

     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 2004.

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ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

     The following table sets forth information regarding the names, ages (as of March 1, 2005) 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.

     David H. Welch was appointed President, Chief Executive Officer and a director of the Company effective April 1, 2004 upon the resignation of D. Peter Canty. Mr. Welch most recently served as Senior Vice President of BP America, Inc. since 2003, and Vice President of BP, Inc. since 1999.

     Craig L. Glassinger was named Executive Vice President of Business Development in April 2004. Previously, Mr. Glassinger served as Senior Vice President – Planning, Acquisitions and Analysis since April 2002. From February 2001 until April 2002, he served as Vice President – Resources and from December 1995 to February 2001 he served as Vice President – Acquisitions.

     James H. Prince was named Executive Vice President in April 2004. He has previously served as Chief Financial Officer since August 1999, 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.

     Andrew L. Gates, III was named Senior Vice President, General Counsel and Secretary in April 2004. He previously served as Vice President, General Counsel and Secretary since August 1995.

     E. J. Louviere was named Senior Vice President – Land in April 2004. Previously, he served as Vice President – Land since June 1995. He has been employed by Stone since its inception in 1993.

     J. Kent Pierret was named Senior Vice President in April 2004. Mr. Pierret previously served as Vice President and Chief Accounting Officer since June 1999 and Treasurer since 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.

     Gerald G. Yunker was named Senior Vice President – Exploitation in April 2004 after serving as Vice President – Resources since 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.

     Michael E. Madden was named Vice President – Exploration and Production Technology in April 2004 and 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.

     Jerome F. Wenzel, Jr. joined Stone in October 2004 as Vice President – Production and Drilling. Prior to joining Stone, Mr. Wenzel held managerial and executive positions with Amoco and BP over a 29 year career. Most recently, Mr. Wenzel was Vice President and Business Unit of INTEC Engineering.

     Florence M. Ziegler was named Vice President – Human Resources in April 2004. She has been employed by Stone since its inception in 1993 and has served as the Director of Human Resources since 1997.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     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, 2005, the last reported sales price on the New York Stock Exchange Composite Tape was $49.45 per share. As of that date, there were 170 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 and 6³/4% Senior Subordinated Notes due 2014. In addition, our bank credit facility that contains provisions that may have the effect of limiting or prohibiting the payment of dividends.

Issuer Purchases of Equity Securities

     There were no purchases of Stone’s common stock by us or on our behalf during the quarterly period ended December 31, 2004.

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, 2004. 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.”

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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, 2004. 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 located in the conventional shelf of the Gulf of Mexico (the “GOM”), deep shelf of the GOM, deep water of the GOM and several basins of 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. During 2004, we implemented a broadened growth strategy designed to diversify from the conventional Gulf of Mexico Shelf by exploring opportunities in the deep water environment of the Gulf of Mexico and expanding our Rocky Mountain asset base. See “Item 1. Business – Strategy and Operational Overview.” 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. See “Item 1. Business – Risk Factors.”

     2004 Highlights.

     Our primary 2004 goals were to grow production and reserves and lower debt levels. Although our production growth was hampered by Hurricane Ivan, we did achieve other goals indicated below:

	•	Deep Water Initiative – Entered into an agreement with Kerr-McGee for exploration in the deep water and deep shelf of the Gulf of Mexico.
	•	GOM Acquisition – Completed a preferential rights acquisition of additional working interest in South Timbalier Blocks 143, 164, 165, 166 and 171.
	•	Debt Offering – Issued $200 million of 63/4% Senior Subordinated Notes due 2014 through a private placement.
	•	Rockies Acquisitions – Completed exploration acreage acquisitions in the Williston Basin of North Dakota and Montana and potential coal-bed methane play in Utah.
	•	New CEO – The board of directors appointed David H. Welch as President, Chief Executive Officer and director of Stone effective April 1, 2004. Mr. Welch most recently served as Senior Vice President of BP America, Inc. since 2003, and Vice President of BP, Inc. since 1999. D. Peter Canty retired as President and Chief Executive Officer in April but retained his seat on the board of directors.

     2005 Outlook.

     Based on our outlook of commodity prices and our estimated production, we expect to finance our 2005 capital program with cash flow from operating activities. We have hedged a portion of our estimated 2005 Gulf Coast Basin oil and natural gas production with zero-premium collars. In addition, we have swap contracts for a portion of our estimated natural gas production from the Rocky Mountains. See “Item 7A. – Quantitative and Qualitative Disclosures About Market Risk for details of hedges and our hedge strategy.”

     Our 2005 capital expenditures budget is approximately $315 million, excluding acquisitions and capitalized interest and general and administrative expenses. To the extent that our 2005 cash flow from operating activities exceeds our estimated 2005 capital expenditures, we may pay down a portion of our existing debt. If cash flow from operating activities during 2005 is not sufficient to fund estimated 2005 capital expenditures, we believe that our bank credit facility, under which we have $228.9 million of available borrowings at March 1, 2005, will provide us with adequate liquidity.

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Results of Operation

     2004 Compared to 2003. 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.”

     For the year 2004, we reported net income totaling $134.9 million, or $5.01 per share, compared to net income for the year ended December 31, 2003 of $134.5 million, or $5.07 per share. The variance in annual results was due to the following components:

     Production. During 2004, total production volumes decreased 9% to 88.2 Bcfe compared to 96.9 Bcfe produced during 2003. Oil production during 2004 totaled approximately 5.4 million barrels compared to 2003 oil production of 5.7 million barrels, while natural gas production during 2004 totaled approximately 55.5 billion cubic feet compared to 62.5 billion cubic feet produced during 2003. The decrease in overall 2004 production, compared to 2003, was primarily the result of extended production downtime from Hurricane Ivan.

     Certain fields in the Main Pass and Mississippi Canyon areas remained shut-in as of December 31, 2004 due to damage to downstream pipelines and production facilities sustained during Hurricane Ivan, which hit during the month of September. Production from certain fields previously shut-in was re-established during the first quarter of 2005 and Stone expect the remaining fields to resume production before the end of 2005.

     Prices. Prices realized during 2004 averaged $39.38 per barrel of oil and $5.94 per Mcf of gas compared to 2003 average realized prices of $30.41 per barrel of oil and $5.34 per Mcf of gas. On a gas equivalent basis, average 2004 prices were 18% higher than prices realized during 2003. All unit pricing amounts include the settlement of hedging contracts.

     We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During 2004, hedging transactions decreased the average price we received for natural gas by $0.18 per Mcf compared to a net decrease of $0.03 per Mcf of natural gas realized during 2003. We had no hedges in place for 2003 oil production.

     Oil and Gas Revenue. As a result of 18% higher realized prices on a gas equivalent basis, oil and gas revenue increased 7% to $544.2 million in 2004 from $508.3 million during 2003 despite a 9% decline in total production volumes during 2004.

     Expenses. During 2004, we incurred lease operating expenses of $100.0 million, compared to $72.8 million incurred during 2003. On a unit of production basis, 2004 lease operating expenses were $1.13 per Mcfe as compared to $0.75 per Mcfe for 2003. The increase in lease operating expenses in 2004 is due to a combination of increases in overall industry service costs, additional costs associated with storm-related shut-ins and evacuations and increases in maintenance costs included in lease operating expenses during 2004. Included in lease operating expenses are maintenance costs, which represent repairs and maintenance costs that vary from year to year. Maintenance costs totaled $29.1 million in 2004 compared to $11.4 million in 2003. The increase in maintenance costs during 2004 is due primarily to $4.2 million for hurricane-related repairs in excess of estimated insurance recoveries and $6.8 million related to three replacement wells drilled during 2004.

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     DD&A expense on oil and gas properties for 2004 totaled $185.3 million, or $2.10 per Mcfe compared to DD&A expense of $168.0 million, or $1.73 per Mcfe in 2003. The increase in DD&A per Mcfe is attributable to the unit cost of current year reserve additions and related future development costs, exceeding the per unit amortizable base as of the beginning of the year.

     During 2004 and 2003, we incurred $5.9 million and $6.3 million, respectively, of accretion expense related to the January 1, 2003 adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” Stone expects accretion expense to total approximately $7.2 million during 2005 as a result of property acquisitions and additional assets placed in service during 2004.

     Derivative expenses represent primarily the cost of put contracts charged to earnings as the contracts settle during the respective periods. During 2004, we incurred derivative expenses of $4.1 million compared to $8.7 million in 2003. The decline in derivative expenses in 2004 is the result of lower costs of put contracts for 2004 hedged production volumes. For 2005, Stone currently expects no derivative expense as production hedges are with zero-premium collars and swaps.

     Interest expense for 2004 totaled $16.1 million, net of $7.7 million of capitalized interest, compared to interest of $19.1 million, net of $8.6 million of capitalized interest, during 2003. The decrease in interest expense in 2004 is the result of the September 2003 redemption of our 8³/4% senior subordinated notes, which lowered the average interest rate on our outstanding debt, combined with lower average borrowings outstanding during 2004.

     Reserves. At December 31, 2004, our estimated proved oil and gas reserves totaled 825.0 Bcfe, compared to December 31, 2003 reserves of 816.3 Bcfe. The increase in estimated proved reserves during 2004 was the combined result of drilling results and acquisitions made during the year. Estimated proved natural gas reserves totaled 485.6 Bcf and estimated proved oil reserves totaled 56.6 MMBbls at the end of 2004. The reserve estimates were determined by independent petroleum consultants in accordance with guidelines established by the SEC.

     Our standardized measure of discounted future net cash flows was $1.9 billion and $1.8 billion at December 31, 2004 and 2003, respectively. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine these estimates of 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 $41.14 per barrel and $6.58 per Mcf for 2004 and $31.79 per barrel and $6.30 per Mcf for 2003.

     2003 Compared to 2002. 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.

     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:

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     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 lease operating expenses, including maintenance costs, of $72.8 million, compared to $76.7 million incurred during 2002. On a unit of production basis, 2003 lease operating expenses were $0.75 per Mcfe as compared to $0.73 per Mcfe for 2002. Maintenance costs, which represent 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 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 8³/4% 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.

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     Our standardized measure of discounted future net cash flows before income taxes was $1.8 billion and $1.4 billion at December 31, 2003 and 2002, respectively. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine these estimates of 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.

Liquidity and Capital Resources

     Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $369.5 million during 2004 compared to $391.5 million and $222.9 million in 2003 and 2002, respectively. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2005 capital expenditures with cash flow provided by operating activities.

     Net cash flow used in investing activities totaled $475.0 million, $341.9 million and $216.6 million during 2004, 2003 and 2002, respectively, which primarily represents our investment in oil and gas properties.

     Net cash flow provided by (used in) financing activities totaled $112.6 million, ($60.1) million and $8.1 million for the years ended December 31, 2004, 2003 and 2002, respectively. Net cash flow provided by financing activities generated during 2004 primarily relates to the proceeds from our 6³/4% Senior Subordinated Notes offering offset in part by the use of offering proceeds to repay borrowings under our bank credit facility. Net cash flow used in financing activities during 2003 was the result of the $61.0 million of repayments under the amended credit facility. As a result of these activities, cash and cash equivalents increased from $17.1 million as of December 31, 2003 to $24.3 million as of December 31, 2004.

     We had a working capital deficit at December 31, 2004 of $28.6 million. Working capital deficits are not unusual at the end of a period, and are usually the result of accounts payable related to ongoing exploration and development activity. 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 2004 totaled $521.9 million and included $201.5 million of acquisitions cost, $20.0 million of asset retirement costs and adjustments associated with SFAS No. 143, $16.0 million of capitalized salaries, general and administrative costs, net of overhead reimbursements, and $7.7 million of capitalized interest. These investments were funded by cash flows provided by operating activities, borrowings under our bank credit facility and working capital.

     Our 2005 capital expenditures budget, excluding acquisitions and capitalized interest and general and administrative expenses, is approximately $315 million, or 14% higher than our 2004 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 fund our 2005 capital program with cash flow provided by operating activities.

     To the extent that 2005 cash flow from operating activities exceeds our estimated 2005 capital expenditures, we may pay down a portion of our existing debt. If cash flow from operating activities during 2005 is not sufficient to fund estimated 2005 capital expenditures, we believe that our bank credit facility will provide us with adequate liquidity.

     We do not budget acquisitions; however, we are continually evaluating opportunities that fit our specific acquisition profile. See “Item 1. Business – Strategy and Operational Overview.” Any one or a combination of certain of these possible transactions could fully utilize our existing sources of capital. Although we have no current 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 parental guarantees 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. See “Item 1. Business – Risk Factors.”

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     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. See “Item 1. Business – Risk Factors.”

     Bank Credit Facility. At March 1, 2005, we had $158.0 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 $400 million, with availability of an additional $228.9 million in borrowings as of March 1, 2005. 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 estimated proved oil and gas reserves.

     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 $599 million, which is adjusted for future earnings and cash proceeds from equity offerings after December 31, 2003. 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.”

Off-Balance Sheet Arrangements

     We have no off-balance sheet arrangements.

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, 2004.

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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 was 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 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 that is calculated based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. During 2004, 2003 and 2002, we capitalized interest costs of $7.7 million, $8.6 million, and $8.5 million, respectively. We also capitalize the portion of salaries, general and administrative expenses that are attributable to our acquisition, exploration and development activities. During 2004, 2003 and 2002, we capitalized salaries, general and administrative costs, net of overhead reimbursements, of $16.0 million, $14.2 million, and $10.5 million, respectively.

     Generally accepted accounting principles allow the option 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, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs.

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     Under the full cost method of accounting, we are required to compare, at the end of each financial reporting period, 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. On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment, which is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 (R) supersedes Accounting Pronouncement Bulletin (APB) No. 25, Accounting for Stock Issued to Employees, and amends FASB No. 95, Statement of Cash Flows. Generally, the approach in SFAS No. 123 (R) is similar to the approach described in SFAS No. 123; however, SFAS No. 123 (R) requires all share-based payments to employees, including grants of employee stock options, be recognized in the income statement based on their fair values. Pro forma disclosure will no longer be an alternative.

     SFAS No. 123 (R) permits public companies to adopt its requirements using one of two methods:

	1.	A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of Statement 123 (R) for all share-based payments granted after the effective date and (b) based on the requirements of Statement 123 for all awards granted to employees prior to the effective date of Statement 123 (R) that remain unvested on the effective date.
	2.	A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under Statement 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

     SFAS No. 123 (R) must be adopted no later than July 1, 2005. We expect to adopt SFAS No. 123 (R) on July 1, 2005 using the modified prospective method. 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. It is currently not known whether the implementation of this proposed Standard would result in financial results materially different from those presented.

     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, 2004, we had a net deferred tax liability of $198.1 million, which 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, we estimate our diluted net income per share would have declined approximately 26%. Assuming the costs to operate our properties, including lease operating expenses, including maintenance cost, increased 10%, we estimate our diluted earnings per share would have declined approximately 5%. 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 provided by 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. During 2004, we realized a net decrease in revenue from our hedging transactions of $10.1 million. Our contracts totaled 2,513 MBbls of oil and 38,430 BBtus of natural gas, which represented approximately 46% and 73%, respectively, of our total oil and gas production during 2004. We realized a net decrease in revenue during 2003 from our hedging contracts of $1.6 million. During 2003, we hedged 37,775 BBtus of natural gas, which represented approximately 60% of our natural 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 natural gas, which represented approximately 68% and 37%, respectively, of our oil and gas production for the year.

     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.

     Derivative expenses incurred during 2004 totaled $4.1 million, which relates to the amortization of the historical cost associated with put contracts that settled during the year. During 2003, we recognized $8.7 million of derivative expenses, of which $5.1 million was associated with the costs of put contracts that settled during the year. The remaining $3.6 million of derivative expense for 2003 related to amortization of other comprehensive loss from the Enron swap.

     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 New York Mercantile Exchange (“NYMEX”) futures contracts for the three days prior to the settlement date.

     Stone has entered into zero-premium collars with various counterparties for a portion of our expected 2005 oil and natural gas production from the Gulf Coast Basin. The natural gas collar settlements are based on an average of NYMEX prices for the last three days of a respective month. The oil collar settlements are based upon an average of the NYMEX closing price for West Texas Intermediate (“WTI”) during the entire calendar month. The contracts require payments to the counterparties if the average price is above the ceiling price or payment from the counterparties if the average price is below the floor price. We utilized fixed-price swaps to hedge a portion of our future gas production from the Rocky Mountains. 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. Settlements under the collar contracts are realized in oil and gas revenue.

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     The following tables show our hedging positions as of March 3, 2005:

     Interest Rate Risk

     Stone had long-term debt outstanding of $482.0 million at December 31, 2004, of which $400.0 million, or approximately 83%, bears interest at fixed rates. The $400.0 million of fixed-rate debt is comprised of $200.0 million of 8¹/4% senior subordinated notes due 2011 and $200.0 million of 6³/4% senior subordinated notes due 2014. The remaining $82.0 million of debt outstanding at December 31, 2004 bears interest at a floating rate under our bank credit facility. At December 31, 2004, the weighted average interest rate under our floating-rate debt was approximately 3.8%. At December 31, 2004, 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 2004, our interest expense, net of capitalization, would have increased approximately $1.9 million, net of taxes, resulting in a $0.02 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, 2004. At December 31, 2004, the fair value of the 8¹/4% senior subordinated notes due 2011 and 6³/4% senior subordinated notes due 2014 totaled $216.5 million and $198.5 million, respectively. The fair value of the Notes has been estimated based on quotes from brokers. Our zero-premium collar 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 registered public accounting firm on our accounting or financial reporting that would require our independent registered public accounting firm 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.

Management’s Report on Internal Control Over Financial Reporting

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control – Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2004. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders of
Stone Energy Corporation:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Stone Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Stone Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Stone Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Stone Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Stone Energy Corporation as of December 31, 2004 and 2003, and the related consolidated statement of income, cash flows, changes in stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2004 of Stone Energy Corporation and our report dated March 4, 2005, expressed an unqualified opinion thereon.

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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, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

     There was no information required to be reported on a current report on Form 8-K during the quarterly period ended December 31, 2004 that was not reported on a Form 8-K and otherwise required by this annual report on Form 10-K.

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 2005 Annual Meeting of Stockholders to be held on May 18, 2005. 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 2005 Annual Meeting of Stockholders to be held on May 18, 2005.

     The information required by Item 12 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2005 Annual Meeting of Stockholders to be held on May 18, 2005.

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 2005 Annual Meeting of Stockholders to be held on May 18, 2005.

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 2005 Annual Meeting of Stockholders to be held on May 18, 2005.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements:

The following consolidated financial statements, notes to the consolidated financial statements and the Report of Independent Registered Public Accounting Firm thereon are included beginning on pages F-1 of this Form 10-K:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheet as of December 31, 2004 and 2003

Consolidated Statement of Income for the three years in the period ended December 31, 2004

Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2004

Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period ended December 31, 2004

Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2004

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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34

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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 REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders of
Stone Energy Corporation:

We have audited the accompanying consolidated balance sheet of Stone Energy Corporation (a Delaware corporation) as of December 31, 2004 and 2003, and the related consolidated statement of income, cash flows, changes in stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2004. 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 the standards of the Public Company Accounting Oversight Board (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, 2004 and 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, 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.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Stone Energy Corporation’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 4, 2005, expressed an unqualified opinion thereon.

F-2

STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Amounts in thousands of dollars, except per share amounts)

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

F-3

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

The accompanying notes are an integral part of this statement.

F-4

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Amounts in thousands of dollars)