UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2008

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

For the transition period from ___to ___

Commission File Number: 1-12074

STONE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

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

		Name of each exchange
Title of each class		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. oYes þ No

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes o No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ     Accelerated filer o     Non-accelerated filer o     Smaller reporting company o

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

The aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1,861,734,131 as of June 30, 2008 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of February 23, 2009, the registrant had outstanding 40,075,479 shares of Common Stock, par value $.01 per share.

Document incorporated by reference: Portions of the Definitive Proxy Statement of Stone Energy Corporation relating to the Annual Meeting of Stockholders to be held on May 28, 2009 are incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

				Page No.
		PART I
Item 1.		Business			3
Item 1A.		Risk Factors			8
Item 1B.		Unresolved Staff Comments			15
Item 2.		Properties			16
Item 3.		Legal Proceedings			18
Item 4.		Submission of Matters To a Vote of Security Holders			20
Item 4A.		Executive Officers of the Registrant			20
		PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			21
Item 6.		Selected Financial Data			23
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			24
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			38
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance			38
Item 11.		Executive Compensation			38
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			38
Item 13.		Certain Relationships and Related Transactions, and Director Independence			38
Item 14.		Principal Accounting Fees and Services			38
		PART IV
Item 15.		Exhibits and Financial Statement Schedules			39
		Index to Financial Statements			F-1
		Glossary of Certain Industry Terms			G-1
EX-10.8
EX-21.1
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1

PART I

     This section highlights information that is discussed in more detail in the remainder of the document. Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “Forward-Looking Statements” section beginning on page 7 of this document for an explanation of these types of statements. We use the terms “Stone”, “Stone Energy”, “company”, “we”, “us” and “our” to refer to Stone Energy Corporation and its consolidated subsidiaries. Certain terms relating to the oil and gas industry are defined in “Glossary of Certain Industry Terms”, which begins on page G-1 of this Form 10-K.

ITEM 1. BUSINESS

The Company

     Stone Energy is an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties located primarily in the Gulf of Mexico (“GOM”). We are also active in the Appalachia region. Prior to June 29, 2007, we also had operations in the Rocky Mountain Basins and the Williston Basin (“Rocky Mountain Region”). Prior to November 30, 2008, we participated in an exploratory joint venture in Bohai Bay, China. We were incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. As of December 31, 2008, our estimated proved oil and natural gas reserves were approximately 518.9 Bcfe.

Strategy and Operational Overview

     Since our initial public offering in 1993, we have been engaged in the acquisition, exploration, exploitation, development and operation of mature oil and gas properties in the Gulf Coast Basin, which includes onshore Louisiana and offshore GOM. On August 28, 2008, we completed the acquisition of Bois d’Arc Energy, Inc. (“Bois d’Arc”) in a cash and stock transaction totaling approximately $1.7 billion. Bois d’Arc was an independent exploration company engaged in the discovery and production of oil and natural gas in the GOM. The primary factors considered by management in making the acquisition included the belief that the merger would position the combined company as one of the largest independent Gulf of Mexico-focused exploration and production companies, with a solid production base, a strong portfolio for continued development of proved and probable reserves, and an extensive inventory of exploration opportunities. We are also active in the Appalachia region and anticipate pursuing alternatives in the deep water Gulf of Mexico.

     Gulf of Mexico — Conventional Shelf (Including Onshore Louisiana)

     Our conventional shelf strategy is to apply the latest geophysical interpretation tools to identify underdeveloped properties and the latest production techniques to increase production attributable to these properties. Prior to acquiring a property, we perform a thorough geological, geophysical and engineering analysis of the property to formulate a comprehensive development plan. We also employ our extensive technical database, which includes both 3-Dimensional and 4-Component seismic data. After we acquire a property, we seek to increase cash flow from existing reserves and establish additional proved reserves through the drilling of new wells, workovers and recompletions of existing wells and the application of other techniques designed to increase production.

     Gulf of Mexico — Deep Water/ Deep Shelf

     We believe that the deep water of the GOM is an important exploration area, even though it involves high risk, high costs and substantial lead time to develop infrastructure. We have made a significant investment in seismic data and have assembled a technical team with prior geological, geophysical and engineering experience in the deep water arena to evaluate potential opportunities. As of December 31, 2008, we had no production or proved reserves in the deep water of the GOM.

     Our current property base also contains multiple deep shelf exploration opportunities in the GOM, which are defined as prospects below 15,000 feet. The deep shelf presents higher risk with high potential opportunities usually with existing infrastructure, which shortens the lead time to production.

     Appalachia

     During 2007, we began securing leasehold interests in the Appalachia regions of Pennsylvania and West Virginia. As of February 23, 2009, we have secured leasehold interests in approximately 24,000 net acres and have two wells which are currently on production. We expect to add leasehold interests and drill additional wells to further expand our interests in Appalachia.

     Rocky Mountain Region

     On June 29, 2007, we completed the sale of substantially all of our Rocky Mountain Region properties and related assets to Newfield Exploration Company. We maintain working interests in several undeveloped plays in the Rocky Mountain Region, which totaled approximately 60,000 net acres as of February 23, 2009.

     Bohai Bay, China

     Prior to November 30, 2008, we participated in an exploratory joint venture in Bohai Bay, China. After the drilling of three wells, we have decided not to pursue any additional investments in this area and have fully written off this investment.

Oil and Gas Marketing

     Our oil and natural gas production is sold at current market prices under short-term contracts. Chevron Texaco E&P Company, Conoco, Inc., and Shell Trading (US) Company, each accounted for between 16% — 29% of our oil and natural gas revenue generated during the year ended December 31, 2008. No other purchaser accounted for 10% or more of our total oil and natural gas revenue during 2008. 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 deepwater GOM and the Appalachia region is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. See “Item 1A. Risk Factors — Competition within our industry may adversely affect our operations.”

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

Regulation

     Our U.S. oil and gas operations are subject to various U.S. federal, state and local laws and regulations.

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

     Certain operations that we conduct are on federal oil and gas leases, which are administered by the Bureau of Land Management (the “BLM”) and the Minerals Management Service (the “MMS”). These leases contain relatively standardized terms and require compliance with detailed BLM and MMS regulations and orders pursuant to various federal laws, including the Outer Continental Shelf Lands Act (the “OCSLA”) (which are subject to change by the applicable agency). Many onshore leases contain stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the times during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban any surface activity. For offshore operations, lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the U.S. Environmental Protection Agency), lessees must obtain a permit from the BLM or the MMS, as applicable, prior to the commencement of drilling, and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf (the

“OCS”) of the GOM, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the MMS exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. Under certain circumstances, the BLM or MMS, as applicable, may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.

     In August, 2005, 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. On January 20, 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. Stone Energy does not anticipate it will be affected any differently than other producers of natural gas.

     In December 2007, the FERC issued rules 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. On September 18, 2008 the FERC issued its order on rehearing which largely approved the existing rules, except the FERC exempted from the reporting requirement certain types of purchases and sales, including purchases and sales of unprocessed gas and bundled sales of gas made pursuant to state regulated retail tariffs. Also, the FERC clarified that other end use purchases and sales are not exempt from the reporting requirements. The monitoring and reporting required by the new rules will likely increase our administrative costs. Stone Energy does not anticipate it will be affected any differently than other producers of natural gas.

     Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive regulation. In recent years, the FERC has undertaken various initiatives to increase competition within the natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system has been substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of 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 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.

     Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by 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. No portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Environmental Regulation

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

     We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used for the exploration and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such hydrocarbons or wastes have been taken for recycling or disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the hydrocarbons and wastes disposed thereon may be subject to laws and regulations imposing joint and several, strict liability, without regard to fault or the legality of the original conduct, that could require us to remove or remediate previously disposed wastes or environmental contamination, or to perform remedial plugging or pit closure to prevent future contamination.

     The Oil Pollution Act of 1990 (or “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. OPA also requires owners and operators of offshore oil production facilities such as us to establish and maintain evidence of financial responsibility of at least $35 million to cover costs that could be incurred in responding to an oil spill. We believe that we are in substantial compliance with the requirements of OPA, and that these requirements are not any more burdensome to us than they are to other similarly situated oil and gas companies.

     Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is considering legislation to reduce emissions of greenhouse gases. President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. This requirement could increase our operational and compliance costs and result in reduced demand for the oil and natural gas we produce.

     Also, as a result of the United States Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources. In July 2008, EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court’s decision in Massachusetts. In the notice, EPA evaluated the potential regulation of greenhouse gases under the Clean Air Act and other potential methods of regulating greenhouse gases. Although the notice did not propose any specific, new regulatory requirements for greenhouse gases, it indicates that federal regulation of greenhouse gas emissions could occur in the near future even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on our business and the demand for the oil and natural gas we produce.

     We have made, and will continue to make, expenditures in efforts to comply with environmental laws and regulations. While we believe that we are in substantial compliance with applicable environmental laws and regulations in effect and that continued compliance with existing requirements will not have a material adverse impact on us, we 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 23, 2009, we had 291 full time employees. We believe that our relationships with our employees are satisfactory. None of our employees is covered by a collective bargaining agreement. Under our supervision, we utilize the services of independent contractors to perform various daily operational duties.

Available Information

     We make available free of charge on our Internet web site (www.stoneenergy.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”). We also make available on our Internet web site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. We will make immediate disclosure by a Current Report on Form 8-K and on our web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. 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 30, 2008.

Forward-Looking Statements

     The information in this Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical or current facts, that address activities, events, outcomes and other matters that we plan, expect, intend, assume, believe, budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this Form 10-K.

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

	•		any expected results or benefits associated with our acquisitions;
	•		estimates of our future oil and natural gas production, including estimates of any increases in oil and gas production;
	•		planned capital expenditures and the availability of capital resources to fund capital expenditures;
	•		our outlook on oil and gas prices;
	•		estimates of our oil and gas reserves;
	•		any estimates of future earnings growth;
	•		the impact of political and regulatory developments;
	•		our outlook on the resolution of pending litigation and government inquiry;
	•		estimates of the impact of new accounting pronouncements on earnings in future periods;
	•		our future financial condition or results of operations and our future revenues and expenses;
	•		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, but are not limited to:

	•		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 the current 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;
	•		inflation;
	•		lack of availability 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 and other regulatory legislation;
	•		the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures; and
	•		the other risks described in this Form 10-K.

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

     Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages.

     All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

ITEM 1A. RISK FACTORS

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

Oil and natural gas prices are volatile. Recent declines in commodity prices have adversely affected, and in the future will 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 depend substantially 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. The recent decline in oil and natural gas prices has adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. If commodity prices continue to decline in 2009, the decline will have similar adverse effects on our reserves and borrowing base. Further, because we have elected to use the full-cost accounting method, we must perform each quarter a “ceiling test” that is impacted by declining prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings. For example, as a result of the dramatic declines in oil and natural gas prices in the second half of 2008, we recorded a non-cash ceiling test impairment of approximately $1.3 billion for the year ended December 31, 2008. See “—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.’’

     In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

     The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. Oil spot prices reached historical highs in July 2008, peaking at more than $145 per barrel, and natural gas spot prices reached near historical highs in July 2008, peaking at more than $13 per MMBtu. These prices have declined significantly since that time and may continue to fluctuate widely in the future. 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 and foreign 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, 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 99.8% of our estimated proved reserves at December 31, 2008 and 99.9% of our production during 2008 were associated with our Gulf Coast Basin properties. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

     Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. We cannot assure you that our future exploitation, exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, the current economic crisis has adversely impacted our ability to obtain financing to fund acquisitions and has lowered the level of activity and depressed values in the oil and natural gas property sales market.

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

     This Form 10-K contains estimates of our proved oil and gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

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

     You should not assume that any present value of future net cash flows from our producing reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on 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 and, or taxes. At December 31, 2008, approximately 23% 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.

The continuing financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our current bank credit facility because of the deterioration of the capital and credit markets and our borrowing base.

     The current credit crisis and related turmoil in the global financial systems have had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions do not improve. 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. A continuation of the economic crisis could further reduce the demand for oil and natural gas and continue to put downward pressure on the prices for oil and natural gas, which have declined significantly since reaching historic highs in July 2008. These price declines have negatively impacted our revenues and cash flows. In 2009, we expect to finance our capital expenditures with cash flow from operations.

     We have an existing bank credit facility with lender commitments totaling $700 million and a borrowing base set at $625 million. The borrowing base is determined by the lenders periodically and is based on the estimated value of our oil and gas properties using pricing models determined by the lenders at such time. Our bank credit facility is redetermined semi-annually. Our borrowing base is scheduled to be redetermined by May 2009. Due to current credit conditions and lower commodity prices, we believe that it is likely that our borrowing base will be reduced and that the reduction could be substantial. 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. A continuation of the declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.

     The current credit crisis makes it difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining money from the credit markets has increased as many lenders and institutional investors have increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to existing debt or at all, and reduced and, in some cases, ceased to provide any new funding.

     The credit crisis also has impacted the level of activity in the oil and gas property sales market. The lack of available credit and access to capital has limited and will likely continue to limit the parties interested in any proposed asset transactions and will likely reduce the values we could realize in those transactions.

     The distressed economic conditions also may adversely affect the collectability of our trade receivables. For example, our accounts receivable are primarily from purchasers of our oil and natural gas production and other exploration and production companies which own working interests in the properties that we operate. This industry concentration could adversely impact our overall credit risk, because our customers and working interest owners may be similarly affected by changes in economic and financial market conditions, commodity prices, and other conditions. Further, the credit crisis and turmoil in the financial markets could cause our commodity derivative instruments to be ineffective in the event a counterparty were to be unable to perform its obligations or seek bankruptcy protection.

     Due to these factors, we cannot be certain that funding, if needed, will be available to the extent required and, on acceptable terms. If we are unable to access funding when needed on acceptable terms, we may not be able to fully implement our business plans, complete new property acquisitions to replace our reserves, take advantage of business opportunities, respond to competitive pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

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.

     At December 31, 2008, the principal amount of our outstanding debt was $825 million, including $425 million outstanding under our bank credit facility. 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 2009. Due to current credit conditions and lower commodity prices, we believe that it is likely that our borrowing base will be reduced and that the reduction could be substantial. 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 or other financing. 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 99.8% of our estimated proved reserves at December 31, 2008 and 99.9% of our production during 2008 were associated with our Gulf Coast Basin properties. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the Gulf of Mexico. During 2008, we experienced production deferrals due to Hurricanes Gustav and Ike. During 2007, 2006 and 2005, we experienced production deferrals due to Hurricanes Katrina and Rita and during 2004 we experienced production deferrals due to Hurricane Ivan. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production.

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

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

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

     We may not receive payment for a portion of our future production. We have attempted to diversify our sales and obtain credit protections such as parental guarantees from certain of our purchasers. The recent 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 period-end hedge adjusted commodity prices 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 discounted cash flows. A write-down of oil and gas properties does not impact cash flow from operating activities, but does reduce net income. We also assess the carrying amount of goodwill when events occur that may indicate an impairment exists. These events include, for example, a significant decline in oil and gas prices or a decline in our market capitalization. We recorded an impairment of all our goodwill of approximately $466 million for the year ended December 31, 2008. The risk that we will be required to write down the carrying value of oil and gas properties and goodwill increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. For example, oil and natural gas prices declined significantly throughout the second half of 2008. At December 31, 2008, the spot prices for oil and natural gas were $41.00 per barrel and $5.71 per mcf, respectively. We recorded a non-cash ceiling test impairment of approximately $1.3 billion for the year ended December 31, 2008. Since that time, the volatility in commodity prices has continued and the conditions in the global economic markets have continued to deteriorate. These 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. Further, our ceiling test cushion will be subject to fluctuation as a result of any future acquisition and divestiture activities.

There are uncertainties in successfully integrating our acquisitions.

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

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

     We have made initial investments in acreage and wells in Appalachia. These activities are more uncertain than drilling in areas that are developed and have established production. Our operations in Appalachia are still in the early stages and, to date, we have booked a limited amount of proved reserves associated with our properties in Appalachia. 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 Appalachia or other emerging plays will be successful, or if successful will achieve the resource potential levels that we currently anticipate based on the drilling activities that have been completed or achieve the anticipated economic returns based on our current cost models.

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

     Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves will be found. The cost of drilling and completing wells is often uncertain. Oil and gas drilling and production activities may be shortened, delayed or canceled as a result of a variety of factors, many of which are beyond our control. These factors include:

	•		unexpected drilling conditions;
	•		pressure or irregularities in formations;
	•		equipment failures or accidents;
	•		hurricanes and other weather conditions;
	•		shortages in experienced labor; and
	•		shortages or delays in the delivery of equipment.

     The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient net revenue after operating and other costs to recoup drilling costs.

Our industry experiences numerous operating risks.

     The exploration, development and production of oil and gas properties involves a variety of operating risks including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions.

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

     If any of these industry-operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations.

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

     In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We experienced Gulf of Mexico production interruption in 2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 from Hurricanes Gustav and Ike for which we had no production interruption insurance. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse affect on our financial condition and operations.

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

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

Competition within our industry may adversely affect our operations.

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

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

     Our oil and gas operations are subject to various U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as wetlands and restrictions on the way we can release materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil, or criminal penalties, the issuance of remedial obligations, and the imposition of injunctions limiting or prohibiting certain of our operations. At various times, regulatory agencies have imposed price controls and limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies have restricted the rates of flow of oil and gas wells below actual production capacity. In addition, the OPA requires operators of offshore facilities such as us to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under OPA and other federal and state environmental statutes like the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and Resource Conservation and Recovery Act (“RCRA”), owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other regulated substances, subject to certain limitations. Consequently, a substantial spill from one of our facilities subject to laws such as OPA, CERCLA and RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a material adverse effect on our earnings, results of operations, competitive position or financial condition. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and gas, by-products from oil and gas and other substances, and materials produced or used in connection with oil and gas operations. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.

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

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

Hedging transactions may limit our potential gains or become ineffective.

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

	•		our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;
	•		there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
	•		the counterparties to our futures contracts fail to perform the contracts;
	•		a sudden, unexpected event materially impacts oil or natural gas prices; or
	•		we are unable to market our production in a manner contemplated when entering into the hedge contract.

     Our hedging transactions will impact our earnings in various ways. Due to the volatility of oil and natural gas prices, we may have to recognize mark-to-market gains and losses on derivative instruments as the estimated fair value of our commodity derivative instruments is subject to significant fluctuations from period to period. The amount of any actual gains or losses recognized will likely differ from our period to period estimates and will be a function of the actual price of the commodities on the settlement date of the derivative instrument. For example, for the first two quarterly periods in 2008, we reported unrealized losses on our commodity derivative instruments of $0.3 million and $3.4 million, respectively. In contrast, for the third and fourth quarters of 2008, we reported unrealized gains on our commodity derivative instruments of $5.0 million and $1.9 million, respectively. We expect that commodity prices will continue to fluctuate in the future and, as a result, our periodic financial results will continue to be subject to fluctuations related to our derivative instruments.

     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 Bylaws previously provided for a classified board of directors. Our Bylaws have since been restated and provide for the phase-out of the classification of the board of directors prior to the annual meeting of stockholders in 2010 and pursuant to such phase-out, the directors will be elected to serve a term of one year and until their successors are elected and qualified. Our board of directors are elected by plurality voting. Also, our Certificate of Incorporation authorizes our board of directors to issue preferred stock without stockholder approval and to set the rights, preferences and other designations, including voting rights of those shares, as the board may determine. Additional provisions include restrictions on business combinations and the availability of authorized but unissued common stock. These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock.

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

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

We may have risks from global warming.

     Global warming can be defined as the increase in the average temperature of the earth’s near-surface air and oceans since the mid-20^th century. Causes of this condition are still a subject of scientific debate, but it is generally held that it is at least partly the result of greenhouse gas emissions. Increasing global temperature will likely cause sea levels to rise, result in increases in the number and intensity of severe weather events including hurricanes and other unanticipated events. Political and public debate continues to be the best response to global warming. The taxation of carbon emissions is one proposed response to the perceived crisis. We are unable to determine at this time the specific risks to us from this condition.

ITEM 1B. UNRESOLVED STAFF COMMENTS

     None.

ITEM 2. PROPERTIES

     As of February 23, 2009, our property portfolio consisted of 73 active properties and 120 primary term leases in the Gulf Coast Basin and three active properties in the Appalachia region. We serve as operator on 75% of our active properties. The properties that we operate accounted for 94% of our year-end 2008 estimated proved reserves. This high operating percentage allows us to better control the timing, selection and costs of our drilling and production activities.

Oil and Natural Gas Reserves

     The information in this Annual Report on Form 10-K relating to our estimated oil and natural gas proved reserves is based upon reserve reports prepared as of December 31, 2008. Estimates of our proved reserves were prepared by Netherland, Sewell & Associates, Inc.

     The following table sets forth our estimated proved oil and natural gas reserves (99.8% of which are located in the Gulf Coast Basin and 0.2% are located in the Appalachia region) as of December 31, 2008.

														Percent
		Proved				Proved				Total				Proved
		Developed				Undeveloped				Proved				Developed
Oil (MBbls)			28,410				8,154				36,564				78	%
Natural gas (MMcf)			227,857				71,697				299,554				76	%
Total oil and natural gas (MMcfe)			398,317				120,618				518,935				77	%

     The following represents additional information on individually significant properties:

						December 31, 2008
				2008		Estimated Proved		Nature of
Field Name		Location		Production		Reserves		Interest
Mississippi Canyon Block 109		GOM Shelf		7.9 Bcfe		74.5 Bcfe		Working
Ship Shoal Block 113		GOM Shelf		0.7 Bcfe		60.0 Bcfe		Working
Ewing Bank Block 305		GOM Shelf		9.5 Bcfe		54.9 Bcfe		Working
South Pelto Block 22		GOM Shelf		2.6 Bcfe		27.8 Bcfe		Working
Main Pass Block 288		GOM Shelf		3.8 Bcfe		23.3 Bcfe		Working

     There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein only represents estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by geological engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, these revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geological success, prices, future production levels, operating costs, development costs and income taxes that may not prove to be correct. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of these estimates depends on the accuracy of the assumptions upon which they are based.

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

Acquisition, Production and Drilling Activity

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

		Year Ended December 31,
		2008				2007				2006
		(In thousands)
Acquisition costs, net of sales of unevaluated properties		$	1,830,468			$	18,730			$	228,108
Development costs (1)			59,586				154,507				370,201
Exploratory costs			146,529				10,966				160,371
Sale of Rocky Mountain Region properties			—				(1,363,939	)			—
Subtotal			2,036,583				(1,179,736	)			758,680
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements			45,757				36,178				41,543
Total additions (reductions) to oil and gas properties, net		$	2,082,340				($1,143,558	)		$	800,223

     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, 2008.

		Gross				Net
Productive Wells:
Oil (1):
Gulf Coast Basin			146				106
Rocky Mountain Region			—				—
Bohai Bay, China			—				—
Appalachia			—				—
			146				106
Gas (2):
Gulf Coast Basin			85				62
Rocky Mountain Region			—				—
Bohai Bay, China			—				—
Appalachia			2				1
			87				63
Total			233				169
Developed Acres:
Gulf Coast Basin			87,642				70,297
Rocky Mountain Region			40				14
Bohai Bay, China			—				—
Appalachia			428				214
			88,110				70,525
Undeveloped Acres (3):
Gulf Coast Basin			988,689				833,308
Rocky Mountain Region			144,442				59,829
Bohai Bay, China			—				—
Appalachia			32,365				23,842
			1,165,496				916,979
Total			1,253,606				987,504

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

		Year Ended December 31,
		2008								2007								2006
		Gross				Net				Gross				Net				Gross				Net
Exploratory Wells:
Productive			6.00				3.50				1.00				1.00				6.00				3.49
Nonproductive			6.00				3.98				1.00				1.00				13.00				9.26
Development Wells:
Productive			9.00				7.18				19.00				12.71				43.00				22.48
Nonproductive			1.00				0.25				1.00				0.33				1.00				0.51

Title to Properties

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

ITEM 3. LEGAL PROCEEDINGS

     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. These assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from properties located on the Outer Continental Shelf, which are transported through the State of Louisiana, should be sourced to the State of Louisiana for purposes of computing the Louisiana franchise tax apportionment ratio. The Company disagrees with these contentions and intends to vigorously defend itself against these claims. The franchise tax years 2007 and 2008 remain subject to examination.

     In 2005, Stone received an inquiry from the Philadelphia Stock Exchange investigating matters including trading prior to Stone’s October 6, 2005 announcement regarding the revision of Stone’s proved reserves. Stone cooperated fully with this inquiry. Stone has not received any further inquiries from the Philadelphia Exchange since the original request for information.

     On or around November 30, 2005, George Porch filed a putative class action in the United States District Court for the Western District of Louisiana (the “Federal Court”) against Stone, David Welch, Kenneth Beer, D. Peter Canty and James Prince purporting to allege violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. Three similar complaints were filed soon thereafter. All complaints had asserted a putative class period commencing on June 17, 2005 and ending on October 6, 2005. All complaints contended that, during the putative class period, defendants, among other things, misstated or failed to disclose (i) that Stone had materially overstated Stone’s financial results by overvaluing its oil reserves through improper and aggressive reserve methodologies; (ii) that Stone lacked adequate internal controls and was therefore unable to ascertain its true financial condition; and (iii) that as a result of the foregoing, the values of Stone’s proved reserves, assets and future net cash flows were materially overstated at all relevant times. On March 17, 2006, these purported class actions were consolidated, with El Paso Fireman & Policeman’s Pension Fund designated as Lead Plaintiff (“Securities Action”). Lead Plaintiff filed a consolidated class action complaint on or about June 14, 2006. The consolidated complaint alleges claims similar to those described above and expands the putative class period to commence on May 2, 2001 and to end on March 10, 2006. On September 13, 2006, Stone and the individual defendants filed motions seeking dismissal of that action.

     On August 17, 2007, a Federal Magistrate Judge issued a report and recommendation (the “Report”) recommending that the Federal Court grant in part and deny in part the Motions to Dismiss. The Report recommended that (i) the claims asserted against defendants Kenneth Beer and James Prince pursuant to Section 10(b) of the Securities Exchange Act and Rule 10b-5 promulgated thereunder and (ii) claims asserted on behalf of putative class members who sold their Company shares prior to October 6, 2005 be dismissed and that the Motions to Dismiss be denied with respect to the other claims against Stone and the individual defendants.

     On October 1, 2007, the Federal Court issued an Order directing that judgment on the Motions to Dismiss be entered in accordance with the recommendations of the Report. On October 23, 2007, Stone and the individual defendants filed a motion seeking permission to appeal the denial of the Motions to Dismiss to the Fifth Circuit Court of Appeals, which motion was denied. The discovery process is now underway. The parties have exchanged initial disclosures, document requests, and interrogatories and have begun producing documents. On or about May 12, 2008, Lead Plaintiff filed a motion to certify the Securities Action as a class action under Rule 23 of the Federal Rules of Civil Procedure (“Class Certification Motion”). Defendants filed their opposition to the Class Certification Motion on June 27, 2008. Defendants also filed a Motion for Judgment on the Pleadings and a related Motion to Amend Answer to the Consolidated Class Action Complaint on or about June 11, 2008. The Court has not yet ruled on any of these three motions. The trial date and deadlines previously set by the parties’ agreed Joint Plan of Work and Proposed Scheduling Order were vacated by the Court on December 1, 2008.

     In addition, on or about December 16, 2005, Robert Farer and Priscilla Fisk filed respective complaints in the Federal Court purportedly alleging claims derivatively on behalf of Stone. Similar complaints were filed thereafter in the Federal Court by Joint Pension Fund, Local No. 164, I.B.E.W., and in the 15^th Judicial District Court, Parish of Lafayette, Louisiana (the “State Court”) by Gregory Sakhno. Stone was named as a nominal defendant and David Welch, Kenneth Beer, D. Peter Canty, James Prince, James Stone, John Laborde, Peter Barker, George Christmas, Richard Pattarozzi, David Voelker, Raymond Gary, B.J. Duplantis and Robert Bernhard were named as defendants in these actions. The State Court action purportedly alleged claims of breach of fiduciary duty, abuse of control, gross mismanagement, and waste of corporate assets against all defendants, and claims of unjust enrichment and insider selling against certain individual defendants. The Federal Court derivative actions asserted purported claims against all defendants for breach of fiduciary duty, abuse of control, gross mismanagement, waste of corporate assets and unjust enrichment and claims against certain individual defendants for breach of fiduciary duty and violations of the Sarbanes-Oxley Act of 2002.

     On March 30, 2006, the Federal Court entered an order naming Robert Farer, Priscilla Fisk and Joint Pension Fund, Local No. 164, I.B.E.W. as co-lead plaintiffs in the Federal Court derivative action. On December 21, 2006, the Federal Court stayed the Federal Court derivative action at least until resolution of the then-pending motion to dismiss the Securities Action after which time a hearing was to be conducted by the Federal Court to determine the propriety of maintaining that stay. As of the date hereof, the Federal Court has yet to consider any potential modification of the stay.

     On July 18, 2008, each of Stone, Stone Energy Offshore, L.L.C. (“Merger Sub”), Bois d’Arc Energy, Inc. (“Bois d’Arc”) and Comstock Resources (“Comstock”) was served with a summons and complaint in which Bois d’Arc, its directors and certain of its officers, as well as Comstock, Stone and Merger Sub, were named as defendants in a putative class action lawsuit seeking certification in the District Court of Clark County, Nevada, entitled Packard v. Allison, et al., Case No. A567393. This lawsuit was brought by Gail Packard, a purported Bois d’Arc stockholder, on behalf of a putative class of Bois d’Arc stockholders and, among other things, sought to enjoin the named defendants from proceeding with the proposed acquisition of Bois d’Arc by Stone, sought to have the merger agreement rescinded, and sought an award of monetary damages. Plaintiff asserted that the decisions by Bois d’Arc’s directors and Comstock to approve the proposed merger constituted breaches of their respective fiduciary duties because, plaintiff alleged, they did not engage in a fair process to ensure the highest possible purchase price for Bois d’Arc’s stockholders, did not properly value Bois d’Arc, did not disclose material facts regarding the proposed merger, and did not protect against conflicts of interest arising from the participation agreement to be entered into between Stone and former executives of Bois d’Arc, parachute gross-up payments, and the change in control and severance arrangements. The complaint was subsequently amended to substitute Thomas Packard as plaintiff in lieu of Gail Packard, and the amended complaint eliminated Stone and Merger Sub as defendants. On August 21, 2008, the court denied plaintiff’s motions for a preliminary injunction and for expedited discovery, noting that a likelihood of plaintiff’s success on the merits is questionable. Each of the remaining defendants filed a motion to dismiss plaintiff’s complaint. Plaintiff’s complaint was dismissed without prejudice on December 24, 2008.

     Stone’s Certificate of Incorporation and/or its Restated Bylaws provide, to the extent permissible under the law of Delaware (Stone’s state of incorporation), for indemnification of and advancement of defense costs to Stone’s current and former directors and officers for potential liabilities related to their service to Stone. Stone has purchased directors and officers insurance policies that, under certain circumstances, may provide coverage to Stone and/or its officers and directors for certain losses resulting from securities-related civil liabilities and/or the satisfaction of indemnification and advancement obligations owed to directors and officers. These insurance policies may not cover all costs and liabilities incurred by Stone and its current and former officers and directors in these regulatory and civil proceedings.

     The foregoing pending actions are at an early stage and subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation and the regulatory proceedings. Accordingly, based on the current status of the litigation and inquiries, 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. Furthermore, to the extent that our insurance policies are ultimately available to cover any costs and/or liabilities resulting from these actions, they may not be sufficient to cover all costs and liabilities incurred by us and our current and former officers and directors in these regulatory and civil proceedings.

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

     No matters were submitted for a vote of our stockholders during the fourth quarter of 2008.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

     The following table sets forth information regarding the names, ages (as of February 23, 2009) 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			60			President, Chief Executive Officer and Director
Kenneth H. Beer			51			Senior Vice President and Chief Financial Officer
Andrew L. Gates, III			61			Senior Vice President, General Counsel and Secretary
E. J. Louviere			60			Senior Vice President — Land
J. Kent Pierret			53			Senior Vice President, Chief Accounting Officer and Treasurer
Richard L. Smith			50			Senior Vice President — Exploration and Business Development
Jerome F. Wenzel, Jr.			56			Senior Vice President — Operations/Exploitation
Florence M. Ziegler			48			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 Senior Vice President and Chief Financial Officer in August 2005. He previously 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 spent five years as 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.

     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 appointed Vice President — Exploration and Business Development in June 2007 and was named Senior Vice President — Exploration and Business Development in 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.

     Jerome F. Wenzel, Jr. joined Stone in October 2004 as Vice President-Production and Drilling and was named Senior Vice President — Operations/Exploitation in September 2005. 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.

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
2007
First Quarter		$	35.35			$	26.92
Second Quarter			35.60				29.03
Third Quarter			40.43				27.43
Fourth Quarter			48.53				38.59
2008
First Quarter		$	55.89			$	39.14
Second Quarter			73.96				52.20
Third Quarter			68.14				37.86
Fourth Quarter			41.61				8.47
2009
First Quarter (through February 23, 2009)		$	13.73			$	4.77

     On February 23, 2009, the last reported sales price on the New York Stock Exchange Composite Tape was $4.81 per share. As of that date, there were 743 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 8¹/4% Senior Subordinated Notes due 2011 and 6³/4% Senior Subordinated Notes due 2014. 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. The following table sets forth information regarding our repurchases or acquisitions of common stock during the fourth quarter of 2008:

										Total Number of				Maximum Number (or
										Shares (or Units)				Approximate Dollar Value)
		Total Number				Average				Purchased as Part				of Shares (or Units) that
		of Shares (or				Price Paid				of Publicly				May Yet be Purchased
		Units)				per Share (or				Announced Plans or				Under the Plans or
Period		Purchased				Unit)				Programs				Programs
Share Repurchase Program:
October 2008			100,000			$	25.39	(b)			100,000
November 2008			—				—				—
December 2008			—				—				—
			100,000				25.39				100,000			$	93,275,821
Other:
October 2008			6,973	(a)			30.87				—
November 2008			—				—				—
December 2008			63	(a)			15.25				—
			7,036				30.73				—				N/A
Total			107,036			$	25.74				100,000

Equity Compensation Plan Information

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

Stock Performance Graph

     As required by applicable rules of the Securities and Exchange Commission, 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 and the Peer Groups (as defined below) on December 31, 2003 at $42.45 per share for the Company’s Common Stock and at the closing price of the stocks comprising the S&P 500 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 Groups at the beginning of the period.
	3.		Dividends are reinvested on the ex-dividend dates.

Measurement
Period						New				Old
(Fiscal Year						Peer				Peer
Covered)		SGY				Group				Group				S&P 500
12/31/04			106.22				142.98				134.03				110.88
12/31/05			107.26				226.36				208.26				116.33
12/31/06			83.27				221.11				212.74				134.70
12/31/07			110.51				240.44				245.11				142.10
12/31/08			25.96				90.07				121.38				89.53

     The companies that comprised our Peer Group in 2008 are as follows: ATP Oil & Gas Corporation, Bois d’Arc Energy, Inc., Callon Petroleum Company, Energy Partners, Ltd., Energy XXI (Bermuda) Limited, Mariner Energy Inc., McMoRan Exploration Company, Newfield Exploration Company, PetroQuest Energy, Inc., Swift Energy Company, and W&T Offshore, Inc. We acquired Bois d’Arc Energy, Inc. on August 28, 2008.

     Cabot Oil & Gas Corporation, Comstock Resources, Inc., Forest Oil Corporation, and St. Mary Land and Exploration Company, were removed from the Company’s Peer Group and were replaced by ATP Oil & Gas Corporation, Energy XXI (Bermuda) Limited, Mariner Energy Inc., McMoRan Exploration Company, and PetroQuest Energy, Inc. We sold substantially all of our Rocky Mountain Region properties in 2007 to focus on our Gulf of Mexico properties, and the eliminated companies are not focused in 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 Securities and Exchange Commission or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.

ITEM 6. SELECTED FINANCIAL DATA

      The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2008. This information is derived from our Financial Statements and the notes thereto. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”

		Year Ended December 31,
		2008				2007				2006				2005				2004
		(In thousands, except per share amounts)
Statement of Operations Data:
Operating revenue:
Oil production		$	461,050			$	424,205			$	348,979			$	244,469			$	214,153
Gas production			336,665				329,047				337,321				391,771				330,048
Derivative income, net			3,327				—				2,688				—				—
Total operating revenue			801,042				753,252				688,988				636,240				544,201
Operating expenses:
Lease operating expenses			171,107				149,702				159,043				114,664				100,045
Production taxes			7,990				9,945				13,472				13,179				7,408
Depreciation, depletion and amortization			288,384				302,739				320,696				241,426				210,861
Write-down of oil and gas properties			1,309,403				8,164				510,013				—				—
Goodwill impairment			465,985				—				—				—				—
Accretion expense			17,392				17,620				12,391				7,159				5,852
Salaries, general and administrative expenses			43,504				33,584				34,266				22,705				14,311
Incentive compensation expense			2,315				5,117				4,356				1,252				2,318
Derivative expenses, net			—				666				—				3,388				4,099
Total operating expenses			2,306,080				527,537				1,054,237				403,773				344,894
Gain on Rocky Mountain Region properties divestiture			—				59,825				—				—				—
Income (loss) from operations			(1,505,038	)			285,540				(365,249	)			232,467				199,307
Other (income) expenses:
Interest expense			13,243				32,068				35,931				23,151				16,835
Interest income			(11,250	)			(12,135	)			(2,524	)			(1,095	)			(208	)
Other income, net			(5,877	)			(5,657	)			(4,657	)			(2,799	)			(2,269	)
Merger expense reimbursement			—				—				(51,500	)			—				—
Merger expenses			—				—				50,029				—				—
Early extinguishment of debt			—				844				—				—				845
Total other (income) expenses, net			(3,884	)			15,120				27,279				19,257				15,203
Net income (loss) before income taxes			(1,501,154	)			270,420				(392,528	)			213,210				184,104
Income tax provision (benefit)			(363,923	)			88,984				(138,306	)			76,446				64,436
Net income (loss)			($1,137,231	)		$	181,436				($254,222	)		$	136,764			$	119,668
Earnings and dividends per common share:
Basic earnings (loss) per share			($35.58	)		$	6.57				($9.29	)		$	5.07			$	4.50
Diluted earnings (loss) per share			($35.58	)		$	6.54				($9.29	)		$	5.02			$	4.45
Cash dividends declared			—				—				—				—				—
Cash Flow Data:
Net cash provided by operating activities		$	522,478			$	465,158			$	399,035			$	461,213			$	369,668
Net cash provided by (used in) investing activities			(1,357,907	)			344,812				(660,456	)			(499,932	)			(475,159	)
Net cash provided by (used in) financing activities			428,440				(393,706	)			240,575				94,170				112,648
Balance Sheet Data (at end of period):
Working capital (deficit)		$	123,339			$	412,445			$	1,845			$	16,506				($28,598	)
Oil and gas properties, net			1,624,321				1,181,312				1,784,425				1,810,959				1,517,308
Total assets			2,106,003				1,889,603				2,128,471				2,140,317				1,695,664
Long-term debt, less current potion			825,000				400,000				797,000				563,000				482,000
Stockholders’ equity			587,092				885,802				711,640				944,123				772,934

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, 2008. Our financial statements and the notes thereto, which are found elsewhere in this Form 10-K, contain detailed information that should be referred to in conjunction with the following discussion. See “Item 8. Financial Statements and Supplementary Data — Note 1.”

Executive Overview

     We are an independent oil and natural gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties located primarily in the Gulf of Mexico (“GOM”). We are also active in the Appalachia region. Prior to June 29, 2007, we also had operations in the Rocky Mountain Basins and the Williston Basin (“Rocky Mountain Region”). Prior to November 30, 2008, we participated in an exploratory joint venture in Bohai Bay, China. Our business strategy is to increase oil and natural gas reserves, production and cash flow through the acquisition, exploitation and development of mature properties in the Gulf Coast Basin, which includes onshore Louisiana and offshore GOM, and exploring opportunities in the deep water environment of the Gulf of Mexico, Appalachia, and other potential areas. See “Item 1. Business — Strategy and Operational Overview.”

   2008 Significant Events.

	•		Acquisition — On August 28, 2008, we completed the acquisition of Bois d’Arc Energy, Inc. (“Bois d’Arc”) in a cash and stock transaction totaling approximately $1.7 billion. Bois d’Arc was an independent exploration company engaged in the discovery and production of oil and natural gas in the Gulf of Mexico. The primary factors considered by management in making the acquisition included the belief that the merger would position the combined company as one of the largest independent Gulf of Mexico-focused exploration and production companies, with a solid production base, a strong portfolio for continued development of proved and probable reserves, and an extensive inventory of exploration opportunities. Pursuant to the terms and conditions of the agreement and plan of merger, we paid total merger consideration of approximately $935 million in cash and issued approximately 11.3 million common shares, valued at $63.52 per share. The per share value of the Stone common shares issued was calculated as the average of Stone’s closing share price for the two days prior to through the two days after the merger announcement date of April 30, 2008. The cash component of the merger consideration was funded with approximately $510 million of cash on hand and $425 million of borrowings from our amended and restated bank credit facility. The revenues and expenses associated with Bois d’Arc have been included in Stone’s consolidated financial statements since August 28, 2008, the date the acquisition closed.
	•		Amended Credit Facility — In connection with the acquisition of Bois d’Arc on August 28, 2008, we entered into an amended and restated bank credit facility of $700 million, maturing on July 1, 2011, through a syndicated bank group. The new facility currently has a borrowing base of $625 million. See “Liquidity and Capital Resources — Bank Credit Facility” below for additional information regarding the amended and restated credit facility.
	•		Hurricanes — Hurricanes Gustav and Ike caused significant disruption in our operations for the third and fourth quarters of 2008 resulting in production deferrals approximating 18.1 Bcfe and significant damage to our offshore facilities. We estimate the incremental uninsured plug and abandonment cost resulting from the hurricanes could exceed $75 million, allocated over several years.
	•		Declining Commodity Prices — During the fourth quarter of 2008, we experienced a significant decline in oil and natural gas prices which resulted in a ceiling test write-down of $1.3 billion and goodwill impairment of $466.0 million.

   2009 Outlook.

     Our 2009 capital expenditures budget is approximately $300 million excluding acquisitions and capitalized interest and general and administrative expenses. Approximately 75% of the capital expenditures budget is expected to be spent on our GOM exploitation program, supporting facilities, and abandonment projects. The remaining budgeted capital expenditures include GOM exploration drilling (shelf and deep water), GOM lease sale expenditures, seismic and reprocessing projects, and acreage acquisition and drilling in Appalachia.

   Known Trends and Uncertainties.

     Credit Crisis — Beginning in the second half of 2008 and continuing into 2009, world financial markets experienced a severe reduction in the availability of credit. It is difficult to predict the impact of this condition on us in future quarters. Possible negative impacts could include a substantial decrease in the availability of borrowings under our credit facility, a need to repay borrowings sooner than expected, an increased counterparty credit risk on our derivatives contracts and under our bank credit facility and the requirement by contractual counterparties of us to post collateral guaranteeing performance.

     Declining Commodity Prices — We have experienced a significant decline in oil and natural gas prices in the last several months. This has resulted in a ceiling test write-down of our oil and gas properties and goodwill impairment in the fourth quarter of 2008. It has also caused a reduction in our planned capital expenditures budget for 2009. Should these restrained pricing conditions persist it could severely impact future cash flows, substantially reduce the available borrowings under our credit facility, constrain capital budgets beyond 2009 and result in additional ceiling test write-downs and impairments.

     Bank Credit Facility Borrowing Base Redetermination — As of February 23, 2009, we had $153.9 million of borrowing base availability under our bank credit facility. Our next redetermination is scheduled to be completed by May 2009. Given the current conditions in the credit markets and lower commodity prices (see discussions above), we believe it is likely that the borrowing base under our bank credit facility will be reduced and that the reduction could be substantial. If our borrowing base is reduced below any outstanding balances under our bank credit facility plus any outstanding letters of credit, our bank credit facility allows us one 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 monthly installments over ninety days or some longer period acceptable to the banks not to exceed six months.

     Gulf Coast Basin Reserve Replacement — We have faced challenges in replacing production in the Gulf Coast Basin at a reasonable unit cost. Our recent acquisition of Bois d’Arc as well as our successful participation in offshore lease sales has provided us with an improved inventory of quality drilling projects. However, a constrained capital budget caused by falling commodity prices will make it difficult to replace reserves in 2009.

     Louisiana Franchise Taxes — We have been involved in litigation with the state of Louisiana over the proper computation of franchise taxes allocable to the state. This litigation relates to the state’s position that sales of crude oil and natural gas from properties located on the Outer Continental Shelf, 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.” As of December 31, 2008, the state of Louisiana had asserted claims of additional franchise taxes in the amount of $9.0 million plus accrued interest of $4.2 million. There are two open franchise tax years which the state has not yet audited.

     Hurricanes — Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. In 2008, we experienced deferrals of production due to Hurricanes Gustav and Ike of approximately 18.1 Bcfe. In 2007, 2006 and 2005, we experienced deferrals of production due to Hurricanes Katrina and Rita of approximately 3.6 Bcfe, 15.6 Bcfe and 16.4 Bcfe, respectively. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes is becoming more difficult to obtain. We have already narrowed our insurance coverage to selected properties and expect rates to rise to reflect underwriters’ losses incurred from the recent hurricanes.

     Asset Retirement Obligations and Accretion — Due to falling commodity prices and hurricanes, the timing on a substantial portion of our asset retirement obligations was revised in the fourth quarter of 2008 leading to a redetermination of the present value of these obligations. In this redetermination, our credit adjusted risk free interest rate was increased to account for current credit conditions. This will result in a material increase in accretion expense in the future.

     Regulatory Inquiries and Stockholder Lawsuits — We have been named as a defendant in certain regulatory inquiries and stockholder lawsuits resulting from our reserve restatement. The ultimate resolution of these matters and their impact on us is uncertain. See “Item 3. Legal Proceedings.”

Liquidity and Capital Resources

     Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $522.5 million during 2008 compared to $465.2 million and $399.0 million in 2007 and 2006, respectively. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2009 capital expenditures with cash flow provided by operating activities.

     Net cash flow used in investing activities totaled $1.4 billion during the year ended December 31, 2008, which primarily represents cash used in the acquisition of Bois d’Arc and our investment in oil and natural gas properties. Net cash flow provided by investing activities totaled $344.8 million during the year ended December 31, 2007, which primarily represents proceeds received from the sale of substantially all of our Rocky Mountain Region properties offset by our investment in oil and natural gas properties. Net cash flow used in investing activities totaled $660.5 million during 2006, which primarily represents our investment in oil and natural gas properties.

     Net cash flow provided by financing activities totaled $428.4 million during the year ended December 31, 2008, which primarily represents borrowings under our bank credit facility in conjunction with our acquisition of Bois d’Arc and proceeds from the exercise of stock options and vesting of restricted stock. Net cash flow used in financing activities totaled $393.7 million during the year ended December 31, 2007, which primarily represents the redemption of our Senior Floating Rate Notes due 2010 and repayments of borrowings under our bank credit facility. Net cash flow provided by financing activities totaled $240.6 million for the year ended December 31, 2006, which primarily represents proceeds from the issuance of our Senior Floating Rate Notes due 2010, borrowings net of repayments under our bank credit facility and proceeds from the exercise of stock options.

     We had working capital at December 31, 2008 of $123.3 million. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity. “Liquidity” is defined as the ability to obtain cash quickly either through the conversion of assets or incurrence of liabilities. See “Bank Credit Facility.”

     Our 2009 capital expenditures budget, excluding acquisitions, capitalized interest and general and administrative expenses, is approximately $300 million, or 20% less than our 2008 capital expenditures, excluding acquisitions and capitalized interest and general and administrative expenses. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2009 capital program with cash flow provided by operating activities.

     To the extent that 2009 cash flow from operating activities exceeds our estimated 2009 capital expenditures, we may pay down a portion of our existing debt, expand our capital budget, repurchase shares of common stock, or invest in the money markets. If cash flow from operating activities during 2009 is not sufficient to fund estimated 2009 capital expenditures we may use the liquidity provided by our bank credit facility to the extent available, sell certain select properties, or reduce our capital budget. See “Known Trends and Uncertainties” and “— Bank Credit Facility.”

     We do not budget acquisitions; however, we are continually evaluating opportunities that fit our specific acquisition profile. See “Item 1. Business — Strategy and Operational Overview.” Any one or a combination of certain of these possible transactions could fully utilize our existing sources of capital. Although we have no current plans to access the public markets for purposes of capital, if the opportunity arose, we would consider such funding sources to provide capital in excess of what is currently available to us.

     Bank Credit Facility. At December 31, 2008, we had $425 million of outstanding borrowings under our bank credit facility and letters of credit totaling $46.1 million had been issued under the facility. As of February 23, 2009, after accounting for the $46.1 million of letters of credit, we had $153.9 million of borrowings available under the credit facility.

     On August 28, 2008, we entered into an amended and restated bank credit facility totaling $700 million, maturing on July 1, 2011, through a syndicated bank group led by Bank of America, N.A., BNP Paribas, Natixis, The Bank of Nova Scotia, Capital One, N.A. and Toronto Dominion (Texas) LLC. The new facility had an initial borrowing base of $700 million and replaced the previous $300 million facility. In early December 2008, we received notice from our bank group that the borrowing base under our bank credit facility was reduced from $700 million to $625 million. At December 31, 2008, the weighted average interest rate under the credit facility was approximately 3.8%. The facility is required to be guaranteed by all of our material direct and indirect subsidiaries. The facility is guaranteed by Stone Energy Offshore, L.L.C. (“Stone Offshore”), a wholly owned subsidiary of Stone that holds the assets acquired in the Bois d’Arc transaction.

     The borrowing base under the credit facility is redetermined semi-annually, in May and November, by the lenders taking into consideration the estimated value of our oil and gas properties and those of our direct and indirect material subsidiaries in accordance with the lenders’ customary practices for oil and gas loans. In addition, we and the lenders each have discretion at any time, but not more than two additional times in any calendar year, to have the borrowing base redetermined. See “Item 1A. Risk Factors — The continuing financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our current bank credit facility because of the deterioration of the capital and credit markets and our borrowing base.”

     The credit facility is collateralized by substantially all of Stone’s and Stone Offshore’s assets. Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and gas reserves representing at least 80% of the discounted present value of the future net cash flows from their oil and gas reserves reviewed in determining the borrowing base. At Stone’s option, loans under the credit facility will bear interest at a rate based on the adjusted London Interbank Offering Rate plus an applicable margin, or a rate based on the prime rate or Federal funds rate plus an applicable margin.

     Under the financial covenants of our credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a ratio of EBITDA to consolidated Net Interest, as defined in the credit agreement, for the preceding four quarterly periods of not less than 3.0 to 1.0. As of December 31, 2008 our debt to EBITDA Ratio was 1.39 to 1 and our EBITDA to consolidated Net Interest Ratio was approximately 249 to 1. In addition, the credit facility places certain customary restrictions or requirements with respect to disposition of properties, incurrence of additional debt, change of ownership and reporting responsibilities. These covenants may limit or prohibit us from paying cash dividends but do allow for limited stock repurchases.

     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, 2008, 200,000 shares had been repurchased under this program at a total cost of $6.7 million.

     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, 2008 (in thousands):

						Less
						than								4-5				More than
		Total				1 Year				1-3 Years				Years				5 Years
Contractual Obligations and Commitments:
81/4% Senior Subordinated Notes due 2011		$	200,000			$	—			$	200,000			$	—			$	—
63/4% Senior Subordinated Notes due 2014			200,000				—				—				—				200,000
Bank credit facility (1)			425,000				—				425,000				—				—
Interest and commitment fees (2)			171,653				47,015				84,730				27,000				12,908
Asset retirement obligations including accretion			702,746				70,709				53,616				113,934				464,487
Rig commitments			28,525				28,525				—				—				—
Long-lead items (3)			8,200				8,200				—				—				—
Seismic data commitments (4)			5,162				5,162				—				—				—
Operating lease obligations			2,117				793				1,184				140				—
Total Contractual Obligations and Commitments		$	1,743,403			$	160,404			$	764,530			$	141,074			$	677,395

Results of Operations

     2008 Compared to 2007. 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,
		2008				2007				Variance				% Change
Production:
Oil (MBbls)			4,916				6,088				(1,172	)			(19	%)
Natural gas (MMcf)			34,409				45,088				(10,679	)			(24	%)
Oil and natural gas (MMcfe)			63,903				81,617				(17,714	)			(22	%)
Average prices: (1)
Oil (per Bbl)		$	93.79			$	69.68			$	24.11				35	%
Natural gas (per Mcf)			9.78				7.30				2.48				34	%
Oil and natural gas (per Mcfe)			12.48				9.23				3.25				35	%
Expenses (per Mcfe):
Lease operating expenses		$	2.68			$	1.83			$	0.85				46	%
Salaries, general and administrative expenses (2)			0.68				0.41				0.27				66	%
DD&A expense on oil and gas properties			4.45				3.67				0.78				21	%
Estimated Proved Reserves at December 31:
Oil (MBbls)			36,564				31,586				4,978				16	%
Natural gas (MMcf)			299,554				213,083				86,471				41	%
Oil and natural gas (MMcfe)			518,935				402,598				116,337				29	%

     For the year ended 2008, we reported a net loss totaling $1,137.2 million, or $35.58 per share, compared to net income for the year ended December 31, 2007 of $181.4 million, or $6.54 per share. All per share amounts are on a diluted basis. On August 28, 2008, we completed our acquisition of Bois d’Arc. The revenues and expenses associated with Bois d’Arc have been included in Stone’s consolidated financial statements since August 28, 2008.

     We follow the full cost method of accounting for oil and gas properties. At the end of 2008, we recognized ceiling test write-downs of our oil and gas properties (United States and China) totaling $1,309.4 million ($851.1 million after taxes). At the end of 2007, we recognized a ceiling test write-down of our China oil and gas properties totaling $8.2 million ($5.5 million after taxes). The write-downs did not impact our cash flow from operations but did reduce net income and stockholders’ equity. At December 31, 2008, approximately $157.8 million of unevaluated costs were determined to be impaired and were reclassified to proved oil and gas properties and included in our ceiling test computation.

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

     Included in 2007 net income before income taxes is a $59.8 million gain ($40.1 million after taxes) on the sale of our Rocky Mountain Region properties, representing the excess of the proceeds from the sale over the carrying value of the oil and gas properties and other assets sold and transaction costs.

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

     Production. 2008 production totaled 4,916,000 barrels of oil and 34.4 Bcf of natural gas compared to 6,088,000 barrels of oil and 45.1 Bcf of natural gas produced during 2007, a decrease on a gas equivalent basis of 17.7 Bcfe. 2008 total production rates were negatively impacted by extended Gulf Coast shut-ins due to Hurricanes Gustav and Ike, amounting to volumes of approximately 18.1 Bcfe (50 MMcfe per day). Slightly offsetting this decrease was the production associated with our Bois d’Arc acquisition, which closed on August 28, 2008, totaling approximately 6.4 Bcfe through December 31, 2008. 2007 total production rates were negatively impacted by extended Gulf Coast shut-ins due to Hurricanes Katrina and Rita, amounting to volumes of approximately 3.6 Bcfe (10 MMcfe per day). Without the effects of the hurricane production deferrals, year to year total production volumes decreased approximately 3.2 Bcfe. The decrease was primarily the result of the sale of substantially all of our Rocky Mountain Region properties on June 29, 2007 and the divestiture of non-core Gulf of Mexico properties in the first quarter of 2008. Rocky Mountain Region production was 6.6 Bcfe for the year ended December 31, 2007.

     Prices. Prices realized during 2008 averaged $93.79 per barrel of oil and $9.78 per Mcf of natural gas compared to 2007 average realized prices of $69.68 per barrel of oil and $7.30 per Mcf of natural gas. On a gas equivalent basis, average 2008 prices were 35% higher than prices realized during 2007. 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, 2008 and 2007, our effective hedging transactions increased our average realized natural gas prices by $0.44 per Mcf and $0.23 per Mcf, respectively. Average realized oil prices were decreased during the years ended December 31, 2008 and 2007 by $7.01 per barrel and $0.42 per barrel, respectively.

     Income. Oil and natural gas revenue increased 6% to $797.7 million in 2008 from $753.3 million during 2007. The increase was due to a 35% increase in average realized prices on a gas equivalent basis, partially offset by a 22% decline in production volumes. Oil and natural gas revenue related to the properties acquired from Bois d’Arc totaled $47.3 million from August 28, 2008 through December 31, 2008. We sold substantially all of our Rocky Mountain Region properties on June 29, 2007. Rocky Mountain Region oil and natural gas revenue amounted to $47.4 million for the year ended December 31, 2007.

     Derivative Income/Expense. During 2008, certain of our derivative contracts were determined to be partially ineffective because of differences in the relationship between the fixed price in the derivative contract and actual prices realized. During the second half of 2008, as a result of extended shut-ins of production after Hurricanes Gustav and Ike, our September 2008 crude oil and natural gas production levels were below the volumes that we had hedged. Consequently, some of our crude oil and natural gas hedges for September 2008 were deemed to be ineffective. Net derivative income for the year ended December 31, 2008, totaled $3.3 million, consisting of $0.7 million of cash settlements on the ineffective derivative contracts, $4.5 million of changes in the fair market value of the ineffective portion of derivative contracts, less $1.9 million of amortization of the cost of puts. During 2007, certain of our derivative contracts were determined to be partially ineffective because of differences in the relationship between the fixed price in the derivative contract and actual prices realized. Net derivative expense for the year ended December 31, 2007 totaled $0.7 million, representing changes in the fair market value of the ineffective portion of the derivatives.

     Expenses. During 2008, we incurred lease operating expenses of $171.1 million, compared to $149.7 million incurred during 2007. The increase in lease operating expenses is primarily the result of increased service costs and the acquisition of the Bois d’Arc properties. Included in lease operating expenses from August 28, 2008 through December 31, 2008 are $28.6 million of expenses for the properties acquired from Bois d’Arc. On a unit of production basis, 2008 lease operating expenses were $2.68 per Mcfe as compared to $1.83 per Mcfe for 2007, primarily a result of the production disruption from Hurricanes Gustav and Ike and increased service costs. Partially offsetting the increase in lease operating expenses was the sale of our Rocky Mountain Region properties in June 2007. Rocky Mountain Region lease operating expenses totaled $10.0 million for the year ended December 31, 2007.

     Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for 2008 totaled $284.7 million, or $4.45 per Mcfe, compared to DD&A expense of $299.2 million, or $3.67 per Mcfe in 2007. The increase in 2008 DD&A on a unit basis is 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.

     During 2008 and 2007, salaries, general and administrative (“SG&A”) expenses (exclusive of incentive compensation) totaled $43.5 million and $33.6 million, respectively. The increase in SG&A expenses in 2008 is primarily due to additional compensation expense associated with restricted stock issuances, higher legal fees, and the expensing of deferred financing costs associated with our amended credit facility. Included in 2007 SG&A expenses are severance and retention payments of $2.1 million made to employees in our Denver District in connection with the sale of substantially all of our Rocky Mountain Region properties in June 2007 and the resulting discontinuation of operations of such district. Total 2007 SG&A expenses for the Denver District were $3.8 million.

     Interest expense for 2008 totaled $13.2 million, net of $26.4 million of capitalized interest, compared to interest of $32.1 million, net of $16.2 million of capitalized interest, during 2007. The decrease in interest expense in 2008 primarily relates to the redemption of our Senior Floating Rate Notes due 2010 in August 2007. The decrease also results from an increase in capitalized interest related to unevaluated properties acquired from Bois d’Arc on August 28, 2008.

     For the years ended December 31, 2008 and 2007, production taxes totaled $8.0 million and $9.9 million, respectively. The decrease in production taxes resulted from the sale of substantially all of our Rocky Mountain Region properties in June 2007. Rocky Mountain Region production taxes totaled $4.0 million for the year ended December 31, 2007.

     We estimate that we have incurred $7.0 million of current federal income tax expense for calendar year 2008. We have a $31.2 million current income tax receivable at December 31, 2008 as a result of current year estimated tax payments exceeding our current estimated federal income tax liability. Our previous estimate of current taxes was adjusted downward primarily as a result of production deferrals associated with the hurricanes as well as a decline in commodity prices.

     Asset Retirement Obligations. Due to falling commodity prices and hurricanes, the timing on a substantial portion of our asset retirement obligations was revised in the fourth quarter of 2008 leading to a redetermination of the present value of these obligations. In this redetermination, our credit adjusted risk free interest rate was increased to account for current credit conditions, resulting in a significant downward revision to our asset retirement obligations of approximately $87.6 million.

     Reserves. At December 31, 2008, our estimated proved oil and gas reserves totaled 518.9 Bcfe, compared to December 31, 2007 reserves of 402.6 Bcfe. The increase in estimated proved reserves during 2008 was primarily the result of the acquisition of Bois d’Arc in August 2008. Estimated proved natural gas reserves totaled 299.6 Bcf and estimated proved oil reserves totaled 36.6 MMBbls at the end of 2008. The reserve estimates at December 31, 2008 were prepared by Netherland, Sewell & Associates, Inc. in accordance with guidelines established by the SEC.

     Our standardized measure of discounted future net cash flows was $793.1 million and $1.5 billion at December 31, 2008 and 2007, respectively. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine these estimates of future net cash flows using market prices for oil and gas on the last day of the fiscal period. The average year-end oil and gas prices net of differentials on all of our properties used in determining these amounts, excluding the effects of hedges in place at year-end, were $39.70 per barrel and $5.87 per Mcf for 2008 and $94.63 per barrel and $7.27 per Mcf for 2007.

     2007 Compared to 2006. 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,
		2007				2006				Variance				% Change
Production:
Oil (MBbls)			6,088				5,593				495				9	%
Natural gas (MMcf)			45,088				43,508				1,580				4	%
Oil and natural gas (MMcfe)			81,617				77,066				4,551				6	%
Average prices: (1)
Oil (per Bbl)		$	69.68			$	62.40			$	7.28				12	%
Natural gas (per Mcf)			7.30				7.75				(0.45	)			(6	%)
Oil and natural gas (per Mcfe)			9.23				8.91				0.32				4	%
Expenses (per Mcfe):
Lease operating expenses		$	1.83			$	2.06				($0.23	)			(11	%)
Salaries, general and administrative expenses (2)			0.41				0.44				(0.03	)			(7	%)
DD&A expense on oil and gas properties			3.67				4.11				(0.44	)			(11	%)
Estimated Proved Reserves at December 31:
Oil (MBbls)			31,586				41,360				(9,774	)			(24	%)
Natural gas (MMcf)			213,083				342,782				(129,699	)			(38	%)
Oil and natural gas (MMcfe)			402,598				590,942				(188,344	)			(32	%)

     For the year ended 2007, net income totaled $181.4 million, or $6.54 per share, compared to a net loss for the year ended December 31, 2006 of $254.2 million, or $9.29 per share. All per share amounts are on a diluted basis.

     Included in 2007 net income before income taxes is a $59.8 million gain ($40.1 million after taxes) on the sale of our Rocky Mountain Region properties, representing the excess of the proceeds from the sale over the carrying value of the oil and gas properties and other assets sold and transaction costs.

     We follow the full cost method of accounting for oil and gas properties. At the end of 2007, we recognized a ceiling test write-down of our China oil and gas properties totaling $8.2 million ($5.5 million after taxes). At the end of 2006, we recognized a ceiling test write-down of our U.S. oil and gas properties totaling $510.0 million ($330.5 million after taxes). The write-downs did not impact our cash flow from operations but did reduce net income and stockholders’ equity.

     Included in the 2006 net loss is $51.5 million in merger expense reimbursements partially offset by $50.0 million in merger related expenses. Merger expenses include a $43.5 million termination fee incurred in connection with the proposed merger with Energy Partners Ltd. (“EPL”). Prior to entering into the EPL merger agreement, we terminated our merger agreement with Plains Exploration and Production Company (“Plains”) and Plains Acquisition Corp. (“Plains Acquisition”) on June 22, 2006. As

required under the terms of the terminated merger agreement among Stone, Plains and Plains Acquisition, Plains was entitled to a termination fee of $43.5 million (“Plains Termination Fee”), which was advanced by EPL to Plains on June 22, 2006. Pursuant to the EPL merger agreement, we were obligated to repay all or a portion of this termination fee under certain circumstances if the EPL merger was not consummated. The $43.5 million termination fee was recorded as merger expenses in the income statement during the second quarter of 2006. Of this amount, $25.3 million was potentially reimbursable to EPL under certain circumstances described in the EPL merger agreement and therefore was recorded as deferred revenue on the balance sheet as of June 30, 2006 and September 30, 2006. The remaining $18.2 million of the termination fee was recorded as merger expense reimbursement in the income statement during the three months ended June 30, 2006. On October 11, 2006, we entered into an agreement with EPL pursuant to which the EPL merger agreement was terminated. Pursuant to the termination of the EPL merger agreement, EPL paid us $8 million and released all claims to the $43.5 million Plains Termination Fee. The $8.0 million fee paid to us by EPL in conjunction with the termination of the EPL merger agreement was recorded as merger expense reimbursement in earnings in the fourth quarter of 2006. Additionally, the remaining $25.3 million of the Plains Termination Fee was recognized as merger expense reimbursement in earnings in the fourth quarter of 2006.

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

     Production. 2007 production totaled 6,088,000 barrels of oil and 45.1 Bcf of natural gas compared to 5,593,000 barrels of oil and 43.5 Bcf of natural gas produced during 2006, an increase on a gas equivalent basis of 4.6 Bcfe. 2007 and 2006 total production rates were negatively impacted by extended Gulf Coast shut-ins due to Hurricanes Katrina and Rita, amounting to volumes of approximately 3.6 Bcfe (10 MMcfe per day) and 15.6 Bcfe (43 MMcfe per day), respectively. Without the effects of the hurricane production deferrals, year to year total production volumes decreased approximately 7.5 Bcfe. The decrease was primarily the result of the sale of substantially all of our Rocky Mountain Region properties on June 29, 2007. Rocky Mountain Region production was 11.9 Bcfe for the year ended December 31, 2006 and 6.6 Bcfe for the year ended December 31, 2007.

     Prices. Prices realized during 2007 averaged $69.68 per barrel of oil and $7.30 per Mcf of natural gas compared to 2006 average realized prices of $62.40 per barrel of oil and $7.75 per Mcf of natural gas. On a gas equivalent basis, average 2007 prices were 4% higher than prices realized during 2006. 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, 2007 and 2006, our effective hedging transactions increased our average realized natural gas prices by $0.23 per Mcf and $0.85 per Mcf, respectively. Average realized oil prices were decreased during the year ended December 31, 2007 by $0.42 per barrel and were increased by $0.02 per barrel for the year ended December 31, 2006.

     Income. As a result of 4% higher realized prices on a gas equivalent basis and a 6% increase in production volumes for the year, oil and natural gas revenue increased 10% to $753.3 million in 2007 from $686.3 million during 2006. Rocky Mountain Region year ended December 31, 2007 oil and natural gas revenue amounted to $47.4 million, representing 6% of total company oil and natural gas revenue for such period.

     Interest income totaled $12.1 million during 2007 compared to $2.5 million during 2006. The increase in interest income is the result of an increase in our cash balances during the period after the sale of substantially all of our Rocky Mountain Region properties in June 2007.

     Derivative Income/Expense. During 2007 and 2006, certain of our derivative contracts were determined to be partially ineffective because of differences in the relationship between the fixed price in the derivative contract and actual prices realized. Derivative expense for the year ended December 31, 2007 totaled $0.7 million, representing changes in the fair market value of the ineffective portion of the derivatives. Derivative income for the year ended December 31, 2006 totaled $2.7 million, consisting of $2.3 million of cash settlements on the ineffective portion of derivatives and $0.4 million of changes in the fair market value of the ineffective portion of derivatives.

     Expenses. During 2007, we incurred lease operating expenses of $149.7 million, compared to $159.0 million incurred during 2006. On a unit of production basis, 2007 lease operating expenses were $1.83 per Mcfe as compared to $2.06 per Mcfe for 2006. The decrease in lease operating expenses is primarily the result of a decrease in major maintenance activity in 2007, net of estimated insurance recoveries. We sold substantially all of our Rocky Mountain Region properties in June 2007. Rocky Mountain Region lease operating expenses were $10.0 million and $10.6 million for the years ended December 31, 2007 and 2006, respectively.

     DD&A expense on oil and gas properties for 2007 totaled $299.2 million, or $3.67 per Mcfe, compared to DD&A expense of $316.8 million, or $4.11 per Mcfe in 2006. At December 31, 2006, we recorded a ceiling test write-down, which reduced our net investment in oil and gas properties and resulted in a reduction of the going forward unit cost of DD&A of $0.86 per Mcfe.

     During 2007 and 2006, SG&A expenses (exclusive of incentive compensation) totaled $33.6 million and $34.3 million, respectively. Included in 2007 SG&A are severance and retention payments of $2.1 million made to employees in our Denver District in connection with the sale of substantially all of our Rocky Mountain Region properties in June 2007 and the resulting discontinuation of operations of such district. Total 2007 SG&A expenses for the Denver District were $3.8 million. Exclusive of the $2.1 million severance and retention payments, 2007 Denver District SG&A represented 5.5% of total company SG&A.

     Interest expense for 2007 totaled $32.1 million, net of $16.2 million of capitalized interest, compared to interest expense of $35.9 million, net of $18.2 million of capitalized interest, during 2006. In June 2007, a portion of the proceeds from the sale of substantially all of our Rocky Mountain Region properties was used to pay down all outstanding borrowings under our bank credit facility resulting in a decrease in interest expense for the year ended December 31, 2007.

     During 2007 and 2006, we incurred $17.6 million and $12.4 million, respectively, of accretion expense related to asset retirement obligations. The increase in 2007 accretion expense is due to increases in estimated asset retirement costs determined in late 2006.

     For the years ended December 31, 2007 and 2006, production taxes totaled $9.9 million and $13.5 million, respectively. The decrease in production taxes resulted from the sale of substantially all of our Rocky Mountain Region properties in June 2007. 2007 Rocky Mountain Region production taxes totaled $4.0 million, representing 40% of total company production taxes for such period.

     We estimated that we incurred $95.6 million of current federal and state income tax expense for calendar year 2007 of which $57.6 million was unpaid through December 31, 2007.

     Reserves. At December 31, 2007, our estimated proved oil and gas reserves totaled 402.6 Bcfe, compared to December 31, 2006 reserves of 590.9 Bcfe. The decrease in estimated proved reserves during 2007 was primarily the result of the sale of substantially all of our Rocky Mountain Region properties in June 2007. Estimated proved natural gas reserves totaled 213.1 Bcf and estimated proved oil reserves totaled 31.6 MMBbls at the end of 2007. The reserve estimates at December 31, 2007 were prepared by Netherland, Sewell & Associates, Inc. in accordance with guidelines established by the SEC.

     Our standardized measure of discounted future net cash flows was $1.5 billion and $1.2 billion at December 31, 2007 and 2006, respectively. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine these estimates of future net cash flows using market prices for oil and gas on the last day of the fiscal period. The average year-end oil and gas prices net of differentials on all of our properties used in determining these amounts, excluding the effects of hedges in place at year-end, were $94.63 per barrel and $7.27 per Mcf for 2007 and $56.90 per barrel and $5.39 per Mcf for 2006.

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. We adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements,” on January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure about fair value measurements. The net effect of the implementation of SFAS No. 157 on our financial statements was immaterial.

     As of December 31, 2008, we held certain financial assets and liabilities that are required to be measured at fair value on a recurring basis, including our commodity derivative instruments and our investments in money market funds. Additionally, fair value concepts were applied in the recording of assets and liabilities acquired in the Bois d’Arc transaction.

     In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Liabilities — Including an amendment of FASB Statement No. 115”. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. This statement became effective for us on January 1, 2008. We did not elect the fair value option for any of our existing financial instruments other than those mandated by other FASB standards and accordingly the impact of the adoption of SFAS No. 159 on our financial statements was immaterial. We have not determined whether or not we will elect this option for financial instruments we may acquire in the future.

     Business Combinations and Goodwill. Our 2008 accounting for the acquisition of Bois d’Arc was governed by the accounting concepts of SFAS No. 141, “Business Combinations.” This standard requires the application of the purchase method of accounting and requires the application of fair value concepts in determining the cost of the acquired entity and allocating that cost to assets acquired (including goodwill) and liabilities assumed. SFAS No. 142, “Goodwill and Other Intangible Assets,” requires the testing for impairment of goodwill at least annually. It establishes a two-step methodology for determining impairment that begins with an estimation of the fair value of the reporting unit. The first step is a screen for potential impairment, and the second step measures the amount of impairment, if any. This authoritative guidance provided the framework for the determination of our goodwill impairment at December 31, 2008.

     Asset Retirement Obligations. Our accounting for asset retirement obligations is governed by SFAS No. 143, “Accounting for Asset Retirement Obligations”. This statement requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The adoption of SFAS No. 143 requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. As required by SFAS No. 143, our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

     Full Cost Method. We 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, 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. generally accepted accounting principles allow the option of two acceptable methods for accounting for oil and gas properties. The successful efforts method is the allowable alternative to the full cost method. The primary differences between the two methods are in the treatment of exploration costs and in the computation of DD&A. Under the full cost method, all exploratory costs are capitalized while under the successful efforts method exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under full cost accounting, DD&A is computed on cost centers represented by entire countries while under successful efforts cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs.

     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 (based on period-end hedge adjusted commodity prices 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 discounted cash flows.

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

     Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Our most significant estimates are:

	•		remaining proved oil and gas reserves volumes and the timing of their production;
	•		estimated costs to develop and produce proved oil and gas reserves;
	•		accruals of exploration costs, development costs, operating costs and production revenue;
	•		timing and future costs to abandon our oil and gas properties;
	•		the effectiveness and estimated fair value of derivative positions;
	•		classification of unevaluated property costs;
	•		capitalized general and administrative costs and interest;
	•		insurance recoveries related to hurricanes;
	•		estimates of fair value in business combinations;
	•		goodwill impairment testing and measurement;
	•		current income taxes; and
	•		contingencies.

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

Recent Accounting Developments

     Non-controlling Interests & Business Combinations. In December 2007, the FASB issued SFAS No. 160, “Non-controlling Interests in Consolidated Financial Statements, an amendment of ARB No. 151” and SFAS No. 141(R), “Business Combinations”. These statements are designed to improve, simplify and converge internationally the accounting for business combinations and the reporting of non-controlling interests in consolidated financial statements. These statements are effective for us beginning on January 1, 2009.

     Derivative Instruments and Hedging Activities. In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities. SFAS No. 161 will be effective for financial statements issued for fiscal years beginning after November 15, 2008.

     We do not anticipate that the implementation of these new standards will have a material effect on our financial statements.

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 loss per share for 2008 would have increased approximately $1.91 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 zero-premium collars and fixed-price swaps with various counterparties for a portion of our expected 2009 and 2010 oil and natural gas production from the Gulf Coast Basin. The natural gas collar settlements are based on an average of NYMEX prices for the last three days of a respective month. The oil collar settlements are based upon an average of the NYMEX closing price for West Texas Intermediate (“WTI”) during the entire calendar month. The collar contracts require payments to the counterparties if the average price is above the ceiling price or payment from the counterparties if the average price is below the floor price. Some of our fixed-price gas swap settlements are based on an average of NYMEX prices for the last three days of a respective month and some are based on the NYMEX price for the last day of a respective month. The fixed-price oil swap settlements are based upon an average of the NYMEX closing price for WTI during the entire calendar 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.

     The following tables show our hedging positions as of February 23, 2009:

		Zero-Premium Collars
		Natural Gas												Oil
		Daily												Daily
		Volume				Floor				Ceiling				Volume				Floor				Ceiling
		(MMBtus/d)				Price				Price				(Bbls/d)				Price				Price
2009			20,000			$	8.00			$	14.30				3,000			$	80.00			$	135.00
2009			20,000				9.00				14.63

		Fixed-Price Swaps
		Natural Gas								Oil
		Daily								Daily
		Volume				Swap				Volume				Swap
		(MMBtus/d)				Price				(Bbls/d)				Price
2009			20,000			$	10.15				2,000			$	107.90
2010			20,000				6.97				2,000				63.00
2010			30,000				6.50

     We believe these positions have hedged approximately 40% to 45% of our estimated 2009 production and 25% to 32% of our estimated 2010 production.

     Interest Rate Risk

     We had long-term debt outstanding of $825 million at December 31, 2008, of which $400 million, or approximately 48%, bears interest at fixed rates. The $400 million of fixed-rate debt is comprised of $200 million of 8¹/4% Senior Subordinated Notes due 2011 and $200 million of 6³/4% Senior Subordinated Notes due 2014. At December 31, 2008, the remaining $425 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, 2008, the weighted average interest rate under our bank credit facility was approximately 3.8%. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. Assuming a 200 basis point increase in market interest rates during 2008 our interest expense, net of capitalization, would have increased approximately $0.4 million, net of taxes, resulting in a $.01 per diluted share increase in our reported net loss.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     Information concerning this Item begins on Page F-1.

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

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

ITEM 9A. CONTROLS AND PROCEDURES

          Evaluation of Disclosure Controls and Procedures

     We have established disclosure controls and procedures to ensure that material information relating to Stone Energy Corporation and its consolidated subsidiaries (collectively “Stone”) is made known to the Officers who certify Stone’s financial reports and the Board of Directors. 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 chief executive officer and our chief financial officer, with the participation of other members of our senior management, reviewed and evaluated the effectiveness of Stone’s disclosure controls and procedures as of December 31, 2008. Based on this evaluation, our chief executive officer and chief financial officer believe:

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

     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, 2008 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 chief executive officer and chief financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008. 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, 2008. 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, 2008.

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, 2008, 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, 2008, 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, 2008 and 2007, 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, 2008 and our report dated February 26, 2009 expressed an unqualified opinion thereon.

		/s/Ernst & Young LLP

New Orleans, Louisiana
February 26, 2009

ITEM 9B. OTHER INFORMATION

     None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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

     Additional information required by Item 10, including information regarding our audit committee financial experts, is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2009 Annual Meeting of Stockholders to be held on May 28, 2009. 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 2009 Annual Meeting of Stockholders to be held on May 28, 2009.

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 2009 Annual Meeting of Stockholders to be held on May 28, 2009.

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 2009 Annual Meeting of Stockholders to be held on May 28, 2009.

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 2009 Annual Meeting of Stockholders to be held on May 28, 2009.

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, 2008 and 2007
Consolidated Statement of Operations for the three years in the period ended December 31, 2008
Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2008
Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period ended December 31, 2008
Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2008
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		Agreement and Plan of Merger, by and among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and Bois d’Arc Energy, Inc., dated as of April 30, 2008 (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K dated April 30, 2008 (File No. 001-12074)).
2.2		Stockholder Agreement, by and among Stone Energy Corporation and Comstock Resources, Inc., dated as of April 30, 2008 (incorporated by reference to Exhibit 2.2 to the Registrant’s Current Report on Form 8-K dated April 30, 2008 (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 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 dated May 15, 2008 (File No. 001-12074)).
4.1		Indenture between Stone Energy Corporation and JPMorgan Chase Bank dated December 10, 2001 (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-4 (Registration No. 333-81380)).
4.2		Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on December 15, 2004.)
4.3		First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank dated December 10, 2001 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K dated August 27, 2008 (File No. 001-12074)).
4.4		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 dated August 27, 2008 (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 2004 Amended and Restated Stock Incentive Plan (incorporated by reference to the Registrant’s Registration Statement on Form S-8 (Registration No. 333-107440)).
†10.3		Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.4		Stone Energy Corporation Amended and Restated Revised Annual Incentive Compensation Plan, dated November 14, 2007 (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-12074)).
†10.5		Stone Energy Corporation Deferred Compensation Plan (incorporated by reference to Exhibit 4.5 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.6		Adoption Agreement between Fidelity Management Trust Company and Stone Energy Corporation for the Stone Energy Corporation Deferred Compensation Plan dated December 1, 2004 (incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).
†10.7		Letter Agreement dated May 19, 2005 between Stone Energy Corporation and Kenneth H. Beer (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed May 24, 2005 (File No. 001-12074)).
*†10.8		Letter Agreement dated December 2, 2008 between Stone Energy Corporation and David H. Welch.
†10.9		Letter Agreement dated June 28, 2007 between Stone Energy Corporation and Richard L. Smith (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated June 28, 2007 (File No. 001-12074)).
10.10		$700,000,000 Second Amended and Restated Credit Agreement between Stone Energy Corporation and the financial institutions named therein, dated August 28, 2008 (incorporated by reference to Exhibit 4.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-12074)).
10.11		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)).
† 10.12		Stone Energy Corporation Executive Change of Control and Severance Plan (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)).
† 10.13		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)).
† 10.14		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)).
*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.

SIGNATURES

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

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

Signature		Title		Date
/s/ David H. Welch		President, Chief Executive Officer		February 26, 2009
David H. Welch		and Director
		(principal executive officer)
/s/ Kenneth H. Beer		Senior Vice President and		February 26, 2009
Kenneth H. Beer		Chief Financial Officer
		(principal financial officer)
/s/ J. Kent Pierret		Senior Vice President, Chief		February 26, 2009
J. Kent Pierret		Accounting Officer and Treasurer
		(principal accounting officer)
/s/ Robert A. Bernhard		Director		February 26, 2009
Robert A. Bernhard
/s/ George R. Christmas		Director		February 26, 2009
George R. Christmas
/s/ B.J. Duplantis		Director		February 26, 2009
B.J. Duplantis
/s/ Peter D. Kinnear		Director		February 26, 2009
Peter D. Kinnear
/s/ John P. Laborde		Director		February 26, 2009
John P. Laborde
/s/ Richard A. Pattarozzi		Director		February 26, 2009
Richard A. Pattarozzi
/s/ Donald E. Powell		Director		February 26, 2009
Donald E. Powell
/s/ Kay G. Priestly		Director		February 26, 2009
Kay G. Priestly
/s/ David R. Voelker		Director		February 26, 2009
David R. Voelker

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheet as of December 31, 2008 and 2007			F-3
Consolidated Statement of Operations for the years ended December 31, 2008, 2007 and 2006			F-4
Consolidated Statement of Cash Flows for the years ended December 31, 2008, 2007 and 2006			F-5
Consolidated Statement of Changes in Stockholders’ Equity for the years ended December 31, 2008, 2007 and 2006			F-6
Consolidated Statement of Comprehensive Income for the years ended December 31, 2008, 2007 and 2006			F-7
Notes to Consolidated Financial Statements			F-8