Stone Energy (SGY) 10-K 2011 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

or

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

For the transition period from                    to                    

Commission File Number: 1-12074

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

625 E. Kaliste Saloom Road Lafayette, Louisiana	70508
(Address of principal executive offices)	(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.    x  Yes    ¨   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.    ¨  Yes    x   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.    x  Yes    ¨  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).    x  Yes    ¨  No

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

Indicate by check mark whether the registrant is 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	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1.46 billion as of June 30, 2011 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of February 21, 2012, the registrant had outstanding 48,880,229 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 24, 2012 are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

		Page No.
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	17
Item 2.	Properties	17
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Selected Financial Data	25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 8.	Financial Statements and Supplementary Data	35
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	36
Item 9A.	Controls and Procedures	36
Item 9B.	Other Information	37
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	38
Item 11.	Executive Compensation	39
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	39
Item 13.	Certain Relationships and Related Transactions, and Director Independence	39
Item 14.	Principal Accounting Fees and Services	39
PART IV
Item 15.	Exhibits, Financial Statement Schedules	40
	Index to Financial Statements	F-1
	Glossary of Certain Industry Terms	G-1

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PART I

This section highlights information that is discussed in more detail in the remainder of the document. Throughout this document, we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section 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. 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 expanded our reserve base outside of the conventional shelf of the Gulf of Mexico (“GOM”) and into the more prolific reserve basins of the GOM deep water and Gulf Coast deep gas as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia. As of December 31, 2011, our estimated proved oil and natural gas reserves were approximately 602 Bcfe. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana. We have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.

Strategy and Operational Overview

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

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. Our GOM conventional shelf properties accounted for approximately 50% of our estimated proved oil and natural gas reserves at December 31, 2011.

Gulf of Mexico — Deep Water

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 recent acquisition of the Pompano deep water field added approximately 102 Bcfe of estimated proved oil and natural gas reserves at December 31, 2011. Our deep water properties accounted for approximately 19% of our estimated proved oil and natural gas reserves at December 31, 2011.

Gulf of Mexico — Deep Shelf Gas

The deep shelf presents higher risk with high potential opportunities usually with existing infrastructure, which shortens the lead time to production. Our current property base in the GOM also contains multiple deep shelf exploration opportunities, which are defined as prospects below 15,000 feet. Additionally, we have identified onshore deep gas opportunities in south Louisiana. Our deep shelf gas properties accounted for approximately 2% of our estimated proved oil and natural gas reserves at December 31, 2011.

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Appalachia

During 2006, we began securing leasehold interests in the Appalachia regions of Pennsylvania and West Virginia. As of December 31, 2011, we had leasehold interests in approximately 83,000 net acres. During 2011, we drilled a total of 27 Marcellus Shale wells and fractured 16 wells. We expect to add leasehold interests and drill additional wells to further expand our interests in Appalachia. Our Appalachian properties accounted for approximately 28% of our estimated proved oil and natural gas reserves at December 31, 2011.

Unconventional Onshore Oil

We maintain working interests in several undeveloped plays in the Rocky Mountain region, which totaled approximately 105,000 net acres as of December 31, 2011. We have budgeted funds in 2012 for work in our fields in the Paradox basin of the Rocky Mountain region, continued non-operated development drilling in the Eagle Ford Shale formation and other new venture opportunities. Four wells were drilled in 2011 on our Eagle Ford Shale acreage with two wells fractured and producing. Estimated proved oil reserves from our unconventional onshore oil properties accounted for less than 1% of our estimated proved oil and natural gas reserves at December 31, 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 and Conoco, Inc. accounted for approximately 46% and 28%, respectively, of our oil and natural gas revenue generated during the year ended December 31, 2011. No other purchaser accounted for 10% or more of our total oil and natural gas revenue during 2011. 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 Gulf Coast onshore, the Appalachia region, the Rocky Mountain region and Eagle Ford Shale formation 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

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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 (“BLM”) and the Bureau of Ocean Energy Management (“BOEM”), a successor agency to the Minerals Management Service. These leases contain relatively standardized terms and require compliance with detailed BLM and BOEM regulations and orders pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“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 BOEM 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 BOEM, 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 (“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 BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM 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 the Bureau of Safety and Environmental Enforcement (“BSEE”), a new federal agency created to enforce compliance with safety and environmental rules of the OCS, 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 by these requirements 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 by these requirements 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.

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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 may 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.

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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 (“SDWA”) Underground Injection Control Program. While the EPA has yet to take any action to enforce 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 with initial results scheduled to be released in late 2012 and a final report scheduled to be issued in 2014. In addition, a number of other federal agencies, including the U.S. Department of Energy, Department of the Interior, and White House Council on Environmental Quality, are studying various aspects of hydraulic fracturing. 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, Texas, 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.

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Air emissions.On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA is currently considering comments submitted on the proposed rules and has indicated that it expects to adopt final rules by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

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 21, 2012, we had 352 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 (“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 May 24, 2011.

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.

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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:

• 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;

• consequences of the Deepwater Horizon oil spill and resulting stringent regulatory requirements;

• 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.

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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.

The April 2010 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. 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.

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEM, 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. However, legislation has been proposed in the U.S. Congress to increase the minimum level of financial responsibility to $300 million or more. 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 imposed by the Bureau of Ocean Energy Management 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 BOEM 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, BOEM 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 BOEM 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.

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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 50% of our estimated proved reserves at December 31, 2011 and 97% of our production during 2011 were associated with our Gulf Coast Basin conventional shelf 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.

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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 Form 10-K 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, 2011 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, 2011, approximately 40% 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.

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.

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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 2012. 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 50% of our estimated proved reserves at December 31, 2011 and 97% of our production during 2011 were associated with our Gulf Coast Basin conventional shelf properties. Approximately 21% of our estimated proved reserves at December 31, 2011 were associated with our GOM deep water and deep shelf gas 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. In past years, we have experienced shut-ins and losses of production due to the effects of hurricanes in the Gulf of Mexico. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production.

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Our acreage must be drilled before lease expiration in order to hold the acreage by production. If natural gas prices remain depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage may expire (seeItem 2. Properties –Productive Well and Acreage Data).

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. 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. 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.

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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 the Rocky Mountain region and other regions. These activities are more uncertain than drilling in areas that are developed and have established production. Our operations in these regions 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. We are also involved in drilling operations that utilize hydraulic fracturing, which may potentially present additional operational and environmental risks. 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 is 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.

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Currently, we have general liability insurance coverage with an annual aggregate limit of up to $100 million applicable to our working interest. We also have an offshore property physical damage policy that contains a $80 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 $600 million per occurrence. Additionally, we maintain $150 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. In past years, we have experienced production interruptions 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 within our industry 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

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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”) or the Intercontinental Exchange (“ICE”). 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 is 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.

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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, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. In its rulemaking under the Act, the CFTC has issued final 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

16

transactions or derivative instruments would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. 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 legislation and regulatory initiatives relating to hydraulic fracturing could cause us to incur increased costs and experience additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our 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 certain hydraulic fracturing activities involving diesel fuel under the SDWA’s Underground Injection Control Program and has begun the process of drafting guidance documents for companies that plan to conduct hydraulic fracturing using diesel fuel. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The EPA has commenced a comprehensive study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. In addition, U.S. Department of Energy and the U.S. Government Accountability Office are studying various aspects of hydraulic fracturing, and the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing activities performed on federal lands. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or other federal programs. Legislation also 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, including states in which we operate. For example, effective February 1, 2012, the Railroad Commission of Texas (the entity that regulates oil and natural gas production in Texas) began requiring all operators to disclose on a public website the chemical ingredients and water volumes used to hydraulically fracture wells in Texas. The disclosure of proprietary information regarding chemicals or formulas used in hydraulic fracturing could diminish the value of such information and could result in competitive harm to us. 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 21, 2012, our property portfolio consisted of 74 active properties and 114 primary term leases in the Gulf Coast Basin (onshore and offshore), five active properties in the Appalachia region, three active properties in the Rocky Mountain region and one active property in the Eagle Ford Shale formation. We serve as operator on 75% of our active properties. The properties that we operate accounted for 92% of our year-end 2011 estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities.

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Oil and Natural Gas Reserves

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 twenty 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, 2011 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 has a technical staff of over 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 (approximately 50% of which are located in the conventional shelf of the Gulf Coast Basin, 28% are located in the Appalachian region, 19% are located in the GOM deep water and 2% are located in the GOM deep shelf) as of December 31, 2011. The 2011 average 12-month oil and gas prices net of differentials were $100.97 per barrel of oil and $4.74 per Mcf of gas.

Summary of Oil and Gas Reserves as of December 31, 2011
	Oil (MBbls)		Natural Gas (MMcf)		Oil and Natural  Gas (MMcfe)
Reserves Category:
PROVED
Developed		31,026		174,067		360,224
Undeveloped		14,728		153,285		241,656
TOTAL PROVED		45,754		327,352		601,880

At December 31, 2011, we reported estimated proved undeveloped reserves (“PUDs”) of 241.7 Bcfe, which accounted for 40% of our total estimated proved oil and gas reserves. This figure ties to a projected 55 new wells (164.8 Bcfe) and 25 sidetracks from existing wellbores (76.9 Bcfe). Our timetable for the 25 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 55 PUD locations, we project twelve wells to be drilled in 2012 (55.5 Bcfe); thirteen wells in 2013 (16.7 Bcfe); eight wells in 2014 (20.2 Bcfe); thirteen wells in 2015 (46.9 Bcfe), and nine wells in 2016 (25.5 Bcfe). None of these 55 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 PUDs during 2011.

	Oil and Natural Gas (MMcfe)			Future Development Costs ($ in thousands)
PUDs beginning of year		149,047		$	366,484
Revisions of previous estimates		(13,048	)		(29,246	)
Conversions to proved developed reserves		(13,460	)		(21,734	)
Additional PUDs added		119,117			292,491
PUDs end of year		241,656		$	607,995

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During 2011 we invested approximately $21.7 million to convert 13.5 Bcfe of proved undeveloped reserves to proved developed reserves, mainly in the Appalachian region.

The following represents additional information on our significant properties:

Field Name	Location	2011 Production (MMcfe)		December 31, 2011 Estimated Proved Reserves (MMcfe)		Nature of Interest
Mary	Appalachia		1,125		114,497		Working
Pompano	GOM Deep Water		85		101,227		Working
Mississippi Canyon Block 109	GOM Shelf		11,999		81,981		Working
Ship Shoal Block 113	GOM Shelf		12,631		49,303		Working
Heather	Appalachia		2,572		29,561		Working
Ewing Bank Block 305	GOM Shelf		4,266		22,413		Working
Main Pass Block 288	GOM Shelf		2,801		20,965		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 during the periods indicated.

	Year Ended December 31,
	2011		2010		2009
	(In thousands)
Acquisition costs, net of sales of unevaluated properties	$	270,354	$	127,069	$	9,072
Development costs (1)		426,355		241,387		199,375
Exploratory costs		84,199		42,205		78,582
Subtotal		780,908		410,661		287,029
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements		66,111		51,016		44,282
Total additions to oil and gas properties, net	$	847,019	$	461,677	$	331,311

(1) Includes asset retirement costs of $96,386, $56,444 and $78,387 for the years ended December 31, 2011, 2010 and 2009, respectively.

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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,
	2011		2010			2009
Production:
Oil (MBbls)		6,427		5,714			6,207
Natural gas (MMcf)		39,517		41,937			41,335
Oil and natural gas (MMcfe)		78,079		76,221			78,577
Average sales prices:(1)
Oil (per Bbl)	$	103.31	$	73.14		$	70.72
Natural gas (per Mcf)		4.94		5.56			6.59
Oil and natural gas (per Mcfe)		11.00		8.54			9.05
Expenses (per Mcfe):					��
Lease operating expenses (2)	$	2.30	$	2.00		$	2.00

(1) Includes the settlement of effective hedging contracts.

(2) Includes oil and gas operating costs and major maintenance expense and excludes production and ad valorem taxes.

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, 2011.

FIELD: Mary
	Year Ended December 31,
	2011		2010		2009
Production:
Oil (MBbls)		25		—		—
Natural gas (MMcf)		977		79		—
Oil and natural gas (MMcfe)		1,125		79		—
Average sales prices:
Oil (per Bbl)	$	75.60	$	—		—
Natural gas (per Mcf)		6.08		4.78		—
Oil and natural gas (per Mcfe)		6.94		4.78		—
Expenses (per Mcfe):
Lease operating expenses (1)	$	1.40	$	1.51		—

(1) Includes oil and gas operating costs and major maintenance expense and excludes production and ad valorem taxes.

The Pompano field accounted for approximately 17% of our estimated proved oil and natural gas reserves at December 31, 2011. We completed the acquisition of the Pompano field on December 28, 2011.

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

	Year Ended December 31,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive		6.00		3.00		6.00		4.10		12.00		6.75
Dry		1.00		0.64		—		—		—		—
Development Wells:
Productive		37.00		32.92		20.00		15.75		5.00		4.00
Dry		—		—		—		—		4.00		4.00

During the period beginning January 1, 2012 and ending February 21, 2012, we participated in the drilling of 3.00 gross (2.28 net) exploratory wells and 6.00 gross (4.00 net) development wells.

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Productive Well and Acreage Data. The following table sets forth certain statistics regarding the number of productive wells and developed and undeveloped acreage as of December 31, 2011.

	Gross		Net
Productive Wells:
Oil (1):
Gulf Coast Basin		137		121
Unconventional Onshore Oil		6		3
Appalachia		—		—
		143		124
Gas (2):
Gulf Coast Basin		91		66
Unconventional Onshore Oil		—		—
Appalachia		29		17
		120		83
Total		263		207
Developed Acres:
Gulf Coast Basin		399,795		311,675
Unconventional Onshore Oil		1,074		376
Appalachia		2,636		2,636
		403,505		314,687
Undeveloped Acres (3):
Gulf Coast Basin		603,352		487,754
Unconventional Onshore Oil		127,477		104,860
Appalachia		87,935		80,036
		818,764		672,650
Total		1,222,269		987,337

(1) 14 gross wells each have dual completions.

(2) 13 gross wells each have dual completions.

(3) Leases covering approximately 8.3% of our undeveloped gross acreage will expire in 2012, 28.7% in 2013, 13.1% in 2014, 13.8% in 2015, 12.4% in 2016, 2.4% in 2017, 13.3% in 2018, 4.0% in 2019, 2.1% in 2020 and 1.9% thereafter.

Title to Properties

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

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ITEM 3. LEGAL PROCEEDINGS

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 proposed assessments from the LDR for additional franchise taxes in the amount of $8.7 million resulting from audits of Stone and our subsidiaries. These assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the OCS, 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 2010 and 2011 for Stone remain subject to examination.

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 subsequently 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 alleged 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 were 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 disagreed with plaintiffs’ contentions. In October 2011, the parties agreed to a settlement of all claims asserted in this action, and the settlement was effected on January 31, 2012. The settlement did not have a materially adverse effect on the Company.

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. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

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

	High		Low
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	$	33.49	$	21.28
Second Quarter		35.94		27.44
Third Quarter		34.46		16.19
Fourth Quarter		29.71		14.64
2012
First Quarter (through February 21, 2012)	$	34.52	$	25.61

On February 21, 2012, the last reported sales price on the New York Stock Exchange Composite Tape was $33.89 per share. As of that date, there were 440 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 6 ³/4% Senior Subordinated Notes due 2014 and our 8 ⁵/8% 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 are sometimes 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 2011:

Period	Total Number of Shares (or Units) Purchased		Average Price Paid per  Share (or Unit)		Total Number of Shares (or Units) Purchased as Part of  Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet be Purchased Under the Plans or Programs
Share Repurchase Program:
October 2011		—		—		—
November 2011		—		—		—
December 2011		—		—		—
		—		—		—	$	92,928,632
Other:
October 2011		—	$	—		—
November 2011		—		—		—
December 2011		—		—		—
		—		—		—		N/A
Total		—	$	—		—

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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 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, 2006 at $35.35 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 (Fiscal Year Covered)	SGY		2011 Peer Group		2010 Peer Group		S&P 500 Index
12/31/07		132.70		132.37		110.97		105.49
12/31/08		31.17		71.22		41.27		66.46
12/31/09		51.06		115.56		69.07		84.05
12/31/10		63.06		139.39		105.99		96.71
12/31/11		74.63		126.93		76.36		98.76

The companies that comprised our Peer Group in 2011 were: ATP Oil & Gas Corporation, Cabot Oil & Gas Corporation, Callon Petroleum Company, Carrizo Oil & Gas, Inc., Cimarex Energy Company, Comstock Resources, Inc., Denbury Resources Inc., Energy Partners, Ltd., Energy XXI (Bermuda) Limited, Exco Resources Inc., McMoRan Exploration Company, Newfield Exploration Company, Petrohawk Energy Corporation, Petroleum Development Corporation, PetroQuest Energy, Inc., Range Resources Corporation, SM Energy Company, Swift Energy Company, W&T Offshore, Inc. and Whiting Petroleum Corporation. We expanded our Peer Group in 2011 to provide for comparables that better reflect our expansion into regions other than the Gulf of Mexico.

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.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2011. 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.

	Year Ended December 31,
	2011			2010			2009			2008			2007
	(In thousands, except per share amounts)
Statement of Operations Data:
Operating revenue:
Oil production	$	663,958		$	417,948		$	438,942		$	461,050		$	424,205
Gas production		195,243			233,055			272,353			336,665			329,047
Other operational income		3,938			5,916			4,326			5,989			4,917
Derivative income, net		1,418			3,265			3,061			3,327			—
Total operating revenue		864,557			660,184			718,682			807,031			758,169
Operating expenses:
Lease operating expenses		179,475			152,326			156,786			171,107			149,702
Other operational expenses		2,149			5,579			11,798			—			—
Production taxes		9,380			5,808			7,920			7,990			9,945
Depreciation, depletion and amortization		280,020			248,201			259,639			288,384			302,739
Write-down of oil and gas properties		—			—			508,989			1,324,327			8,164
Goodwill impairment		—			—			—			465,985			—
Accretion expense		30,764			34,469			39,306			17,392			17,620
Salaries, general and administrative expenses		40,169			42,759			41,367			43,504			33,584
Incentive compensation expense		11,600			5,888			6,402			2,315			5,117
Derivative expenses, net		—			—			—			—			666
Total operating expenses		553,557			495,030			1,032,207			2,321,004			527,537
Gain on divestiture		—			—			—			—			59,825
Income (loss) from operations		311,000			165,154			(313,525	)		(1,513,973	)		290,457
Other (income) expenses:
Interest expense		9,289			12,192			21,361			13,243			32,068
Interest income		(420	)		(1,464	)		(528	)		(11,250	)		(12,135	)
Other (income) expense, net		(1,942	)		(105	)		472			189			(740	)
Loss on early extinguishment of debt		607			1,820			—			—			844
Total other expenses		7,534			12,443			21,305			2,182			20,037
Net income (loss) before income taxes		303,466			152,711			(334,830	)		(1,516,155	)		270,420
Income tax provision (benefit)		109,134			56,282			(116,559	)		(369,146	)		88,984
Net income (loss)		194,332			96,429			(218,271	)		(1,147,009	)		181,436
Net income (loss) attributable to non-controlling interest		—			—			27			(77	)		—
Net income (loss) attributable to Stone Energy Corp.	$	194,332		$	96,429		($	218,298	)	($	1,146,932	)	$	181,436
Earnings and dividends per common share:
Basic earnings (loss) per share	$	3.97		$	1.99		($	4.97	)	($	35.89	)	$	6.50
Diluted earnings (loss) per share	$	3.97		$	1.99		($	4.97	)	($	35.89	)	$	6.49
Cash dividends declared		—			—			—			—			—
Cash Flow Data:
Net cash provided by operating activities	$	570,850		$	424,794		$	507,787		$	522,478		$	465,158
Net cash provided by (used in) investing activities		(679,250	)		(374,088	)		(316,079	)		(1,357,907	)		344,812
Net cash provided by (used in) financing activities		39,895			(13,043	)		(190,552	)		428,440			(393,706	)
Balance Sheet Data (at end of period):
Working capital (deficit)	($	13,282	)	$	30,382		$	26,137		$	123,339		$	412,445
Oil and gas properties, net		1,875,048			1,397,809			1,185,709			1,628,170			1,181,312
Total assets		2,165,751			1,679,090			1,454,242			2,109,852			1,889,603
Long-term debt, less current potion		620,000			575,000			575,000			825,000			400,000
Stone Energy Corporation stockholders’ equity		667,829			430,357			325,659			577,391			885,802

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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, 2011. 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.”Certain 2008 and 2009 amounts have been changed from amounts previously presented to correct prior period immaterial errors. 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. 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 expanded our reserve base outside of the conventional shelf of the GOM and into the more prolific reserve basins of the GOM deep water and Gulf Coast deep gas as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia. See“Item 1. Business – Strategy and Operational Overview.”

2011 Significant Events.

Acquisition of Pompano Field Working Interest – On December 28, 2011, we completed the acquisition of BP Exploration & Production Inc.’s (“BP”) 75% operated working interest in the five block deep water Pompano field in Mississippi Canyon, a 51% operated working interest in the adjacent Mississippi Canyon block 29, a 50% non-operated working interest in the Mica field which ties back to the Pompano platform, and a 75% interest in 23 deep water exploration leases located in the vicinity of the Pompano field. The stated purchase price of $204 million was adjusted under the agreement to $167.6 million, after adjusting for the effective date of July 1, 2011. The acquisition added estimated proved reserves of approximately 102 Bcfe to our reserve base as of December 31, 2011.

Appalachian Basin (Marcellus Shale) – We drilled a total of 27 horizontal Marcellus Shale wells and fractured 16 wells in 2011. Our year-end 2011 net production exit rate from Appalachia was approximately 20 MMcfe per day. The Marcellus Shale accounted for nearly 30% of our total estimated proved reserves at December 31, 2011 compared to just over 15% in 2010.

Mississippi Canyon 109 (Amberjack) Drilling Program – Our Amberjack drilling program included seven wells, four of which were drilled in 2011. All seven wells were successful in the two year program which was completed in 2011.

Deep Gas – During 2011, we had discoveries at our South Erath and LaPosada prospects.

2012 Outlook.

Our 2012 capital expenditure budget is approximately $625 million. This figure compares with a $475 - $500 million capital budget for 2011 and excludes material acquisitions and capitalized salaries, general and administrative expenses and interest. The budget is spread across our major areas of investment with approximately 34% allocated to the GOM conventional shelf, 24% allocated to deep water/deep gas projects, 30% allocated to the Marcellus Shale and 12% allocated to onshore oil projects and new venture opportunities. The allocation of capital across the various areas is subject to change based on several factors including permitting times, rig availability, non-operator decisions, farm-in opportunities and commodity pricing.

Known Trends and Uncertainties.

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 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.”

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Liquidity and Capital Resources

At February 21, 2012, we had $302.9 million of availability under our bank credit facility and cash on hand of approximately $75.9 million. Our capital expenditure budget for 2012 has been set at $625 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. We are also considering accessing the public or private markets or monetizing other assets as a source of financing.

We are subject to an annual evaluation by the BOEM for a continuation of our current exemption from supplemental bonding on plugging and abandoning obligations. It is possible that future legislation or agency action could have an adverse impact on our liquidity in the event we are required to post additional bonds or letters of credit.

Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $570.9 million during 2011 compared to $424.8 million and $507.8 million in 2010 and 2009, respectively. Based on our outlook of commodity prices and our estimated production, we expect our 2012 capital expenditures to exceed our cash flow provided by operating activities which will require additional borrowings under our bank credit facility.

Net cash flow used in investing activities totaled $679.3 million during 2011, which primarily represents our investment in oil and natural gas properties of $764.9 million offset by proceeds from the sale of oil and natural gas properties of $87.9 million. Approximately $270.4 million of the investment in oil and gas properties in 2011 related to leasehold acquisitions and the acquisition of producing properties. 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 provided by financing activities totaled $39.9 million for the year ended December 31, 2011, which primarily represents borrowings net of repayments under our bank credit facility of $45.0 million, less $4.0 million of deferred financing costs associated with our new bank credit facility and $2.6 million of net payments for share based compensation. 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 8 ¹/4% Senior Subordinated Notes due 2011 of $200.5 million, net of proceeds from the public offering of our 8 ⁵/8% 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.

Although we had a working capital deficit at December 31, 2011 of $13.3 million, we had $302.9 million of availability under our bank credit facility at February 21, 2012, providing for adequate liquidity.

Capital Expenditures.In 2011, additions to oil and gas property costs of $847.0 million included $270.4 million of lease and property acquisition costs, $24.1 million of capitalized salaries, general and administrative expenses (inclusive of incentive compensation) and $42.0 million of capitalized interest. These investments were financed by cash flow from operations and borrowings under our bank credit facility.

Bank Credit Facility. On April 26, 2011, we entered into an amended and restated revolving credit facility totaling $700 million through a syndicated bank group, replacing our previous $700 million facility. The credit facility matures on September 15, 2014. However, if the notes issued under our 2004 indenture are retired on or before April 15, 2014, the credit facility then matures on April 26, 2015. Our initial borrowing base under the credit facility was set at $400 million. On October 31, 2011, the bank group reaffirmed the existing borrowing base at $400 million.

At December 31, 2011, we had $45 million of outstanding borrowings under our bank credit facility and letters of credit totaling $61.1 million had been issued under the facility. As of February 21, 2012, we had $70 million of outstanding borrowings under our bank credit facility and letters of credit totaling $27.1 million had been issued under the facility, leaving $302.9 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”).

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The borrowing base under our bank credit facility is redetermined by the lenders semi-annually, on May 1 and November 1, 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 our 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 consolidated EBITDA to consolidated Net Interest Expense, 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, 2011, our debt to EBITDA Ratio was 1.09 to 1 and our EBITDA to consolidated Net Interest Expense Ratio was approximately 70.37 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. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.

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, 2011, 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. During the years ended December 31, 2009 and 2008, respectively, 100,000 shares and 200,000 shares were repurchased under this program. No shares were repurchased during the years ended December 31, 2011 or 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, 2011 (in thousands):

	Total		Less than 1 Year		1-3 Years		4-5 Years		More than 5 Years
Contractual Obligations and Commitments:
8 5/8% Senior Notes due 2017	$	375,000	$	—	$	—	$	—	$	375,000
6 3/4% Senior Subordinated Notes due 2014		200,000		—		200,000		—		—
Bank credit facility (1)		45,000		—		45,000		—		—
Interest and commitment fees (2)		213,613		49,282		96,948		64,688		2,695
Asset retirement obligations including accretion		782,265		66,345		183,656		61,614		470,650
Rig commitments (3)		26,031		24,220		1,811		—		—
Seismic data commitments (4)		33,245		14,658		18,587		—		—
Operating lease obligations		1,775		723		840		212		—
Total Contractual Obligations and Commitments	$	1,676,929	$	155,228	$	546,842	$	126,514	$	848,345

(1) The bank credit facility matures on September 15, 2014. However, if the notes issued under our 2004 indenture are retired on or before April 15, 2014, the credit facility then matures on April 26, 2015. For purposes of this table, it is assumed that the 2004 notes are not retired.

(2) Includes interest on senior notes, senior subordinated notes and bank credit facility. Assumes 4.25% interest rate on the bank credit facility and 0.5% fee on unused commitments under bank credit facility.

(3) Includes a rig agreement executed in January 2012 with a term of 36 days at a day rate of $31 per day.

(4) Represents pre-commitments for seismic data purchases. Includes a seismic purchase committed to in February 2012 for a three-year period for a total of $8,500.

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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 BOEM. Our TRIR is provided to the BOEM 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:

Year Ended December 31,	TRIR Performance		TRIR Goal
2011		0.33		0.65
2010		0.51		0.65
2009		0.18		0.85

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

2011 Compared to 2010.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,
	2011		2010		Variance			% Change
Production:
Oil (MBbls)		6,427		5,714		713			12	%
Natural gas (MMcf)		39,517		41,937		(2,420	)		(6	%)
Oil and natural gas (MMcfe)		78,079		76,221		1,858			2	%
Average prices:(1)
Oil (per Bbl)	$	103.31	$	73.14	$	30.17			41	%
Natural gas (per Mcf)		4.94		5.56		(0.62	)		(11	%)
Oil and natural gas (per Mcfe)		11.00		8.54		2.46			29	%
Expenses (per Mcfe):
Lease operating expenses	$	2.30	$	2.00	$	0.30			15	%
Salaries, general and administrative expenses (2)		0.51		0.56		(0.05	)		(9	%)
DD&A expense on oil and gas properties		3.54		3.18		0.36			11	%
Estimated Proved Reserves at December 31:
Oil (MBbls)		45,754		33,203		12,551			38	%
Natural gas (MMcf)		327,352		274,705		52,647			19	%
Oil and natural gas (MMcfe)		601,880		473,923		127,957			27	%

(1) Includes the settlement of effective hedging contracts.

(2) Exclusive of incentive compensation expense.

For the year ended December 31, 2011, we reported net income totaling $194.3 million, or $3.97 per share, compared to net income for the year ended December 31, 2010 of $96.4 million, or $1.99 per share. All per share amounts are on a diluted basis.

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

Production.Production volumes during the year ended December 31, 2011 totaled 6,427,000 barrels of oil and 39.5 Bcf of natural gas compared to 5,714,000 barrels of oil and 41.9 Bcf of natural gas produced during the year ended December 31, 2010, an increase on a gas equivalent basis of 1.9 Bcfe. The increase in oil production volumes was primarily due to increases in production at our Mississippi Canyon Block 109 and Ship Shoal Block 113 fields where we had development operations. The decrease in gas production volumes was primarily due to natural production declines.

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Prices. Prices realized during the year ended December 31, 2011 averaged $103.31 per barrel of oil and $4.94 per Mcf of natural gas, or 29% higher, on an Mcfe basis, than 2010 average realized prices of $73.14 per barrel of oil and $5.56 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 year ended December 31, 2011, effective hedging transactions increased our average realized natural gas price by $0.49 per Mcf and decreased our average realized oil price by $5.09 per Bbl. During the year ended December 31, 2010, effective hedging transactions increased our average realized natural gas price by $0.93 per Mcf and decreased our average realized oil price by $5.09 per Bbl.

Revenue. Oil and natural gas revenue increased 32% to $859.2 million during the year ended December 31, 2011 from $651.0 million during the year ended December 31, 2010. The increase was primarily due to a 41% increase in average realized oil prices along with a 12% increase in oil production volumes, partially offset by a decline in average realized gas prices and gas production volumes.

Expenses. Lease operating expenses for the years ended December 31, 2011 and 2010 totaled $179.5 million and $152.3 million, respectively. On a unit of production basis, lease operating expenses were $2.30 per Mcfe and $2.00 per Mcfe for the years ended December 31, 2011 and 2010, respectively. The increase in lease operating expenses in 2011 was primarily attributable to increased platform and well maintenance.

For the year ended December 31, 2011, other operational expenses of $2.1 million included $0.7 million for the settlement of litigation associated with an expensed operation in the first quarter of 2011, a $0.3 million loss on the sale of non-dedicated tubular inventory and $1.1 million of miscellaneous inventory charges. 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.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the year ended December 31, 2011 totaled $276.5 million, or $3.54 per Mcfe, compared to DD&A expense of $242.7 million, or $3.18 per Mcfe in the year ended December 31, 2010. The increase in DD&A in 2011 on a unit basis was primarily attributable to the unit cost of current year net reserve additions (including future development costs) exceeding the per unit amortizable base as of the beginning of the year. The average unit cost of the deep water assets acquired from BP had a minimal impact on the DD&A rate because the acquisition occurred late in the year.

For the years ended December 31, 2011 and 2010, accretion expense totaled $30.8 million and $34.5 million, respectively. The decrease is primarily due to a change in the timing on certain of our asset retirement obligations.

For the years ended December 31, 2011 and 2010, incentive compensation expense totaled $11.6 million and $5.9 million, respectively. These amounts related to incentive compensation bonuses calculated based on the achievement of certain strategic objectives for each year.

Interest expense for the year ended December 31, 2011 totaled $9.3 million, net of $42.0 million of capitalized interest, compared to interest expense of $12.2 million, net of $30.8 million of capitalized interest, during the year ended December 31, 2010. The decrease in interest expense is primarily the result of an increase in the amount of interest capitalized as a part of the cost of oil and gas properties.

Our effective income tax rate was 36.0% and 36.9% for the years ended December 31, 2011 and 2010, respectively. The decreased rate primarily relates to the finalization of permanent deductions in the filing of prior period amended returns.

Asset Retirement Obligations. In October 2010, we received notification from the BOEM indicating that certain identified wells and facilities operated by us would 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. The final order has been issued by the BSEE, the successor to the BOEM in this matter, and our current estimate of asset retirement obligations includes the impact of the timing of this plan.

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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	%

(1) Includes the settlement of effective hedging contracts.

(2) Exclusive of incentive compensation expense.

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 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 $0.93 per Mcf and $2.45 per Mcf, respectively. Average realized oil prices were decreased during the year ended December 31, 2010 by $5.09 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.

Revenue. 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.

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.

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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. For the year ended December 31, 2009, other operational expenses of $11.8 million included a charge of $2.4 million related to the cancellation of a drilling contract based on declining commodity prices and the economic environment at that time and a $9.4 million write-down of our tubular inventory. The $9.4 million charge was the result of the market value of certain of our tubular goods falling below historical cost.

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.

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.

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 BOEM indicating that certain identified wells and facilities operated by us would 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.

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.

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, 2011, 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 recording the acquisition of various deep water assets from BP in December 2011.

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Business Combinations.Our acquisition in 2011 of various deep water assets from BP was accounted for according to the guidance provided in Accounting Standards Codification 805, Business Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration transferred at fair value. Differences between the net fair value of assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain.

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. Estimated future net cash flows from proved reserves are calculated based on a twelve-month average pricing assumption.

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.

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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;

• estimates of fair value in business combinations;

• 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

None.

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 2011 would have decreased approximately $1.07 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 2012, 2013 and 2014 oil and natural gas production from the Gulf Coast Basin. Some of our fixed-price oil swap settlements are based upon an average of the NYMEX closing price for West Texas Intermediate (“WTI”) during the entire calendar month and some are based on the average of the ICE closing price for Brent crude oil during the entire calendar month. Our fixed-price gas swap settlements 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 fixed-price swap contracts for 2012, 2013 and 2014 are with J.P. Morgan Chase Bank, N.A., The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank of Nova Scotia, Bank of America and Natixis.

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The following table illustrates our hedging positions for calendar years 2012, 2013 and 2014 as of February 21, 2012:

	Fixed-Price  Swaps NYMEX (except where noted)
	Natural Gas				Oil
	Daily Volume (MMBtus/d)		Swap Price ($)		Daily Volume (Bbls/d)			Swap Price ($)
2012		10,000		5.035		1,000			90.30
2012		10,000		5.040		1,000			90.41
2012		10,000		5.050		1,000			90.45
2012						1,000			95.50
2012						2,000			97.60
2012						1,000			98.15
2012						1,000			100.00
2012						1,000			101.55
2012						1,000			104.25
2012						1,000	†		111.02
2013		10,000		5.270		1,000			94.45
2013		10,000		5.320		1,000			94.60
2013						1,000			97.15
2013						1,000			101.53
2013						1,000			103.00
2013						1,000			104.50
2013						1,000	†		107.30
2014						1,000	†		103.30

† Brent oil contract

We believe these positions have hedged approximately 44% of our estimated 2012 production from estimated proved reserves, 31% of our estimated 2013 production from estimated proved reserves and 3% of our estimated 2014 production from estimated proved reserves.

Interest Rate Risk.We had long-term debt outstanding of $620 million at December 31, 2011, of which $575 million, or approximately 93%, bears interest at fixed rates. The $575 million of fixed-rate debt is comprised of $375 million of 8 ⁵/8% Senior Notes due 2017 and $200 million of 6 ³/4% Senior Subordinated Notes due 2014. At December 31, 2011, the remaining $45 million of our outstanding long-term debt bears interest at a floating rate and consists of borrowings outstanding under our bank credit facility. At December 31, 2011, the weighted average interest rate under our bank credit facility was approximately 4.25%. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. The $45 million of outstanding borrowings under the credit facility related to a borrowing on December 27, 2011 and as such, interest expense for our floating rate bank credit facility was minimal in 2011.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information concerning this Item begins on Page F-1.

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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, 2011. Based on this evaluation, our principal executive officer and principal financial officer believe that as of the end of the year ended December 31, 2011:

• 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, 2011 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, 2011. 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, 2011. 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, 2011.

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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, 2011, 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, 2011, 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, 2011 and 2010, 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, 2011 and our report dated February 27, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 27, 2012

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The following table sets forth information regarding the names, ages (as of February 21, 2012) 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		63	President, Chief Executive Officer and Director
Kenneth H. Beer		54	Executive Vice President and Chief Financial Officer
Andrew L. Gates, III		64	Senior Vice President, General Counsel and Secretary
E. J. Louviere		63	Senior Vice President – Land
John R. Pantaleo		54	Vice President – Gulf of Mexico
J. Kent Pierret		56	Senior Vice President, Chief Accounting Officer and Treasurer
Richard L. Smith		53	Executive Vice President – Exploration and Business Development
Richard L. Toothman, Jr.		47	Vice President – Appalachia
Jerome F. Wenzel, Jr.		59	Executive Vice President – Operations
Florence M. Ziegler		51	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. Pantaleowas 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.

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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 2012 Annual Meeting of Stockholders to be held on May 24, 2012. 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 2012 Annual Meeting of Stockholders to be held on May 24, 2012.

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 2012 Annual Meeting of Stockholders to be held on May 24, 2012.

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 2012 Annual Meeting of Stockholders to be held on May 24, 2012.

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 2012 Annual Meeting of Stockholders to be held on May 24, 2012.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	1.	Financial Statements:
		The following consolidated financial statements, notes to the consolidated financial statements and the Report of Independent Registered Public Accounting Firm thereon are included beginning on page F-1 of this Form 10-K:
		Report of Independent Registered Public Accounting Firm
		Consolidated Balance Sheet as of December 31, 2011 and 2010
		Consolidated Statement of Operations for the three years in the period ended December 31, 2011
		Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2011
		Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period ended December 31, 2011
		Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2011
		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:

2.1	Purchase and Sale Agreement by and between BP Exploration & Production Inc. and Stone Energy Offshore, L.L.C., dated effective as of November 18, 2011 (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed December 28, 2011 (File No. 001-12074)).
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 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)).

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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	First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)).
†10.4	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)).
†10.5	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)).
†10.6	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)).
†10.7	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)).
†10.8	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)).
†10.9	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)).
†10.10	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)).
10.11	$700,000,000 Third Amended and Restated Credit Agreement among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions named therein, dated April 26, 2011 (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-12074)).
10.12	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)).

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†10.13	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)).
†10.14	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)).
†10.15	Stone Energy Corporation Executive Change in Control Severance Policy (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)).
10.16	Form of Indemnification Agreement between Stone Energy Corporation and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed March 27, 2009 (File No. 001-12074)).
*21.1	Subsidiaries of the Registrant.
*23.1	Consent of Independent Registered Public Accounting Firm.
*23.2	Consent of Netherland, Sewell & Associates, Inc.
*31.1	Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2	Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1	Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
**101.INS	XBRL Instance Document
**101.SCH	XBRL Schema Document
**101.CAL	XBRL Calculation Linkbase Document
**101.DEF	XBRL Definition Linkbase Document
**101.LAB	XBRL Label Linkbase Document
**101.PRE	XBRL Presentation Linkbase Document
*99.1	Report of Netherland, Sewell & Associates, Inc.

* Filed or furnished herewith.

** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

# Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

† Identifies management contracts and compensatory plans or arrangements.

42

SIGNATURES

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

	STONE ENERGY CORPORATION
Date: February 27, 2012	By:	/s/ David H. Welch
		David H. Welch
		President and Chief Executive Officer

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

Signature	Title	Date
/s/ David H. Welch David H. Welch	President, Chief Executive Officer and Director	February 27, 2012
	(principal executive officer)
/s/ Kenneth H. Beer	Executive Vice President and	February 27, 2012
Kenneth H. Beer	Chief Financial Officer (principal financial officer)
/s/ J. Kent Pierret	Senior Vice President, Chief	February 27, 2012
J. Kent Pierret	Accounting Officer and Treasurer (principal accounting officer)
/s/ George R. Christmas George R. Christmas	Director	February 27, 2012
/s/ B.J. Duplantis B.J. Duplantis	Director	February 27, 2012
/s/ Peter D. Kinnear Peter D. Kinnear	Director	February 27, 2012
/s/ John P. Laborde John P. Laborde	Director	February 27, 2012
/s/ Robert S. Murley Robert S. Murley	Director	February 27, 2012
/s/ Richard A. Pattarozzi Richard A. Pattarozzi	Director	February 27, 2012
/s/ Donald E. Powell Donald E. Powell	Director	February 27, 2012
/s/ Kay G. Priestly Kay G. Priestly	Director	February 27, 2012
/s/ Phyllis M. Taylor Phyllis M. Taylor	Director	February 27, 2012

43

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheet as of December 31, 2011 and 2010	F-3
Consolidated Statement of Operations for the years ended December 31, 2011, 2010 and 2009	F-4
Consolidated Statement of Cash Flows for the years ended December 31, 2011, 2010 and 2009	F-5
Consolidated Statement of Changes in Stockholders’ Equity for the years ended December  31, 2011, 2010 and 2009	F-6
Consolidated Statement of Comprehensive Income for the years ended December  31, 2011, 2010 and 2009	F-7
Notes to Consolidated Financial Statements	F-8

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

Stone Energy Corporation

We have audited the accompanying consolidated balance sheets of Stone Energy Corporation as of December 31, 2011 and 2010, 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, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Stone Energy Corporation as of December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2009 the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Stone Energy Corporation’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

February 27, 2012

F-2

STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

(Amounts in thousands of dollars, except per share amounts)

	December 31,
	2011			2010
Assets
Current assets:
Cash and cash equivalents	$	38,451		$	106,956
Restricted cash		—			5,500
Accounts receivable		118,139			88,529
Fair value of hedging contracts		25,177			12,955
Current income tax receivable		19,946			—
Deferred taxes		26,072			27,274
Inventory		4,643			6,465
Other current assets		791			768
Total current assets		233,219			248,447
Oil and gas properties, full cost method of accounting:
Proved		6,648,168			5,789,578
Less: accumulated depreciation, depletion and amortization		(5,174,729	)		(4,804,949	)
Net proved oil and gas properties		1,473,439			984,629
Unevaluated		401,609			413,180
Other property and equipment, net of accumulated depreciation of $24,263 and $22,467, respectively		11,172			10,722
Fair value of hedging contracts		22,543			—
Other assets, net of accumulated depreciation and amortization of $5,911 and $11,277, respectively		23,769			22,112
Total assets	$	2,165,751		$	1,679,090
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	102,946		$	103,208
Undistributed oil and gas proceeds		27,328			10,037
Accrued interest		14,059			14,062
Fair value of hedging contracts		11,122			32,144
Asset retirement obligations		62,676			42,300
Current income tax payable		—			239
Other current liabilities		28,370			16,075
Total current liabilities		246,501			218,065
Long-term debt		620,000			575,000
Deferred taxes		247,835			99,227
Asset retirement obligations		363,103			331,620
Fair value of hedging contracts		815			3,606
Other long-term liabilities		19,668			21,215
Total liabilities		1,497,922			1,248,733
Commitments and contingencies
Stockholders’ equity:
Common stock, $.01 par value; authorized 100,000,000 shares; issued 48,076,860 and 47,764,505 shares, respectively		481			478
Treasury stock (16,582 shares, respectively, at cost)		(860	)		(860	)
Additional paid-in capital		1,338,565			1,331,500
Accumulated deficit		(692,225	)		(886,557	)
Accumulated other comprehensive income (loss)		21,868			(14,204	)
Total stockholders’ equity		667,829			430,357
Total liabilities and stockholders’ equity	$	2,165,751		$	1,679,090

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

F-3

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF OPERATIONS

(Amounts in thousands, except per share amounts)

	Year Ended December 31,
	2011			2010			2009
Operating revenue:
Oil production	$	663,958		$	417,948		$	438,942
Gas production		195,243			233,055			272,353
Other operational income		3,938			5,916			4,326
Derivative income, net		1,418			3,265			3,061
Total operating revenue		864,557			660,184			718,682
Operating expenses:
Lease operating expenses		179,475			152,326			156,786
Other operational expenses		2,149			5,579			11,798
Production taxes		9,380			5,808			7,920
Depreciation, depletion and amortization		280,020			248,201			259,639
Write-down of oil and gas properties		—			—			508,989
Accretion expense		30,764			34,469			39,306
Salaries, general and administrative expenses		40,169			42,759			41,367
Incentive compensation expense		11,600			5,888			6,402
Total operating expenses		553,557			495,030			1,032,207
Income (loss) from operations		311,000			165,154			(313,525	)
Other (income) expenses:
Interest expense		9,289			12,192			21,361
Interest income		(420	)		(1,464	)		(528	)
Other income		(1,942	)		(776	)		(36	)
Loss on early extinguishment of debt		607			1,820			—
Other expense		—			671			508
Total other expenses		7,534			12,443			21,305
Net income (loss) before income taxes		303,466			152,711			(334,830	)
Provision (benefit) for income taxes:
Current		(20,386	)		5,808			30,376
Deferred		129,520			50,474			(146,935	)
Total income taxes		109,134			56,282			(116,559	)
Net income (loss)		194,332			96,429			(218,271	)
Less: Net income attributable to non-controlling interest		—			—			27
Net income (loss) attributable to Stone Energy Corporation	$	194,332		$	96,429		($	218,298	)
Basic earnings (loss) per share attributable to Stone Energy Corporation stockholders	$	3.97		$	1.99		($	4.97	)
Diluted earnings (loss) per share attributable to Stone Energy Corporation stockholders	$	3.97		$	1.99		($	4.97	)
Average shares outstanding		47,988			47,681			43,953
Average shares outstanding assuming dilution		48,030			47,706			43,953

The accompanying notes are an integral part of this statement.

F-4

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands of dollars)

	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income (loss)	$	194,332		$	96,429		($	218,271	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		280,020			248,201			259,639
Write-down of oil and gas properties		—			—			508,989
Accretion expense		30,764			34,469			39,306
Deferred income tax provision (benefit)		129,520			50,474			(146,935	)
Settlement of asset retirement obligations		(63,391	)		(36,901	)		(66,780	)
Non-cash stock compensation expense		5,905			5,692			5,944
Excess tax benefits		(1,493	)		(299	)		(2	)
Non-cash derivative (income) expense		(2,216	)		(324	)		5,142
Loss on early extinguishment of debt		607			1,820			—
Other non-cash expenses		306			1,837			10,971
Change in current income taxes		(19,451	)		(10,871	)		66,185
(Increase) decrease in accounts receivable		(19,600	)		49,633			50,159
(Increase) decrease in other current assets		(66	)		74			627
Decrease in inventory		1,619			2,123			17,561
Increase (decrease) in accounts payable		6,039			(773	)		(10,200	)
Increase (decrease) in other current liabilities		29,583			(18,088	)		(14,431	)
Other		(1,628	)		1,298			(117	)
Net cash provided by operating activities		570,850			424,794			507,787
Cash flows from investing activities:
Investment in oil and gas properties		(764,933	)		(401,767	)		(320,214	)
Proceeds from sale of oil and gas properties, net of expenses		87,930			31,635			5,553
Sale of fixed assets		—			—			35
Investment in fixed and other assets		(2,247	)		(2,949	)		(1,412	)
Acquisition of non-controlling interest in subsidiary		—			(1,007	)		(41	)
Net cash used in investing activities		(679,250	)		(374,088	)		(316,079	)
Cash flows from financing activities:
Proceeds from bank borrowings		75,000			—			—
Repayments of bank borrowings		(30,000	)		(175,000	)		(250,000	)
Redemption of senior subordinated notes		—			(200,503	)		—
Proceeds from issuance of senior notes		—			375,000			—
Proceeds from stock offering, net of expenses		—			—			60,447
Deferred financing costs		(4,017	)		(11,474	)		(141	)
Excess tax benefits		1,493			299			2
Purchase of treasury stock		—			—			(347	)
Net payments for share based compensation		(2,581	)		(1,365	)		(513	)
Net cash provided by (used in) financing activities		39,895			(13,043	)		(190,552	)
Net increase (decrease) in cash and cash equivalents		(68,505	)		37,663			1,156
Cash and cash equivalents, beginning of year		106,956			69,293			68,137
Cash and cash equivalents, end of year	$	38,451		$	106,956		$	69,293
Supplemental disclosures of cash flow information: Cash (paid) refunded during the year for:
Interest, net of amount capitalized	($	9,808	)	($	8,760	)	($	20,623	)
Income taxes		935			(26,525	)		35,920

The accompanying notes are an integral part of this statement.

F-5

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Amounts in thousands of dollars)

	Stone Energy Corporation Stockholders
	Common Stock		Treasury Stock			Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Non-controlling Interest			Total Stockholders’ Equity
Balance, December 31, 2008	$	394	($	860	)	$	1,257,633		($	764,688	)	$	84,912		$	87		$	577,478
Net income (loss)		—		—			—			(218,298	)		—			27			(218,271	)
Adjustment for fair value accounting of derivatives, net of tax		—		—			—			—			(100,292	)		—			(100,292	)
Acquisition of non-controlling interest		—		—			73			—			—			(114	)		(41	)
Exercise of stock options and vesting of restricted stock		—		—			(514	)		—			—			—			(514	)
Amortization of stock compensation expense		—		—			8,845			—			—			—			8,845
Net tax deficit from stock option exercises and restricted stock vesting		—		—			(1,647	)		—			—			—			(1,647	)
Stock repurchase and cancellation		—		—			(346	)		—			—			—			(346	)
Issuance of common stock		81		—			60,366			—			—			—			60,447
Balance, December 31, 2009		475		(860	)		1,324,410			(982,986	)		(15,380	)		—			325,659
Net income		—		—			—			96,429			—			—			96,429
Adjustment for fair value accounting of derivatives, net of tax		—		—			—			—			1,176			—			1,176
Exercise of stock options and vesting of restricted stock		3		—			(1,370	)		—			—			—			(1,367	)
Amortization of stock compensation expense		—		—			8,462			—			—			—			8,462
Net tax deficit from stock option exercises and restricted stock vesting		—		—			(2	)		—			—			—			(2	)
Balance, December 31, 2010		478		(860	)		1,331,500			(886,557	)		(14,204	)		—			430,357
Net income		—		—			—			194,332			—			—			194,332
Adjustment for fair value accounting of derivatives, net of tax		—		—			—			—			36,072			—			36,072
Exercise of stock options and vesting of restricted stock		3		—			(2,584	)		—			—			—			(2,581	)
Amortization of stock compensation expense expense		—		—			8,914			—			—			—			8,914
Net tax benefit from stock option exercises and restricted stock vesting		—		—			735			—			—			—			735
Balance, December 31, 2011	$	481	($	860	)	$	1,338,565		($	692,225	)	$	21,868		$	—		$	667,829

The accompanying notes are an integral part of this statement.

F-6

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

(Amounts in thousands of dollars)

	Year Ended December 31,
	2011		2010		2009
Net income (loss) attributable to Stone Energy Corporation	$	194,332	$	96,429	($	218,298	)
Other comprehensive income (loss) net of tax effect:
Adjustment for fair value accounting of derivatives		36,072		1,176		(100,292	)
Comprehensive income (loss) attributable to Stone Energy Corporation	$	230,404	$	97,605	($	318,590	)

The accompanying notes are an integral part of this statement.

F-7

STONE ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Amounts in thousands of dollars, except per share and price amounts)

NOTE 1 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stone Energy is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties. 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 expanded our reserve base outside of the conventional shelf of the Gulf of Mexico (“GOM”) and into the more prolific reserve basins of the GOM deep water and Gulf Coast deep gas as well as onshore oil and gas shale opportunities, including the Marcellus Shale in Appalachia. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.

A summary of significant accounting policies followed in the preparation of the accompanying consolidated financial statements is set forth below.

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiaries, Stone Energy Offshore, L.L.C. (“Stone Offshore”), Stone Energy, L.L.C. and Caillou Boca Gathering, LLC (“Caillou Boca”). On December 31, 2010, Stone Energy, L.L.C. was merged into Stone Offshore. From August 2008 to the second quarter of 2009, Calliou Boca was a majority owned subsidiary. During the second quarter of 2009, we acquired the entire non-controlling interest in Calliou Boca. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates:

The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (“U.S. GAAP”) requires our management 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 revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization, unevaluated property costs, estimated future net cash flows from proved reserves, cost to abandon oil and gas properties, taxes, accruals of capitalized costs, operating costs and production revenue, capitalized general and administrative costs and interest, insurance recoveries, effectiveness and estimated fair value of derivative positions, the purchase price allocation on properties acquired, estimates of fair value in business combinations and contingencies.

Fair Value Measurements:

U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures about fair value measurements. As of December 31, 2011, 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 recording the acquisition of various deep water assets from BP Exploration & Production Inc. (“BP”) in December 2011.

Business Combinations:

Our acquisition in 2011 of various deep water assets from BP was accounted for according to the guidance provided in Accounting Standards Codification (“ASC”) 805, Business Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration transferred at fair value. Differences between the net fair value of assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain.

Cash and Cash Equivalents:

We consider all money market funds and highly liquid investments in overnight securities through our commercial bank accounts, which result in available funds on the next business day, to be cash and cash equivalents.

F-8

Restricted Cash:

At December 31, 2010, the restricted cash balance of $5,500 related to escrowed amounts on deposit with a qualified intermediary involved in a tax-free exchange of properties. These amounts became unrestricted in January 2011.

Oil and Gas Properties:

We follow the full cost method of accounting for 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 finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. 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. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.

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 depreciation, depletion and amortization (“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.

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.

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 (SeeNote 6 – Investment in Oil and Gas Properties).

Historically, estimated future net cash flows from proved reserves were calculated based on period-end hedge adjusted commodity prices, and the impact of price increases subsequent to the period end could be considered. In December 2008, the Securities and Exchange Commission (“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. Additionally, consideration of the impact of subsequent price increases after period end is no longer allowed. 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.

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.

F-9

Asset Retirement Obligations:

U.S. GAAP requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The application of this rule requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

Other Property and Equipment:

Building and land are recorded at cost. Our office building in Lafayette, Louisiana is being depreciated on the straight-line method over its estimated useful life of 39 years.

Inventory:

We maintain an inventory of tubular goods. Items remain in inventory until dedicated to specific projects, at which time they are transferred to oil and gas properties. Items are carried at the lower of cost or market applied to items specifically identified.

Earnings Per Common Share:

Under U.S. GAAP, certain instruments granted in share-based payment transactions are participating securities prior to vesting and are therefore required to be included in the earnings allocation in calculating earnings per share under the two-class method. Companies are required to treat unvested share-based payment awards with a right to receive non-forfeitable dividends as a separate class of securities in calculating earnings per share.

Production Revenue:

We recognize production revenue under the entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production.

Income Taxes:

Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures, including future abandonment costs, related to evaluated projects are capitalized and depreciated, depleted and amortized on the UOP method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion (for 2010 and 2011, special provisions allowed for current deductions for the cost of certain equipment). Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, different reporting methods used in the capitalization of employee, general and administrative and interest expenses, and different reporting methods for stock-based compensation.

Derivative Instruments and Hedging Activities:

The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. 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 (loss), net of related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flow from operations. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet at fair value and changes in fair value are recognized in earnings through derivative expense (income).

F-10

Stock-Based Compensation:

We record stock-based compensation based on the grant date fair value of issued stock options and restricted stock over the vesting period of the instrument. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The fair value of restricted shares is typically determined based on the average of our high and low stock prices on the grant date.

NOTE 2 — EARNINGS PER SHARE:

The following table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods.

	Year Ended December 31,
	2011			2010			2009
Income (numerator):
Basic:
Net income (loss) attributable to Stone Energy Corporation	$	194,332		$	96,429		($	218,298	)
Net income attributable to participating securities		(3,670	)		(1,559	)		—
Net income (loss) attributable to common stock – basic	$	190,662		$	94,870		($	218,298	)
Diluted:
Net income (loss) attributable to Stone Energy Corporation	$	194,332		$	96,429		($	218,298	)
Net income attributable to participating securities		(3,667	)		(1,558	)		—
Net income (loss) attributable to common stock – diluted	$	190,665		$	94,871		($	218,298	)
Weighted average shares (denominator):
Weighted average shares - basic		47,988			47,681			43,953
Diluted effect of stock options		42			25			—
Weighted average shares - diluted		48,030			47,706			43,953
Basic income (loss) per common share	$	3.97		$	1.99		($	4.97	)
Diluted income (loss) per common share	$	3.97		$	1.99		($	4.97	)

Stock options that were considered antidilutive because the exercise price of the option exceeded the average price of our common stock for the applicable period totaled approximately 374,000 and 420,000 during the years ended December 31, 2011 and 2010, respectively. All outstanding stock options (approximately 495,000 shares) were considered antidilutive during the year ended December 31, 2009 because we had a net loss for the period.

During the years ended December 31, 2011, 2010 and 2009, approximately 312,000, 255,000 and 129,000 shares of common stock, respectively, were issued from authorized shares upon the vesting (lapse of forfeiture restrictions) of restricted stock by employees and nonemployee directors. During the year ended December 31, 2009, 100,000 shares of common stock were repurchased under our stock repurchase program. On June 10, 2009, 8,050,000 shares of common stock were issued in a public offering.

F-11

NOTE 3 — ACCOUNTS RECEIVABLE:

In our capacity as operator for our co-venturers, we incur drilling and other costs that we bill to the respective parties based on their working interests. We also receive payments for these billings and, in some cases, for billings in advance of incurring costs. Our accounts receivable are comprised of the following amounts:

	As of December 31,
	2011		2010
Other co-venturers	$	8,890	$	6,769
Trade		91,959		75,653
Insurance receivable		4,236		1,718
Unbilled accounts receivable		13,009		4,352
Other		45		37
	$	118,139	$	88,529

We have accrued insurance receivables to the extent we have concluded the insurance recovery is probable. The accrual only relates to costs previously recorded in our financial statements, including asset retirement obligations and repair expenses included in lease operating expenses.

NOTE 4 — CONCENTRATIONS:

Sales to Major Customers

Our production is sold on month-to-month contracts at prevailing prices. We obtain credit protections such as parental guarantees from certain of our purchasers. The following table identifies customers from whom we derived 10% or more of our total oil and gas revenue during the years ended:

	December 31,
	2011			2010			2009
Conoco, Inc.		28	%		26	%		27	%
Hess Corporation		(a	)		11	%		11	%
Sequent Energy Management LP		(a	)		10	%		13	%
Shell Trading (US) Company		46	%		40	%		34	%
(a) Less than 10 percent

The maximum amount of credit risk exposure at December 31, 2011 relating to these customers amounted to $69,914.

We believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and gas production.

Production and Reserve Volumes

Approximately 50% of our estimated proved reserves (unaudited) at December 31, 2011 and 97% of our production during 2011 were associated with our Gulf Coast Basin conventional shelf properties. Approximately 21% of our estimated proved reserves (unaudited) at December 31, 2011 were associated with our GOM deep water and deep shelf gas properties.

Cash and Cash Equivalents

A substantial portion of our cash balances are not federally insured. At December 31, 2011 approximately $5,551 was invested in the J.P. Morgan Prime Money Market Fund (Capital Shares). An additional $29,868 was in accounts at J.P. Morgan Chase & Co.

F-12

NOTE 5 — ACQUISITIONS AND DIVESTITURES:

Acquisitions

On December 28, 2011, we completed the acquisition of BP’s 75% operated working interest in the five block deep water Pompano field in Mississippi Canyon, a 51% operated working interest in the adjacent Mississippi Canyon block 29, a 50% non-operated working interest in the Mica field which ties back to the Pompano platform and a 75% interest in 23 deep water exploration leases located in the vicinity of the Pompano field. The acquisition was accounted for according to the guidance provided in ASC 805, Business Combinations, which requires application of the acquisition method. This methodology requires the recordation of net assets acquired and consideration transferred at fair value (seeNote 8—Fair Value Measurements). Differences between the net fair value of assets acquired and consideration transferred are recorded as goodwill or a bargain purchase gain. The following represents the allocation of the recorded value of net assets acquired in the transaction. Consideration transferred in the transaction was $167,631 in cash, resulting in no goodwill or bargain purchase gain.

Proved oil and gas properties.	$	208,680
Unevaluated oil and gas properties.		17,314
Asset retirement obligations.		(58,363	)
Total fair value of net assets.	$	167,631

The following unaudited summary pro forma combined statement of operations data of Stone for the years ended December 31, 2011 and 2010 has been prepared to give effect to the acquisition of the deep water assets from BP as if it had occurred on January 1, 2010. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2010 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities, and other factors.

	Year Ended December 31,
	2011		2010
	(Unaudited)
Revenues	$	1,007,376	$	799,461
Income from operations		392,054		243,387
Net income		242,118		141,763
Basic earnings per share	$	4.95	$	2.93
Diluted earnings per share	$	4.95	$	2.92

In January 2011, we completed the acquisition of an additional 15% working interest in the Pyrenees project at a cost of approximately $14,974, bringing our ownership up to a 30% working interest. In December 2011, we completed the acquisition of a 25% non-operated working interest in the deep water Wideberth development project at a cost of approximately $31,000 and the assumption of approximately $1,078 of asset retirement obligations.

During the second half of 2011, we added approximately 10,000 net acres to our West Virginia leasehold position, including the acquisition of over 6,700 net acres from a single entity at a cost of approximately $19,000. During 2010, we acquired an approximate 26,000 net acre leasehold position in Appalachia from various landowners at a cost of approximately $74,334.

Divestitures

In the fourth quarter of 2011, we completed the sale of our non-operated interest in the Main Pass Block 296 and 311 fields to two separate parties for total cash consideration of approximately $80,381 and the assumption by the third parties of the associated asset retirement obligation of approximately $10,900. In April 2010, we divested our leasehold interest in approximately 7,000 acres in the Marcellus Shale for approximately $30,315. In the fourth quarter of 2010, we completed the sale of our interest in the Main Pass Block 41 Field for cash consideration of approximately $5,500. The estimated asset retirement obligation for this field was $632. The sales of these properties were accounted for as an adjustment of net capitalized costs with no gain or loss recognized.

F-13

NOTE 6 — INVESTMENT IN OIL AND GAS PROPERTIES:

The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore the continental United States:

		$000,000,00			$000,000,00			$000,000,00
	Year Ended December 31,
	2011			2010			2009
Oil and gas properties, proved and unevaluated:
Balance, beginning of year	$	6,202,758		$	5,741,081		$	5,409,770
Costs incurred during the year (capitalized):
Acquisition costs, net of sales of unevaluated properties		270,354			127,069			9,072
Exploratory costs		84,199			42,205			78,582
Development costs (1)		426,355			241,387			199,375
Salaries, general and administrative costs		24,430			20,521			19,107
Interest		42,033			30,783			25,573
Less: overhead reimbursements		(352	)		(288	)		(398	)
Total costs incurred during the year, net of divestitures		847,019			461,677			331,311
Balance, end of year	$	7,049,777		$	6,202,758		$	5,741,081
Accumulated depreciation, depletion and amortization (DD&A):
Balance, beginning of year	($	4,804,949	)	($	4,555,372	)	($	3,781,600	)
Provision for DD&A		(276,480	)		(242,745	)		(253,790	)
Write-down of oil and gas properties		—			—			(508,989	)
Sale of proved properties		(93,300	)		(6,832	)		(10,993	)
Balance, end of year	($	5,174,729	)	($	4,804,949	)	($	4,555,372	)
Net capitalized costs, proved and unevaluated	$	1,875,048		$	1,397,809		$	1,185,709
DD&A per Mcfe	$	3.54		$	3.18		$	3.23

(1) Includes asset retirement costs of $96,386, $56,444 and $78,387, respectively.

		$000,000,000,		$000,000,000,		$000,000,000,
Costs incurred during the year (expensed):
Lease operating expenses	$	179,475	$	152,326	$	156,786
Production taxes		9,380		5,808		7,920
Accretion expense		30,764		34,469		39,306
Expensed costs	$	219,619	$	192,603	$	204,012

At December 31, 2009, our ceiling test computation (See Note 1) resulted in a write-down of our U.S. oil and gas properties of $165,057 based on twelve-month average prices of $58.95 per barrel of oil and $3.49 per Mcf of natural gas. The benefit of hedges in place at December 31, 2009 reduced the write-down by $94,541. At March 31, 2009, our ceiling test computation resulted in a write-down of our U.S. oil and gas properties of $343,932 based on a March 31, 2009 gas price of $3.62 per Mcf and an oil price of $45.64 per barrel.

The following table discloses net costs incurred (evaluated) on our unevaluated properties:

		$000,000,000			$000,000,000		$000,000,000
	Year Ended December 31,
	2011			2010		2009
Unevaluated oil and gas properties:
Net costs incurred (evaluated) during year:
Acquisition costs	($	2,397	)	$	42,664	($	203,776	)
Exploration costs		(51,207	)		10,491		15,337
Capitalized interest		42,033			30,783		23,943
	($	11,571	)	$	83,938	($	164,496	)

F-14

The following table discloses financial data associated with unevaluated costs at December 31, 2011:

	Balance as of December 31, 2011		Net Costs Incurred During the Year Ended December 31,
			2011		2010		2009		2008 and prior
Acquisition costs	$	245,771	$	61,496	$	108,344	$	9,603	$	66,328
Exploration costs		99,542		55,931		9,658		33,953		—
Capitalized interest		56,296		19,232		28,226		5,002		3,836
Total unevaluated costs	$	401,609	$	136,659	$	146,228	$	48,558	$	70,164

Approximately 80 specifically identified drilling projects are included in unevaluated costs at December 31, 2011 and are expected to be evaluated in the next four years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs capitalized on unevaluated properties during the years ended December 31, 2011, 2010 and 2009 totaled $42,033, $30,783 and $23,943, respectively.

NOTE 7 — DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

Our hedging strategy is designed to protect our near and intermediate term cash flow from future declines in oil and natural gas prices. This protection is essential to capital budget planning which is sensitive to expenditures that must be committed to in advance such as rig contracts and the purchase of tubular goods. We enter into hedging transactions to secure a commodity price for a portion of future production that is acceptable at the time of the transaction. These hedges are designated as cash flow hedges upon entering into the contract. We do not enter into hedging transactions for trading purposes. We have no fair value hedges.

The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, it is recorded as either an asset or liability measured at fair value and subsequent changes in the derivative’s fair value are recognized in equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements of effective hedges are reflected in revenue from oil and gas production and cash flows from operations. Instruments not qualifying for hedge accounting are recorded in the balance sheet at fair value and changes in fair value are recognized in earnings through derivative expense (income). Typically, a small portion of our derivative contracts are determined to be ineffective. This is because oil and natural gas price changes in the markets in which we sell our products are not 100% correlative to changes in the underlying price basis indicative in the derivative contract. Monthly settlements of ineffective hedges are recognized in earnings through derivative expense (income) and cash flows from operations.

We have entered into fixed-price swaps with various counterparties for a portion of our expected 2012, 2013 and 2014 oil and natural gas production from the Gulf Coast Basin. Some of our fixed-price oil swap settlements are based on an average of the New York Mercantile Exchange (“NYMEX”) closing price for West Texas Intermediate (“WTI”) during the entire calendar month and some are based on the average of the Intercontinental Exchange (“ICE”) closing price for Brent crude oil during the entire calendar month. Our fixed-price gas swap settlements 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 fixed-price swap contracts for 2012, 2013 and 2014 are with J.P. Morgan Chase Bank, N.A., The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, the Bank of Nova Scotia, Bank of America and Natixis.

During 2009, a portion of our oil and natural gas production was hedged with zero-premium collars. The natural gas collar settlements were based on an average of NYMEX prices for the last three days of a respective month. The oil collar settlements were based on an average of the NYMEX closing price for WTI during the entire calendar month. The collar contracts required payments to the counterparties if the average price was above the ceiling price or payment from the counterparties if the average price was below the floor price.

All of our derivative instruments at December 31, 2011 and December 31, 2010 were designated as effective cash flow hedges; however, during the years ended December 31, 2011, 2010 and 2009, certain of our derivative contracts were determined to be partially ineffective. The following tables disclose the location and fair value amounts of derivative instruments reported in our balance sheet at December 31, 2011 and December 31, 2010.

F-15

Fair Value of Derivative Instruments at December 31, 2011
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of hedging contracts	$	25,177	Current liabilities: Fair value of hedging contracts	($	11,122	)
	Long-term assets: Fair value of hedging contracts		22,543	Long-term liabilities: Fair value of hedging contracts		(815	)
		$	47,720		($	11,937	)

Fair Value of Derivative Instruments at December 31, 2010
	Asset Derivatives			Liability Derivatives
Description	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity contracts	Current assets: Fair value of hedging contracts	$	12,955	Current liabilities: Fair value of hedging contracts	($	32,144	)
	Long-term assets: Fair value of hedging contracts		—	Long-term liabilities: Fair value of hedging contracts		(3,606	)
		$	12,955		($	35,750	)

The following table discloses the effect of derivative instruments in the statement of operations for the years ended December 31, 2011, 2010 and 2009.

The Effect of Derivative Instruments on the Statement of Operations for the Years Ended December 31, 2011, 2010 and 2009
Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI on Derivative (a)			Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) (b)				Gain Recognized in Income on Derivative (Ineffective Portion)
				Location				Location
	2011				2011				2011
Commodity contracts	$	36,072		Operating revenue - oil/gas production	($	13,274	)	Derivative income, net	$	1,418
Total	$	36,072			($	13,274	)		$	1,418
	2010				2010				2010
Commodity contracts	$	1,176		Operating revenue - oil/gas production	$	9,631		Derivative income, net	$	3,265
Total	$	1,176			$	9,631			$	3,265
	2009				2009				2009
Commodity contracts	($	100,292	)	Operating revenue - oil/gas production	$	163,176		Derivative income, net	$	3,061
Total	($	100,292	)		$	163,176			$	3,061

(a) Net of related tax effect.

(b) For the year ended December 31, 2011, effective hedging contracts decreased oil revenue by $32,706 and increased gas revenue by $19,432. For the year ended December 31, 2010, effective hedging contracts decreased oil revenue by $29,047 and increased gas revenue by $38,678. For the year ended December 31, 2009, effective hedging contracts increased oil revenue by $61,747 and increased gas revenue by $101,429.

On March 3, 2009, we unwound all of our then existing crude oil hedges for the period from April 2009 through December 2009, resulting in proceeds of approximately $59,007. On March 6, 2009, we unwound two of our natural gas hedges for the period from April 2009 through December 2009, resulting in proceeds of approximately $53,814. These amounts (net of the ineffective portion and related deferred income tax effect) were recorded in accumulated other comprehensive income in 2009. As the original time periods for these contracts expired, applicable amounts were reclassified into earnings.

At December 31, 2011, we had accumulated other comprehensive income of $21,868, net of tax, which related to the fair value of our swap contracts that were outstanding as of December 31, 2011. We believe that approximately $7,303 of the accumulated other comprehensive income will be reclassified into earnings in the next twelve months.

F-16

The following table illustrates our hedging positions for calendar years 2012, 2013 and 2014 as of February 21, 2012:

	Fixed-Price Swaps NYMEX (except where noted)
	Natural Gas				Oil
	Daily Volume (MMBtus/d)		Swap Price ($)		Daily Volume (Bbls/d)			Swap Price ($)
2012		10,000		5.035		1,000			90.30
2012		10,000		5.040		1,000			90.41
2012		10,000		5.050		1,000			90.45
2012						1,000			95.50
2012						2,000			97.60
2012						1,000			98.15
2012						1,000			100.00
2012						1,000			101.55
2012						1,000			104.25
2012						1,000	†		111.02
2013		10,000		5.270		1,000			94.45
2013		10,000		5.320		1,000			94.60
2013						1,000			97.15
2013						1,000			101.53
2013						1,000			103.00
2013						1,000			104.50
2013						1,000	†		107.30
2014						1,000	†		103.30

† Brent oil contract

NOTE 8 – FAIR VALUE MEASUREMENTS:

U.S. GAAP establishes a 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, 2011 and 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. We utilize the services of an independent third party to assist us in valuing our derivative instruments. We used the income approach in determining the fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts for the credit risk of Stone and its counterparties in the discount rate applied to estimated future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value hierarchy. For a more detailed description of our derivative instruments, seeNote 7 - Derivative Instruments and Hedging Activities. We used the market approach in determining the fair value of our investments in money market funds, which are included within the Level 1 fair value hierarchy.

F-17

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2011:

	Fair Value Measurements at December 31, 2011
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Money market funds	$	5,551	$	5,551	$	—	$	—
Hedging contracts		47,720		—		47,720		—
Total	$	53,271	$	5,551	$	47,720	$	—

	Fair Value Measurements at December 31, 2011
Liabilities	Total			Quoted Prices in Active Markets for Identical Liabilities (Level  1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Hedging contracts	($	11,937	)	$	—	($	11,937	)	$	—
Total	($	11,937	)	$	—	($	11,937	)	$	—

The following tables present our assets and liabilities that are measured at fair value on a recurring basis at December 31, 2010:

	Fair Value Measurements at December 31, 2010
Assets	Total		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Money market funds	$	7,306	$	7,306	$	—	$	—
Hedging contracts		12,955		—		12,955		—
Total	$	20,261	$	7,306	$	12,955	$	—

	Fair Value Measurements at December 31, 2010
Liabilities	Total			Quoted Prices in Active Markets for Identical Liabilities (Level  1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Hedging contracts	($	35,750	)	$	—	($	35,750	)	$	—
Total	($	35,750	)	$	—	($	35,750	)	$	—

The fair value of cash and cash equivalents and our variable-rate bank debt approximated book value at December 31, 2011 and 2010. As of December 31, 2011 and 2010, the fair value of our $375,000 8 ⁵/8% Senior Notes due 2017 was approximately $386,250 and $380,625, respectively. As of December 31, 2011 and 2010, the fair value of our $200,000 6 ³/4% Senior Subordinated Notes due 2014 was approximately $199,000 and $197,000, respectively. The fair value of our outstanding notes was determined based upon quotes obtained from brokers.

We applied fair value concepts in the recording of deep water assets acquired from BP (seeNote 5-Acquisitions and Divestitures). The fair value of proved and unevaluated oil and gas properties was estimated using a market approach. Significant inputs were market value comparisons for similar transactions within a one year period. These inputs were considered Level 3 inputs. Asset retirement obligations were determined in accordance with applicable accounting standards.

F-18

NOTE 9 — ASSET RETIREMENT OBLIGATIONS:

The change in our asset retirement obligations during 2011, 2010 and 2009 is set forth below:

	Year Ended December 31,
	2011			2010			2009
Asset retirement obligations as of the beginning of the year, including current portion	$	373,920		$	320,599		$	275,628
Liabilities incurred		7,993			1,528			3,035
Liabilities settled		(63,226	)		(36,392	)		(67,858	)
Liabilities assumed		59,441			—			—
Divestment of properties		(10,900	)		(692	)		(5,941	)
Accretion expense		30,764			34,469			39,306
Revision of estimates		27,787			54,408			76,429
Asset retirement obligations as of the end of the year, including current portion	$	425,779		$	373,920		$	320,599

NOTE 10 — INCOME TAXES:

An analysis of our deferred taxes follows:

	As of December 31,
	2011			2010
Tax effect of temporary differences:
Oil and gas properties – full cost	($	381,413	)	($	224,624	)
Asset retirement obligations		153,281			134,611
Stock compensation		4,962			4,932
Hedges		(12,882	)		8,205
Alternative minimum tax credit carryforward		5,358			—
Other		8,931			4,923
	($	221,763	)	($	71,953	)

We estimate that we have an approximate $20,386 current federal income tax benefit for the year ended December 31, 2011. We have a $19,946 current income tax receivable at December 31, 2011.

A reconciliation between the statutory federal income tax rate and our effective income tax rate as a percentage of income before income taxes follows:

	Year Ended December 31,
	2011			2010			2009
Income tax expense computed at the statutory federal income tax rate		35.0	%		35.0	%		(35.0	%)
Domestic production activities deduction		—			(0.6	)		—
State taxes and other		1.1			2.6			0.2
Statutory depletion		(0.1	)		(0.1	)		—
Effective income tax rate		36.0	%		36.9	%		(34.8	%)

In 2010 and 2009, we recognized a tax deduction for domestic production activities pursuant to Internal Revenue Code Section 199.

Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to $20,290, $292 and ($54,003) for the years ended December 31, 2011, 2010 and 2009, respectively.

F-19

As of December 31, 2011 and 2010, we had unrecognized tax benefits of $385 and $425, respectively. If recognized, all of our unrecognized tax benefits as of December 31, 2011 would impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits follows:

Total unrecognized tax benefits as of December 31, 2010	$	425
Increases (decreases) in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		—
Tax positions taken during the current period		—
Settlements with taxing authorities		(40	)
Lapse of applicable statute of limitations		—
Total unrecognized tax benefits as of December 31, 2011	$	385

Our unrecognized tax benefits pertain to proposed state income tax audit adjustments. We believe that our unrecognized tax benefits may be reduced to zero within the next 12 months upon completion and ultimate settlement of the state examinations.

It is our policy to classify interest and penalties associated with underpayment of income taxes as interest expense and general and administrative expenses, respectively. We have recognized $25, ($1,157) and $3,171 of interest expense related to uncertain tax positions for the years ended December 31, 2011, 2010 and 2009, respectively. We have not recognized any penalties in connection with our uncertain tax positions. The liabilities for unrecognized tax benefits and accrued interest payable are components of other current liabilities on our balance sheet.

The tax years 2008 through 2010 remain subject to examination by major tax jurisdictions.

NOTE 11 — LONG-TERM DEBT:

Long-term debt consisted of the following:

	As of December 31,
	2011		2010
6 3/4% Senior Subordinated Notes due 2014	$	200,000	$	200,000
8 5/8% Senior Notes due 2017		375,000		375,000
Bank debt		45,000		—
Total long-term debt	$	620,000	$	575,000

Bank Debt

On April 26, 2011, we entered into an amended and restated revolving credit facility totaling $700,000 through a syndicated bank group, replacing our previous $700,000 facility. The credit facility matures on September 15, 2014. However, if the notes issued under our 2004 indenture are retired on or before April 15, 2014, the credit facility then matures on April 26, 2015. Our initial borrowing base under the credit facility was set at $400,000. On October 31, 2011, the bank group reaffirmed the existing borrowing base at $400,000. On December 31, 2011, we had $45,000 of outstanding borrowings under our bank credit facility, letters of credit totaling $61,145 had been issued pursuant to the facility, and the weighted average interest rate under the bank credit facility was 4.25%. As of February 21, 2012, we had $70,000 of outstanding borrowings under our bank credit facility and letters of credit totaling $27,145 had been issued pursuant to the facility, leaving $302,855 of availability under the facility.

The borrowing base under our bank credit facility is redetermined by the lenders semi-annually, typically on May 1 and November 1, 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. If a reduction in our borrowing base were to fall below any outstanding balances under the credit facility plus any outstanding letters of credit, our agreement with the banks allows us one or more of three options to cure the borrowing base deficiency: (1) repay amounts outstanding sufficient to cure the deficiency within 10 days after our written election to do so; (2) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in the properties within thirty days after our written election to do so or (3) arrange to pay the deficiency in five equal monthly installments.

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Our bank credit facility is guaranteed by our only material subsidiary, Stone Offshore. 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 our bank 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 bank 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 consolidated EBITDA to consolidated Net Interest Expense, 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, 2011, our debt to EBITDA Ratio was 1.09 to 1 and our EBITDA to consolidated Net Interest Expense Ratio was approximately 70.37 to 1. In addition, our bank 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. These covenants also restrict our ability to prepay other indebtedness under certain circumstances.

Senior Notes

On January 26, 2010, we completed a public offering of $275,000 aggregate principal amount of 8 ⁵/8% Senior Notes due 2017 (the “2017 Notes”), which are fully and unconditionally guaranteed on a senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone. The net proceeds from the offering after deducting underwriting discounts, commissions, fees and expenses totaled $265,299. On November 17, 2010, we completed a public offering of an additional $100,000 aggregate principal amount of our 2017 Notes. The net proceeds from this offering after deducting underwriting discounts, commissions, fees and expenses totaled approximately $98,227. The 2017 Notes rank equally in right of payment with all of our existing and future senior debt, and rank senior in right of payment to all of our existing and future subordinated debt, including our outstanding senior subordinated notes. The 2017 Notes mature on February 1, 2017, and interest is payable on each February 1 and August 1, commencing on August 1, 2010. We may, at our option, redeem all or part of the 2017 Notes at any time prior to February 1, 2014 at a make-whole redemption price, and at any time on or after February 1, 2014 at fixed redemption prices. In addition, prior to February 1, 2013, we may, at our option, redeem up to 35% of the 2017 Notes with the cash proceeds of certain equity offerings. The 2017 Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. The violation of any of these covenants could give rise to a default, which if not cured could give the holder of the 2017 Notes a right to accelerate payment. At December 31, 2011, $13,477 had been accrued in connection with the February 1, 2012 interest payment.

Senior Subordinated Notes

On December 15, 2004, we issued $200,000 6 ³/4% Senior Subordinated Notes due 2014 (the “2014 Notes”). The 2014 Notes were sold at par value and we received net proceeds of $195,500. The 2014 Notes are subordinated to our senior unsecured credit facility. There is no sinking fund requirement. Beginning December 15, 2009, the 2014 Notes are redeemable at our option, in whole or in part, at 103.375% of their principal amount and thereafter at prices declining annually to 100% on and after December 15, 2012. The 2014 Notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. The violation of any of these covenants could give rise to a default, which if not cured could give the holder of the 2014 Notes a right to accelerate payment. At December 31, 2011, $563 had been accrued in connection with the June 15, 2012 interest payment. On August 28, 2008, we entered into a supplemental indenture governing the terms of our 2014 Notes. The 2014 Notes are now guaranteed by Stone Offshore on an unsecured senior subordinated basis.

On December 5, 2001, we issued $200,000 8 ¹/4% Senior Subordinated Notes due 2011 (the “2011 Notes”). In January 2010 we used the proceeds from the 2017 Notes offering to purchase our 2011 Notes pursuant to a tender offer and consent solicitation. In February 2010, the remaining 2011 Notes were redeemed in full. The total cost of the redemption was $202,382 which included $200,483 to redeem the notes plus accrued and unpaid interest of $1,899. The transaction resulted in a charge to earnings of $1,820 in 2010.

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Deferred Financing Cost and Interest Cost

Other assets at December 31, 2011 and 2010 included approximately $14,437 and $14,764, respectively, of deferred financing costs, net of accumulated amortization. These costs at December 31, 2011 related primarily to the issuance of the 2017 Notes, the 2014 Notes and our bank credit facility. The costs associated with the 2017 Notes and the 2014 Notes are being amortized over the life of the notes using a method that applies effective interest rates of 8.8% and 7.1%, respectively. The costs associated with our bank credit facility are being amortized over the term of the facility.

Total interest cost incurred, before capitalization, on all obligations for the years ended December 31, 2011, 2010 and 2009 was $51,322, $42,975 and $46,934 respectively.

NOTE 12 — STOCK-BASED COMPENSATION:

We record stock compensation expense under U.S. GAAP for stock options and other equity-based compensation awards based on the fair value on the date of grant. Compensation expense for equity-based compensation awards is recognized in our financial statements over the vesting period of the award.

For the year ended December 31, 2011, we incurred $8,914 of stock based compensation, of which $8,796 related to restricted stock issuances, $118 related to stock option grants and of which a total of approximately $3,010 was capitalized into oil and gas properties. For the year ended December 31, 2010, we incurred $8,462 of stock based compensation, of which $8,263 related to restricted stock issuances, $199 related to stock option grants and of which a total of approximately $2,775 was capitalized into oil and gas properties. For the year ended December 31, 2009, we incurred $8,845 of stock based compensation, of which $7,624 related to restricted stock issuances, $1,221 related to stock option grants and of which a total of approximately $2,901 was capitalized into oil and gas properties. Because of the non-cash nature of stock based compensation, the expensed portion of stock based compensation is added back to the net income (loss) in arriving at net cash provided by operating activities in our statement of cash flows. The capitalized portion is not included in net cash used in investing activities.

Under our 2009 Amended and Restated Stock Incentive Plan (the “2009 Plan”), we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise price of not less than the fair market value of the common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire ten years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire ten years subsequent to award. In addition, the 2009 Plan provides that shares available under the 2009 Plan may be granted as restricted stock. Restricted stock typically vests over a one to three-year period.

Stock Options.There were no stock option grants during the years ended December 31, 2011 or 2010, and stock options granted during the year ended December 31, 2009 were immaterial.

A summary of stock option activity under the Plan during the year ended December 31, 2011 is as follows (amounts in table represent actual values except where indicated otherwise):

	Number of Options			Wgtd. Avg. Exercise Price		Wgtd. Avg. Term		Aggregate Intrinsic Value (in  thousands)
Options outstanding, beginning of period		484,694		$	39.43
Granted		—			—
Exercised		—			—
Forfeited		(13,300	)		37.98
Expired		(33,000	)		48.85
Options outstanding, end of period		438,394			38.76		3.6 years	$	1,143
Options exercisable, end of period		378,710			41.66		3.1 years		457
Options unvested, end of period		59,684			20.36		6.1 years		686

Exercise prices for stock options outstanding at December 31, 2011 range from $6.97 to $53.20.

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A summary of stock option activity under the Plan during the year ended December 31, 2010 is as follows (amounts in table represent actual values except where indicated otherwise):

	Number of Options			Wgtd. Avg. Exercise Price		Wgtd. Avg. Term		Aggregate Intrinsic Value (in  thousands)
Options outstanding, beginning of period		495,283		$	39.61
Granted		—			—
Exercised		—			—
Forfeited		(6,190	)		40.85
Expired		(4,399	)		57.76
Options outstanding, end of period		484,694			39.43		3.8 years	$	880
Options exercisable, end of period		396,115			43.21		3.4 years		176
Options unvested, end of period		88,579			22.50		6.9 years		704

A summary of stock option activity under the Plan during the year ended December 31, 2009 is as follows (amounts in table represent actual values except where indicated otherwise):

	Number of Options			Wgtd. Avg. Exercise Price		Wgtd. Avg. Term		Aggregate Intrinsic Value (in  thousands)
Options outstanding, beginning of period		510,779		$	45.21
Granted		64,474			8.64
Exercised		—			—
Forfeited		(14,470	)		33.59
Expired		(65,500	)		54.15
Options outstanding, end of period		495,283			39.61		4.7 years	$	607
Options exercisable, end of period		363,709			44.40		4.1 years		—
Options unvested, end of period		131,574			26.37		7.3 years		607

Restricted Stock.The fair value of restricted shares is typically determined based on the average of our high and low stock prices on the grant date. During the year ended December 31, 2011, we issued 597,062 shares of restricted stock valued at $14,100. During the year ended December 31, 2010, we issued 395,869 shares of restricted stock valued at $6,251. During the year ended December 31, 2009, we issued 538,635 shares of restricted stock valued at $5,831.

A summary of the restricted stock activity under the Plan for the years ended December 31, 2011, 2010 and 2009 is as follows (amounts in table represent actual values):

	2011					2010					2009
	Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share		Number of Restricted Shares			Wgtd. Avg. Fair Value Per Share
Restricted stock outstanding, beginning of period		783,606		$	17.24		751,437		$	20.68		408,383		$	43.31
Issuances		597,062			23.62		395,869			15.79		538,635			10.83
Lapse of restrictions		(419,543	)		19.91		(343,657	)		23.09		(177,123	)		41.73
Forfeitures		(37,385	)		18.92		(20,043	)		18.07		(18,458	)		26.74
Restricted stock outstanding, end of period		923,740		$	20.08		783,606		$	17.24		751,437		$	20.68

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As of December 31, 2011, there was $11,541 of unrecognized compensation cost related to all non-vested share-based compensation arrangements under the Plan. That cost is being amortized on a straight-line basis over the vesting period and is expected to be recognized over a weighted-average period of 1.8 years.

Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits are credited to additional paid-in capital to the extent realized. If book compensation expense exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital or an increase in income tax expense depending on certain circumstances. Adjustments to additional paid-in capital related to the net tax effect of stock option exercises and restricted stock vesting were $735, ($2) and ($1,647) in 2011, 2010 and 2009, respectively.

NOTE 13 — SHARE REPURCHASE PROGRAM:

On September 24, 2007, our Board of Directors authorized a share repurchase program for an aggregate amount of up to $100,000. 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, 2011, 300,000 shares had been repurchased under this program at a total cost of $7,071, or an average price of $23.57 per share. During the years ended December 31, 2009 and 2008, respectively, 100,000 shares and 200,000 shares were repurchased under this program. No shares were repurchased during the years ended December 31, 2011 and 2010.

NOTE 14 — COMMITMENTS AND CONTINGENCIES:

Lease Commitments

We lease office facilities in Lafayette and New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia under the terms of long-term, non-cancelable leases expiring on various dates through 2015. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net annual commitments under all leases, subleases and contracts with non-cancelable terms in excess of 12 months at December 31, 2011 were as follows:

2012	$	723
2013		611
2014		229
2015		212

Payments related to our lease obligations for the years ended December 31, 2011, 2010 and 2009 were approximately $446, $703 and $738, respectively.

Other Commitments

We are contingently liable to surety insurance companies in the amount of $90,652 relative to bonds issued on our behalf to the Bureau of Ocean Energy Management (“BOEM”), federal and state agencies and certain third parties from which we purchased oil and gas working interests. The bonds represent guarantees by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.

In connection with our exploration and development efforts, we are contractually committed to the use of drilling rigs and the acquisition of seismic data in the aggregate amount of $59,276 to be incurred over the next three years.

The Oil Pollution Act of 1990 (“OPA”) imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under OPA and a final rule adopted by the BOEM in August 1998, responsible parties of covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state waters to at least $35,000 in Outer Continental Shelf (“OCS”) waters, with higher amounts of up to $150,000 in certain limited circumstances where the BOEM believes such a level is justified by the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the facility may exceed the applicable threshold volumes specified under the BOEM’s final rule. We do not anticipate that we will experience any difficulty in continuing to satisfy the BOEM’s requirements for demonstrating financial responsibility under OPA and the BOEM’s regulations.

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Litigation

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

Franchise Tax Action. We have been served with several petitions filed by the Louisiana Department of Revenue (“LDR”) in Louisiana state court claiming additional franchise taxes due. In addition, we have received preliminary assessments from the LDR for additional franchise taxes resulting from audits of Stone and other subsidiaries. These assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the OCS, 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. Total asserted claims plus estimated accrued interest amount to approximately $30,111. The franchise tax years 2010 and 2011 for Stone remain subject to examination, which potentially exposes us to additional estimated assessments of $3,276 including accrued interest. We estimate the potential range of loss upon resolution of this matter to be between $0 and $34,000.

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 alleged that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs. The Company disagreed with plaintiffs’ contentions. In October 2011, the parties agreed to a settlement of all claims asserted in this action, and the settlement was effected on January 31, 2012. The settlement was accrued in the quarter ended September 30, 2011 and did not have a material impact on our financial position or results of operations.

NOTE 15 — EMPLOYEE BENEFIT PLANS:

We have entered into deferred compensation and disability agreements with certain of our officers and former officers. We have purchased a split-dollar life insurance policy to provide certain retirement and death benefits for one of our officers and death benefits payable to us. The aggregate death benefit of the policy was $446 at December 31, 2011, of which $325 was payable to the officer or his beneficiaries and $121 was payable to us. Total cash surrender value of the policy, net of related surrender charges at December 31, 2011, was approximately $26 and is recorded in other assets. The benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2011, the liability for such vested benefits was approximately $1,009 and is recorded in other long-term liabilities.

The following is a brief description of each incentive compensation plan applicable to our employees:

Annual Cash Incentive Compensation Plan

The Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, provides for annual cash incentive bonuses that are tied to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. Stone incurred expenses of $11,600, $5,888, and $6,402, net of amounts capitalized, for each of the years ended December 31, 2011, 2010 and 2009, respectively, related to incentive compensation bonuses to be paid under the revised plan.

Stock Incentive Plans

At the 2011 Annual Meeting of Stockholders, the stockholders approved the First Amendment (the “First Amendment”) to the Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (the “2009 Plan”). The First Amendment increases the number of shares of common stock that Stone may issue under the 2009 Plan, and the number of shares of common stock that may be issued under the 2009 Plan through incentive stock options by 2,800,000 shares, effective May 20, 2011. The 2009 Plan is an amendment and restatement of the company’s 2004 Amended and Restated Stock Incentive Plan (the “2004 Plan”) and it supersedes and replaces in its entirety the 2004 Plan. The 2009 Plan provides for the granting of incentive stock options and restricted stock awards or any combination as is best suited to the circumstances of the particular employee or nonemployee director. The 2009 Plan eliminates the automatic grant of stock options or restricted stock awards to Nonemployee Directors that was provided for in the 2004 Plan so that awards under the 2009 Plan are entirely at the discretion of the Board of Directors. Under the 2009 Plan, we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise

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price of not less than the fair market value of the common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire ten years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire ten years subsequent to award. In addition, the 2009 Plan provides that shares available under the 2009 Plan may be granted as restricted stock. Restricted stock grants typically vest in one to three years at the discretion of the Compensation Committee of the board of directors. At December 31, 2011, we had approximately 3,305,141 additional shares available for issuance pursuant to the Plan.

401(k) and Deferred Compensation Plans

The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the directions of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2011, 2010 and 2009, Stone contributed $1,435, $1,301 and $1,161, respectively, to the plan.

The Stone Energy Corporation Deferred Compensation Plan provides eligible executives and employees with the option to defer up to 100% of their compensation for a calendar year and we may, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by the board of directors. To date there have been no matching contributions made by Stone. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2011 and 2010, plan assets of $6,410 and $6,314, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.

Change of Control and Severance Plans

On April 7, 2009, we amended and restated our Executive Change of Control and Severance Plan effective as of December 31, 2008 (as so amended and restated, the “Executive Plan”). The amended and restated Executive Plan also replaced and superseded our Executive Change in Control and Severance Policy that was maintained for certain designated executives (specifically, the CEO and CFO). The Executive Plan will provide the company’s officers that are terminated in the event of a change of control and upon certain other terminations of employment with change of control and severance benefits as defined in the Executive Plan. Executives who are terminated within the scope of the Executive Plan will be entitled to certain payments and benefits including the following: a base salary up to the date of termination; in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of his annual pay and any target bonus at the one hundred percent level; a lump sum amount representing a pro rata share of the bonus opportunity up to the date of termination at the then projected rate of payout; in the case of officers other than the CEO and CFO and an involuntary termination occurring outside a change of control period, a lump sum severance payment in an amount equal to the executive’s annual base salary; in the case of officers other than the CEO and CFO and an involuntary termination occurring during a change of control period, a lump sum severance payment in an amount equal to 2.99 times the executive’s annual base salary; continued health plan coverage for six months and outplacement services. In the case of the CEO and CFO, if the payments would be “excess parachute payments,” they will be reduced as necessary to avoid the 20% excise tax under Section 4999 of the Internal Revenue Code (the “Code”) but only if the executive is in a better net after-tax position after such reduction. Also, if a payment would be to a “key employee” for purposes of Section 409A of the Code, payment will be delayed until six months after his termination if required to comply with Section 409A. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: lapse of restrictions on restricted stock, accelerated vesting and cash-out of all in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and a pro-rated portion of the projected bonus, if any, for the year of change of control.

On December 7, 2007, our board of directors approved and adopted the Stone Energy Corporation Employee Change of Control Severance Plan (“Employee Severance Plan”), as amended and restated to comply with the final regulations under Section 409A of the Internal Revenue Code and to provide that said plan will remain in force and effect unless and until terminated by the board. The Employee Severance Plan amended and restated the company’s previous Employee Change of Control Severance Plan dated November 16, 2006. The Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the 6 month period following a change of control, including a resignation by the employee relating to a change in duties. Employees who are terminated within the scope of the Employee Severance Plan will be entitled to certain payments and benefits including the following: a lump sum equal to (1) his weekly pay times his full years of service, plus (2) one week’s pay for each full $10,000 of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay; continued health plan coverage for six months; and a pro-rated portion of the employee’s targeted bonus for the year. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: lapse of restrictions on restricted stock, accelerated vesting and cash-out of all

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in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and a lump sum cash payment equal to the product of (i) the number of “restricted shares” of company stock that the employee would have received under the company’s stock plan but did not receive for the time-vested portion of his long-term stock incentive award, if any, for the calendar year in which the change of control occurs times (ii) the price per share of the company’s common stock utilized in effecting the change of control, provided that such amount shall be prorated by multiplying such amount by the number of full months that have elapsed from January 1 of that calendar year to the effective date of the change of control and then dividing the result by twelve (12).

NOTE 16 — OIL AND GAS RESERVE INFORMATION – UNAUDITED:

Our estimated net proved oil and gas reserves at December 31, 2011 have been prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates. 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. In January 2010, the FASB issued its final standard on oil and gas reserves 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.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the market value of the oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

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The following table sets forth an analysis of the estimated quantities of net proved and proved developed oil (including condensate) and natural gas reserves, all of which are located onshore and offshore the continental United States. Estimated proved oil and natural gas reserves at December 31, 2011, 2010 and 2009 are prepared in accordance with the SEC’s new rule, “Modernization of Oil and Gas Reporting”.

	Oil (MBbls)			Natural Gas (MMcf)			Oil and Natural Gas (MMcfe)
Estimated proved reserves as of December 31, 2008		36,564			299,554			518,935
Revisions of previous estimates		1,964			(53,423	)		(41,636	)
Extensions, discoveries and other additions		417			12,198			14,703
Sale of reserves		(402	)		(300	)		(2,714	)
Production		(6,207	)		(41,335	)		(78,577	)
Estimated proved reserves as of December 31, 2009		32,336			216,694			410,711
Revisions of previous estimates		3,299			13,439			33,231
Extensions, discoveries and other additions		2,668			82,846			98,854
Purchase of producing properties		637			3,816			7,637
Sale of reserves		(23	)		(153	)		(289	)
Production		(5,714	)		(41,937	)		(76,221	)
Estimated proved reserves as of December 31, 2010		33,203			274,705			473,923
Revisions of previous estimates		2,988			(23,801	)		(5,869	)
Extensions, discoveries and other additions		3,544			93,520			114,784
Purchase of producing properties		14,396			24,595			110,971
Sale of reserves		(1,950	)		(2,150	)		(13,850	)
Production		(6,427	)		(39,517	)		(78,079	)
Estimated proved reserves as of December 31, 2011		45,754			327,352			601,880
Estimated proved developed reserves:
as of December 31, 2009		24,380			172,452			318,729
as of December 31, 2010		25,000			174,876			324,876
as of December 31, 2011		31,026			174,067			360,224

The following narrative provides the reasons for the significant changes in the quantities of our estimated proved reserves by year.

Year Ended December 31, 2011. Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (94 Bcfe), our deep gas development project at LaPosada (11 Bcfe) and our GOM drilling program at Mississippi Canyon Block 109 (6 Bcfe). Purchase of producing properties primarily relates to our acquisition of the Pompano and Mica fields (102 Bcfe) and our acquisition of an additional 15% working interest in the Pyrenees project (6 Bcfe). Sale of reserves primarily relates to the sale of our non-operated interest in the Main Pass Block 296 and 311 fields (13 Bcfe).

Year Ended December 31, 2010. Revisions of previous estimates were the result of positive reserve report pricing changes extending the economic limits of reservoirs (28 Bcfe) and well performance (5 Bcfe). Extensions, discoveries and other additions were primarily the result of our Appalachia drilling program (77 Bcfe) and our GOM drilling program primarily at Mississippi Canyon Block 109 (18 Bcfe).

Year Ended December 31, 2009. Revisions of previous estimates were almost entirely the result of changes in reserve report prices for oil and natural gas increasing (in the case of oil) or decreasing (in the case of gas) economic limits of reservoirs.

The following tables present the standardized measure of future net cash flows related to estimated proved oil and gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2011. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and gas reserves. Prior to December 31, 2009, we were required to determine estimated future net cash flows using period-end market prices for oil and gas without considering hedge contracts in place at the end of the period. Effective December 31, 2009, the SEC issued a final rule which changed prices used in reserves calculations. Prices are no longer based on a single-day, period-end price. Rather, they are now

F-28

based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The 2011 average 12-month oil and gas prices net of differentials were $100.97 per barrel of oil and $4.74 per Mcf of gas. 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. The 2009 average 12-month oil and gas prices net of differentials were $58.95 per barrel of oil and $3.49 per Mcf of gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.

	Standardized Measure Year Ended December 31,
	2011			2010			2009
Future cash inflows	$	6,171,279		$	3,803,004		$	2,663,285
Future production costs		(1,747,806	)		(1,191,718	)		(950,434	)
Future development costs		(1,219,214	)		(907,956	)		(912,500	)
Future income taxes		(852,364	)		(330,651	)		(38,845	)
Future net cash flows		2,351,895			1,372,679			761,506
10% annual discount		(808,933	)		(415,050	)		(146,519	)
Standardized measure of discounted future net cash flows	$	1,542,962		$	957,629		$	614,987

	Changes in Standardized Measure Year Ended December 31,
	2011			2010			2009
Standardized measure at beginning of year	$	957,629		$	614,987		$	793,104
Sales and transfers of oil and gas produced, net of production costs		(670,347	)		(487,418	)		(546,737	)
Changes in price, net of future production costs		502,324			485,272			284,504
Extensions and discoveries, net of future production and development costs		293,168			270,629			21,249
Changes in estimated future development costs, net of development costs incurred during the period		97,852			119,986			183,058
Revisions of quantity estimates		(27,854	)		147,509			(150,609	)
Accretion of discount		118,722			64,836			79,904
Net change in income taxes		(300,363	)		(196,219	)		(27,436	)
Purchases of reserves in-place		567,286			21,264			—
Sales of reserves in-place		(36,278	)		1,424			3,152
Changes in production rates due to timing and other		40,823			(84,641	)		(25,202	)
Net increase (decrease) in standardized measure		585,333			342,642			(178,117	)
Standardized measure at end of year	$	1,542,962		$	957,629		$	614,987

F-29

NOTE 17 — SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:

The results of operations by quarter are as follows:

	2011 Quarter Ended
	March 31		June 30		September 30		December 31
Operating revenue	$	198,738	$	234,132	$	213,007	$	222,742
Income from operations		64,752		92,155		80,694		73,399
Net income attributable to Stone Energy		39,792		57,196		51,821		45,523
Basic earnings per share attributable to Stone Energy Corporation stockholders	$	0.81	$	1.17	$	1.06	$	0.93
Diluted earnings per share attributable to Stone Energy Corporation stockholders	$	0.81	$	1.17	$	1.06	$	0.93

	2010 Quarter Ended
	March 31		June 30		September 30		December 31
Operating revenue	$	166,235	$	167,638	$	155,417	$	171,447
Income from operations		45,392		44,107		34,555		41,100
Net income attributable to Stone Energy		25,418		27,872		19,382		23,757
Basic earnings per share attributable to Stone Energy Corporation stockholders	$	0.52	$	0.57	$	0.40	$	0.49
Diluted earnings per share attributable to Stone Energy Corporation stockholders	$	0.52	$	0.57	$	0.40	$	0.49

F-30

NOTE 18 – GUARANTOR FINANCIAL STATEMENTS:

Stone Offshore is an unconditional guarantor (the “Guarantor Subsidiary”) of our 6 ³/4% Senior Subordinated Notes due 2014 and our 8 ⁵/8% Senior Notes due 2017. Our remaining subsidiaries (the “Non-Guarantor Subsidiaries”) have not provided guarantees. The following presents consolidating financial information as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, and consolidated basis. Elimination entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2011

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	37,389		$	926		$	136		$	—		$	38,451
Accounts receivable		36,463			81,452			1,353			(1,129	)		118,139
Fair value of hedging contracts		—			25,177			—			—			25,177
Current income tax receivable		19,946			—			—			—			19,946
Deferred taxes *		8,269			17,803			—			—			26,072
Inventory		4,360			283			—			—			4,643
Other current assets		791			—			—			—			791
Total current assets		107,218			125,641			1,489			(1,129	)		233,219
Oil and gas properties, full cost method:
Proved, net		387,554			1,083,192			2,693			—			1,473,439
Unevaluated		246,269			155,340			—			—			401,609
Other property and equipment, net		11,172			—			—			—			11,172
Fair value of hedging contracts		—			22,543			—			—			22,543
Other assets, net		20,873			2,896			—			—			23,769
Investment in subsidiary		733,533			(273	)		—			(733,260	)		—
Total assets	$	1,506,619		$	1,389,339		$	4,182		($	734,389	)	$	2,165,751
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	78,170		$	25,866		$	39		($	1,129	)	$	102,946
Undistributed oil and gas proceeds		26,036			1,292			—			—			27,328
Accrued interest		14,059			—			—			—			14,059
Fair value of hedging contracts		—			11,122			—			—			11,122
Asset retirement obligations		—			62,676			—			—			62,676
Other current liabilities		22,974			5,396			—			—			28,370
Total current liabilities		141,239			106,352			39			(1,129	)		246,501
Long-term debt		620,000			—			—			—			620,000
Deferred taxes *		56,970			190,865			—			—			247,835
Asset retirement obligations		7,626			351,061			4,416			—			363,103
Fair value of hedging contracts		—			815			—			—			815
Other long-term liabilities		12,955			6,713			—			—			19,668
Total liabilities		838,790			655,806			4,455			(1,129	)		1,497,922
Commitments and contingencies
Stockholders’ equity:
Common stock		481			—			—			—			481
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,338,565			1,724,232			1,639			(1,725,871	)		1,338,565
Accumulated earnings (deficit)		(692,225	)		(1,012,567	)		(1,912	)		1,014,479			(692,225	)
Accumulated other comprehensive income (loss)		21,868			21,868			—			(21,868	)		21,868
Total stockholders’ equity		667,829			733,533			(273	)		(733,260	)		667,829
Total liabilities and stockholders’ equity	$	1,506,619		$	1,389,339		$	4,182		($	734,389	)	$	2,165,751

* Deferred income taxes have been allocated to guarantor subsidiary where related oil and gas properties reside.

F-31

CONDENSED CONSOLIDATING BALANCE SHEET

DECEMBER 31, 2010

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	105,115		$	1,659		$	182		$	—		$	106,956
Restricted cash		5,500			—			—			—��			5,500
Accounts receivable		26,760			61,560			902			(693	)		88,529
Fair value of hedging contracts		12,955			—			—			—			12,955
Deferred taxes *		27,274			—			—			—			27,274
Inventory		6,168			297			—			—			6,465
Other current assets		753			15			—			—			768
Total current assets		184,525			63,531			1,084			(693	)		248,447
Oil and gas properties, full cost method:
Proved, net		260,434			720,309			3,886			—			984,629
Unevaluated		337,725			75,455			—			—			413,180
Other property and equipment, net		10,722			—			—			—			10,722
Other assets, net		22,112			—			—			—			22,112
Investment in subsidiary		427,273			1,561			—			(428,834	)		—
Total assets	$	1,242,791		$	860,856		$	4,970		($	429,527	)	$	1,679,090
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable to vendors	$	60,019		$	43,881		$	—		($	692	)	$	103,208
Undistributed oil and gas proceeds		9,491			546			—			—			10,037
Accrued interest		14,062			—			—			—			14,062
Fair value of hedging contracts		32,144			—			—			—			32,144
Asset retirement obligations		—			42,300			—			—			42,300
Current income tax payable		239			—			—			—			239
Other current liabilities		16,075			—			—			—			16,075
Total current liabilities		132,030			86,727			—			(692	)		218,065
Long-term debt		575,000			—			—			—			575,000
Deferred taxes *		(41,804	)		141,031			—			—			99,227
Asset retirement obligations		129,100			198,105			4,415			—			331,620
Fair value of hedging contracts		3,606			—			—			—			3,606
Other long-term liabilities		14,502			6,713			—			—			21,215
Total liabilities		812,434			432,576			4,415			(692	)		1,248,733
Commitments and contingencies
Stockholders’ equity:
Common stock		478			—			—			—			478
Treasury stock		(860	)		—			—			—			(860	)
Additional paid-in capital		1,331,500			1,673,598			1,640			(1,675,238	)		1,331,500
Accumulated earnings (deficit)		(886,557	)		(1,245,318	)		(1,085	)		1,246,403			(886,557	)
Accumulated other comprehensive loss		(14,204	)		—			—			—			(14,204	)
Total stockholders’ equity		430,357			428,280			555			(428,835	)		430,357
Total liabilities and stockholders’ equity	$	1,242,791		$	860,856		$	4,970		($	429,527	)	$	1,679,090

* Deferred income taxes have been allocated to guarantor subsidiary where related oil and gas properties reside.

F-32

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2011

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	5,675		$	658,283		$	—		$	—		$	663,958
Gas production		19,470			175,773			—			—			195,243
Other operational income		3,085			249			604			—			3,938
Derivative income, net		—			1,418			—			—			1,418
Total operating revenue		28,230			835,723			604			—			864,557
Operating expenses:
Lease operating expenses		6,632			172,612			231			—			179,475
Other operational expenses		1,404			745			—			—			2,149
Production taxes		1,434			7,946			—			—			9,380
Depreciation, depletion, amortization		17,860			261,326			834			—			280,020
Accretion expense		15			30,385			364			—			30,764
Salaries, general and administrative		40,073			94			2			—			40,169
Incentive compensation expense		11,600			—			—			—			11,600
Total operating expenses		79,018			473,108			1,431			—			553,557
Income (loss) from operations		(50,788	)		362,615			(827	)		—			311,000
Other (income) expenses:
Interest expense		9,043			246			—			—			9,289
Interest income		(178	)		(242	)		—			—			(420	)
Other (income) expense, net		(52	)		(1,890	)		—			—			(1,942	)
Loss on early extinguishment of debt		607			—			—			—			607
(Income) loss from investment in subsidiaries		(232,751	)		827			—			231,924			—
Total other (income) expenses		(223,331	)		(1,059	)		—			231,924			7,534
Income (loss) before taxes		172,543			363,674			(827	)		(231,924	)		303,466
Provision (benefit) for income taxes:
Current		(20,386	)		—			—			—			(20,386	)
Deferred		(1,403	)		130,923			—			—			129,520
Total income taxes		(21,789	)		130,923			—			—			109,134
Net income (loss)	$	194,332		$	232,751		($	827	)	($	231,924	)	$	194,332

F-33

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2010

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenue:
Oil production	$	51,357		$	366,591		$	—		$	—		$	417,948
Gas production		61,137			171,918			—			—			233,055
Other operational income		4,831			(54	)		1,139			—			5,916
Derivative income, net		3,265			—			—			—			3,265
Total operating revenue		120,590			538,455			1,139			—			660,184
Operating expenses:
Lease operating expenses		64,868			87,458			—			—			152,326
Other operational expenses		2,097			3,482			—			—			5,579
Production taxes		3,631			2,177			—			—			5,808
Depreciation, depletion, amortization		40,351			206,856			994			—			248,201
Accretion expense		14,503			19,524			442			—			34,469
Salaries, general and administrative		42,741			17			1			—			42,759
Incentive compensation expense		5,888			—			—			—			5,888
Total operating expenses		174,079			319,514			1,437			—			495,030
Income (loss) from operations		(53,489	)		218,941			(298	)		—			165,154
Other (income) expenses:
Interest expense		12,192			—			—			—			12,192
Interest income		(1,439	)		(25	)		—			—			(1,464	)
Other (income) expense, net		548			(692	)		39			—			(105	)
Loss on early extinguishment of debt		1,820			—			—			—			1,820
(Income) loss from investment in subsidiary		(140,366	)		337			—			140,029			—
Total other (income) expenses		(127,245	)		(380	)		39			140,029			12,443
Income (loss) before taxes		73,756			219,321			(337	)		(140,029	)		152,711
Provision (benefit) for income taxes:
Current		5,896			(88	)		—			—			5,808
Deferred		(28,569	)		79,043			—			—			50,474
Total income taxes		(22,673	)		78,955			—			—			56,282
Net income (loss)	$	96,429		$	140,366		($	337	)	($	140,029	)	$	96,429

F-34

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2009

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Operating revenue:
Oil production	$	136,513		$	302,429		$	—	$	—		$	438,942
Gas production		123,511			148,842			—		—			272,353
Other operational income		3,475			(36	)		887		—			4,326
Derivative income, net		3,061			—			—		—			3,061
Total operating revenue		266,560			451,235			887		—			718,682
Operating expenses:
Lease operating expenses		36,563			120,223			—		—			156,786
Other operational expenses		10,742			1,056			—		—			11,798
Production taxes		6,022			1,898			—		—			7,920
Depreciation, depletion, amortization		47,695			211,465			479		—			259,639
Write-down of oil and gas properties		3,849			505,140			—		—			508,989
Accretion expense		16,058			23,203			45		—			39,306
Salaries, general and administrative		41,178			184			5		—			41,367
Incentive compensation expense		6,402			—			—		—			6,402
Total operating expenses		168,509			863,169			529		—			1,032,207
Income (loss) from operations		98,051			(411,934	)		358		—			(313,525	)
Other (income) expenses:
Interest expense		21,183			178			—		—			21,361
Interest income		(515	)		(13	)		—		—			(528	)
Other (income) expense, net		(49	)		187			334		—			472
(Income) loss from investment in subsidiary		268,011			3			—		(268,014	)		—
Total other (income) expenses		288,630			355			334		(268,014	)		21,305
Income (loss) before taxes		(190,579	)		(412,289	)		24		268,014			(334,830	)
Provision (benefit) for income taxes:
Current		30,376			—			—		—			30,376
Deferred		(2,657	)		(144,278	)		—		—			(146,935	)
Total income taxes		27,719			(144,278	)		—		—			(116,559	)
Net income (loss)		(218,298	)		(268,011	)		24		268,014			(218,271	)
Less: net income attributable to non-controlling interest		—			—			—		27			27
Net income (loss) attributable to Stone Energy Corporation	($	218,298	)	($	268,011	)	$	24	$	267,987		($	218,298	)

F-35

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2011

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	194,332		$	232,751		($	827	)	($	231,924	)	$	194,332
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		17,860			261,326			834			—			280,020
Accretion expense		15			30,385			364			—			30,764
Deferred income tax provision (benefit)		(1,403	)		130,923			—			—			129,520
Settlement of asset retirement obligations		—			(63,391	)		—			—			(63,391	)
Non-cash stock compensation expense		5,905			—			—			—			5,905
Excess tax benefits		(1,493	)		—			—			—			(1,493	)
Non-cash derivative income		—			(2,216	)		—			—			(2,216	)
Loss on early extinguishment of debt		607			—			—			—			607
Non-cash (income) loss from investment in subsidiaries		(230,861	)		(1,063	)		—			231,924			—
Other non-cash expenses		306			—			—			—			306
Change in current income taxes		(19,451	)		—			—			—			(19,451	)
Change in intercompany receivables/payables		217,287			(217,724	)		437			—			—
Increase in accounts receivable		(11,022	)		(7,688	)		(890	)		—			(19,600	)
(Increase) decrease in other current assets		(80	)		14			—			—			(66	)
Decrease in inventory		1,605			14			—			—			1,619
Increase in accounts payable		2,658			3,341			40			—			6,039
Increase in other current liabilities		23,440			6,143			—			—			29,583
Other		(1,628	)		—			—			—			(1,628	)
Net cash provided by (used in) operating activities		198,077			372,815			(42	)		—			570,850
Cash flows from investing activities:
Investment in oil and gas properties		(309,026	)		(455,903	)		(4	)		—			(764,933	)
Proceeds from sale of oil and gas properties, net of expenses		5,575			82,355			—			—			87,930
Investment in fixed and other assets		(2,247	)		—			—			—			(2,247	)
Net cash used in investing activities		(305,698	)		(373,548	)		(4	)		—			(679,250	)
Cash flows from financing activities:
Proceeds from bank borrowings		75,000			—			—			—			75,000
Repayment of bank borrowings		(30,000	)		—			—			—			(30,000	)
Deferred financing costs		(4,017	)		—			—			—			(4,017	)
Excess tax benefits		1,493			—			—			—			1,493
Net payments for share based compensation		(2,581	)		—			—			—			(2,581	)
Net cash provided by financing activities		39,895			—			—			—			39,895
Net decrease in cash and cash equivalents		(67,726	)		(733	)		(46	)		—			(68,505	)
Cash and cash equivalents, beginning of period		105,115			1,659			182			—			106,956
Cash and cash equivalents, end of period	$	37,389		$	926		$	136		$	—		$	38,451

F-36

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2010

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	96,429		$	140,366		($	337	)	($	140,029	)	$	96,429
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		40,351			206,856			994			—			248,201
Accretion expense		14,503			19,524			442			—			34,469
Deferred income tax provision (benefit)		(28,569	)		79,043			—			—			50,474
Settlement of asset retirement obligations		(6,461	)		(30,440	)		—			—			(36,901	)
Non-cash stock compensation expense		5,692			—			—			—			5,692
Excess tax benefits		(299	)		—			—			—			(299	)
Non-cash derivative income		(324	)		—			—			—			(324	)
Loss on early extinguishment of debt		1,820			—			—			—			1,820
Non-cash (income) loss from investment in subsidiary		(140,366	)		337			—			140,029			—
Other non-cash expenses		1,837			—			—			—			1,837
Change in current income taxes		(10,783	)		(88	)		—			—			(10,871	)
Change in intercompany receivable/payables		349,118			(347,941	)		(1,177	)		—			—
(Increase) decrease in accounts receivable		(11,556	)		61,254			(65	)		—			49,633
Decrease in other current assets		18			56			—			—			74
Decrease in inventory		1,848			275			—			—			2,123
Increase (decrease) in accounts payable		(1,045	)		272			—			—			(773	)
Decrease in other current liabilities		(17,423	)		(665	)		—			—			(18,088	)
Other expenses		1,230			68			—			—			1,298
Net cash provided by (used in) operating activities		296,020			128,917			(143	)		—			424,794
Cash flows from investing activities:
Investment in oil and gas properties		(265,198	)		(136,394	)		(175	)		—			(401,767	)
Proceeds from sale of oil and gas properties, net of expenses		25,455			6,180			—			—			31,635
Acquisition of non-controlling interest		—			(1,007	)		—			—			(1,007	)
Investment in fixed and other assets		(2,949	)		—			—			—			(2,949	)
Net cash used in investing activities		(242,692	)		(131,221	)		(175	)		—			(374,088	)
Cash flows from financing activities:
Repayment of bank borrowings		(175,000	)		—			—			—			(175,000	)
Redemption of senior subordinated notes		(200,503	)		—			—			—			(200,503	)
Proceeds from issuance of senior notes		375,000			—			—			—			375,000
Deferred financing costs		(11,474	)		—			—			—			(11,474	)
Excess tax benefits		299			—			—			—			299
Net payments for share based compensation		(1,365	)		—			—			—			(1,365	)
Net cash used in financing activities		(13,043	)		—			—			—			(13,043	)
Net increase (decrease) in cash and cash equivalents		40,285			(2,304	)		(318	)		—			37,663
Cash and cash equivalents, beginning of period		64,830			3,963			500			—			69,293
Cash and cash equivalents, end of period	$	105,115		$	1,659		$	182		$	—		$	106,956

F-37

CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, 2009

(In thousands of dollars)

	Parent			Guarantor Subsidiary			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	($	218,298	)	($	268,011	)	$	24		$	268,014		($	218,271	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		47,695			211,465			479			—			259,639
Write-down of oil and gas properties		3,849			505,140			—			—			508,989
Accretion expense		16,058			23,203			45			—			39,306
Deferred income tax benefit		(2,657	)		(144,278	)		—			—			(146,935	)
Settlement of asset retirement obligations		(9,364	)		(57,416	)		—			—			(66,780	)
Non-cash stock compensation expense		5,944			—			—			—			5,944
Excess tax benefits		(2	)		—			—			—			(2	)
Non-cash derivative expense		5,142			—			—			—			5,142
Non-cash (income) loss from investment in subsidiary		268,011			3			—			(268,014	)		—
Other non-cash expenses		9,915			1,056			—			—			10,971
Change in current income taxes		64,481			1,704			—			—			66,185
(Increase) decrease in accounts receivable		177,984			(127,809	)		440			(456	)		50,159
Decrease in other current assets		585			42			—			—			627
Decrease in inventory		16,478			1,083			—			—			17,561
Decrease in accounts payable		(5,652	)		(3,787	)		(761	)		—			(10,200	)
Increase (decrease) in other current liabilities		(19,448	)		5,017			—			—			(14,431	)
Other expenses		739			(856	)		—			—			(117	)
Net cash provided by (used in) operating activities		361,460			146,556			227			(456	)		507,787
Cash flows from investing activities:
Investment in oil and gas properties		(177,341	)		(143,405	)		76			456			(320,214	)
Proceeds from sale of oil and gas properties, net of expenses		5,553			—			—			—			5,553
Sale of fixed assets		—			35			—			—			35
Investment in fixed and other assets		(1,412	)		—			—			—			(1,412	)
Acquisition of non-controlling interest in subsidiary		—			(41	)		—			—			(41	)
Net cash provided by (used in) investing activities		(173,200	)		(143,411	)		76			456			(316,079	)
Cash flows from financing activities:
Repayments of bank borrowings		(250,000	)		—			—			—			(250,000	)
Proceeds from stock offering		60,447			—			—			—			60,447
Deferred financing costs		(141	)		—			—			—			(141	)
Excess tax benefits		2			—			—			—			2
Purchase of treasury stock		(347	)		—			—			—			(347	)
Net payments for share based compensation		(513	)		—			—			—			(513	)
Net cash used in financing activities		(190,552	)		—			—			—			(190,552	)
Net increase (decrease) in cash and cash equivalents		(2,292	)		3,145			303			—			1,156
Cash and cash equivalents, beginning of period		67,122			818			197			—			68,137
Cash and cash equivalents, end of period	$	64,830		$	3,963		$	500		$	—		$	69,293

F-38

GLOSSARY OF CERTAIN INDUSTRY TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this Form 10-K. The revisions and additions to the definition section in Rule 4-10(a) of Regulation S-X contained in the SEC’s new rule, “Modernization of Oil and Gas Reporting”, are included. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the new rule.

Bcf. One billion cubic feet of gas.

Bcfe.One billion cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological termsstructural featureandstratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Gross acreage or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

LIBOR. Represents the London Inter-Bank Offering Rate of interest.

Liquidity.The ability to obtain cash quickly either through the conversion of assets or the incurrence of liabilities.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of gas.

Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet of gas equivalent. Determined using the ratio of one barrel of crude oil to six mcf of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells expressed as whole numbers and fractions of whole numbers.

Overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of production and capital costs.

G-1

Pari Passu. The term is Latin and translates to “without partiality.” Commonly refers to two securities or obligations having equal rights to payment.

Primary term lease. An oil and gas property with no existing production, in which Stone has a specific time frame to establish production without losing the rights to explore the property.

Productive well. A well that is found to be mechanically capable of producing hydrocarbons in sufficient quantities that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction technology equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved oil and gas reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Reasonable certainty is defined as “much more likely to be achieved than not”.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Standardized measure of discounted future net cash flows. The standardized measure represents value-based information about an enterprise’s proved oil and gas reserves based on estimates of future cash flows, including income taxes, from production of proved reserves assuming continuation of certain economic and operating conditions. Future cash flows are based on a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve month period prior to the end of the reporting period.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest. An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

G-2

EXHIBIT INDEX

Exhibit Number	Description
2.1	Purchase and Sale Agreement by and between BP Exploration & Production Inc. and Stone Energy Offshore, L.L.C., dated effective as of November 18, 2011 (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed December 28, 2011 (File No. 001-12074)).
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 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	First Amendment to Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Exhibit 4.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (File No. 001-12074)).
†10.4	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)).

†10.5	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)).
†10.6	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)).
†10.7	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)).
†10.8	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)).
†10.9	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)).
†10.10	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)).
10.11	$700,000,000 Third Amended and Restated Credit Agreement among Stone Energy Corporation as Borrower, Bank of America, N.A. as Administrative Agent and Issuing Bank, and the financial institutions named therein, dated April 26, 2011 (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 (File No. 001-12074)).
10.12	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)).
†10.13	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)).
†10.14	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)).
†10.15	Stone Energy Corporation Executive Change in Control Severance Policy (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)).
10.16	Form of Indemnification Agreement between Stone Energy Corporation and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed March 27, 2009 (File No. 001-12074)).
*21.1	Subsidiaries of the Registrant.
*23.1	Consent of Independent Registered Public Accounting Firm.
*23.2	Consent of Netherland, Sewell & Associates, Inc.

*31.1	Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*31.2	Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
*#32.1	Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350.
**101.INS	XBRL Instance Document
**101.SCH	XBRL Schema Document
**101.CAL	XBRL Calculation Linkbase Document
**101.DEF	XBRL Definition Linkbase Document
**101.LAB	XBRL Label Linkbase Document
**101.PRE	XBRL Presentation Linkbase Document
*99.1	Report of Netherland, Sewell & Associates, Inc.

* Filed or furnished herewith.

** Furnished, not filed. Users of this data submitted electronically herewith are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

# Not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

† Identifies management contracts and compensatory plans or arrangements.