UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

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

Commission File Number: 1-12074

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

State or other jurisdiction of incorporation or organization: Delaware		I.R.S. Employer Identification No. 72-1235413

625 E. Kaliste Saloom Road Lafayette, Louisiana (Address of principal executive offices)		70508 (Zip Code)

Registrant’s telephone number, including area code: (337) 237-0410

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

Title of each class		Name of each exchange on which registered
Common Stock, Par Value $.01 Per Share		New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þ Yes o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes þ No

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 whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o 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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes þ No

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $471,997,324 as of June 30, 2010 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of February 22, 2011, the registrant had outstanding 49,009,409 shares of Common Stock, par value $.01 per share.

Documents incorporated by reference: Portions of the Definitive Proxy Statement of Stone Energy Corporation relating to the Annual Meeting of Stockholders to be held on May 20, 2011 are incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

		Page No.
PART I
Item 1. Business			3
Item 1A. Risk Factors			9
Item 1B. Unresolved Staff Comments			18
Item 2. Properties			18
Item 3. Legal Proceedings			23
Item 4. (Removed and Reserved)			23
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			24
Item 6. Selected Financial Data			26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			38
Item 8. Financial Statements and Supplementary Data			39
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			39
Item 9A. Controls and Procedures			39
Item 9B. Other Information			41
PART III
Item 10. Directors, Executive Officers and Corporate Governance			41
Item 11. Executive Compensation			42
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			42
Item 13. Certain Relationships and Related Transactions, and Director Independence			42
Item 14. Principal Accounting Fees and Services			42
PART IV
Item 15. Exhibits and Financial Statement Schedules			43
Index to Financial Statements			F-1
Glossary of Certain Industry Terms			G-1
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-99.1

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 and its consolidated subsidiaries. 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 natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties located primarily in the Gulf of Mexico (“GOM”). We have been operating in the Gulf Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. More recently, we have made strategic investments in the deep water and deep shelf GOM, which we have targeted as an important exploration area. We are also active in the Appalachia region, where we have established a significant acreage position and have development operations in the Marcellus Shale. We have also targeted several exploratory oil projects in the Rocky Mountain region. As of December 31, 2010, our estimated proved oil and natural gas reserves were approximately 473.9 Bcfe. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana.

Strategy and Operational Overview

     Our business strategy is to leverage high cash flow generated from existing assets to maintain relatively stable GOM shelf production, profitably grow gas reserves and production rates in price-advantaged basins such as Appalachia and the Gulf Coast Basin, and profitably grow oil reserves and production rates in material impact areas such as the deep water GOM and the Rocky Mountain region.

     Gulf of Mexico — Conventional Shelf (Including Onshore Louisiana)

     Our conventional shelf strategy is to apply the latest geophysical interpretation tools to identify underdeveloped properties and the latest production techniques to increase production attributable to these properties. 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/ Deep Shelf

     We believe that the deep water of the GOM is an important exploration area, even though it involves high risk, high costs and substantial lead time to develop infrastructure. We have made a significant investment in seismic data and leasehold interests and have assembled a technical team with prior geological, geophysical and engineering experience in the deep water arena to evaluate potential opportunities.

     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 usually with existing infrastructure, which shortens the lead time to production.

     Appalachia

     During 2006, we began securing leasehold interests in the Appalachia regions of Pennsylvania and West Virginia. As of February 22, 2011, we have secured leasehold interests in approximately 79,000 net acres. During 2010, we successfully drilled 15 operated horizontal wells. We expect to add leasehold interests and drill additional wells to further expand our interests in Appalachia.

     Rocky Mountain Region

     We maintain working interests in several undeveloped plays in the Rocky Mountain region, which totaled approximately 92,000 net acres as of February 22, 2011. In December 2010, drilling operations on an exploration well in the Paradox Basin were finished, and the well is currently being tested. A second horizontal exploration well started drilling in January 2011.

Oil and Gas Marketing

     Our oil and natural gas production is sold at current market prices under short-term contracts. Shell Trading (US) Company, Conoco, Inc., Sequent Energy Management LP and Hess Corporation each accounted for between 10% — 40% of our oil and natural gas revenue generated during the year ended December 31, 2010. No other purchaser accounted for 10% or more of our total oil and natural gas revenue during 2010. We do not believe that the loss of any of our major purchasers would 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.”

Competition and Markets

     Competition in the Gulf Coast Basin, the deep water and deep shelf GOM, the Appalachia region and the Rocky Mountain region 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 “Item 1A. 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 oil and 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 oil and natural gas. In addition, the restructuring of the natural gas pipeline industry 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 of the states where we conduct operations 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 Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”), the successor agency to the Minerals Management Service. These leases contain relatively standardized terms and require compliance with detailed BLM and BOEMRE regulations and orders pursuant to various federal laws, including the Outer Continental Shelf Lands Act (the “OCSLA”) (which are subject to change by the applicable agency). 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 BOEMRE 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 U.S. Environmental Protection Agency, the (“EPA”)), lessees must obtain a permit from the BLM or the BOEMRE, 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 the 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 BOEMRE generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEMRE 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 BOEMRE, 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.

     Natural Gas. In 2005, the U.S. Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Stone Energy, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission (“FERC”), in contravention of rules prescribed by the FERC. In 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. The Commodities Futures Trading Commission (“CFTC”) has similar authority with respect to energy futures commodity markets. Stone Energy does not anticipate it will be affected any differently than other producers of natural gas.

     In 2007, the FERC issued rules (“Order 704”) requiring that any market participant, including a producer such as Stone Energy, that engages in sales for resale or purchases for resale of natural gas that equal or exceed 2.2 million MMBtus during a calendar year to annually report such sales or purchases to the FERC, beginning on May 1, 2009. These rules are intended to increase the transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets and in detecting market manipulation. The monitoring and reporting required by these rules have increased our administrative costs. Stone Energy does not anticipate it will be affected any differently than other producers of natural gas.

     Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of FERC Order No. 636 require that interstate pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas supplies. In many instances, the results of FERC Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Similarly, the natural gas pipeline industry is also subject to state regulations, which may change from time to time in ways that affect the availability, terms, and cost of transportation. However, we do not believe that any such changes would affect our business in a way that would be materially different from the way such changes would affect our competitors.

     Oil. Effective November 4, 2009, pursuant to the Energy Independence and Security Act of 2007, the Federal Trade Commission (“FTC”) issued a rule prohibiting market manipulation in the petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from knowingly engaging in any act, practice, or course of business, including the making of any untrue statement of material fact, that operates or would operate as a fraud or deceit upon any person, or intentionally failing to state a material fact that under the circumstances renders a statement made by such person misleading, provided that such omission distorts or is likely to distort market conditions for any such product. A violation of this rule may result in civil penalties of up to $1,000,000 per day per violation, in addition to any applicable penalty under the Federal Trade Commission Act.

     Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are transacted at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids, and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase.

     In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. As it relates to intrastate crude oil, condensate and natural gas liquids pipelines, state regulation is generally less rigorous than the federal regulation of interstate pipelines. State

agencies have generally not investigated or challenged existing or proposed rates in the absence of shipper complaints or protests, which are infrequent and are usually resolved informally.

     We do not believe that the regulatory decisions or activities relating to interstate or intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that materially differs from the way it affects other crude oil, condensate and natural gas liquids producers or marketers.

     Miscellaneous. Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by the U.S. Congress, states, the FERC and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the oil and natural gas industry has been heavily regulated. We can give no assurance that the regulatory approach currently pursued by the FERC or any other agency 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.

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 require the acquisition of permits authorizing air emissions and wastewater discharge from operations and 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 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 hydrocarbons or wastes have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and 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 environmental contamination, or to perform remedial plugging or pit closure to prevent future contamination.

     Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) and regulations adopted pursuant to OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the OCS. The OPA subjects owners of oil handling facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages. Although defenses exist to the liability imposed by OPA, they are limited. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

     Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (“CAA”). The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

     In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major

producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

     The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

     Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

     We have made, and will continue to make, expenditures in our effort to comply with environmental laws and regulations. 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. However, we also believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards and, thus, 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 to cover a portion of 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 February 22, 2011, we had 331 full time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. We utilize the services of independent contractors to perform various daily operational duties.

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, which have been approved by our board of directors. We will make timely 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. A copy of our Code of Business Conduct and Ethics is also available, free of charge by

writing us at: Chief Financial Officer, Stone Energy Corporation, P.O. Box 52807, Lafayette, LA 70505. The annual CEO certification required by Section 303A.12 of the New York Stock Exchange Listed Company Manual was submitted on February 17, 2010.

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 current 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 and government inquiry;
	•		estimates of the impact of new accounting pronouncements on earnings in future periods;
	•		our future financial condition or results of operations and our future revenues and expenses;
	•		our access to capital and our anticipated liquidity;
	•		estimates of future income taxes; and
	•		our business strategy and other plans and objectives for future operations.

     We caution you that these forward-looking statements are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and marketing of oil and natural gas. These risks include, among other things:

	•		consequences of the Deepwater Horizon oil spill and resulting stringent regulatory requirements;
	•		commodity price volatility;
	•		domestic and worldwide economic conditions;
	•		the availability of capital on economic terms to fund our capital expenditures and acquisitions;
	•		our level of indebtedness;
	•		declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and ceiling test write-downs and impairments;
	•		our ability to replace and sustain production;
	•		the impact of a financial crisis on our business operations, financial condition and ability to raise capital;
	•		the ability of financial counterparties to perform or fulfill their obligations under existing agreements;
	•		third party interruption of sales to market;
	•		lack of availability and cost of goods and services;
	•		regulatory and environmental risks associated with drilling and production activities;
	•		drilling and other operating risks;
	•		unsuccessful exploration and development drilling activities;
	•		hurricanes and other weather conditions;
	•		the adverse effects of changes in applicable tax, environmental, derivatives and other regulatory legislation, including changes affecting our offshore and Appalachian operations;
	•		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.

     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.

ITEM 1A. RISK FACTORS

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

BP’s Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable.

     In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the Gulf of Mexico. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the BOEMRE issued a series of notices to lessees and operators implementing a six-month moratorium on drilling activities in federal offshore waters and imposing a variety of new safety measures and permitting requirements.

     In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico more difficult, more time consuming, and more costly. For example, OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. If we are unable to provide the level of financial assurance required by OPA, we may be forced to sell our properties or operations located on the OCS or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased.

New regulatory requirements and permitting procedures recently imposed by the Bureau of Ocean Energy Management, Regulation and Enforcement could significantly delay our ability to obtain permits to drill new wells in offshore waters.

     Subsequent to the BP Deepwater Horizon incident in the U.S. Gulf of Mexico, the BOEMRE issued a series of “Notice to Lessees” (“NTLs”) imposing new regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These new regulatory requirements include the following:

	•		The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.
	•		The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.
	•		The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.
	•		The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

     Since the adoption of these new regulatory requirements, BOEMRE has been taking much longer to review and approve permits for new wells. Due to the extremely slow pace of permit review and approval, various industry sources have determined that BOEMRE may take six months or longer to approve applications for drilling permits that were previously approved in less than 30 days. The new rules also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper waters on the OCS.

Oil and natural gas prices are volatile. Declines in commodity prices have adversely affected, and in the future may adversely affect, our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.

     Our revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flow available for capital expenditures and our ability to access funds under our bank credit facility and through the capital markets. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. If commodity prices decline in the future, the decline could have adverse effects on our reserves and borrowing base.

     The prices we receive for our oil and natural gas depend upon factors beyond our control, including among others:

	•		changes in the supply of and demand for oil and natural gas;
	•		market uncertainty;
	•		the level of consumer product demands;
	•		hurricanes and other weather conditions;
	•		domestic governmental regulations and taxes;
	•		the price and availability of alternative fuels;
	•		political and economic conditions in oil producing countries, particularly those in the Middle East, Russia, South America and Africa;
	•		actions by the Organization of Petroleum Exporting Countries (“OPEC”);
	•		the foreign supply of oil and natural gas;
	•		the price of oil and gas imports; and
	•		overall domestic and foreign economic conditions.

     These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

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. Approximately 83% of our estimated proved reserves at December 31, 2010 and 99.5% of our production during 2010 were associated with our Gulf Coast Basin properties. 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 at a unit cost that is sustainable at prevailing commodity prices.

     Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot assure you that our future exploitation, exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs.

Our actual recovery of reserves may substantially differ from our proved reserve estimates.

     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 and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

     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.

     You should not assume that any present value of future net cash flows from our producing reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2010 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2010, approximately 31% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary 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. 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 redetermined 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.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations are almost exclusively in the Gulf of Mexico.

     We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the GOM is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the GOM, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

     In addition, the BOEMRE recently issued a NTL dated to be effective October 15, 2010 that establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron” — wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease — in the GOM. Historically, many oil and natural gas producers in the GOM have delayed the plugging, abandoning or removal of such idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The determination of productive lease termination dates are generally based on management’s estimate as to when it would become likely that production, including from future development activities, would cease on the lease. The recently issued NTL, however, sets forth more stringent standards for decommissioning timing requirements — any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. Triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. In addition, the potential increase in decommissioning activity in the GOM over the next few years as a result of the NTL could likely result in increased demand for salvage contractors and equipment, resulting in increased estimates of plugging, abandonment and removal costs and increases in related asset retirement

obligations. For additional information about our asset retirement obligations, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Known Trends and Uncertainties — Asset Retirement Obligations.”

A financial crisis may impact our business and financial condition. A financial crisis may adversely impact our ability to obtain funding under our current bank credit facility or in the capital markets.

     The credit crisis and related turmoil in the global financial systems had an impact on our business and our financial condition. An economic crisis could reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas. Historically, we have used our cash flow from operations and borrowings under our bank credit facility to fund our capital expenditures and have relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. In the future, we may not be able to access adequate funding under our bank credit facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, an increased counterparty credit risk on our derivatives contracts and the requirement by contractual counterparties of us to post collateral guaranteeing performance.

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

     The terms of the current 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 current and future 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 is 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 our bank credit facility, which is redetermined semi-annually, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values. Our borrowing base is scheduled to be redetermined by May 2011. Upon a redetermination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to repay a portion of our bank debt.

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

and our market value and operating performance at the time of such offering, refinancing or sale of assets. We cannot assure you that any such offering, refinancing or sale of assets can be successfully completed.

We have experienced significant shut-ins and losses of production due to the effects of hurricanes in the Gulf of Mexico.

     Approximately 83% of our estimated proved reserves at December 31, 2010 and 99.5% of our production during 2010 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. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the Gulf of Mexico. During 2009 and 2008, we experienced production deferrals due to Hurricanes Gustav and Ike. During 2007, 2006 and 2005, we experienced production deferrals due to Hurricanes Katrina and Rita, and during 2004, we experienced production deferrals due to Hurricane Ivan. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production.

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

     The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural 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. The tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by customers. We are unable to predict, however, what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.

     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 the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a 12-month average hedge adjusted commodity price and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, 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 estimated discounted future net cash flows. A write-down of oil and gas properties does not impact cash flow from operating activities, but does reduce net income. We also assess the carrying amount of goodwill when events occur that may indicate an impairment exists. These events include, for example, a significant decline in oil and gas prices or a decline in our market capitalization. We recorded an impairment of all our goodwill of approximately $466 million for the year ended December 31, 2008. The risk that we will be required to write down the carrying value of oil and gas properties and goodwill 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 or our undeveloped property values, or if estimated future development costs increase. For example, oil and natural gas prices declined significantly throughout the second half of 2008 and into 2009. We recorded a non-cash ceiling test impairment of approximately $1.3 billion for the year ended December 31, 2008 and approximately $509.0 million for the year ended December 31, 2009. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future and incur additional charges against future earnings.

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.

Part of our strategy includes drilling in new or emerging plays. As a result, our drilling in these areas is subject to greater risk and uncertainty.

     We have made initial investments in acreage and wells in Appalachia and in the Rocky Mountain region. These activities are more uncertain than drilling in areas that are developed and have established production. Our operations in Appalachia and in the Rocky Mountain region are still in the early stages. Because emerging plays and new formations have limited or no production history, we are less able to use past drilling results to help predict future results. The lack of historical information may result in not being able to fully execute our expected drilling programs in these areas or the return on investment in these areas may turn out not to be as attractive as anticipated. We cannot assure you that our future drilling activities in these emerging plays will be successful, or if successful will achieve the resource potential levels that we currently anticipate based on the drilling activities that have been completed or achieve the anticipated economic returns based on our current cost models.

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 reserves 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;
	•		hurricanes and other 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. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions, including the effects of hurricanes.

     We have begun to explore for natural gas and oil in the deep waters of the GOM (water depths greater than 2,000 feet) where operations are more difficult and more expensive 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 GOM 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.

     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.

We may not be insured against all of the operating risks to which our business in exposed.

     In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of wells, oil pollution, third party liability, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages and losses.

     Currently, we have general liability insurance coverage with an annual aggregate limit of up to $75 million applicable to our working interest. We also have an offshore property physical damage policy that contains a $75 million annual aggregate named windstorm limit. Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $10 million to $150 million per occurrence. Exploratory deep water wells have a coverage limit of $300 million per occurrence. Additionally, we maintain $35 million in oil pollution liability coverage. Our control of well and oil pollution liability policy limits are scaled proportionately to our working interests, and all of our policies described above are subject to deductibles, sub-limits and/or self-insurance. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

     An operational or hurricane related event may cause damage or liability in excess of our coverage, which might severely impact our financial position. We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event may also cause a significant interruption to our business, which might also severely impact our financial position. For example, we experienced production interruptions in 2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance.

     We reevaluate the purchase of insurance, policy limits and terms annually each May. In light of the recent catastrophic accident in the GOM, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the GOM, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

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

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

Competition within our industry may adversely affect our operations.

     Competition in the Gulf Coast Basin, the Appalachia region and the Rocky Mountain region 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 into 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 the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and Resource Conservation and Recovery Act (“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 key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. 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 or become ineffective.

     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 New York Mercantile Exchange (“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 or is shut-in for extended periods due to hurricanes or other factors;
	•		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;
	•		a sudden, unexpected event materially impacts oil or natural gas prices; or
	•		we are unable to market our production in a manner contemplated when entering into the hedge contract.

     Currently, some of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our bank credit facility. Our existing derivative agreements with our lenders are secured by the security documents executed by the parties under our bank credit facility. Future collateral requirements for our commodity hedging activities are uncertain and will depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.

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 and Bylaws 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 board of directors are elected by plurality voting. 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, 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.

Resolution of litigation could materially affect our financial position and results of operations.

     We have been named as a defendant in certain lawsuits (See “Item 3. Legal Proceedings”). In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

     Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. Federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively impact the value of an investment in our common stock.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

     In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.

     In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

     The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

     The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. It is not possible to predict when the CFTC will finalize these regulations. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells.

     Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. We routinely use hydraulic fracturing techniques in many of our natural gas wells drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program. While the EPA has yet to take any action to enforce or implement this newly asserted regulatory authority, industry groups have filed suit challenging the EPA’s recent decision. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well construction, set back, and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

     As of February 22, 2011, our property portfolio consisted of 65 active properties and 102 primary term leases in the Gulf Coast Basin, five active properties in the Appalachia region, and two active properties in the Rocky Mountain region. We serve as operator on 76% of our active properties. The properties that we operate accounted for 90.2% of our year-end 2010 estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities.

Oil and Natural Gas Reserves

     In December 2008, the SEC issued a final rule, “Modernization of Oil and Gas Reporting,” which adopted revisions to the SEC’s oil and gas reporting requirements. Among other things, the revisions: (1) replaced the single-day year-end pricing with a twelve-month average pricing assumption; (2) permit the reporting of probable and possible reserves in addition to the existing requirement to disclose proved reserves; (3) allow the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; (4) require the disclosure of the independence and qualifications of third party preparers of reserves; and (5) require the filing of reports when a third party is relied upon to prepare or audit reserve estimates. We were required to adopt the provisions of the new rule as of December 31, 2009.

     Our Reserves Committee Charter provides that the reserves committee has the sole authority to recommend to the Board of Directors appointments or replacements of one or more firms of independent reservoir engineers and geoscientists. The reserves committee reviews annually the arrangements of the independent reservoir engineers and geoscientists with management, including the scope and general extent of the examination of our reserves, the reports to be rendered, the services and fees, and consideration of the independence of such independent reservoir engineers and geoscientists. The reserves committee may consult with management but may not delegate these responsibilities. The reserves committee provides oversight in regards to the reserve estimation process but not the actual determination of estimated proved reserves. Our Reserves Committee Charter provides that it is the duty of management and not the duty of the reserves committee to plan or conduct reviews or to determine that our reserve estimates are complete and accurate and are in accordance with generally accepted engineering standards and applicable rules and regulations of the SEC. Our Director of Strategic Planning is the in-house person designated as primarily responsible for the process of reserve preparation. He is a petroleum engineer with nineteen years experience in reservoir engineering and analysis. His duties include oversight of estimate preparation of non year-end quarterly estimations and coordination with the outside engineering consultants on the preparation of year-end reserve estimates. The year-end reserve estimates prepared by our outside engineering firm are independent of any oversight of the Director of Strategic Planning or the reserves committee.

     Estimates of our proved reserves at December 31, 2010 were prepared by Netherland, Sewell & Associates, Inc. (“NSA”), a nationally recognized engineering firm. NSA provides a complete range of geological, geophysical, petrophysical and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. NSA currently has a technical staff of approximately 70 professionals who are intimately familiar with recognized industry reserve and resource definitions, specifically those set forth by the SEC. NSA’s letter is filed as an exhibit to this Annual Report on Form 10-K.

     The following table sets forth our estimated proved oil and gas reserves (83% of which are located in the Gulf Coast Basin and 17% are located in the Appalachia region) as of December 31, 2010. The 2010 average 12-month oil and gas prices net of differentials were $77.68 per barrel of oil and $4.46 per Mcf of gas.

Summary of Oil and Gas Reserves as of December 31, 2010
Based on Average Fiscal-Year Prices

										Oil and
		Oil				Natural Gas				Natural Gas
		(MBbls)				(MMcf)				(MMcfe)
Reserves Category:
PROVED
Developed			25,000				174,876				324,876
Undeveloped			8,203				99,829				149,047
TOTAL PROVED			33,203				274,705				473,923

     At December 31, 2010, we reported estimated proved undeveloped reserves (“PUD’s”) of 149.0 Bcfe, which accounted for 31% of our total estimated proved oil and gas reserves. This figure ties to a projected 31 new wells (95.3 Bcfe) and 18 sidetracks from existing wellbores (53.7 Bcfe). Our timetable for the 18 sidetrack wells is totally dependent on the life of the currently producing zones. After the current zones have depleted, we would utilize the existing wellbore to sidetrack to the PUD objective. Regarding the remaining 31 PUD locations, we project eight wells to be drilled in 2011 (21.0 Bcfe); eleven wells in 2012 (40.8 Bcfe); ten wells in 2013 (28.6 Bcfe); and two wells in 2014 (4.9 Bcfe). None of these 31 PUD wells will have been on our books in excess of five years at the time of their scheduled drilling. The following table discloses our progress toward the conversion of PUD’s during 2010.

						Future Development
		Oil and Natural Gas				Costs
		(MMcfe)				($ in thousands)
PUD’s beginning of year			91,982			$	254,299
Revisions of previous estimates			(4,302	)			(8,970	)
Conversions to proved developed reserves			—				—
Additional PUD’s added			61,367				121,155
PUD’s end of year			149,047			$	366,484

     Our progress in 2010 towards the drilling of PUD wells was delayed due to permitting restrictions in the GOM. However, we did spud a PUD well in late 2010 that was completed in early 2011. This resulted in the conversion of approximately 4.2 Bcfe of previously booked PUD reserves to proved developed producing reserves in 2011.

     The following represents additional information on our significant properties:

December 31, 2010

2010

Estimated Proved

Production

Reserves

Nature of

Field Name

Location

(MMcfe)

(MMcfe)

Interest

Mississippi Canyon Block 109

GOM Shelf

10,019

87,038

Working

Ship Shoal Block 113

GOM Shelf

5,782

59,399

Working

Ewing Bank Block 305

GOM Shelf

6,176

27,796

Working

Mary

Appalachia

23

26,092

Working

Main Pass Block 288

GOM Shelf

3,374

20,308

Working

South Pelto Block 22

GOM Shelf

3,802

19,483

Working

     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 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. 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.

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 in the United States and China during the periods indicated. Certain amounts for 2008 have been corrected in the following table to reflect a change in our asset retirement obligations during that year.

		Year Ended December 31,
		2010				2009				2008
		(In thousands)
Acquisition costs, net of sales of unevaluated properties		$	127,069			$	9,072			$	1,830,468
Development costs (1)			241,387				199,375				78,359
Exploratory costs			42,205				78,582				146,529
Subtotal			410,661				287,029				2,055,356
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements			51,016				44,282				45,757
Total additions to oil and gas properties, net		$	461,677			$	331,311			$	2,101,113

     Production Volumes, Sales Price and Cost Data. The following table sets forth certain information regarding our production volumes, sales prices and average production costs for the periods indicated.

		Year Ended December 31,
		2010				2009				2008
Production:
Oil (MBbls)			5,714				6,207				4,916
Natural gas (MMcf)			41,937				41,335				34,409
Oil and natural gas (MMcfe)			76,221				78,577				63,903
Average sales prices: (1)
Oil (per Bbl)		$	73.14			$	70.72			$	93.79
Natural gas (per Mcf)			5.56				6.59				9.78
Oil and natural gas (per Mcfe)			8.54				9.05				12.48
Expenses (per Mcfe):
Lease operating expenses (2)		$	2.00			$	2.00			$	2.68

     Production Volumes, Sales Price and Cost Data for Individually Significant Fields. The following table sets forth certain information regarding our production volumes, sales prices and average production costs for the periods indicated for any field(s) containing 15% or more of our total estimated proved reserves at December 31, 2010.

		Year Ended December 31,
Mississippi Canyon Block 109		2010				2009				2008
Production:
Oil (MBbls)			1,389				861				1,035
Natural gas (MMcf)			1,686				1,092				1,700
Oil and natural gas (MMcfe)			10,019				6,256				7,913
Average sales prices: (1)
Oil (per Bbl)		$	77.29			$	66.68			$	107.96
Natural gas (per Mcf)			4.89				3.81				9.55
Oil and natural gas (per Mcfe)			11.54				9.86				16.18
Expenses (per Mcfe):
Lease operating expenses (2)		$	1.27			$	2.19			$	0.86

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

		Year Ended December 31,
		2010								2009								2008
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells:
Productive			6.00				4.10				12.00				6.75				6.00				3.50
Dry			—				—				—				—				6.00				3.98
Development Wells:
Productive			20.00				15.75				5.00				4.00				9.00				7.18
Dry			—				—				4.00				4.00				1.00				0.25

     During the period beginning January 1, 2011 and ending February 22, 2011, we participated in the drilling of five gross (2.89 net) exploratory wells and four gross (4.00 net) development wells.

     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, 2010.

		Gross				Net
Productive Wells:
Oil (1):
Gulf Coast Basin			153				119
Rocky Mountain Region			3				1
Appalachia			—				—
			156				120
Gas (2):
Gulf Coast Basin			105				79
Rocky Mountain Region			—				—
Appalachia			10				8
			115				87
Total			271				207
Developed Acres:
Gulf Coast Basin			440,195				338,856
Rocky Mountain Region			1,234				432
Appalachia			1,116				1,116
			442,545				340,404
Undeveloped Acres (3):
Gulf Coast Basin			528,656				377,609
Rocky Mountain Region			109,030				91,708
Appalachia			88,253				78,599
			725,939				547,916
Total			1,168,484				888,320

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

     Franchise Tax Action. On December 30, 2004, Stone was served with two petitions (civil action numbers 2004-6227 and 2004-6228) filed by the Louisiana Department of Revenue (“LDR”) in the 15th Judicial District Court (Parish of Lafayette, Louisiana) claiming additional franchise taxes due. In one case, the LDR is seeking additional franchise taxes from Stone in the amount of $640,000, plus accrued interest of $352,000 (calculated through December 15, 2004), for the franchise tax year 2001. In the other case, the LDR is seeking additional franchise taxes from Stone (as successor to Basin Exploration, Inc.) in the amount of $274,000, plus accrued interest of $159,000 (calculated through December 15, 2004), for the franchise tax years 1999, 2000 and 2001. On December 29, 2005, the LDR filed another petition in the 15^th Judicial District Court claiming additional franchise taxes due for the taxable years ended December 31, 2002 and 2003 in the amount of $2.6 million plus accrued interest calculated through December 15, 2005 in the amount of $1.2 million. Also, on January 2, 2008, Stone was served with a petition (civil action number 2007-6754) claiming $1.5 million of additional franchise taxes due for the 2004 franchise tax year, plus accrued interest of $800,000 calculated through November 30, 2007. Further, on January 7, 2009, Stone was served with a petition (civil action number 2008-7193) claiming additional franchise taxes due for the taxable years ended December 31, 2005 and 2006 in the amount of $4.0 million plus accrued interest calculated through October 21, 2008 in the amount of $1.7 million. In addition, we have received assessments from the LDR for additional franchise taxes in the amount of $2.9 million resulting from audits of a subsidiary. These assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the Outer Continental Shelf, which are transported through the State of Louisiana, should be sourced to the State of Louisiana for purposes of computing the Louisiana franchise tax apportionment ratio. The Company disagrees with these contentions and intends to vigorously defend itself against these claims. The franchise tax years 2007 through 2010 for Stone remain subject to examination.

     Ad Valorem Tax Suit. In August 2009, Gene P. Bonvillain, in his capacity as Assessor for the Parish of Terrebonne, State of Louisiana, filed civil action No. 90-03540 and other consolidated cases in the United States District Court for the Eastern District of Louisiana against approximately thirty oil and gas companies, including Stone, and their respective chief executive officers for allegedly unpaid ad valorem taxes. The amount originally alleged to be due by Stone for the years 1998 through 2008 was $11.3 million. The defendants were subsequently served and filed motions to dismiss this litigation pursuant to Rule 12(b)(6) of the Federal Rules of Civil Procedure. On March 29, 2010, the trial court judge dismissed plaintiff’s claims without prejudice, with the dismissal to become effective within ten days unless plaintiff filed an amended complaint correcting its deficiencies. On April 8, 2010, plaintiff filed a first amended complaint without naming any of the chief executive officers as defendants and with an amount allegedly due by Stone of “not less than” $3.5 million. Defendants filed motions to dismiss this litigation, and the trial court judge granted these motions to dismiss on July 26, 2010. Subsequently, Bonvillain appealed the dismissal, and the appeal is currently pending before the 5^th Circuit Court of Appeals. In its appellate brief, Bonvillain stated that its appeal against Stone “is hereby waived.” On January 26, 2011, an order was entered formally dismissing Stone from this appeal, and this matter is now concluded.

     Lafourche Parish, Louisiana, Landowner Action. In December 2008, Stephen E. Coignet, et al., filed civil action No. 110741 in the 17^th Judicial District Court, Lafourche Parish, Louisiana, against Stone. Plaintiffs have since filed three supplemental petitions, including a third supplemental and restated petition on October 25, 2010. Plaintiffs are landowners of approximately sixty acres that are subject to mineral leases in favor of Stone. Plaintiffs allege that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs in excess of $60 million. Plaintiffs’ expert witness provided his report, dated December 28, 2010, stating his opinion that one well did not produce as much production as it should have, resulting in a loss to plaintiffs “in excess of $4 million,” that imprudent operations destroyed hydrocarbon bearing zones resulting in a loss to plaintiffs “in excess of $20 million,” and that imprudent operation of a water injection secondary recovery project resulted in damages to plaintiffs of “approximately $4,755,000.” There are also allegations of failure to protect from drainage from a well on adjoining land, trespass, and various other breaches of the mineral leases. The Company disagrees with plaintiffs’ contentions and intends to vigorously defend itself against these claims.

     Litigation is subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of these matters and are unable to estimate a range of possible losses or any minimum loss from such matters.

ITEM 4. (REMOVED AND RESERVED)

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.

		High				Low
2009
First Quarter		$	13.73			$	1.55
Second Quarter			9.85				3.09
Third Quarter			18.43				5.83
Fourth Quarter			20.51				13.75
2010
First Quarter		$	19.76			$	14.12
Second Quarter			20.63				11.13
Third Quarter			15.19				10.30
Fourth Quarter			23.31				14.21
2011
First Quarter (through February 22, 2011)		$	27.21			$	21.28

     On February 22, 2011, the last reported sales price on the New York Stock Exchange Composite Tape was $26.00 per share. As of that date, there were 406 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 indentures executed in connection with our 6³/4% Senior Subordinated Notes due 2014 and our 8⁵/8% Senior Notes due 2017. In addition, our bank credit facility contains provisions that may have the effect of limiting or prohibiting the payment of dividends.

Issuer Purchases of Equity Securities

     On September 24, 2007, our Board of Directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. Additionally, shares were withheld from certain employees to pay taxes associated with the employees’ vesting of restricted stock. The following table sets forth information regarding our repurchases or acquisitions of common stock during the fourth quarter of 2010:

														Maximum Number (or
										Total Number of				Approximate Dollar
										Shares (or Units)				Value) of Shares
										Purchased as Part				(or Units) that May
		Total Number of								of Publicly				Yet be Purchased
		Shares (or Units)				Average Price Paid				Announced Plans or				Under the Plans or
Period		Purchased				per Share (or Unit)				Programs				Programs
Share Repurchase Program:
October 2010			—				—				—
November 2010			—				—				—
December 2010			—				—				—
			—				—				—			$	92,928,632
Other:
October 2010			378	(a)		$	14.91				—
November 2010			—				—				—
December 2010			—				—				—
			378			$	14.91				—				N/A
Total			378			$	14.91				—

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.

Stock Performance Graph

     As required by applicable rules of the Securities and Exchange Commission (“SEC”), the performance graph shown below was prepared based upon the following assumptions:

	1.		$100 was invested in the Company’s Common Stock, the S&P 500 Index and the Peer Groups (as defined below) on December 31, 2005 at $45.53 per share for the Company’s Common Stock and at the closing price of the stocks comprising the S&P 500 Index and the Peer Groups, respectively, on such date.
	2.		Peer Group investment is weighted based upon the market capitalization of each individual company within the Peer Group at the beginning of the period.
	3.		Dividends are reinvested on the ex-dividend dates.

Measurement Period														S&P 500
(Fiscal Year Covered)		SGY				2010 Peer Group				2009 Peer Group				Index
12/31/06			77.64				99.35				98.12				115.79
12/31/07			103.03				110.24				104.95				122.16
12/31/08			24.20				41.00				39.32				76.96
12/31/09			39.64				68.62				65.52				97.33
12/31/10			48.96				105.30				102.21				111.99

     The companies that comprised our Peer Group in 2010 were: ATP Oil & Gas Corporation, Carrizo Oil & Gas, Inc., Energy Partners, Ltd., Energy XXI (Bermuda) Limited, Mariner Energy Inc., McMoRan Exploration Company, Newfield Exploration Company, PetroQuest Energy, Inc., Swift Energy Company, and W&T Offshore, Inc. Callon Petroleum Company was removed from the Peer Group and was replaced by Carrizo Oil & Gas, Inc. in 2010 due to its more comparable size, focus areas and market capitalization with the other members of the Peer Group.

     The information in this Form 10-K appearing under the heading “Stock Performance Graph” is being “furnished” pursuant to Item 2.01(e) of Regulation S-K under the Securities Act of 1933, as amended, and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

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, 2010. This information is derived from our Consolidated 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.” The information included in this table for the years ended December 31, 2009 and 2008 includes the effects of corrections on the previously reported financial statements, as further discussed in “Item 8. Financial Statements and Supplementary Data — Note 2.”

		Year Ended December 31,
		2010				2009				2008				2007				2006
						(In thousands, except per share amounts)
Statement of Operations Data:
Operating revenue:
Oil production		$	417,948			$	438,942			$	461,050			$	424,205			$	348,979
Gas production			233,055				272,353				336,665				329,047				337,321
Derivative income, net			3,265				3,061				3,327				—				2,688
Total operating revenue			654,268				714,356				801,042				753,252				688,988
Operating expenses:
Lease operating expenses			152,326				156,786				171,107				149,702				159,043
Other operational expense			5,450				2,400				—				—				—
Production taxes			5,808				7,920				7,990				9,945				13,472
Depreciation, depletion and amortization			248,201				259,639				288,384				302,739				320,696
Write-down of oil and gas properties			—				508,989				1,324,327				8,164				510,013
Goodwill impairment			—				—				465,985				—				—
Accretion expense			34,469				39,306				17,392				17,620				12,391
Salaries, general and administrative expenses			42,759				41,367				43,504				33,584				34,266
Incentive compensation expense			5,888				6,402				2,315				5,117				4,356
Impairment of inventory			129				9,398				—				—				—
Derivative expenses, net			—				—				—				666				—
Total operating expenses			495,030				1,032,207				2,321,004				527,537				1,054,237
Gain on Rocky Mountain Region properties divestiture			—				—				—				59,825				—
Income (loss) from operations			159,238				(317,851	)			(1,519,962	)			285,540				(365,249	)
Other (income) expenses:
Interest expense			12,192				21,361				13,243				32,068				35,931
Interest income			(1,464	)			(528	)			(11,250	)			(12,135	)			(2,524	)
Other income, net			(6,021	)			(3,854	)			(5,800	)			(5,657	)			(4,657	)
Merger expense reimbursement			—				—				—				—				(51,500	)
Merger expenses			—				—				—				—				50,029
Loss on early extinguishment of debt			1,820				—				—				844				—
Total other (income) expenses, net			6,527				16,979				(3,807	)			15,120				27,279
Net income (loss) before income taxes			152,711				(334,830	)			(1,516,155	)			270,420				(392,528	)
Income tax provision (benefit)			56,282				(116,559	)			(369,146	)			88,984				(138,306	)
Net income (loss)			96,429				(218,271	)			(1,147,009	)			181,436				(254,222	)
Net income (loss) attributable to non-controlling interest			—				27				(77	)			—				—
Net income (loss) attributable to Stone Energy Corp.		$	96,429				($218,298	)			($1,146,932	)		$	181,436				($254,222	)
Earnings and dividends per common share:
Basic earnings (loss) per share		$	1.99				($4.97	)			($35.89	)		$	6.50				($9.29	)
Diluted earnings (loss) per share		$	1.99				($4.97	)			($35.89	)		$	6.49				($9.29	)
Cash dividends declared			—				—				—				—				—
Cash Flow Data:
Net cash provided by operating activities		$	424,794			$	507,787			$	522,478			$	465,158			$	399,035
Net cash provided by (used in) investing activities			(374,088	)			(316,079	)			(1,357,907	)			344,812				(660,456	)
Net cash provided by (used in) financing activities			(13,043	)			(190,552	)			428,440				(393,706	)			240,575
Balance Sheet Data (at end of period):
Working capital		$	30,382			$	26,137			$	123,339			$	412,445			$	1,845
Oil and gas properties, net			1,397,809				1,185,709				1,628,170				1,181,312				1,784,425
Total assets			1,679,090				1,454,242				2,109,852				1,889,603				2,128,471
Long-term debt, less current potion			575,000				575,000				825,000				400,000				797,000
Stone Energy Corporation stockholders’ equity			430,357				325,659				577,391				885,802				711,640

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

     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, 2010. Our Consolidated 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 1A. Risk Factors” and “Item 8. Financial Statements and Supplementary Data — Note 1.” Results for 2009 and 2008 have been corrected, as further discussed in “Item 8. Financial Statements and Supplementary Data — Note 2.” All period to period comparisons are based upon corrected amounts.

Executive Overview

     We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties located primarily in the Gulf of Mexico (“GOM”). We have been operating in the Gulf Coast Basin since our incorporation in 1993 and have established a technical and operational expertise in this area. More recently, we have made strategic investments in the deep water and deep shelf GOM, which we have targeted as important exploration areas. We are also active in the Appalachia region, where we have established a significant acreage position and have development operations in the Marcellus Shale. We have also targeted several exploratory oil projects in the Rocky Mountain region. See “Item 1. Business — Strategy and Operational Overview.”

     2010 Significant Events.

     Public Offering of Senior Notes — On January 26, 2010, we completed a public offering of $275 million aggregate principal amount of 8⁵/8% Senior Notes due 2017. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $265.3 million. Approximately $202 million of the net proceeds from the offering were used to fund the tender offer and consent solicitation and redemption of our outstanding 8¹/4% Senior Subordinated Notes due 2011. The remaining proceeds were used for general corporate purposes, including the repayment of borrowings under our bank credit facility.

     On November 17, 2010, we completed a public offering of an additional $100 million aggregate principal amount our 8⁵/8% Senior Notes due 2017. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $98.2 million. We used the net proceeds from the offering for general corporate purposes, which included the repayment of borrowings under our bank credit facility and the payment of amounts due related to the acquisition of additional lease acreage in Appalachia.

     Deepwater Horizon Explosion and Oil Spill — In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the GOM. As a result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil spill that produced widespread economic, environmental and natural resource damage in the Gulf Coast region. In response to the explosion and spill, the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE,” formerly the Minerals Management Service) of the U.S. Department of the Interior issued a “Notice to Lessees” (“NTL”) on May 30, 2010, and a revised notice on July 12, 2010, implementing a moratorium on deepwater drilling activities that effectively halted deepwater drilling of wells. While the moratorium was in place, the BOEMRE issued a series of NTLs and adopted changes to its regulations to impose a variety of new measures intended to help prevent a similar disaster in the future. The moratorium was lifted on October 12, 2010, but offshore operators must now comply with strict new safety and operating requirements. We are experiencing lengthy delays in the permitting process.

     Appalachian Basin (Marcellus Shale Play) — During 2010, we substantially increased our investment in Appalachia with the drilling of fifteen operated horizontal wells and the increase of our leasehold position to 79,000 net acres.

     2011 Outlook.

     Our 2011 capital expenditure budget is approximately $425 million which is flat with the revised 2010 capital expenditure budget and excludes material acquisitions and capitalized salaries, general and administrative expenses and interest. Approximately 50% — 55% of the capital expenditure budget is expected to be spent on the GOM shelf, including drilling, recompletions, facilities and abandonment. Approximately 25% of the budget is projected to be spent in Appalachia, including drilling, facilities and minor land acquisitions. The remaining budget is for exploration projects in the Rocky Mountain region, the deep shelf, the GOM deep water and other new venture opportunities.

     Known Trends and Uncertainties.

     Deepwater Horizon Explosion and Oil Spill — The explosion and sinking of the Deepwater Horizon drilling rig and resulting oil spill has created uncertainties about the impact on our future operations in the GOM (see “Item 1A. Risk Factors”). Increased regulation in a number of areas could disrupt, delay or prohibit future drilling programs and ultimately impact the fair value of our

unevaluated properties, a substantial portion of which is in the deep water of the GOM. As of December 31, 2010, we have approximately $270 million of investments in unevaluated oil and gas properties that relate to offshore leases, the majority of which are in the deep water GOM. If the fair value of these investments were to fall below the recorded amounts, the excess would be transferred to evaluated oil and gas properties thereby affecting the computation of amounts for depreciation, depletion and amortization and potentially our ceiling test computation. As of December 31, 2010, the computation of our ceiling test indicated a cushion of approximately $139.5 million.

     Asset Retirement Obligations — In October 2010, we received notification from the BOEMRE indicating that certain identified wells and facilities operated by us will need to be retired on a timing schedule which was accelerated from the timing estimated in calculating liabilities for asset retirement obligations at December 31, 2009. In February 2011, we submitted an abandonment plan addressing the identified wells and facilities. The BOEMRE has indicated they will issue a final order upon review of the plan. During 2010, we increased our asset retirement obligations in the amount of $54.4 million for the estimated impact of the accelerated timing of the retirement of these assets and other factors. The final order will ultimately determine the impact on our asset retirement obligations and could result in an additional upward or downward revision. See “Item 1A. Risk Factors.”

     Hurricanes — Since the majority of our production originates in the GOM, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes is becoming more difficult to obtain. We have narrowed our insurance coverage to selected properties, increased our deductibles and are shouldering more hurricane related risk in the environment of rising insurance rates. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

     Louisiana Franchise Taxes — We have been involved in litigation with the state of Louisiana over the proper computation of franchise taxes allocable to the state. This litigation relates to the state’s position that sales of crude oil and natural gas from properties located on the Outer Continental Shelf (“OCS”), which are transported through the state of Louisiana, should be sourced to Louisiana for purposes of computing franchise taxes. We disagree with the state’s position. However, if the state’s position were to be upheld, we could incur additional expense for alleged underpaid franchise taxes in prior years and higher franchise tax expense in future years. See “Item 3. Legal Proceedings.”

Liquidity and Capital Resources

     At February 22, 2011, we had $301.9 million of availability under our bank credit facility and cash on hand of approximately $90.4 million. Our capital expenditure budget for 2011 has been set at $425 million, which excludes material acquisitions and capitalized salaries, general and administrative expenses and interest. We intend to finance our capital expenditure budget primarily with cash flow from operations and borrowings under our bank credit facility. Our bank credit facility matures on July 1, 2011. We are currently exploring alternatives for an extension or renegotiation of our bank credit facility which would extend the due date. If we do not have sufficient cash flow from operations or availability under our bank credit facility, we may be forced to reduce our capital expenditures. To the extent that 2011 cash flow from operations exceeds our estimated 2011 capital expenditures, we may pay down a portion of our existing debt, expand our capital budget, or invest in the money markets.

     There is a significant amount of uncertainty regarding our industry resulting from the explosion and sinking of the Deepwater Horizon oil rig in the GOM and resulting oil spill. Several bills have been introduced in Congress which would require us to demonstrate our capabilities for greater financial responsibility in the event of spills. In addition, we are subject to an annual evaluation for exemption from supplemental bonding on plugging and abandoning obligations. It is possible that the resolution of these uncertainties could cause severe impacts on our liquidity in the event we are required to post additional bonds or letters of credit.

     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.

     Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $424.8 million during 2010 compared to $507.8 million and $522.5 million in 2009 and 2008, respectively. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2011 capital expenditures with cash flow provided by operating activities and borrowings under our bank credit facility.

     Net cash flow used in investing activities totaled $374.1 million during 2010, which primarily represents our investment in oil and natural gas properties of $401.8 million offset by proceeds from the sale of oil and natural gas properties of $31.6 million. Net cash flow used in investing activities totaled $316.1 million during 2009, which primarily represents our investment in oil and natural gas properties. Net cash flow used in investing activities totaled $1.4 billion during the year ended December 31, 2008,

which primarily represents cash of $922.7 million used in connection with the acquisition of Bois d’Arc Energy, Inc. (“Bois d’Arc”) and our investment in oil and natural gas properties of $446.8 million.

     Net cash flow used in financing activities totaled $13.0 million for the year ended December 31, 2010, which primarily represents repayments of borrowings under our bank credit facility of $175 million, the redemption of our 8¹/4% Senior Subordinated Notes due 2011 of $200.5 million, net of proceeds from the public offering of our 8⁵/8% Senior Notes due 2017 of approximately $375 million less $11.5 million of deferred financing costs. Net cash flow used in financing activities totaled $190.6 million for the year ended December 31, 2009, which primarily represents repayments of borrowings under our bank credit facility of $250 million partially offset by proceeds from the sale of common stock of approximately $60.4 million. Net cash flow provided by financing activities totaled $428.4 million during the year ended December 31, 2008, which primarily represents $425 million of borrowings under our bank credit facility in conjunction with our acquisition of Bois d’Arc and $15.9 million of proceeds from the exercise of stock options and vesting of restricted stock.

     We had working capital at December 31, 2010 of $30.4 million.

     Capital Expenditures. In 2010, additions to oil and gas property costs of $461.7 million included $127.1 million of lease and property acquisition costs, $20.2 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $30.8 million of capitalized interest. These investments were financed by cash flow from operations.

     Bank Credit Facility. On August 28, 2008, we entered into an amended and restated revolving credit facility totaling $700 million, maturing on July 1, 2011, with a syndicated bank group. We are currently exploring alternatives for an extension or renegotiation of our bank credit facility which would extend the due date. On January 26, 2010, we completed a public offering of $275 million aggregate principal amount of 8⁵/8% Senior Notes due 2017. In connection with this offering, our borrowing base was automatically reduced from $425 million to $395 million. On November 17, 2010, we completed a public offering of an additional $100 million aggregate principal amount of our 8⁵/8% Senior Notes due 2017. Upon completion of this offering, our borrowing base was automatically reduced from $395 million to $365 million.

     At December 31, 2010 and February 22, 2011, we had no outstanding borrowings under our bank credit facility and letters of credit totaling $63.1 million had been issued under the facility, leaving $301.9 million of availability under the facility. Our bank credit facility is guaranteed by our only material subsidiary, Stone Energy Offshore, L.L.C. (“Stone Offshore”).

     The borrowing base under our bank credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. Our bank credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At Stone’s option, loans under the credit facility will bear interest at a rate based on the adjusted London Interbank Offering Rate plus an applicable margin, or a rate based on the prime rate or Federal funds rate plus an applicable margin.

     Under the financial covenants of our credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a ratio of EBITDA to consolidated Net Interest, as defined in the credit agreement, for the preceding four quarterly periods of not less than 3.0 to 1.0. As of December 31, 2010, our debt to EBITDA Ratio was 1.43 to 1 and our EBITDA to consolidated Net Interest Ratio was approximately 41.72 to 1. In addition, the credit facility includes 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 but do allow for limited stock repurchases.

     Senior Notes Offering and Redemption of Senior Subordinated Notes. On January 26, 2010, we completed a public offering of $275 million aggregate principal amount of 8⁵/8% Senior Notes due 2017. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $265.3 million. Approximately $202 million of the net proceeds from the offering were used to fund the tender offer and consent solicitation and redemption of our outstanding 8¹/4% Senior Subordinated Notes due 2011. The remaining proceeds were used for general corporate purposes, including the repayment of borrowings under our bank credit facility.

     On November 17, 2010, we completed a public offering of an additional $100 million aggregate principal amount of our 8⁵/8% Senior Notes due 2017. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $98.2 million. We used the net proceeds from the offering for general corporate purposes, which included the repayment of borrowings under our bank credit facility and the payment of amounts due related to the acquisition of additional lease acreage in Appalachia.

     Share Repurchase Program. On September 24, 2007, our Board of Directors authorized a share repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased from time to time in the open market or through privately negotiated transactions. The repurchase program is subject to business and market conditions, and may be suspended or discontinued at any time. Through December 31, 2010, 300,000 shares had been repurchased under this program at a total cost of approximately $7.1 million, or an average price of $23.57 per share. No shares were repurchased during the year ended December 31, 2010.

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

Contractual Obligations and Other Commitments

     The following table summarizes our significant contractual obligations and commitments, other than hedging contracts, by maturity as of December 31, 2010 (in thousands):

						Less than												More than
		Total				1 Year				1-3 Years				4-5 Years				5 Years
Contractual Obligations and Commitments:
8⅝% Senior Notes due 2017		$	375,000			$	—			$	—			$	—			$	375,000
63/4% Senior Subordinated Notes due 2014			200,000				—				—				200,000				—
Interest and commitment fees (1)			250,929				46,607				91,688				77,596				35,038
Asset retirement obligations including accretion			639,140				42,500				101,666				145,823				349,151
Rig commitments			9,850				9,850				—				—				—
Seismic data commitments (2)			3,578				3,578				—				—				—
Operating lease obligations			1,879				507				947				425				—
Total Contractual Obligations and Commitments		$	1,480,376			$	103,042			$	194,301			$	423,844			$	759,189

Safety Performance

     We measure our safety performance based on the total recordable incident rate (“TRIR”) which is the number of safety incidents per 200,000 man-hours worked for employees and certain contractors. All onshore safety incidents are reported to the Occupational Safety and Health Administration (“OSHA”) and are tracked on OSHA Form 301. All offshore safety incidents are reported to the BOEMRE. Our TRIR is provided to the BOEMRE as part of a voluntary program for safety monitoring in the Gulf of Mexico. Our TRIR for the last three calendar years was as follows:

		TRIR				TRIR
Year Ended December 31,		Performance				Goal
2010			0.51				0.65
2009			0.18				0.85
2008			0.44				0.85

     Although our safety initiatives do not require a significant capital expenditures commitment, we expended approximately $800,000 in 2010 in general and administrative costs towards our safety efforts. Our safety initiative includes formal programs for observation and reporting of at-risk and safe behavior in and away from the work place, employee awards for results and observations, employee participation in offsite training programs and internal safety audits. We have an annual cash incentive compensation plan which includes a safety component based on our annual TRIR.

Results of Operations

     2010 Compared to 2009. 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 Natural Gas Reserves.”

		Year Ended December 31,
		2010				2009				Variance				% Change
Production:
Oil (MBbls)			5,714				6,207				(493	)			(8	%)
Natural gas (MMcf)			41,937				41,335				602				1	%
Oil and natural gas (MMcfe)			76,221				78,577				(2,356	)			(3	%)
Average prices: (1)
Oil (per Bbl)		$	73.14			$	70.72			$	2.42				3	%
Natural gas (per Mcf)			5.56				6.59				(1.03	)			(16	%)
Oil and natural gas (per Mcfe)			8.54				9.05				(0.51	)			(6	%)
Expenses (per Mcfe):
Lease operating expenses		$	2.00			$	2.00			$	—				0	%
Salaries, general and administrative expenses (2)			0.56				0.53				0.03				6	%
DD&A expense on oil and gas properties			3.18				3.23				(0.05	)			(2	%)
Estimated Proved Reserves at December 31:
Oil (MBbls)			33,203				32,336				867				3	%
Natural gas (MMcf)			274,705				216,694				58,011				27	%
Oil and natural gas (MMcfe)			473,923				410,711				63,212				15	%

     For the year ended December 31, 2010, we reported net income totaling $96.4 million, or $1.99 per share, compared to a net loss for the year ended December 31, 2009 of $218.3 million, or $4.97 per share. All per share amounts are on a diluted basis.

     We follow the full cost method of accounting for oil and gas properties. At March 31, 2009 and December 31, 2009, we recognized ceiling test write-downs of our oil and gas properties (United States) totaling $509.0 million ($330.8 million after taxes).

     The variance in annual results was also due to the following components:

     Production. Production volumes during the year ended December 31, 2010 totaled 5,714,000 barrels of oil and 41.9 Bcf of natural gas compared to 6,207,000 barrels of oil and 41.3 Bcf of natural gas produced during the year ended December 31, 2009, a decrease on a gas equivalent basis of 2.4 Bcfe. Production deferrals due to hurricanes during the year ended December 31, 2009 amounted to 11.8 Bcfe. Without the effects of the hurricane production deferrals, year to year total production volumes decreased approximately 14.2 Bcfe, primarily the result of natural production declines in the GOM.

     Prices. Prices realized during the year ended December 31, 2010 averaged $73.14 per barrel of oil and $5.56 per Mcf of natural gas, or 6% lower, on an Mcfe basis, than 2009 average realized prices of $70.72 per barrel of oil and $6.59 per Mcf of natural gas. All unit pricing amounts include the settlement of effective hedging contracts.

     We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During the years ended December 31, 2010 and 2009, our effective hedging transactions increased our average realized natural gas price by $0.92 per Mcf and $2.45 per Mcf, respectively. Average realized oil prices were decreased during the year ended December 31, 2010 by $5.08 per barrel as a result of effective hedging transactions. During the year ended December 31, 2009, our effective hedging transactions increased our average realized oil price by $9.95 per barrel.

     Income. Oil and natural gas revenue decreased 8% to $651.0 million during the year ended December 31, 2010 from $711.3 million during the year ended December 31, 2009. The decrease was primarily due to a 6% decrease in average realized prices on a gas equivalent basis along with a 3% decrease in oil and natural gas production volumes.

     Derivative Income/Expense. During the years ended December 31, 2010 and 2009, certain of our derivative contracts were determined to be partially ineffective because of differences in the relationship between the fixed price in the derivative contract and actual prices realized. Net derivative income for the year ended December 31, 2010, totaled $3.3 million, consisting of $3.0 million of cash settlements on the ineffective portion of derivative contracts, plus $0.3 million of changes in the fair market value of

the ineffective portion of derivative contracts. Net derivative income for the year ended December 31, 2009, totaled $3.1 million, consisting of $8.2 million of cash settlements on the ineffective portion of derivative contracts, less $5.1 million of changes in the fair market value of the ineffective portion of derivative contracts.

     Expenses. Lease operating expenses for the years ended December 31, 2010 and 2009 totaled $152.3 million and $156.8 million, respectively. Lease operating expenses during the year ended December 31, 2009 included approximately $9.3 million of repairs in excess of estimated insurance recoveries related to damage from Hurricanes Gustav and Ike. On a unit of production basis, lease operating expenses were $2.00 per Mcfe for each of the years ended December 31, 2010 and 2009.

     For the year ended December 31, 2010, other operational expenses of $5.5 million included a $2.2 million loss on the sale of non-dedicated tubular inventory and a total of $3.3 million of charges related to a delay in the drilling of the second well in our Amberjack drilling program as a result of the deep water drilling moratorium. The other operational expense charge of $2.4 million for the year ended December 31, 2009 related to the cancellation of a drilling contract based on declining commodity prices and the economic environment at that time.

     Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the year ended December 31, 2010 totaled $242.7 million, or $3.18 per Mcfe, compared to DD&A expense of $253.8 million, or $3.23 per Mcfe in the year ended December 31, 2009.

     For the years ended December 31, 2010 and 2009, accretion expense totaled $34.5 million and $39.3 million, respectively. The decrease is primarily due to a decrease in our credit adjusted risk free rate at December 31, 2009.

     During the years ended December 31, 2010 and 2009, SG&A expenses (exclusive of incentive compensation) totaled $42.8 million and $41.4 million, respectively.

     For the years ended December 31, 2010 and 2009, incentive compensation expense totaled $5.9 million and $6.4 million, respectively. These amounts related to incentive compensation bonuses calculated based on the achievement of certain strategic objectives for each year.

     The impairment of inventory for the years ended December 31, 2010 and 2009 totaling $0.1 million and $9.4 million, respectively, related to the write-down of our tubular inventory. These charges were the result of the market value of these tubular goods falling below historical cost. We consider only tubular goods not committed to capital projects to be inventory items.

     Interest expense for the year ended December 31, 2010 totaled $12.2 million, net of $30.8 million of capitalized interest, compared to interest expense of $21.4 million, net of $25.6 million of capitalized interest, during the year ended December 31, 2009. The decrease in interest cost is primarily the result of a decrease in outstanding borrowings under our bank credit facility.

     Our effective income tax rate increased during the year ended December 31, 2010 due to the increased impact of state jurisdictions on our overall rate.

     Asset Retirement Obligations. In October 2010, we received notification from the BOEMRE indicating that certain identified wells and facilities operated by us will need to be retired on a timing schedule, which was accelerated from the timing estimated in calculating liabilities for asset retirement obligations at December 31, 2009. During 2010, we increased our asset retirement obligations in the amount of $54.4 million for the estimated impact of the accelerated timing of the retirement of these assets as well as other factors.

     Reserves. At December 31, 2010, our estimated proved oil and natural gas reserves totaled 473.9 Bcfe, compared to December 31, 2009 reserves of 410.7 Bcfe. Estimated proved natural gas reserves totaled 274.7 Bcf and estimated proved oil reserves totaled 33.2 MMBbls at the end of 2010. The increase in estimated proved reserves from year-end 2009 was primarily due to successful drilling operations in Appalachia and the GOM shelf as well as positive pricing revisions. The reserve estimates at December 31, 2010 were prepared by Netherland, Sewell & Associates, Inc. (“NSA”) in accordance with guidelines established by the SEC.

     Our standardized measure of discounted future net cash flows was $957.6 million and $615.0 million at December 31, 2010 and 2009, respectively. As required by the SEC, we determined this estimate of future net cash flows using a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month of our fiscal year. The 12-month average oil and gas prices net of differentials on all of our properties used in determining this amount, excluding the effects of hedges in place at year-end, were $77.68 per barrel and $4.46 per mcf for 2010 and $58.95 per barrel and $3.49 per Mcf for 2009. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves.

     2009 Compared to 2008. 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 Natural Gas Reserves.”

		Year Ended December 31,
		2009				2008				Variance				% Change
Production:
Oil (MBbls)			6,207				4,916				1,291				26	%
Natural gas (MMcf)			41,335				34,409				6,926				20	%
Oil and natural gas (MMcfe)			78,577				63,903				14,674				23	%
Average prices: (1)
Oil (per Bbl)		$	70.72			$	93.79				($23.07	)			(25	%)
Natural gas (per Mcf)			6.59				9.78				(3.19	)			(33	%)
Oil and natural gas (per Mcfe)			9.05				12.48				(3.43	)			(27	%)
Expenses (per Mcfe):
Lease operating expenses		$	2.00			$	2.68				($0.68	)			(25	%)
Salaries, general and administrative expenses (2)			0.53				0.68				(0.15	)			(22	%)
DD&A expense on oil and gas properties			3.23				4.45				(1.22	)			(27	%)
Estimated Proved Reserves at December 31:
Oil (MBbls)			32,336				36,564				(4,228	)			(12	%)
Natural gas (MMcf)			216,694				299,554				(82,860	)			(28	%)
Oil and natural gas (MMcfe)			410,711				518,935				(108,224	)			(21	%)

     For the year ended December 31, 2009, we reported a net loss totaling $218.3 million, or $4.97 per share, compared to a net loss for the year ended December 31, 2008 of $1,146.9 million, or $35.89 per share. All per share amounts are on a diluted basis. On August 28, 2008, we completed our acquisition of Bois d’Arc. The revenues and expenses associated with Bois d’Arc have been included in Stone’s consolidated financial statements since August 28, 2008.

     We follow the full cost method of accounting for oil and gas properties. At March 31, 2009 and December 31, 2009, we recognized ceiling test write-downs of our oil and gas properties (United States) totaling $509.0 million ($330.8 million after taxes). At the end of 2008, we recognized a ceiling test write-down of our oil and gas properties (United States and China) totaling $1,324.3 million ($860.8 million after taxes). The write-downs did not impact our cash flow from operations but did reduce net income and stockholders’ equity. At December 31, 2008, approximately $157.8 million of unevaluated costs were determined to be impaired and were reclassified to proved oil and gas properties and included in our ceiling test computation.

     The 2008 net loss included a goodwill impairment charge totaling $466.0 million (no tax effect). The goodwill impairment charge did not impact our cash flow from operations but did reduce net income and stockholders’ equity. The goodwill related to our acquisition of Bois d’Arc.

     The variance in annual results was also due to the following components:

     Production. Production volumes during the year ended December 31, 2009 totaled 6,207,000 barrels of oil and 41.3 Bcf of natural gas compared to 4,916,000 barrels of oil and 34.4 Bcf of natural gas produced during the year ended December 31, 2008, an increase on a gas equivalent basis of 14.7 Bcfe. Production rates were negatively impacted by Gulf Coast shut-ins due to Hurricanes Gustav and Ike during 2009 and 2008, amounting to volumes of approximately 11.8 Bcfe and 18.1 Bcfe, respectively. Without the effects of the hurricane production deferrals, year to year total production volumes increased approximately 8.4 Bcfe, primarily the result of a full year of production associated with the Bois d’Arc properties in 2009.

     Prices. Prices realized during the year ended December 31, 2009 averaged $70.72 per barrel of oil and $6.59 per Mcf of natural gas, or 27% lower, on an Mcfe basis, than 2008 average realized prices of $93.79 per barrel of oil and $9.78 per Mcf of natural gas. All unit pricing amounts include the settlement of effective hedging contracts.

     We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During the years ended December 31, 2009 and 2008, our effective hedging transactions increased our average realized natural gas price by $2.45 per Mcf and $0.44 per Mcf, respectively. During the year ended December 31, 2009, our effective hedging transactions increased our average realized oil price by $9.95 per barrel. Average realized oil prices were decreased during the year ended December 31, 2008 by $7.01 per barrel as a result of effective hedging transactions.

     Income. Oil and natural gas revenue decreased 11% to $711.3 million during the year ended December 31, 2009 from $797.7 million during the year ended December 31, 2008. The decrease was due to a 27% decrease in average realized prices on a gas equivalent basis, partially offset by oil and natural gas revenue associated with the Bois d’Arc properties totaling $169.8 million for the full year of 2009. Oil and natural gas revenue related to the properties acquired from Bois d’Arc totaled $47.3 million from August 28, 2008 through December 31, 2008.

     Interest income totaled $0.5 million during the year ended December 31, 2009 compared to $11.3 million during the year ended December 31, 2008. The decrease in interest income was the result of lower interest rates and a decrease in our cash balances during the periods after the acquisition of Bois d’Arc.

     Derivative Income/Expense. During 2009, certain of our derivative contracts were determined to be partially ineffective because of differences in the relationship between the fixed price in the derivative contract and actual prices realized. Net derivative income for the year ended December 31, 2009, totaled $3.1 million, consisting of $8.2 million of cash settlements on the ineffective portion of derivative contracts, less $5.1 million of changes in the fair market value of the ineffective portion of derivative contracts. During 2008, certain of our derivative contracts were determined to be partially ineffective because of differences in the relationship between the fixed price in the derivative contract and actual prices realized. During the second half of 2008, as a result of extended shut-ins of production after Hurricanes Gustav and Ike, our September 2008 crude oil and natural gas production levels were below the volumes that we had hedged. Consequently, some of our crude oil and natural gas hedges for September 2008 were deemed to be ineffective. Net derivative income for the year ended December 31, 2008, totaled $3.3 million, consisting of $0.7 million of cash settlements on the ineffective derivative contracts, $4.5 million of changes in the fair market value of the ineffective portion of derivative contracts, less $1.9 million of amortization of the cost of puts.

     Expenses. Lease operating expenses for the year ended December 31, 2009 totaled $156.8 million, compared to $171.1 million incurred during the year ended December 31, 2008. The decrease in lease operating expenses was the result of a decline in major maintenance expenses. Partially offsetting the decrease are lease operating expenses from the Bois d’Arc properties for a full year in 2009 compared to a partial year in 2008. Included in lease operating expenses from August 28, 2008 through December 31, 2008 are $28.6 million of expenses for the properties acquired from Bois d’Arc. For the year ended December 31, 2009, lease operating expenses for the properties acquired from Bois d’Arc totaled $62.5 million.

     The other operational expense charge of $2.4 million for the year ended December 31, 2009 related to the cancellation of a drilling contract.

     DD&A expense on oil and gas properties for the year ended December 31, 2009 totaled $253.8 million, or $3.23 per Mcfe, compared to DD&A expense of $284.7 million, or $4.45 per Mcfe in the year ended December 31, 2008. The overall decrease in DD&A from 2008 was primarily due to the 2008 year-end and first quarter 2009 ceiling test write-downs, which reduced the carrying value of the full cost pool for our oil and gas properties.

     For the years ended December 31, 2009 and 2008, accretion expense totaled $39.3 million and $17.4 million, respectively. Due to falling commodity prices and hurricanes, the timing on a substantial portion of our asset retirement obligations was revised in the fourth quarter of 2008 leading to a redetermination of the present value of these obligations. In this redetermination, our credit adjusted risk free interest rate was increased to account for current credit conditions, resulting in a material increase in accretion expense in 2009. Also contributing to the increase was the addition of liabilities associated with properties acquired from Bois d’Arc.

     During the years ended December 31, 2009 and 2008, SG&A expenses (exclusive of incentive compensation) totaled $41.4 million and $43.5 million, respectively.

     For the years ended December 31, 2009 and 2008, incentive compensation expense totaled $6.4 million and $2.3 million, respectively. These amounts related to incentive compensation bonuses calculated based on the achievement of certain strategic objectives for each year.

     The impairment of inventory for the year ended December 31, 2009 totaling $9.4 million related to the write-down of our tubular inventory. This charge was the result of the market value of these tubular goods falling below historical cost. We consider only tubular goods not committed to capital projects to be inventory items.

     Interest expense for the year ended December 31, 2009 totaled $21.4 million, net of $25.6 million of capitalized interest, compared to interest expense of $13.2 million, net of $26.4 million of capitalized interest, during the year ended December 31, 2008. The increase in interest cost in 2009 was primarily the result of an increase in outstanding borrowings under our bank credit facility in the first half of 2009.

     We estimate that we incurred $30.4 million of current federal income tax expense for calendar year 2009. This was largely due to a reclassification between current and deferred income tax expense related to a proposed IRS audit adjustment with respect to the timing of certain deductions. We had an $11.1 million current income tax payable at December 31, 2009.

     Asset Retirement Obligations. Primarily due to changes in estimated reserve lives, the timing on a substantial portion of our asset retirement obligations was revised in the fourth quarter of 2009 leading to a redetermination of the present value of these obligations. In this redetermination, our credit adjusted risk free rate was decreased to account for current credit conditions contributing to a significant upward revision of our asset retirement obligations of $76.4 million at December 31, 2009.

     Reserves. At December 31, 2009, our estimated proved oil and gas reserves totaled 410.7 Bcfe, compared to December 31, 2008 reserves of 518.9 Bcfe. Estimated proved natural gas reserves totaled 216.7 Bcf and estimated proved oil reserves totaled 32.3 MMBbls at the end of 2009. The decline in estimated proved reserves from year-end 2008 was due to production, negative commodity pricing revisions and other revisions to comply with the new SEC rules regarding oil and gas reserve estimation. The reserve estimates at December 31, 2009 were prepared by NSA in accordance with guidelines established by the SEC.

     Our standardized measure of discounted future net cash flows was $615.0 million at December 31, 2009. As required by the SEC, at December 31, 2009, we determined this estimate of future net cash flows using a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month of our fiscal year. The 12-month average oil and gas prices net of differentials on all of our properties used in determining this amount, excluding the effects of hedges in place at year-end, were $58.95 per barrel and $3.49 per Mcf for 2009. Our standardized measure of discounted future net cash flows was $793.1 million at December 31, 2008 using a single-day, period-end price as required under the old SEC guidelines. Prior to the issuance of the SEC’s new rule, “Modernization of Oil and Gas Reporting”, estimates of future net cash flows were based on market prices for oil and gas on the last day of the fiscal period. The average year-end oil and gas prices net of differentials on all of our properties used in determining our standardized measure of discounted future net cash flows at December 31, 2008, excluding the effects of hedges in place at year-end, were $39.70 per barrel and $5.87 per Mcf for 2008. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves.

Off-Balance Sheet Arrangements

     We have no off-balance sheet arrangements.

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 “Item 1A. Risk Factors.”

Accounting Matters and Critical Accounting Policies

     Fair Value Measurements. U.S. Generally Accepted Accounting Principles (“GAAP”), as codified, establish a framework for measuring fair value and require certain disclosures about fair value measurements. There is an established fair value hierarchy which has three levels based on the reliability of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

     As of December 31, 2010, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in money market funds. Additionally, fair value concepts were applied in the recording of assets and liabilities acquired in the Bois d’Arc transaction.

     Business Combinations and Goodwill. Our 2008 acquisition of Bois d’Arc was accounted for using the purchase method of accounting for business combinations. Fair value concepts were used in determining the cost of the acquired entity and allocating that cost to assets acquired (including goodwill) and liabilities assumed. Goodwill is required to be tested for impairment at least annually. There is a two-step methodology for determining impairment that begins with an estimation of the fair value of the reporting unit. The first step is a screen for potential impairment, and the second step measures the amount of impairment, if any. This authoritative guidance provided the framework for the determination of our goodwill impairment at December 31, 2008.

     Asset Retirement Obligations. We are required 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 guidance regarding asset retirement obligations requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of

capital. 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 follow 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 and general and administrative costs (less any reimbursements for such costs) and interest 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 units of production (“UOP”) method. Under the UOP method, the quarterly provision for DD&A is computed by dividing production volumes for the period by the total proved reserves as of the beginning of the period (beginning of the period reserves being determined by adding back production to end of the period reserves), and applying the respective rate to the net cost of proved oil and gas properties, including future development costs.

     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. We also capitalize the portion of salaries, general and administrative expenses that are attributable to our acquisition, exploration and development activities.

     U.S. GAAP allows 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.

     Under the full cost method of accounting, we compare, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties 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. Historically, estimated future net cash flows from proved reserves were calculated based on period-end hedge adjusted commodity prices. In December 2008, the SEC issued a final rule, “Modernization of Oil and Gas Reporting,” which adopted revisions to the SEC’s oil and gas reporting requirements. The revisions replaced the single-day year-end pricing with a twelve-month average pricing assumption. The changes to prices used in reserves calculations under the new rule are used in both disclosures and accounting impairment tests. In January 2010, the Financial Accounting Standards Board (“FASB”) issued its final standard on oil and gas reserve estimation and disclosures aligning its requirements with the SEC’s final rule. The new rules were considered a change in accounting principle that is inseparable from a change in accounting estimate, which did not require retroactive revision.

     Derivative Instruments and Hedging Activities. 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.

     Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP 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. Our most significant estimates are:

	•		remaining proved oil and gas reserve volumes and the timing of their production;
	•		estimated costs to develop and produce proved oil and gas reserves;
	•		accruals of exploration costs, development costs, operating costs and production revenue;
	•		timing and future costs to abandon our oil and gas properties;
	•		the effectiveness and estimated fair value of derivative positions;
	•		classification of unevaluated property costs;
	•		capitalized general and administrative costs and interest;

	•		insurance recoveries related to hurricanes;
	•		estimates of fair value in business combinations;
	•		goodwill impairment testing and measurement;
	•		current income taxes; and
	•		contingencies.

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

Recent Accounting Developments

     Fair Value Measurements and Disclosures. Accounting Standards Update (“ASU”) 2010-06 was issued in January 2010 to improve disclosures about fair value measurements by requiring a greater level of disaggregated information, more robust disclosures about valuation techniques and inputs to fair value measurements, information about significant transfers between the three levels in the fair value hierarchy, and separate presentation of information about purchases, sales, issuances, and settlements on a gross basis rather than as one net number. The guidance provided in ASU 2010-06 became effective for interim and annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. We had no Level 3 fair value measurements during the year ended December 31, 2010.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Commodity Price Risk. Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Price volatility is expected to continue. 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 for 2010 would have decreased approximately $0.83 per share. In order to manage our exposure to oil and natural gas price declines, we occasionally enter into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future production. 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.

     We have entered into fixed-price swaps with various counterparties for a portion of our expected 2011, 2012 and 2013 oil and natural gas production from the Gulf Coast Basin. The fixed-price oil swap settlements are based upon an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate (“WTI”) during the entire calendar month. Some of our fixed-price gas swap settlements are based on an average of NYMEX prices for the last three days of a respective month and some are based on the NYMEX price for the last day of a respective month. 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. Our outstanding fixed-price swap contracts are with J.P. Morgan Chase Bank, N.A., The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia and Natixis.

          The following table illustrates our hedging positions for calendar years 2011, 2012 and 2013 as of February 22, 2011:

		Fixed-Price Swaps
		Natural Gas								Oil
		Daily								Daily
		Volume				Swap				Volume				Swap
		(MMBtus/d)				Price				(Bbls/d)				Price
2011			10,000	(a)		$	4.565				1,000			$	70.05
2011			20,000				5.200				1,000				78.20
2011			10,000				6.830				1,000				80.20
2011											1,000				83.00
2011											1,000				83.05
2011											1,000	(b)			85.20
2011											1,000				85.25
2011											1,000				89.00
2011											1,000	(c)			97.75
2012			10,000				5.035				1,000				90.30
2012			10,000				5.040				1,000				90.41
2012											1,000				90.45
2012											1,000				95.50
2012											1,000				97.60
2012											1,000				100.00
2013											1,000				97.15

     We believe these positions have hedged approximately 40% of our estimated 2011 production from estimated proved reserves, 28% of our estimated 2012 production from estimated proved reserves and 4% of our estimated 2013 production from estimated proved reserves.

     Interest Rate Risk. We had long-term debt outstanding of $575 million at December 31, 2010, all of which bears interest at fixed rates. The $575 million of fixed-rate debt is comprised of $375 million of 8⁵/8% Senior Notes due 2017 and $200 million of 6³/4% Senior Subordinated Notes due 2014. During the year ended December 31, 2010, we had outstanding debt under our bank credit facility at various times, bearing interest at a floating rate. We currently have 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 2010 our interest expense, net of capitalization, would have increased approximately $0.3 million, net of taxes, resulting in a $0.01 per diluted share decrease in our reported net income.

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.

ITEM 9A. CONTROLS AND PROCEDURES

     Evaluation of Disclosure Controls and Procedures

     We have established disclosure controls and procedures to ensure that material information relating to Stone Energy Corporation and its consolidated subsidiaries (collectively “Stone”) is made known to the officers who certify Stone’s financial reports and the Board of Directors. Disclosure controls and procedures, as defined in the rules and regulations of the Securities Exchange Act of 1934, means controls and other procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports that it files or submits under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

     Our principal executive officer and our principal 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 December 31, 2010. Based on this evaluation, our principal executive officer and principal financial officer believe that as of the end of the year ended December 31, 2010:

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

     Changes in Internal Control Over Financial Reporting

     There has not been any change in our internal control over financial reporting that occurred during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

     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 by the Securities Exchange Act of 1934, as amended. Under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, we used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we have concluded that our internal controls over financial reporting were effective as of December 31, 2010. Ernst and Young LLP, an independent public accounting firm, has issued their report on the Company’s internal control over financial reporting as of December 31, 2010.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors
Stone Energy Corporation

We have audited Stone Energy Corporation’s internal control over financial reporting as of December 31, 2010, 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 included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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, Stone Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, 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 sheets of Stone Energy Corporation as of December 31, 2010 and 2009, and the related consolidated statements of operations, cash flows, changes in stockholders’ equity, and comprehensive income for each of the three years in the period ended December 31, 2010 and our report dated March 3, 2011 expressed an unqualified opinion thereon.

New Orleans, Louisiana
March 3, 2011

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

     The following table sets forth information regarding the names, ages (as of February 22, 2011) 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.

Name		Age				Position
David H. Welch			62			President, Chief Executive Officer and Director
Kenneth H. Beer			53			Executive Vice President and Chief Financial Officer
Andrew L. Gates, III			63			Senior Vice President, General Counsel and Secretary
E. J. Louviere			62			Senior Vice President — Land
John R. Pantaleo			53			Vice President — Gulf of Mexico
J. Kent Pierret			55			Senior Vice President, Chief Accounting Officer and Treasurer
Richard L. Smith			52			Executive Vice President — Exploration and Business Development
Richard L. Toothman, Jr.			46			Vice President — Appalachia
Jerome F. Wenzel, Jr.			58			Executive Vice President — Operations
Florence M. Ziegler			50			Vice President — Human Resources and Administration

     David H. Welch was appointed President, Chief Executive Officer and a director of the Company effective April 1, 2004. Prior to joining Stone, Mr. Welch served as Senior Vice President of BP America, Inc. since 2003, and Vice President of BP, Inc. since 1999.

     Kenneth H. Beer was named Executive Vice President and Chief Financial Officer in January 2011. Previously, he served as Senior Vice President and Chief Financial Officer since August 2005. Prior to joining Stone, he served as a director of research and a senior energy analyst at the investment banking firm of Johnson Rice & Company. Prior to joining Johnson Rice in 1992, he was an energy analyst and investment banker at Howard Weil Incorporated.

     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.

     John R. Pantaleo was named Vice President — Gulf of Mexico in August 2010. He previously served as Manager — Drilling & Completions since joining Stone in February 2005. Prior to joining Stone, he worked for ENI Petroleum for approximately 2-1/2 years as Manager of Well Operations. He also spent approximately 23 years with Amoco/BP America, Inc. where he held a number of positions including Deepwater Drilling Manager, Strategic Staffing Manager and Manager Rigs and Contracts.

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

     Richard L. Smith was named Executive Vice President, Exploration and Business Development in January 2011. Previously, he served as Senior Vice President — Exploration and Business Development since January 2009 and Vice President — Exploration and Business Development from June 2007 through January 2009. Prior to joining Stone, Mr. Smith served as the General Manager of Deepwater Gulf of Mexico Exploration of Dominion E&P Inc. from 2003 to 2007. Mr. Smith has also worked for Exxon Corporation and Texaco USA with experience in deep water, shelf, onshore, and international projects.

     Richard L. Toothman, Jr. was named Vice President — Appalachia in May 2010. Prior to joining Stone in May 2010, he was employed by CNX Gas Company in Bluefield, Virginia since August 2005 where he held two executive positions, VP Engineering and Technical Services and VP International Business. He also worked for Consol Energy and Conoco in prior years.

     Jerome F. Wenzel, Jr. was named Executive Vice President, Operations in January 2011. Previously, he served as Senior Vice President — Operations/Exploitation since September 2005. He 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 America, Inc. over a 29 year career.

     Florence M. Ziegler was named Vice President — Human Resources and Administration in September 2005. She has been employed by Stone since its inception in 1993 and served as the Director of Human Resources from 1997 to 2004.

     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 2011 Annual Meeting of Stockholders to be held on May 20, 2011. 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 2011 Annual Meeting of Stockholders to be held on May 20, 2011.

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

     The information required by Item 12 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2011 Annual Meeting of Stockholders to be held on May 20, 2011.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

     The information required by Item 13 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2011 Annual Meeting of Stockholders to be held on May 20, 2011.

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 2011 Annual Meeting of Stockholders to be held on May 20, 2011.

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 page F-1 of this Form 10-K:

Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheet as of December 31, 2010 and 2009
Consolidated Statement of Operations for the three years in the period ended December 31, 2010
Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2010
Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period ended December 31, 2010
Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2010
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:

3.1		Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).
3.2		Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed February 7, 2001).
3.3		Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 21, 2008 (File No. 001-12074)).
4.1		Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on December 15, 2004.)
4.2		First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)).
4.3		Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.4		Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).
4.5		First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)).

†10.1		Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)).
†10.2		Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Appendix A to the Registrant’s Definitive Proxy Statement on Schedule 14A for Stone’s 2009 Annual Meeting of Stockholders (File No. 001-12074)).
†10.3		Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.4		Stone Energy Corporation Amended and Restated Revised Annual Incentive Compensation Plan, dated November 14, 2007 (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-12074)).
†10.5		Stone Energy Corporation Deferred Compensation Plan (incorporated by reference to Exhibit 4.5 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.6		Adoption Agreement between Fidelity Management Trust Company and Stone Energy Corporation for the Stone Energy Corporation Deferred Compensation Plan dated December 1, 2004 (incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.7		Letter Agreement dated May 19, 2005 between Stone Energy Corporation and Kenneth H. Beer (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed May 24, 2005 (File No. 001-12074)).
†10.8		Letter Agreement dated December 2, 2008 between Stone Energy Corporation and David H. Welch (incorporated by reference to Exhibit 10.8 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 001-12074)).
†10.9		Letter Agreement dated June 28, 2007 between Stone Energy Corporation and Richard L. Smith (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed July 2, 2007 (File No. 001-12074)).
10.10		Amendment No.1, dated as of April 28, 2009, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and the financial institutions named therein (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed April 30, 2009 (File No. 001-12074)).
10.11		Amendment No. 2, dated January 11, 2010, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed January 12, 2010 (File No. 001-12074)).
10.12		Amendment No. 3, dated November 9, 2010, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed November 12, 2010 (File No. 001-12074)).
10.13		Amended and Restated Security Agreement, dated as of August 28, 2008, among Stone Energy Corporation and the other Debtors parties hereto in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-12074)).
†10.14		Stone Energy Corporation Executive Change of Control and Severance Plan (as amended and restated effective December 31, 2008) (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed April 8, 2009 (File No. 001-12074)).
†10.15		Stone Energy Corporation Employee Change of Control Severance Plan (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)).