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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, 2005
or


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

For the transition period from to

Commission File Number: 1-12074

STONE ENERGY CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


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


625 E. Kaliste Saloom Road
Lafayette, Louisiana		70508
(Address of Principal Executive Offices)		(Zip Code)

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

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


		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.

o Yes 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer 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 $1,043,487,711 as of June 30, 2005 (based on the last reported sale price of such stock on the New York Stock Exchange Composite Tape on that day).

As of March 1, 2006, the registrant had outstanding 27,161,626 shares of Common Stock, par value $.01 per share.

Document incorporated by reference: Portions of the Definitive Proxy Statement of Stone Energy Corporation relating to the Annual Meeting of Stockholders to be held on May 18, 2006 are incorporated by reference into Part III of this Form 10-K.

EXPLANATORY NOTE

Reserves Restatement – On October 6, 2005, as a result of reservoir level reviews conducted during August 2005 through early October 2005, we announced a downward revision of 171 billion cubic feet of natural gas equivalent (“Bcfe”) of proved reserves. After additional analysis and consultation with outside engineering firms, the revision was increased to 237 Bcfe. Subsequently, after an internal review of the causes of this revision, we decided to restate the unaudited oil and gas reserve disclosures previously included in the footnotes accompanying our financial statements contained in the original Form 10-K filed for the years ended December 31, 2004, 2003, 2002 and 2001 to give effect to the removal of 157 Bcfe of those volumes to the periods in which they did not represent proved reserves within the applicable rules of the Securities and Exchange Commission (“SEC”).

Please refer to pages F-8 to F-11 for additional information regarding the reserves restatement.

Financial Restatement – In view of the overstatement of proved reserves, it was determined to restate the financial statements of the Company for the years ended December 31, 2004, 2003, 2002 and 2001 and the quarters ended March 31, 2005 and June 30, 2005. This overstatement of proved reserves had the effect of understating the write-down of oil and gas properties for 2001 and depreciation, depletion and amortization expense (“DD&A”) for all the periods to be restated which in turn caused the overstatement of various reported amounts.

Additionally, in the process of the preparation of the Company’s Form 10-Q for September 30, 2005, it was determined that approximately $9.8 million of unevaluated oil and gas property costs were inappropriately classified and should have been reclassified to proved oil and gas property costs in 2002. The Financial Restatement includes the effect of this revision for the years ended December 31, 2004, 2003 and 2002. The total cumulative impact of the restatements on stockholders’ equity as of June 30, 2005 was a reduction of approximately $89.8 million, which includes a reduction in beginning stockholders’ equity as of January 1, 2002 of approximately $45.3 million.

Please refer to pages F-8 to F-11 for additional information regarding the financial restatement.

The information herein reflects the restatements described above unless the context provides otherwise.

PART I

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

ITEM 1. BUSINESS

The Company

Stone Energy is an independent oil and gas company engaged in the acquisition and subsequent exploration, development, operation and production of oil and gas properties located in the conventional shelf of the Gulf of Mexico (the “GOM”), the deep shelf of the GOM, the deepwater of the GOM, Rocky Mountain Basins and the Williston Basin. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508.

Available Information

We make available free of charge on our Internet web site (www.stoneenergy.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”). In addition, the public may read and copy any materials filed by us with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. We also make available on our Internet web site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, respectively, which have been approved by our board of directors. We will make immediate disclosure by a Current Report on Form 8-K and on our web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. 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 June 6, 2005.

Strategy and Operational Overview

Since our public offering in 1993, we have been engaged in the acquisition, exploration and development of mature oil and gas properties in the Gulf Coast Basin, which includes onshore Louisiana and offshore GOM. During 2004, we broadened our conventional shelf acquisition and exploitation strategy in order to diversify, extend reserve life and take advantage of a strong oil and gas market. This broadened growth strategy includes targeting reserves and production in the deep shelf and deep water of the GOM, furthering our position in the Rocky Mountain Region (Rocky Mountain Basins and Williston Basin) to complement our existing portfolio of properties in the Gulf Coast Basin (onshore, shelf and deep shelf) and investigating viable opportunities in other areas including international areas. Our strategy is driven by increased availability of lease blocks in the deep water of the GOM, 3D seismic technology improvements in the deep shelf of the GOM, fracturing technology improvements and horizontal drilling applications in the Rocky Mountain Region and other areas. As of March 1, 2006, our property portfolio consisted of 58 active properties and 60 primary term leases in the Gulf Coast Basin and 21 active properties in the Rocky Mountain Region.

As of December 31, 2005, we had estimated proved reserves of approximately 593 billion cubic feet of natural gas equivalent (“Bcfe”), 73% of which were classified as proved developed and 58% of which were natural gas. For the year ended December 31, 2005, we produced an average of 228 million cubic feet of natural gas equivalent (“MMcfe”) per day, which was curtailed due to extended production downtime associated with Hurricanes Katrina and Rita. During 2005, we generated net cash flow from operating activities of $461.2 million.

Gulf of Mexico — Conventional Shelf (Including Onshore Louisiana)

Our conventional shelf strategy is the same acquisition and exploitation combination that we adopted prior to our initial public offering in 1993. We apply the latest geophysical interpretation tools to identify underdeveloped properties and the latest production techniques to increase production attributable to these properties. We seek to acquire properties that have the following characteristics:

	•		mature properties with an established production history and infrastructure;

	•		multiple productive sands and reservoirs;

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

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

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

Gulf of Mexico — Deep Water

We believe that the deep water of the GOM is an important exploration area, even though it involves high risk, high costs and substantial lead time to develop infrastructure. We have assembled a technical team with prior geological, geophysical and engineering experience in the deep water arena to evaluate potential opportunities. During 2005, we drilled three deep water wells, none of which were successful. As of yet, we have no production or reserves in the deep water of the GOM.

Gulf of Mexico — Deep Shelf

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

Rocky Mountain Basins

Our assets in the Rocky Mountain Basins represented 9% of our total production in 2005 and 16% of our total estimated proved reserves (on a volumetric basis) at December 31, 2005. Our Rocky Mountain Basins include positions in the Wind River and Greater Green River Basins in Wyoming and Uinta Basin in Utah.

Williston Basin

On March 1, 2005, we completed the acquisition of approximately 35,000 net acres in the Williston Basin of North Dakota and Montana. The acquisition cost, net of purchase price adjustments, totaled approximately $85.7 million, of which $76.0 million was financed with borrowings under our bank credit facility. During the remainder of 2005 we drilled 20 wells, all of which were productive. We also acquired an additional 314,000 net acres for additional exploration and development in the Williston Basin. Our Williston Basin assets represented 2% of our total production in 2005 and 8% of our total estimated proved reserves (on a volumetric basis) at December 31, 2005.

Oil and Gas Marketing

Our oil and natural gas production is sold at current market prices under short-term contracts. Conoco, Inc., Sequent Energy Management LP and Total Gas & Power North America, Inc. each accounted for between 10%-12% of oil and natural gas revenue generated during the year ended December 31, 2005. No other purchaser accounted for 10% or more of our total oil and natural gas revenue during 2005. We believe that the loss of any of our major purchasers would not result in a material adverse effect on our ability to market future oil and gas production. From time to time, we may enter into transactions that hedge the price of oil and natural gas. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.”

Competition and Markets

Competition in the Gulf Coast Basin and the Rocky Mountain Region is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than ours, which may adversely affect our ability to compete. See “Item 1A. Risk Factors – Competition within our industry may adversely affect our operations.”

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

Regulation

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

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

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

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 natural gas industry has been heavily regulated. We can give no assurance that the regulatory approach currently pursued by the FERC will continue indefinitely. We do not anticipate, however, that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect on our financial condition, results of operations or competitive position. No portion of our business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

Environmental Regulation

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

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

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

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

Employees

On March 1, 2006, we had 271 full time employees. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement. Under our supervision, we utilize the services of independent contractors to perform various daily operational duties.

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; 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, third party interruption of sales to market, inflation, lack of availability of goods and services, environmental risks, drilling and other operating risks, hurricanes and other weather conditions, regulatory changes, the uncertainty inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures and the other risks described in this Form 10-K.

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

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

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

ITEM 1A. RISK FACTORS

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

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

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

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

	•		market uncertainty;

	•		the level of consumer product demands;

	•		hurricanes and other weather conditions;

	•		domestic and foreign governmental regulations;

	•		the price and availability of alternative fuels;

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

	•		the foreign supply of oil and natural gas;

	•		the price of oil and gas imports; and

	•		overall domestic and foreign economic conditions.

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

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

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

In general, the volume of production from oil and gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Gulf of Mexico reservoirs tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. During 2005, 89% of our production and 76% of our estimated proved reserves were derived from Gulf of Mexico reservoirs, while the remaining portions of our production and reserves were derived from the Rocky Mountain Region. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves.

We have identified a material weakness in our internal controls relating to the estimation of proved reserves.

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.

As articulated in “Item 9A. Controls and Procedures” on page 31, management has identified a material weakness in internal controls that did not prevent the overstatement of our proved oil and gas reserves in prior periods. As of the date of this report, we have not completely mitigated the causes of this weakness because we have not had an adequate passage of time to monitor the progress of our continuing training programs.

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

We spend and will continue to spend a substantial amount of capital for the acquisition, exploration, exploitation, development and production of oil and gas reserves. Our capital expenditures, including acquisitions and exclusive of estimated asset retirement costs, were $479.8 million during 2005, $501.2 million during 2004 and $361.9 million during 2003. We have budgeted total capital expenditures in 2006, excluding property acquisitions, asset retirement costs and capitalized salaries, general and administrative costs and interest, to be approximately $360 million. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues and cash flows from operating activities to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditures program. In addition, if our borrowing base under our credit facility is re-determined to a lower amount, this could adversely affect our ability to fund our planned capital expenditures. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot assure you that additional debt or equity financing will be available or cash flows provided by operations will be sufficient to meet these requirements.

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

As of March 1, 2006, we had $563 million in outstanding indebtedness. We have a borrowing base under our bank credit facility of $300 million with availability of an additional $114 million of borrowings as of March 1, 2006. Our borrowing base was reduced from $425 million to $300 million after we announced our reserve revision in October 2005.

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

	•		incurring additional debt;

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

	•		making investments;

	•		creating liens on our assets;

	•		selling assets;

	•		guaranteeing other indebtedness;

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

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

	•		entering into transactions with affiliates.

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

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

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

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

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

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

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

	•		making us vulnerable to increases in interest rates, because debt under our credit facility 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 the credit facility, which is re-determined periodically, is based on an amount established by the bank group after its evaluation of our proved oil and gas reserve values. Upon a re-determination, if borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to repay a portion of our bank debt.

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

We have experienced significant shut-ins and losses of production in 2004 and 2005 due to the effects of hurricanes in the Gulf of Mexico.

Approximately 76% of our estimated proved reserves at December 31, 2005 and 89% of our production during 2005 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. During 2004, we experienced an approximate 7.0 Bcfe deferral of production due to Hurricane Ivan. During 2005, we experienced an approximate 16.4 Bcfe deferral of production resulting from Hurricanes Katrina and Rita. 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. 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 may cause us to record ceiling test write-downs.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under 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), net of related tax effect, to the net capitalized costs of proved oil and gas properties, including estimated capitalized abandonment costs, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows. This charge does not impact cash flow from operating activities, but does reduce net income. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. We cannot assure you that we will not experience ceiling test write-downs in the future.

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

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

	•		bank borrowings or the issuance of debt securities;

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

	•		joint venture financing; and

	•		production payments.

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

There are uncertainties in successfully integrating our acquisitions.

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

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

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

	•		unexpected drilling conditions;

	•		pressure or irregularities in formations;

	•		equipment failures or accidents;

	•		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. If any of these industry-operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions. In accordance with industry practice, we maintain insurance against some, but not all, of the risks described above.

We have begun to explore for natural gas and oil in the deep waters of the GOM (water depths greater than 2,000 feet) where operations are more difficult than in shallower waters. Our deep water drilling and operations require the application of recently developed technologies that involve a higher risk of mechanical failure. The deep waters of the 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.

We maintain insurance of various types to cover our operations, including maritime employer’s liability and comprehensive general liability. Coverage amounts are provided by primary and excess umbrella liability policies. In addition, we maintain operator’s extra expense insurance, which provides coverage for the care, custody and control of wells drilled and/or completed plus re-drill and pollution coverage. The exact amount of coverage for each well is dependent upon its depth and location. We experienced Gulf of Mexico production interruption in 2004 from Hurricane Ivan and in 2005 from Hurricanes Katrina and Rita for which we do not have any loss of production insurance.

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

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.

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

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

Our operations are dependent upon a relatively small group of key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. 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.

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

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

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

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

We do not pay dividends.

We have never declared or paid any cash dividends on our common stock and have no intention to do so in the near future. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indenture executed in connection with our 8¹/4% Senior Subordinated Notes due 2011 and 6³/4% Senior Subordinated Notes due 2014. In addition, we have entered into a credit facility that contains provisions that may have the effect of limiting or prohibiting the payment of dividends.

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

Certain provisions of our Certificate of Incorporation, Bylaws and shareholders’ rights plan and the provisions of the Delaware General Corporation Law may encourage persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. Our Bylaws provide for a classified board of directors, who 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 and with the rights plan described below, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common stock. Our board of directors recently considered a policy to elect directors by majority vote, but a decision was made to continue with plurality voting at this time.

During 1998, our board of directors adopted a shareholder rights agreement, pursuant to which uncertificated stock purchase rights were distributed to our stockholders at a rate of one right for each share of common stock held of record as of October 26, 1998. The rights plan is designed to enhance the board’s ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect stockholders against attempts to acquire us by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover not supported by our board, including a takeover that may be desired by a majority of our stockholders or involving a premium over the prevailing stock price. This shareholder rights agreement expires on September 30, 2008.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

As of March 1, 2006, our property portfolio consisted of 58 active properties and 60 primary term leases in the Gulf Coast Basin and 21 active properties in the Rocky Mountain Region. We serve as operator on 59% of our active properties, including a 64% operating percentage on our Gulf Coast Basin properties and 48% operating percentage on our Rocky Mountain Region properties. The properties that we operate accounted for 72% of our year-end 2005 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 gas reserves is based upon reserve reports prepared as of December 31, 2005. The majority of our Gulf Coast Basin reserves have been audited by Netherland, Sewell & Associates, Inc. The audited properties cover 72.6% of our total reserve base on a volumetric basis. The remainder of our Gulf Coast Basin reserves were engineered by Cawley, Gillespie & Associates, Inc. and represent 3.0% of our reserves on a volumetric basis. Our Rocky Mountain Region reserves were engineered by Ryder Scott Company, L.P. and represent 24.4% of our reserves on a volumetric basis. All product pricing and cost estimates used in the reserve reports are in accordance with the rules and regulations of the SEC. The standardized measure of discounted future net cash flows has been calculated using a discount factor of 10%.

You should not assume that the estimated future net cash flows or the present value of estimated future net cash flows, referred to in the table below, represent the fair value of our estimated oil and gas reserves. As required by the SEC, we determine estimated future net cash flows using period-end market prices for oil and gas without considering hedge contracts in place at the end of the period. Using the information contained in the reserve reports, the average 2005 year-end product prices for all of our properties were $57.17 per barrel of oil and $9.86 per Mcf of gas. The following table sets forth our estimated net proved oil and natural gas reserves and the present value of estimated future net cash flows related to such reserves as of December 31, 2005.


							Percent
	Proved		Proved		Total		Proved
	Developed		Undeveloped		Proved		Developed
Total Company:
Oil (MBbls)		31,557		9,952		41,509		76	%

Natural gas (MMcf)		241,347		102,741		344,088		70	%

Total oil and natural gas (MMcfe)		430,689		162,453		593,142		73	%

Estimated future net cash flows (in thousands) before tax	$	2,757,512	$	1,037,052	$	3,794,564		73	%

Discounted future net cash flows (in thousands) before tax	$	1,993,443	$	571,639	$	2,565,082		78	%

Gulf Coast Basin:
Oil (MBbls)		24,806		6,307		31,113		80	%

Natural gas (MMcf)		196,854		65,043		261,897		75	%

Total oil and natural gas (MMcfe)		345,690		102,885		448,575		77	%

Estimated future net cash flows (in thousands) before tax	$	2,217,695	$	704,218	$	2,921,913		76	%

Discounted future net cash flows (in thousands) before tax	$	1,710,828	$	432,543	$	2,143,371		80	%

Rocky Mountain Region:
Oil (MBbls)		6,751		3,645		10,396		65	%

Natural gas (MMcf)		44,493		37,698		82,191		54	%

Total oil and natural gas (MMcfe)		84,999		59,568		144,567		59	%

Estimated future net cash flows (in thousands) before tax	$	539,817	$	332,834	$	872,651		62	%

Discounted future net cash flows (in thousands) before tax	$	282,615	$	139,096	$	421,711		67	%

The following represents additional information on individually significant properties:


			December 31,
			2005
			Estimated
		2005	Proved	Nature of
Field Name	Location	Production	Reserves	Interest
Ewing Bank Block 305	GOM Shelf	6.0 Bcfe	61.9 Bcfe	Working
Pinedale Vail II	Greater Green River	4.1 Bcfe	55.2 Bcfe	Working
	Basin Wyoming
	USA
Sidney	Williston Basin	1.2 Bcfe	42.6 Bcfe	Working
	North Dakota USA
Main Pass Block 288	GOM Shelf	4.6 Bcfe	37.0 Bcfe	Working
South Pelto Block 23	GOM Shelf	5.2 Bcfe	34.1 Bcfe	Working
South Timbalier Block 143/166/172	GOM Shelf	12.5 Bcfe	24.5 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 gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. Results of drilling, testing and production subsequent to the date of an estimate may justify a revision of such estimate. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately produced. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geological success, prices, future production levels, operating costs, development costs and income taxes that may not prove to be correct. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of these estimates depends on the accuracy of the assumptions upon which they are based. See “Item 1A. Risk Factors – We have identified a material weakness in our internal controls relating to the estimation of proved reserves”.

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

Acquisition, Production and Drilling Activity

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


	Year Ended December 31,
			2004		2003
	2005		(Restated)		(Restated)
	(In thousands)
Acquisition costs, net of sales of unevaluated properties	$	138,080	$	201,550	$	54,456
Development costs		149,890		125,161		109,507
Exploratory costs		156,472		151,571		175,864

Subtotal		444,442		478,282		339,827
Capitalized salaries, general and administrative costs and interest, net of fees and reimbursements		35,339		22,926		22,027
Asset retirement costs		53,687		19,950		49,728

Total additions to oil and gas properties	$	533,468	$	521,158	$	411,582

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, 2005.


	Gross		Net
Productive Wells:
Oil (1):
Gulf Coast Basin		90.00		64.03
Rocky Mountain Region		239.00		134.22

		329.00		198.25

Gas (2):
Gulf Coast Basin		113.00		68.83
Rocky Mountain Region		59.00		24.23

		172.00		93.06

Total		501.00		291.31

Developed Acres:
Gulf Coast Basin		51,570.01		30,787.57
Rocky Mountain Region		58,177.01		30,033.76

Total		109,747.02		60,821.33

Undeveloped Acres (3):
Gulf Coast Basin		635,939.71		406,699.80
Rocky Mountain Region		473,292.41		370,245.06

Total		1,109,232.12		776,944.86


(1)		6 gross wells each have dual completions.

(2)		8 gross wells each have dual completions.

(3)		Leases covering approximately 4% of our undeveloped gross acreage will expire in 2006, 3% in 2007, 7% in both 2008 and 2009, 15% in 2010, 3% in 2011, 2% in 2012, 1% in both 2013 and 2014 and 4% in 2015. Leases covering the remainder of our undeveloped gross acreage (53%) are held by production.

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


	Year Ended December 31,
	2005				2004				2003
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive		7.00		6.17		17.00		11.02		24.00		20.81
Nonproductive		8.00		5.17		11.00		7.78		7.00		4.50

Development Wells:
Productive		37.00		22.42		20.00		9.61		20.00		13.64
Nonproductive		6.00		2.86		3.00		2.07		1.00		0.85

Title to Properties

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

ITEM 3. LEGAL PROCEEDINGS

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

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 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 years 1999, 2000 and 2001. Further, 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. 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. Stone has not yet been given any indication that the LDR plans to review franchise taxes for the franchise tax years 2004 and 2005.

Stone has received notice that the staff of the SEC is conducting an informal inquiry into the revision of Stone’s proved reserves and the financial statement restatement. In addition, Stone has received an inquiry from the Philadelphia Stock Exchange investigating matters including trading prior to Stone’s October 6, 2005 announcement. Stone intends to cooperate fully with both inquiries.

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 against Stone, David H. Welch, Kenneth H. Beer, D. Peter Canty and James H. Prince purporting to allege violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). Three similar complaints were filed soon thereafter. All complaints assert a putative class period commencing on June 17, 2005 and ending on October 6, 2005. All complaints contend 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 the Company 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 the Company’s proved reserves, assets and future net cash flows were materially overstated at all relevant times. A motion to consolidate these actions and to appoint a lead plaintiff will be heard on March 22, 2006. In addition, on or about December 16, 2005, Robert Farer filed a complaint in the United States District Court for the Western District of Louisiana alleging claims derivatively on behalf of Stone, and three similar complaints were filed soon thereafter in federal and state court. Stone is named as a nominal defendant, and certain current and former officers and directors are named as defendants in these actions, which allege breaches of the fiduciary duties owed to Stone, gross mismanagement, abuse of control, waste of corporate assets, unjust enrichment, and violations of the Sarbanes-Oxley Act of 2002. Stone intends to vigorously defend these lawsuits.

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.

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

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

No matters were submitted for a vote of our stockholders during the third or fourth quarters of 2005.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth information regarding the names, ages (as of March 1, 2006) 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.		57	President, Chief Executive Officer and Director
Craig L. Glassinger.		57	Executive Vice President – Business Development
Kenneth H. Beer.		48	Senior Vice President and Chief Financial Officer
Andrew L. Gates, III.		58	Senior Vice President, General Counsel and Secretary
E. J. Louviere.		57	Senior Vice President – Land
J. Kent Pierret.		50	Senior Vice President, Chief Accounting Officer and Treasurer
Jerome F. Wenzel, Jr.		53	Senior Vice President – Operations
Michael E. Madden.		60	Vice President – Reserves
Florence M. Ziegler.		45	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.

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

Kenneth H. Beer was named Senior Vice President and Chief Financial Officer in August 2005 upon the resignation of James H. Prince. He most recently 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 in April 2004. Mr. Pierret previously served as Vice President and Chief Accounting Officer since June 1999 and Treasurer since February 2004. Prior to June 1999, he was a partner in the firm of Pierret, Veazey & Co., CPAs (and its predecessors) from May 1988 to May 1999, which performed a substantial amount of our financial reporting, tax compliance and financial advisory services.

Jerome F. Wenzel, Jr. joined Stone in October 2004 as Vice President-Production and Drilling and was named Senior Vice President – Operations in September 2005. Prior to joining Stone, Mr. Wenzel held managerial and executive positions with Amoco and BP over a 29 year career.

Michael E. Madden was named Vice President – Reserves in September 2005, Vice President – Exploration and Production Technology in April 2004 and Vice President – Engineering in March 2002. Previously, he served as the Lafayette District Manager from February 2001 to March 2002. He has been employed by Stone Energy since its inception in 1993, initially as a reservoir engineer.

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
2004

First Quarter	$	49.57	$	40.55
Second Quarter		51.35		43.12
Third Quarter		47.72		38.95
Fourth Quarter		48.35		39.80

2005

First Quarter	$	52.21	$	41.16
Second Quarter		51.93		40.51
Third Quarter		62.50		48.99
Fourth Quarter		61.75		42.00

2006

First Quarter (through March 1, 2006)	$	51.40	$	40.50

On March 1, 2006, the last reported sales price on the New York Stock Exchange Composite Tape was $42.01 per share. As of that date, there were 163 holders of record of our common stock.

Dividend Restrictions

In the past, we have not paid cash dividends on our common stock, and we do not intend to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain earnings, if any, for the future operation and development of our business. The restrictions on our present or future ability to pay dividends are included in the provisions of the Delaware General Corporation Law and in certain restrictive provisions in the indenture executed in connection with our 8¹/4% Senior Subordinated Notes due 2011 and 6³/4% Senior Subordinated Notes due 2014. In addition, our bank credit facility contains provisions that may have the effect of limiting or prohibiting the payment of dividends.

Issuer Purchases of Equity Securities

There were no purchases of Stone’s common stock by us or on our behalf during the quarterly period ended December 31, 2005.

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.

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, 2005 and has been restated to reflect adjustments to periods 2001 through 2004 that are further discussed in Note 1 to the Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data”. 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,
	2005			2004			2003			2002			2001
				(Restated)			(Restated)			(Restated)			(Restated)
	(In thousands, except per share amounts)
*Statement of Operations Data:*
Operating revenue:
Oil production	$	244,469		$	214,153		$	174,139		$	155,913		$	103,053
Gas production		391,771			330,048			334,166			221,582			292,446

Total operating revenue		636,240			544,201			508,305			377,495			395,499

Operating expenses:
Lease operating expenses		114,664			100,045			72,786			76,673			54,072
Production taxes		13,179			7,408			5,975			5,039			6,408
Depreciation, depletion and amortization		241,426			210,861			188,813			175,496			164,150
Accretion expense		7,159			5,852			6,292			—			—
Write-down of oil and gas properties		—			—			—			—			302,161
Derivative expense		3,388			4,099			8,711			15,968			2,604
Bad debt expense (1)		—			—			—			—			2,343
Salaries, general and administrative expenses		22,705			14,311			14,870			13,190			13,004
Incentive compensation expense		1,252			2,318			2,636			851			523

Total operating expenses		403,773			344,894			300,083			287,217			545,265


Income (loss) from operations		232,467			199,307			208,222			90,278			(149,766	)

Other (income) expenses:
Interest expense		23,151			16,835			19,860			23,141			4,895
Other expense		—			1,541			538			—			—
Early extinguishment of debt		—			845			4,661			—			—
Merger expenses		—			—			—			—			25,785
Other income		(3,894	)		(4,018	)		(3,133	)		(3,328	)		(2,997	)

Total other expenses, net		19,257			15,203			21,926			19,813			27,683

Income (loss) before income taxes		213,210			184,104			186,296			70,465			(177,449	)
Income tax provision (benefit)		76,446			64,436			65,203			24,662			(60,784	)

Income (loss) before cumulative effects of accounting changes, net of tax		136,764			119,668			121,093			45,803			(116,665	)
Cumulative effects of accounting changes, net of tax (2)		—			—			2,099			—			—

Net income (loss)	$	136,764		$	119,668		$	123,192		$	45,803			($116,665	)

Earnings and dividends per common share:
Income (loss) before cumulative effects of accounting changes per share	$	5.07		$	4.50		$	4.60		$	1.74			($4.47	)

Earnings (loss) per common share	$	5.07		$	4.50		$	4.67		$	1.74			($4.47	)

Income (loss) before cumulative effects of accounting changes per share assuming dilution	$	5.02		$	4.45		$	4.56		$	1.73			($4.47	)

Earnings (loss) per common share assuming dilution	$	5.02		$	4.45		$	4.64		$	1.73			($4.47	)

Cash dividends declared		—			—			—			—			—

*Cash Flow Data:*
Net cash provided by operating activities	$	461,213		$	369,668		$	390,811		$	222,891		$	315,617
Net cash used in investing activities		(499,932	)		(475,159	)		(341,180	)		(216,570	)		(656,847	)
Net cash provided by (used in) financing activities		94,170			112,648			(60,140	)		8,133			275,828

*Balance Sheet Data (at end of period):*
Working capital (deficit)	$	16,506			($28,598	)		($38,474	)		($1,212	)		($18,097	)
Oil and gas properties, net		1,810,959			1,517,308			1,216,141			963,494			924,229
Total assets		2,140,317			1,695,664			1,332,485			1,094,930			1,032,105
Long-term debt, less current portion		563,000			482,000			370,000			431,000			426,000
Stockholders’ equity		944,123			772,934			644,111			522,601			484,735


(1)		Relates to 100% allowance for production receivable due from Enron North America.

(2)		Cumulative effects of accounting changes related to the adoption of SFAS No. 143 and change to the Units of Production method of DD&A.

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, 2005. The financial information in this section has been restated, as further discussed in “Item 8. Note 1 – Financial Statements and Supplementary Data.” All period to period comparisons are based upon restated amounts. 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. Note 1 – Financial Statements and Supplementary Data.”

Executive Overview

We are an independent oil and gas company engaged in the acquisition, exploration, exploitation, development and operation of oil and gas properties located in the conventional shelf of the Gulf of Mexico (the “GOM”), deep shelf of the GOM, deep water of the GOM and several basins in the Rocky Mountain Region. Our business strategy is to increase reserves, production and cash flow through the acquisition, exploitation and development of mature properties in the Gulf Coast Basin and exploring opportunities in the deep water environment of the Gulf of Mexico, Rocky Mountain Region and other potential areas. See “Item 1. Business – Strategy and Operational Overview.”

2005 Significant Events.

	•		Williston Acquisition – Early in 2005 we closed on our acquisition of approximately 35,000 net exploratory acres in the Williston Basin North Dakota and Montana. During 2005 we drilled 20 wells to develop this significant asset acquisition and expanded our acreage position with the acquisition of 314,000 additional net acres.

	•		Hurricane Disruption – Hurricanes Katrina and Rita caused significant disruption in our operations resulting in production deferrals approximating 16.4 Bcfe and significant damage to our offshore facilities.

	•		Reserve Revision – In the fall of 2005, we announced a significant downward reserve revision which resulted in the following:

	Ø		the hiring of an outside firm (Davis, Polk & Wardwell) to investigate the causes of the reserve revision;

	Ø		the announcement of an informal inquiry by the staff of the Securities and Exchange Commission;

	Ø		a delay in the filing of our Form 10-Q for the 3^rd quarter of 2005;

	Ø		a reduction in the borrowing base of our credit facility from $425 million to $300 million;

	Ø		the resignation of our former CEO from the board of directors;

	Ø		the implementation of new and improved procedures and controls over the reserve reporting process;

	Ø		the obtaining of waivers from the participants in our bank credit facility to extend the time to file our 3^rd quarter 2005 financial statements and an agreement with these participants to grant them a security interest in our oil and gas properties;

	Ø		the receipt of notices of non-compliance from over 25% of the holders of the outstanding principal amount of our 6.75% Senior Subordinated Notes due 2014, starting a 60 day period beginning February 15, 2006 in which to cure the default relating to the non-issuance of financial statements. As a consequence of these notices, we became unable to borrow additional funds under our bank credit facility until the default was cured; and

	Ø		the filing of securities and derivative lawsuits against us. See “Item 3. Legal Proceedings”.

2006 Outlook.

Our 2006 capital expenditures budget is approximately $360 million, excluding acquisitions, asset retirement costs and capitalized interest and general and administrative expenses. The $360 million is expected to be spent as follows:


Conventional Shelf	30	%
Rocky Mountain Region	35	%
Deep Shelf/Deep Water	31	%
Other	4	%

We also expect to continue to investigate new opportunities in the Rocky Mountain Region and other areas.

Known Trends and Uncertainties

Gulf Coast Basin Reserve Replacement – We have faced challenges in replacing production in the Gulf Coast Basin at a reasonable unit cost. This condition has been caused by a number of factors including the following:

	•		rising costs of drilling and production services;

	•		lack of an adequate inventory of reserve targets of an attractive size; and

	•		inadequate risking of projects to assist in appropriate portfolio management.

During 2005 and early 2006 we have instituted organizational changes which we believe will lead to a replenishment of our prospect inventory in 2006 and 2007. Additionally, we have employed a new risk management system for project evaluation that we believe will result in more efficient portfolio management.

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 would incur higher franchise tax expense in future years barring the implementation of other tax savings measures. See “Item 3. Legal Proceedings.”

Stock Based Compensation – In 2006, we will begin implementation of Statement of Financial Accounting Standard (“SFAS”) No. 123(R) which will require expensing of the fair value of stock option issuances on the income statement. We have previously elected to disclose such amounts.

In 2005, we adjusted our emphasis in our long-term incentive compensation from the issuance of stock options to the issuance of restricted stock. We expect total equity based compensation expense in 2006 to total between $4.5 and $5.0 million after capitalization.

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 2004 we experienced an approximate 7.0 Bcfe deferral of production due to Hurricane Ivan and in 2005 an approximate 16.4 Bcfe deferral due to Hurricanes Katrina and Rita. Although we do include hurricane contingencies in our production forecasting models, hurricane activity can be more frequent and devastating than what is projected as was the case in 2004 and 2005.

Regulatory Inquiries and Stockholder Lawsuits – We are subject to ongoing inquiries by the SEC. We have also been named as a defendant in certain stockholder lawsuits resulting from our reserve restatement. The ultimate resolution of these matters and their impact on us is uncertain.

Liquidity and Capital Resources

Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $461.2 million during 2005 compared to $369.7 million and $390.8 million in 2004 and 2003, respectively. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2006 capital expenditures with cash flow provided by operating activities.

Net cash flow used in investing activities totaled $499.9 million, $475.2 million and $341.2 million during 2005, 2004 and 2003, respectively, which primarily represents our investment in oil and gas properties.

Net cash flow provided by (used in) financing activities totaled $94.2 million, $112.6 million and ($60.1) million for the years ended December 31, 2005, 2004 and 2003, respectively. Net cash flow provided by financing activities generated during 2005 primarily relates to net proceeds from borrowings under our bank credit facility. Net cash flow provided by financing activities generated during 2004 primarily relates to the proceeds from our 6³/4% Senior Subordinated Notes offering offset in part by the use of offering proceeds to repay borrowings under our bank credit facility. Net cash flow used in financing activities during 2003 was primarily the result of the $61.0 million of repayments under the amended credit facility. Cash and cash equivalents increased from $24.3 million as of December 31, 2004 to $79.7 million as of December 31, 2005.

We had working capital at December 31, 2005 of $16.5 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 2006 capital expenditures budget, excluding acquisitions, asset retirement costs and capitalized interest and general and administrative expenses, is approximately $360 million, or 18% higher than our 2005 capital expenditures, excluding acquisitions, asset retirement costs and capitalized interest and general and administrative expenses. Based on our outlook of commodity prices and our estimated production, we expect to fund our 2006 capital program with cash flow provided by operating activities.

To the extent that 2006 cash flow from operating activities exceeds our estimated 2006 capital expenditures, we may pay down a portion of our existing debt. If cash flow from operating activities during 2006 is not sufficient to fund estimated 2006 capital expenditures, we believe that our bank credit facility will provide us with adequate liquidity. See “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 March 1, 2006, we had $163 million of borrowings outstanding under our credit facility and letters of credit totaling $22.9 million had been issued pursuant to the facility. We have a borrowing base under the credit facility of $300 million, with availability of an additional $114.1 million in borrowings as of March 1, 2006. Our borrowing base was reduced from $425 million to $300 million after we announced our reserve revision in October 2005.

Under the financial covenants of our credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the amended credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a Consolidated Tangible Net Worth (as defined). As of December 31, 2005 our debt to EBITDA Ratio was 1.16 and our Consolidated Tangible Net Worth was approximately $185 million in excess of the amount required to be maintained. 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. During 2005, the participating banks in our credit facility granted waivers from certain covenants regarding the filing of our financial statements until March 31, 2006. Additionally, we have agreed to secure borrowings under the facility with a security interest in certain oil and gas properties. As of the date of this filing we had not completed the transfer of the security interests to the banks participating in the facility. If we are unable to complete this transaction by March 31, 2006, it is possible that the balance of the facility could become due at that time; however, we believe we could replace the facility if this were to occur.

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, 2005.


			Less than						More than
	Total		1 Year		1-3 Years		4-5 Years		5 Years
	(In thousands)
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)		163,000		—		163,000		—		—
Interest (2)		242,032		39,780		73,067		60,000		69,185
Asset retirement obligations		356,308		60,900		455		10,769		284,184
Leasehold commitment (3)		5,000		5,000		—		—		—
Exploration commitment (4)		21,270		21,270		—		—		—
Seismic data commitments (5)		94,390		40,750		53,640		—		—
Operating lease obligations		2,184		580		1,062		542		—

Total Contractual Obligations and Commitments	$	1,284,184	$	168,280	$	291,224	$	71,311	$	753,369


(1)		The bank credit facility matures on April 30, 2008. See “Bank Credit Facility” above.

(2)		Assumes 6% interest rate on floating debt.

(3)		Represents sunk cost reimbursement due under the joint venture agreement with Kerr-McGee for deep water and deep shelf exploration.

(4)		Represents final commitment well under joint venture agreement with Kerr-McGee for deep water and deep shelf exploration.

(5)		Represents pre-commitments for seismic data purchases.

Results of Operation

2005 Compared to 2004. 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,
	2005		2004		Variance			% Change
*Production:*
Oil (MBbls)		4,838		5,438		(600	)		(11	%)
Gas (MMcf)		54,129		55,544		(1,415	)		(3	%)
Oil and gas (MMcfe)		83,158		88,172		(5,014	)		(6	%)
*Average prices:* (1)
Oil (per Bbl)	$	50.53	$	39.38	$	11.15			28	%
Gas (per Mcf)		7.24		5.94		1.30			22	%
Oil and gas (per Mcfe)		7.65		6.17		1.48			24	%
*Expenses (per Mcfe):*
Lease operating expenses	$	1.38	$	1.13	$	0.25			22	%
Salaries, general and administrative expenses (2)		0.27		0.16		0.11			69	%
DD&A expense on oil and gas properties		2.87		2.36		0.51			21	%
*Estimated Proved Reserves at December 31:*
Oil (MBbls)		41,509		42,385		(876	)		(2	%)
Gas (MMcf)		344,088		413,902		(69,814	)		(17	%)
Oil and gas (MMcfe)		593,142		668,210		(75,068	)		(11	%)


(1)		Includes the settlement of effective hedging contracts.

(2)		Exclusive of incentive compensation expense.

For the year ended 2005, we reported net income totaling $136.8 million, or $5.02 per share, compared to net income for the year ended December 31, 2004 of $119.7 million, or $4.45 per share. The variance in annual results was due to the following components:

Production. During 2005, total production volumes decreased 6% to 83.2 Bcfe compared to 88.2 Bcfe produced during 2004. Oil production during 2005 totaled approximately 4.8 million barrels compared to 2004 oil production of 5.4 million barrels, while natural gas production during 2005 totaled approximately 54.1 billion cubic feet compared to 55.5 billion cubic feet produced during 2004. The decrease in overall 2005 production was primarily the result of extended production downtime from Hurricanes Katrina and Rita (16.4 Bcfe) in excess of downtime experienced for Hurricane Ivan in 2004 (7.0 Bcfe).

Prices. Prices realized during 2005 averaged $50.53 per barrel of oil and $7.24 per Mcf of gas compared to 2004 average realized prices of $39.38 per barrel of oil and $5.94 per Mcf of gas. On a gas equivalent basis, average 2005 prices were 24% higher than prices realized during 2004. All unit pricing amounts include the settlement of hedging contracts.

We enter into various hedging contracts in order to reduce our exposure to the possibility of declining oil and gas prices. During 2005, hedging transactions decreased the average price we received for natural gas by $0.58 per Mcf and for oil by $2.26 per Bbl compared to a net decrease of $0.18 per Mcf of natural gas realized during 2004.

Oil and Gas Revenue. As a result of 24% higher realized prices on a gas equivalent basis, oil and gas revenue increased 17% to $636.2 million in 2005 from $544.2 million during 2004 despite a 6% decline in total production volumes during 2005.

Expenses. During 2005, we incurred lease operating expenses of $114.7 million, compared to $100.0 million incurred during 2004. On a unit of production basis, 2005 lease operating expenses were $1.38 per Mcfe as compared to $1.13 per Mcfe for 2004. The increase in lease operating expenses in 2005 is due to a combination of increases in overall industry service costs and additional costs associated with storm-related shut-ins and evacuations. Included in lease operating expenses are maintenance costs, which represent repairs and maintenance costs that vary from year to year. Maintenance costs totaled $28.9 million in 2005 compared to $29.1 million in 2004.

DD&A expense on oil and gas properties for 2005 totaled $238.3 million, or $2.87 per Mcfe compared to DD&A expense of $208.0 million, or $2.36 per Mcfe in 2004. The increase in DD&A per Mcfe is attributable to the unit cost of current year net reserve additions (including related future development costs) exceeding the per unit amortizable base as of the beginning of the year. See Known Trends and Uncertainties.

During 2005 and 2004, we incurred $7.2 million and $5.9 million, respectively, of accretion expense related to the January 1, 2003 adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” Stone expects accretion expense to total approximately $12.2 million during 2006 as a result of higher estimated costs combined with a shortened time frame to plug and abandon our facilities.

Interest expense for 2005 totaled $23.2 million, net of $14.9 million of capitalized interest, compared to interest of $16.8 million, net of $7.0 million of capitalized interest, during 2004. The increase in interest expense in 2005 is primarily the result of the issuance of our $200 million 6³/4% Senior Subordinated Notes on December 15, 2004.

Reserves. At December 31, 2005, our estimated proved oil and gas reserves totaled 593.1 Bcfe, compared to December 31, 2004 reserves of 668.2 Bcfe. The decrease in estimated proved reserves during 2005 was the result of production and downward revisions of previous estimates exceeding additions from drilling results and acquisitions made during the year. Estimated proved natural gas reserves totaled 344.1 Bcf and estimated proved oil reserves totaled 41.5 MMBbls at the end of 2005. The reserve estimates at December 31, 2005 were engineered and/or audited by engineering firms in accordance with guidelines established by the SEC.

Our standardized measure of discounted future net cash flows was $1.9 billion and $1.6 billion at December 31, 2005 and 2004, respectively. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine these estimates of future net cash flows using market prices for oil and gas on the last day of the fiscal period. The average year-end oil and gas prices on all of our properties used in determining these amounts, excluding the effects of hedges in place at year-end, were $57.17 per barrel and $9.86 per Mcf for 2005 and $41.06 per barrel and $6.57 per Mcf for 2004.

2004 Compared to 2003. The following table sets forth certain operating information with respect to our oil and gas operations and summary information with respect to our estimated proved oil and gas reserves.


	Year Ended December 31,
	2004		2003		Variance			% Change
*Production:*
Oil (MBbls)		5,438		5,727		(289	)		(5	%)
Gas (MMcf)		55,544		62,536		(6,992	)		(11	%)
Oil and gas (MMcfe)		88,172		96,898		(8,726	)		(9	%)
*Average prices:* (1)
Oil (per Bbl)	$	39.38	$	30.41	$	8.97			29	%
Gas (per Mcf)		5.94		5.34		0.60			11	%
Oil and gas (per Mcfe)		6.17		5.25		0.92			18	%
*Expenses (per Mcfe):*
Lease operating expenses	$	1.13	$	0.75	$	0.38			51	%
Salaries, general and administrative expenses (2)		0.16		0.15		0.01			7	%
DD&A expense on oil and gas properties		2.36		1.92		0.44			23	%
*Estimated Proved Reserves at December 31:*
Oil (MBbls)		42,385		44,508		(2,123	)		(5	%)
Gas (MMcf)		413,902		380,280		33,622			9	%
Oil and gas (MMcfe)		668,210		647,326		20,884			3	%


(1)		Includes the settlement of effective hedging contracts.
(2)		Exclusive of incentive compensation expense.

For the year ended 2004, net income totaled $119.7 million, or $4.45 per share, compared to net income for the year ended December 31, 2003 of $123.2 million, or $4.64 per share. The variance in annual results was due to the following components:

Production. During 2004, total production volumes decreased 9% to 88.2 Bcfe compared to 96.9 Bcfe produced during 2003. Oil production during 2004 totaled approximately 5.4 million barrels compared to 2003 oil production of 5.7 million barrels, while natural gas production during 2004 totaled approximately 55.5 billion cubic feet compared to 62.5 billion cubic feet produced during 2003. The decrease in overall 2004 production, compared to 2003, was primarily the result of extended production downtime from Hurricane Ivan totaling 7.0 Bcfe.

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

During 2004, hedging transactions decreased the average price we received for natural gas by $0.18 per Mcf compared to a net decrease of $0.03 per Mcf of natural gas realized during 2003. We had no hedges in place for 2003 oil production.

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

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

DD&A expense on oil and gas properties for 2004 totaled $208.0 million, or $2.36 per Mcfe compared to DD&A expense of $186.0 million, or $1.92 per Mcfe in 2003. The increase in DD&A per Mcfe is attributable to the unit cost of current year reserve additions and related future development costs, exceeding the per unit amortizable base as of the beginning of the year.

During 2004 and 2003, we incurred $5.9 million and $6.3 million, respectively, of accretion expense related to the January 1, 2003 adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.”

Derivative expenses in 2004 and 2003 represented primarily the cost of put contracts charged to earnings as the contracts settled during the respective periods. During 2004, we incurred derivative expenses of $4.1 million compared to $8.7 million in 2003. The decline in derivative expenses in 2004 is the result of lower costs of put contracts for 2004 hedged production volumes.

Interest expense for 2004 totaled $16.8 million, net of $7.0 million of capitalized interest, compared to interest of $19.9 million, net of $7.8 million of capitalized interest, during 2003. The decrease in interest expense in 2004 is the result of the September 2003 redemption of our 8³/4% Senior Subordinated Notes, which lowered the average interest rate on our outstanding debt, combined with lower average borrowings outstanding during 2004.

Reserves. At December 31, 2004, our estimated proved oil and gas reserves totaled 668.2 Bcfe, compared to December 31, 2003 reserves of 647.3 Bcfe. The increase in estimated proved reserves during 2004 was the combined result of drilling results and acquisitions made during the year. Estimated proved natural gas reserves totaled 413.9 Bcf and estimated proved oil reserves totaled 42.4 MMBbls at the end of 2004.

Our standardized measure of discounted future net cash flows was $1.6 billion and $1.5 billion at December 31, 2004 and 2003, respectively. You should not assume that these estimates of future net cash flows represent the fair value of our estimated oil and natural gas reserves. As required by the SEC, we determine these estimates of future net cash flows using market prices for oil and gas on the last day of the fiscal period. The average year-end oil and gas prices on all of our properties used in determining these amounts, excluding the effects of hedges in place at year-end, were $41.06 per barrel and $6.57 per Mcf for 2004 and $31.72 per barrel and $6.29 per Mcf for 2003.

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

Changes in Accounting Principles. Effective January 1, 2003, management elected to change to the units of production (“UOP”) method of amortizing proved oil and gas property costs from the previously used future gross revenue method. Under the UOP method, the quarterly provision for DD&A is computed by dividing production volumes, instead of revenue, for the period by the total proved reserves, instead of future gross revenue, as of the beginning of the period, and similarly applying the respective rate to the net cost of proved oil and gas properties, including future development costs. Management believes that this change in method is preferable because it removes fluctuations in DD&A expense caused by product pricing volatility within a reporting period and is a method more widely used in the oil and gas industry. As a result of the change in accounting principle, we recognized a charge against our 2003 net income for the cumulative transition adjustment of $4.6 million, net of tax.

In addition, management elected to begin recognizing production revenue under the Entitlement method of accounting effective January 1, 2003. Under this method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is accrued for

the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. The cumulative effect of adoption of the Entitlement method was immaterial.

Asset Retirement Obligations. In July 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” effective for fiscal years beginning after June 15, 2002. This statement requires us to record our estimate of the fair value of liabilities related to future asset retirement obligations in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of an oil and gas property’s useful life. The adoption of SFAS No. 143 requires the use of management’s estimates with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of capital. We adopted SFAS No. 143 on January 1, 2003. Upon adoption, we recognized a gain for a cumulative transition adjustment of $6.7 million, net of tax, for existing asset retirement obligation liabilities, asset retirement costs and accumulated depreciation. In addition, we recorded an $86.7 million increase in the capitalized costs of our oil and gas properties, net of accumulated depreciation, and recognized $76.3 million in additional liabilities related to asset retirement obligations. As required by SFAS No. 143, our estimate of our asset retirement obligations does not give consideration to the value the related assets could have to other parties.

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

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

We capitalize a portion of the interest costs incurred on our debt that is calculated based upon the balance of our unevaluated property costs and our weighted-average borrowing rate. During 2005, 2004 and 2003, we capitalized interest costs of $14.9 million, $7.0 million and $7.8 million, respectively. We also capitalize the portion of salaries, general and administrative expenses that are attributable to our acquisition, exploration and development activities. During 2005, 2004 and 2003, we capitalized salaries, general and administrative costs, net of overhead reimbursements, of $20.5 million, $16.0 million, and $14.2 million, respectively.

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

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), net of related tax effect, to the net capitalized costs of proved oil and gas properties, including estimated capitalized abandonment costs, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and gas properties to the value of the discounted cash flows.

Stock-Based Compensation. On December 16, 2004, the FASB issued SFAS No. 123(R),“Share-Based Payment”, which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123(R) supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123; however, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, be recognized in the income statement based on their fair values. Pro forma disclosure will no longer be an alternative.

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

	1.		A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date.

	2.		A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

We have elected the modified prospective transition method.

In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations. SAB No. 107 provides guidance related to the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No. 123(R) for public companies. As a result, SFAS No. 123(R) will be effective for us on January 1, 2006.

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; and

	•		contingencies.

Derivative Instruments and Hedging Activities. Under SFAS No. 133, as amended, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. We do not use derivative instruments for trading purposes. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in equity through other comprehensive income, net of related taxes, to the extent the hedge is effective. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings. During 2005, certain of our hedges became ineffective when actual production was less than the hedged volumes. This resulted in a charge to income in the amount of $3.4 million.

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Operating Cost Risk

We are currently experiencing rising operating costs which also impacts our cash flow from operating activities and profitability. Assuming the costs to operate our properties, including lease operating expenses and maintenance cost, increased 10%, we estimate our diluted earnings per share for 2005 would have declined approximately 5%.

Commodity Price Risk

Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil and gas price declines and volatility could adversely affect our revenues, cash flow provided by operating activities and profitability. Assuming a 10% decline in realized oil and natural gas prices, including the effects of hedging contracts, we estimate our diluted net income per share for 2005 would have declined approximately 32%. In order to manage our exposure to oil and gas price declines, we occasionally enter into oil and gas price hedging arrangements to secure a price for a portion of our expected future production.

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

The following tables show our hedging positions as of March 1, 2006:


	Zero-Premium Collars
	Natural Gas						Oil
	Daily						Daily
	Volume		Floor		Ceiling		Volume		Floor		Ceiling
	(MMBtus/d)		Price		Price		(Bbls/d)		Price		Price
2006		10,000	$	8.00	$	14.28		3,000	$	55.00	$	76.40
2006		20,000		9.00		16.55		2,000		60.00		78.20
2006		20,000		10.00		16.40

We believe these positions have hedged approximately 35% — 45% of our estimated 2006 production.

Interest Rate Risk

Stone had long-term debt outstanding of $563 million at December 31, 2005, of which $400 million, or approximately 71%, 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. The remaining $163 million of debt outstanding at December 31, 2005 bears interest at a floating rate under our bank credit facility. At December 31, 2005, the weighted average interest rate under our floating-rate debt was approximately 6.0%. At December 31, 2005, we had no interest rate hedge positions in place to reduce our exposure to changes in interest rates. Assuming a 200 basis point increase in market interest rates during 2005 our interest expense, net of capitalization, would have increased approximately $1.0 million, net of taxes, resulting in a $0.04 per diluted share reduction in net income.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information concerning this Item begins on Page F-1.

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

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

ITEM 9A. CONTROLS AND PROCEDURES

Deficiencies Relating to Reserve Reporting

We recently completed an internal review of our estimates of proved oil and natural gas reserves. As a result of this review, we reduced our estimate of total proved oil and natural gas reserves at December 31, 2004 by approximately 237 Bcfe. Management concluded that the impact of the reserve adjustment on previously issued financial statements was material and required a restatement. The audit committee of our board of directors engaged the law firm of Davis Polk & Wardwell (“Davis Polk”) to assist in its investigation of reserve revisions. Davis Polk presented its final report to the audit committee and board of directors on November 28, 2005. The final report found that a number of factors at Stone contributed to the write-down of reserves, including the following:

	•		Stone lacked adequate internal guidance or training on the SEC definition of proved reserves;

	•		There is evidence that some members of Stone management failed to fully grasp the conservatism of the SEC’s “reasonable certainty” standard of booking reserves; and

	•		There is also evidence that there was an optimistic and aggressive “tone from the top” with respect to estimating proved reserves.

As part of its final report, Davis Polk proposed a number of recommendations, including the following:

	•		adopt and distribute written guidelines to its staff on the SEC reserve reporting requirements;

	•		provide annual training for employees on the SEC requirements;

	•		continue to emphasize the difference between SEC’s standard of measuring proved reserves and the criteria that Stone might use in making business decisions; and

	•		institute and cultivate a culture of compliance to ensure that the foregoing contributing factors do not recur.

The audit committee and board of directors have accepted the Davis Polk final report, and the board of directors implemented and resolved to continue to implement all of the recommendations.

Consequently, we have revised our historical proved reserves for the period from December 31, 2001 to June 30, 2005. This revision of reserves also resulted in a restatement of financial information for the years from 2001 through 2004 and for the first six months of 2005. This restatement, as well as specific information regarding its impact, is discussed in Note 1 to the Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data.” Restatement of previously issued financial statements to reflect the correction of a misstatement is an indicator of the existence of a material weakness in internal control over financial reporting as defined in the Public Company Accounting Oversight Board’s Auditing Standard No. 2, “An Audit of Internal Control Over Financial Reporting Performed in Conjunction with an Audit of Financial Statements.” We have identified deficiencies in our internal controls that did not prevent the overstatement of our proved oil and natural gas reserves. These deficiencies, which we believe constituted a material weakness in our internal control over financial reporting, included an overly aggressive and optimistic tone by some members of management which created a weak control environment surrounding the booking of proved oil and natural gas reserves, and inadequate training and understanding of the SEC rules for booking oil and natural gas reserves. In light of the determination that previously issued financial statements should be restated, our management concluded that a material weakness in internal control over financial reporting existed as of December 31, 2005 and disclosed this matter to the audit committee, and our independent registered public accounting firm.

Remedial Actions

Our management, at the direction of our board of directors, is actively working to improve the control environment and to implement controls and procedures that will ensure the integrity of our proved reserve booking process.

We have implemented the following actions to mitigate weaknesses identified:

•

Those members of management that the Davis Polk report specifically suggested contributed to the aggressive and optimistic tone of management in booking estimated proved reserves are no longer employed by or affiliated with Stone as employees, officers or directors.

	•		A new Vice President, Reserves, has been appointed to oversee the booking of estimated proved reserves and the training of all personnel involved in the reserve estimation process.

	•		Formal training programs have been implemented and all personnel involved in the reserve estimation process have, since the announcement of the reserve revision, received formal training in SEC requirements for reporting estimated proved reserves.

	•		A nationally recognized engineering firm with greater capabilities for geological reviews was contracted to audit our Gulf Coast Basin reserves. The Gulf Coast Basin is the area where the downward revisions occurred. Such audit was conducted as of December 31, 2005 and was completed early in 2006.

	•		We have adopted and distributed a written policy and guidelines for booking estimated proved reserves to all personnel involved in the reserve estimation process.

We intend to implement the following actions in 2006:

	•		continue our formal training programs;

	•		have 100% of our proved reserves fully engineered by outside engineering firms no later than December 31, 2006; and

	•		during 2006 and thereafter, consult with our outside engineering firms on a interim basis on the original booking of significant acquisitions, extensions, discoveries and other additions.

Evaluation of Disclosure Control and Procedures

Our Chief Executive Officer and our Chief Financial Officer, with the participation of other members of our senior management, reviewed and evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. In making this evaluation, the Chief Executive Officer and the Chief Financial Officer considered the issues discussed above, together with the remedial steps we have taken. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, because of the material weakness discussed above, as of December 31, 2005 and December 31, 2004, our disclosure controls and procedures were not effective in recording, processing, summarizing and reporting information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (the “Exchange Act”).

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-(f) of the Exchange Act. Under the supervision and with the participation of management, including our Chief Executive Officer, and our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2005 based on the framework in Internal Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on our evaluation under the framework in Internal Control-Integrated Framework, our management concluded we did not maintain effective controls over the booking of our oil and natural gas reserves as of December 31, 2005, and these ineffective controls constituted a material weakness. As a result of this material weakness, estimated proved reserve quantities for 2004 and prior periods were revised downward and our financial statements for the years ended December 31, 2004, 2003, 2002 and 2001 were restated. These restatements affected the Company’s proved oil and gas properties, DD&A and write-down of oil and gas properties accounts.

Because of this material weakness, management has concluded that, as of December 31, 2005, we did not maintain effective internal control over financial reporting, based on the criteria established in Internal Control-Integrated Framework issued by the COSO.

Management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by Ernst and Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Control Over Financial Reporting

Except as discussed above, there has not been any change in our internal control over financial reporting that occurred during our year ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders of
Stone Energy Corporation:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Stone Energy Corporation did not maintain effective internal control over financial reporting as of December 31, 2005, because of the effect of a material weakness related to the booking of proved oil and natural gas reserves, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Stone Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The following material weakness has been identified and included in management’s assessment. The Company did not maintain effective controls over the booking of its oil and natural gas reserves as of December 31, 2005, and these ineffective controls constituted a material weakness. As a result of this material weakness, proved reserve quantities for 2004 and prior periods were revised downward and the Company’s financial statements for the years ended December 31, 2004, 2003, 2002 and 2001 were restated. These restatements affected the Company’s proved oil and gas properties, DD&A and write-down of oil and gas properties accounts. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2005 financial statements, and this report does not affect our report dated March 7, 2006 on those financial statements.

In our opinion, management’s assessment that Stone Energy Corporation did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO control criteria. Also, in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Stone Energy Corporation has not maintained effective internal control over financial reporting as of December 31, 2005, based on the COSO control criteria.


		/s/Ernst & Young LLP

New Orleans, Louisiana
March 7, 2006

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

Additional information required by Item 10, including information regarding our audit committee financial experts, is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held on May 18, 2006. 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 2006 Annual Meeting of Stockholders to be held on May 18, 2006.

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 2006 Annual Meeting of Stockholders to be held on May 18, 2006.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by Item 13 is incorporated herein by reference to such information as set forth in our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held on May 18, 2006.

ITEM 14. PRINCIPAL ACCOUNTANT 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 2006 Annual Meeting of Stockholders to be held on May 18, 2006.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) 1. Financial Statements:

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

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheet as of December 31, 2005 and 2004

Consolidated Statement of Income for the three years in the period ended December 31, 2005

Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2005

Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period ended December 31, 2005

Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2005

Notes to the Consolidated Financial Statements

2. Financial Statement Schedules:

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

3. Exhibits:


3.1	—	Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).

3.2	—	Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).

3.3	—	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).

3.4	—	Amendment to restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 001-12074)).

4.1	—	Rights Agreement, with exhibits A, B and C thereto, dated as of October 15, 1998, between Stone Energy Corporation and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A (File No. 001-12074)).

4.2	—	Amendment No. 1, dated as of October 28, 2000, to Rights Agreement dated as of October 15, 1998, between Stone Energy Corporation and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-4 (Registration No. 333-51968)).

4.3	—	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)).

4.4	—	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.)

†4.5	—	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)).


†4.6	—	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)).

†10.1	—	Deferred Compensation and Disability Agreements between TSPC and D. Peter Canty dated July 16, 1981, and between TSPC and James H. Prince dated August 23, 1981 and September 20, 1981, respectively (incorporated by reference to Exhibit 10.8 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).

†10.2	—	Conveyances of Net Profits Interests in certain properties to D. Peter Canty and James H. Prince (incorporated by reference to Exhibit 10.9 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).

†10.3	—	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)).

†10.4	—	Stone Energy Corporation Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 001-12074)).

†10.5	—	Stone Energy Corporation Amendment to the Annual Incentive Compensation Plan dated January 15, 1997 (incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 001-12074)).

†10.6	—	Stone Energy Corporation Revised Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 001-12074)).

†10.7	—	Stone Energy Corporation 2001 Amended and Restated Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8 (Registration No. 333-107440)).

10.8	—	Credit Agreement between the Registrant, the financial institutions named therein and Bank of America, N.A., as administrative agent, dated April 30, 2004. (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q, filed August 9, 2004 (File No. 001-12074)).

10.9	—	Amendment No. 1 to the Credit Agreement between the Registrant, the financial institutions named therein and Bank of America, N.A., as administrative agent, dated December 14, 2004 (incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).

†10.10	—	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)).

†10.11	—	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)).

16.1	—	Letter of Arthur Andersen LLP, dated June 26, 2002, regarding change in certifying accountant (incorporated by reference to Exhibit 16.1 to the Registrant’s Form 8-K, filed June 27, 2002 (File No. 001-12074)).

18.1	—	Letter of Ernst & Young LLP, dated May 13, 2003, regarding change in accounting principles (incorporated by reference to Exhibit 18.1 to the Registrant’s Quarterly Report on Form 10-Q, for the period ended March 31, 2003 (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.

*23.3	—	Consent of Ryder Scott Company, L.P.

*23.4	—	Consent of Cawley, Gillespie & 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.

SIGNATURES

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


	STONE ENERGY CORPORATION

Date: March 10, 2006	By:	/s/ David H. Welch

		David H. Welch President and Chief Executive Officer

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


Signature	Title	Date

/s/ James H. Stone	Chairman of the Board	March 10, 2006
James H. Stone

/s/ David H. Welch	President, Chief Executive Officer	March 10, 2006
David H. Welch	and Director
	(principal executive officer)

/s/ Kenneth H. Beer	Senior Vice President and	March 10, 2006
Kenneth H. Beer	Chief Financial Officer
	(principal financial officer)

/s/ J. Kent Pierret	Senior Vice President, Chief	March 10, 2006
J. Kent Pierret	Accounting Officer and Treasurer
	(principal accounting officer)

/s/ Peter K. Barker	Director	March 10, 2006
Peter K. Barker

/s/ Robert A. Bernhard	Director	March 10, 2006
Robert A. Bernhard

/s/ George R. Christmas	Director	March 10, 2006
George R. Christmas

/s/ B.J. Duplantis	Director	March 10, 2006
B.J. Duplantis

/s/ Raymond B. Gary	Director	March 10, 2006
Raymond B. Gary

/s/ John P. Laborde	Director	March 10, 2006
John P. Laborde

/s/ Richard A. Pattarozzi	Director	March 10, 2006
Richard A. Pattarozzi

/s/ David R. Voelker	Director	March 10, 2006
David R. Voelker

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders of
Stone Energy Corporation:

We have audited the accompanying consolidated balance sheet of Stone Energy Corporation as of December 31, 2005 and 2004, and the related consolidated statements of income, cash flows, changes in stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Stone Energy Corporation as of December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the 2004 and 2003 consolidated financial statements have been restated to reflect the effects of negative revisions to the Company’s quantities of estimated proved reserves.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” As also discussed in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company elected to change to the units of production method of amortizing proved oil and gas property costs and elected to begin recognizing production revenue under the entitlement method.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Stone Energy Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 7, 2006, expressed an unqualified opinion on management’s assessment and an adverse opinion on the effectiveness of internal control over financial reporting.



	/s/ Ernst & Young LLP

New Orleans, Louisiana
March 7, 2006

F-2

STONE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEET

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


	December 31,
	2005				2004
				(Restated)
ASSETS
Current assets:
Cash and cash equivalents	$	79,708		$	24,257
Accounts receivable		211,685			111,398
Fair value of hedging contracts		7,471			58
Other current assets		2,795			9,310

Total current assets		301,659			145,023

Oil and gas properties—full cost method of accounting:
Proved, net of accumulated depreciation, depletion and amortization of $1,880,180 and $1,640,362, respectively		1,564,312			1,376,151
Unevaluated		246,647			141,157
Building and land, net of accumulated depreciation of $1,167 and $1,016, respectively		5,521			5,416
Fixed assets, net of accumulated depreciation of $15,422 and $14,567, respectively		9,331			4,761
Other assets, net of accumulated depreciation and amortization of $2,896 and $1,539, respectively		12,847			23,156

Total assets	$	2,140,317		$	1,695,664


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable to vendors	$	160,682		$	110,845
Undistributed oil and gas proceeds		59,187			36,457
Asset retirement obligation		53,894			2,912
Fair value of hedging contracts		—			14,346
Other current liabilities		11,390			9,061

Total current liabilities		285,153			173,621

Long-term debt		563,000			482,000
Deferred taxes		231,961			161,500
Asset retirement obligations		113,043			103,179
Other long-term liabilities		3,037			2,430


Total liabilities		1,196,194			922,730


Commitments and contingencies

Common stock, $.01 par value; authorized 100,000,000 shares; issued 27,189,808 and 26,709,094 shares, respectively		272			267
Treasury stock (25,982 and 28,182 shares, respectively, at cost)		(1,348	)		(1,462	)
Additional paid-in capital		500,228			466,478
Unearned compensation		(15,068	)		(1,486	)
Retained earnings		455,183			318,425
Accumulated other comprehensive income (loss)		4,856			(9,288	)

Total stockholders’ equity		944,123			772,934


Total liabilities and stockholders’ equity	$	2,140,317		$	1,695,664

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

F-3

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF INCOME

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


	Year Ended December 31,
	2005			2004			2003
				(Restated)			(Restated)
Operating revenue:
Oil production	$	244,469		$	214,153		$	174,139
Gas production		391,771			330,048			334,166

Total operating revenue		636,240			544,201			508,305

Operating expenses:
Lease operating expenses		114,664			100,045			72,786
Production taxes		13,179			7,408			5,975
Depreciation, depletion and amortization		241,426			210,861			188,813
Accretion expense		7,159			5,852			6,292
Salaries, general and administrative expenses		22,705			14,311			14,870
Incentive compensation expense		1,252			2,318			2,636
Derivative expense		3,388			4,099			8,711

Total operating expenses		403,773			344,894			300,083


Income from operations		232,467			199,307			208,222


Other (income) expenses:
Interest		23,151			16,835			19,860
Other income		(3,894	)		(4,018	)		(3,133	)
Other expense		—			1,541			538
Early extinguishment of debt		—			845			4,661

Total other expenses, net		19,257			15,203			21,926

Net income before income taxes		213,210			184,104			186,296

Income tax provision:
Current		—			—			—
Deferred		76,446			64,436			65,203

Total income taxes		76,446			64,436			65,203

Income before cumulative effects of accounting
changes, net of tax		136,764			119,668			121,093
Cumulative effect of accounting changes, net of tax of $1,130		—			—			2,099

Net income	$	136,764		$	119,668		$	123,192


Earnings per common share:
Income before cumulative effects of accounting changes	$	5.07		$	4.50		$	4.60
Cumulative effects of accounting changes		—			—			0.07

Earnings per common share	$	5.07		$	4.50		$	4.67


Earnings per common share assuming dilution:
Income before cumulative effects of accounting changes	$	5.02		$	4.45		$	4.56
Cumulative effects of accounting changes		—			—			0.08

Earnings per common share assuming dilution	$	5.02		$	4.45		$	4.64


Average shares outstanding		26,951			26,586			26,353

Average shares outstanding assuming dilution		27,244			26,901			26,546

The accompanying notes are an integral part of this statement.

F-4

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands of dollars)


	Year Ended December 31,
	2005			2004			2003
				(Restated)			(Restated)
Cash flows from operating activities:
Net income	$	136,764		$	119,668		$	123,192
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization		241,426			210,861			188,813
Accretion expense		7,159			5,852			6,292
Deferred income tax provision		76,446			64,436			65,203
Cumulative effect of accounting changes		—			—			(2,099	)
Early extinguishment of debt		—			845			1,744
Derivative expenses		—			4,099			8,711
Other non-cash expenses		3,873			489			522
Increase in accounts receivable		(24,605	)		(36,333	)		(266	)
(Increase) decrease in other current assets		(752	)		(600	)		538
Increase in accounts payable		2,100			900			—
Increase in other current liabilities		22,424			5,404			4,091
Investment in derivative contracts		—			(1,683	)		(2,932	)
Payments on asset retirement obligations		(3,741	)		(4,159	)		(2,965	)
Other		119			(111	)		(33	)

Net cash provided by operating activities		461,213			369,668			390,811


Cash flows from investing activities:
Investment in oil and gas properties		(494,125	)		(484,936	)		(339,788	)
Sale of proved properties		1,549			11,948			475
Investment in fixed and other assets		(7,356	)		(2,171	)		(1,867	)

Net cash used in investing activities		(499,932	)		(475,159	)		(341,180	)


Cash flows from financing activities:
Proceeds from bank borrowings		126,000			128,000			100,000
Repayment of bank borrowings		(45,000	)		(216,000	)		(61,000	)
Issuance of 6³/4% Senior Subordinated Notes		—			200,000			—
Redemption of 8³/4% Senior Subordinated Notes		—			—			(100,000	)
Deferred financing costs		(188	)		(7,107	)		(582	)
Proceeds from exercise of stock options		13,358			7,755			1,442

Net cash provided by (used in) financing activities		94,170			112,648			(60,140	)


Net increase (decrease) in cash and cash equivalents		55,451			7,157			(10,509	)
Cash and cash equivalents, beginning of year		24,257			17,100			27,609

Cash and cash equivalents, end of year	$	79,708		$	24,257		$	17,100


Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized)	$	22,560		$	15,945		$	23,626
Income taxes		—			—			—

The accompanying notes are an integral part of this statement.

F-5

STONE ENERGY CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Amounts in thousands of dollars)


															Accumulated			Total
						Additional						Retained			Other			Stockholders’
	Common		Treasury			Paid-In			Unearned			Earnings			Comprehensive			Equity
	Stock		Stock			Capital			Compensation			(Restated)			Income (Loss)			(Restated)
Balance, December 31, 2002	$	263		($1,706	)	$	453,176		$	—		$	75,636			($4,768	)	$	522,601
Net income		—		—			—			—			123,192			—			123,192
Adjustment for fair value accounting of derivatives, net of tax		—		—			—			—			—			(6,356	)		(6,356	)
Effect of accounting treatment for swaps, net of tax		—		—			—			—			—			2,361			2,361
Exercise of stock options		1		—			1,441			—			—			—			1,442
Tax benefit from stock option exercises		—		—			774			—			—			—			774
Issuance of treasury stock		—		156			—			—			(58	)		—			98

Balance, December 31, 2003		264		(1,550	)		455,391			—			198,770			(8,763	)		644,112
Net income		—		—			—			—			119,668			—			119,668
Adjustment for fair value accounting of derivatives, net of tax		—		—			—			—			—			(525	)		(525	)
Exercise of stock options		3		—			7,752			—			—			—			7,755
Tax benefit from stock option exercises		—		—			1,821			—			—			—			1,821
Issuance of restricted stock		—		—			1,514			(1,514	)		—			—			—
Amortization of stock compensation expense		—		—			—			28			—			—			28
Issuance of treasury stock		—		88			—			—			(13	)		—			75

Balance, December 31, 2004		267		(1,462	)		466,478			(1,486	)		318,425			(9,288	)		772,934
Net income		—		—			—			—			136,764			—			136,764
Adjustment for fair value accounting of derivatives, net of tax		—		—			—			—			—			14,144			14,144
Exercise of stock options		5		—			13,400			—			—			—			13,405
Tax benefit from stock option exercises		—		—			3,796			—			—			—			3,796
Issuance of restricted stock		—		—			17,588			(17,588	)		—			—			—
Vesting of restricted stock		—		—			(47	)		—			—			—			(47	)
Cancellation of restricted stock		—		—			(1,009	)		1,009			—			—			—
Tax benefit from restricted stock vesting		—		—			22			—			—			—			22
Amortization of stock compensation expense		—		—			—			2,997			—			—			2,997
Issuance of treasury stock		—		114			—			—			(6	)		—			108

Balance, December 31, 2005	$	272		($1,348	)	$	500,228			($15,068	)	$	455,183		$	4,856		$	944,123

The accompanying notes are an integral part of this statement.

F-6

STONE ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS:

On October 6, 2005, as a result of reservoir level reviews conducted during August 2005 through early October 2005, we announced a downward revision of 171 billion cubic feet of natural gas equivalent (“Bcfe”) of estimated proved reserves. After additional analysis and additional consultation with outside engineering firms, the revision was increased to 237 Bcfe.

Based on internal assessments and consultation with outside engineering firms, we concluded that 157 Bcfe of the negative reserve revisions should have been reflected in 2004 and prior periods and would require a revision of the historical reserve estimates included in our supplemental natural gas and oil operating data. Quantities of estimated proved reserves are used in determining financial statement amounts, including ceiling test charges and depletion, depreciation and amortization (“DD&A”). The revision of our historical reserve estimates required the restatement of the financial statement information derived from these estimates for the periods from 2001 to 2004 and the first two quarters of 2005.

Additionally, in the process of the preparation of our Form 10-Q for September 30, 2005, it was determined that approximately $9,794 of unevaluated oil and gas property costs were inappropriately classified and should have been reclassified to proved oil and gas property costs in 2002. The Financial Restatement includes the effect of this revision for the years ended December 31, 2002, 2003 and 2004.

Reserves Restatement

Our reserves restatement resulted in the following revisions to our estimated proved reserves as of:


	December 31,
	2004				2003				2002
	As		As		As		As		As		As
	Reported		Restated		Reported		Restated		Reported		Restated
Estimated Proved Reserves:
Oil (MBbls)		56,560		42,385		59,162		44,508		52,019		40,735
Gas (MMcf)		485,590		413,902		461,323		380,280		438,652		376,236
Oil and gas (MMcfe)		824,950		668,210		816,295		647,326		750,766		620,644

Financial Restatement

The total cumulative impact of the restatement on our stockholders’ equity as of December 31, 2004 was a reduction of approximately $81,400, which includes a reduction in beginning stockholders’ equity as of January 1, 2002 of approximately $45,290.

F-8

NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)

As to the individual consolidated statement of income line items, our historical financial statements for the years ended December 31, 2004 and 2003 and for each of the quarters in those years and the first two quarters of 2005 reflect the effects of the restatement on (1) the calculation of our historical depletion, depreciation and amortization expense, (2) the effects, if any, on interest expense resulting from changes in unevaluated oil and gas properties, (3) the impact on the cumulative effect of accounting changes and (4) the impact on income taxes. We did not amend our Annual Report on Form 10-K for the year ended December 31, 2004 or our Quarterly Reports on Form 10-Q for any periods prior to June 30, 2005, and the financial statements and related financial information contained in those reports should no longer be relied upon. A summary of the effects of the restatement on reported amounts for the years ended December 31, 2004 and 2003 and quarters ended March 31, 2005 and June 30, 2005 is presented below. Also, the information in the data below represents only those income statement, balance sheet, cash flow statement and statement of comprehensive income line items affected by the restatement.


	Year Ended December 31,
	2004				2003
	As		As		As		As
	Reported		Restated		Reported		Restated
Income Statement:
Depreciation, depletion and amortization	$	188,153	$	210,861	$	170,845	$	188,813
Total operating expenses		322,186		344,894		282,115		300,083
Income from operations		222,015		199,307		226,190		208,222
Interest expense		16,104		16,835		19,132		19,860
Total other expenses, net		14,472		15,203		21,198		21,926
Net income before income taxes		207,543		184,104		204,992		186,296
Income tax provision		72,640		64,436		71,747		65,203
Income before cumulative effects of accounting changes, net of tax		134,903		119,668		133,245		121,093
Cumulative effect of accounting changes, net of tax		—		—		1,225		2,099
Net income		134,903		119,668		134,470		123,192
Earnings per common share:
Income before cumulative effects of accounting changes	$	5.07	$	4.50	$	5.05	$	4.60
Cumulative effects of accounting changes		—		—		0.05		0.07
Earnings per common share	$	5.07	$	4.50	$	5.10	$	4.67
Earnings per common share assuming dilution:
Income before cumulative effects of accounting changes	$	5.01	$	4.45	$	5.02	$	4.56
Cumulative effects of accounting changes		—		—		0.05		0.08
Earnings per common share assuming dilution	$	5.01	$	4.45	$	5.07	$	4.64


	Year Ended December 31,
	2004						2003
	As			As			As			As
	Reported			Restated			Reported			Restated
Cash Flow Statement:
Net income	$	134,903		$	119,668		$	134,470		$	123,192
Depreciation, depletion and amortization		188,153			210,861			170,845			188,813
Deferred income tax provision		72,640			64,436			71,747			65,203
Cumulative effect of accounting changes		—			—			(1,225	)		(2,099	)
Increase in accounts payable		—			900			—			—
Net cash flow provided by operating activities		369,499			369,668			391,539			390,811
Investment in oil and gas properties		(484,767	)		(484,936	)		(340,516	)		(339,788	)
Net cash used in investing activities		(474,990	)		(475,159	)		(341,908	)		(341,180	)
Supplemental disclosure for cash paid during the year for interest (net of amount capitalized)		15,214			15,945			22,898			23,626

F-9

NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)


	Year December 31,
	2004				2003
	As		As		As		As
	Reported		Restated		Reported		Reported
Statement of Comprehensive Income:
Net income	$	134,903	$	119,668	$	134,470	$	123,192
Comprehensive income		134,378		119,143		130,475		119,197


	December 31,
	2004
	As		As
	Reported		Restated
Balance Sheet:
Proved oil and gas properties	$	1,489,498	$	1,376,151
Accumulated depreciation, depletion and amortization		1,516,620		1,640,362
Unevaluated oil and gas properties		153,041		141,157
Total assets		1,820,895		1,695,664
Deferred taxes		205,331		161,500
Total liabilities		966,561		922,730
Retained earnings		399,825		318,425
Total stockholders’ equity		854,334		772,934
Total liabilities and stockholders’ equity		1,820,895		1,695,664


	Quarters Ended
	March 31, 2005				June 30, 2005
	As		As		As		As
	Reported		Restated		Reported		Restated
Income Statement:
Depreciation, depletion and amortization	$	56,192	$	62,021	$	65,676	$	72,399
Total operating expenses		93,805		99,634		106,181		112,904
Income from operations		62,348		56,519		79,057		72,334
Interest expense		5,624		5,831		5,721		5,934
Total other expenses, net		5,035		5,242		4,479		4,692
Net income before income taxes		57,313		51,277		74,578		67,642
Income tax provision		19,965		17,853		26,102		23,675
Net income		37,348		33,424		48,476		43,967
Earnings per common share	$	1.40	$	1.25	$	1.80	$	1.64
Earnings per common share assuming dilution	$	1.38	$	1.24	$	1.79	$	1.62


	Quarters Ended
	March 31, 2005						June 30, 2005
	As			As			As			As
	Reported			Restated			Reported			Restated
Cash Flow Statement:
Net income	$	37,348		$	33,424		$	48,476		$	43,967
Depreciation, depletion and amortization		56,192			62,021			65,676			72,399
Deferred income tax provision		19,965			17,853			26,102			23,675
Net cash flow provided by operating activities		111,186			110,979			139,469			139,256
Investment in oil and gas properties		(180,059	)		(179,852	)		(109,553	)		(109,340	)
Net cash used in investing activities		(180,753	)		(180,546	)		(110,597	)		(110,384	)

F-10

NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)


	Quarters Ended
	March 31, 2004				June 30, 2004				September 30, 2004				December 31, 2004
	As		As		As		As		As		As		As		As
	Reported		Restated		Reported		Restated		Reported		Restated		Reported		Restated
Income Statement:
Depreciation, depletion and amortization	$	46,744	$	53,300	$	50,060	$	56,217	$	46,139	$	51,534	$	45,210	$	49,810
Total operating expenses		75,245		81,801		81,325		87,482		85,562		90,957		80,054		84,654
Income from operations		58,335		51,779		60,899		54,742		42,744		37,349		60,037		55,437
Interest expense		3,949		4,108		3,988		4,150		4,050		4,225		4,117		4,353
Total other expenses, net		3,300		3,459		5,663		5,825		3,413		3,588		2,096		2,331
Net income before income taxes		55,035		48,320		55,236		48,917		39,331		33,761		57,941		53,106
Income tax provision		19,262		16,912		19,333		17,121		13,766		11,816		20,279		18,587
Net income		35,773		31,408		35,903		31,796		25,565		21,945		37,662		34,519
Earnings per common share	$	1.35	$	1.19	$	1.35	$	1.20	$	0.96	$	0.82	$	1.41	$	1.29
Earnings per common share assuming dilution	$	1.33	$	1.17	$	1.33	$	1.18	$	0.95	$	0.82	$	1.40	$	1.28


	Quarters Ended
	March 31, 2003				June 30, 2003				September 30, 2003				December 31, 2003
	As		As		As		As		As		As		As		As
	Reported		Restated		Reported		Restated		Reported		Restated		Reported		Restated
Income Statement:
Depreciation, depletion and amortization	$	41,719	$	45,433	$	41,046	$	44,634	$	42,020	$	45,961	$	46,060	$	52,785
Total operating expenses		68,645		72,358		68,700		72,289		71,704		75,645		73,066		79,791
Income from operations		88,901		85,188		48,512		44,923		44,289		40,349		44,488		37,762
Interest expense		5,521		5,696		5,167		5,357		4,760		4,962		3,684		3,845
Total other expenses, net		4,850		5,025		4,471		4,661		9,268		9,469		2,609		2,771
Net income before income taxes		84,051		80,163		44,041		40,262		35,021		30,880		41,879		34,991
Income tax provision		29,418		28,057		15,414		14,091		12,254		10,807		14,661		12,248
Income before cumulative effects of accounting changes, net of tax		54,633		52,106		28,627		26,171		22,767		20,073		27,218		22,743
Cumulative effect of accounting changes, net of tax		1,225		2,099		—		—		—		—		—		—
Net income		55,858		54,205		28,627		26,171		22,767		20,073		27,218		22,743
Earnings per common share:
Income before cumulative effects of accounting changes	$	2.07	$	1.98	$	1.09	$	0.99	$	0.86	$	0.76	$	1.03	$	0.86
Cumulative effects of accounting changes		0.05		0.08		—		—		—		—		—		—
Earnings per common share	$	2.12	$	2.06	$	1.09	$	0.99	$	0.86	$	0.76	$	1.03	$	0.86
Earnings per common share assuming dilution:
Income before cumulative effects of accounting changes	$	2.06	$	1.97	$	1.08	$	0.98	$	0.86	$	0.75	$	1.02	$	0.86
Cumulative effects of accounting changes		0.05		0.08		—		—		—		—		—		—
Earnings per common share assuming dilution	$	2.11	$	2.05	$	1.08	$	0.98	$	0.86	$	0.75	$	1.02	$	0.86

F-11

NOTE 2 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stone Energy is an independent oil and gas company engaged in the acquisition and subsequent exploration, development, and operation of oil and gas properties located in the conventional Gulf of Mexico (the “GOM”) shelf, the deep shelf of the GOM, deepwater of the GOM, Rocky Mountain Basins and the Williston Basin. Our corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We have additional offices in New Orleans, Houston, and Denver.

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

Basis of Presentation:

The financial statements include our accounts and the accounts of our wholly owned subsidiary. All intercompany balances have been eliminated. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used primarily when accounting for depreciation, depletion and amortization, unevaluated property costs, estimated future net cash flows from proved reserves, cost to abandon oil and gas properties, taxes, reserves of accounts receivable, accruals of capitalized costs, operating costs and production revenue, capitalized employee, general and administrative expenses, effectiveness of financial instruments, the purchase price allocation on properties acquired and contingencies.

Fair Value of Financial Instruments:

The fair value of cash and cash equivalents, accounts receivable, accounts payable to vendors and our variable-rate bank debt approximated book value at December 31, 2005 and 2004. Our hedging contracts, including puts, swaps and zero-premium collars, are recorded in the financial statements at fair value in accordance with the Financial Accounting Standards Board’s (“FASB”) Statement of Financial Accounting Standard (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The carrying amount of our bank debt approximated fair value because the interest rate is variable and reflective of market rates. As of December 31, 2005 and 2004, the fair value of our $200,000 8¹/4% Senior Subordinated Notes due 2011 was $206,500 and $216,500, respectively. As of December 31, 2005 and 2004, the fair value of our $200,000 6³/4% Senior Subordinated Notes due 2014 was $189,000 and $198,500, respectively. The fair values of our outstanding notes were determined based upon quotes obtained from brokers.

Cash and Cash Equivalents:

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

Oil and Gas Properties:

We follow the full cost method of accounting for oil and gas properties. Under this method, all acquisition, exploration, development and estimated abandonment costs, including certain related employee and general and administrative costs (less any reimbursements for such costs) and interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Employee, general and administrative costs that are capitalized include salaries and all related fringe benefits paid to employees directly engaged in the acquisition, exploration and development of oil and gas properties, as well as all other directly identifiable general and administrative costs associated with such activities, such as rentals, utilities and insurance. Fees received from managed partnerships for providing such services are accounted for as a reduction of capitalized costs. During 2005, 2004 and 2003, we capitalized salaries, general and administrative costs (net of reimbursements) in the amount of $20,462, $15,968 and $14,179, respectively. Employee, general and administrative costs associated with production operations and general corporate activities are expensed in the period incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase levels of production from an existing completion interval are charged to lease operating expense in the period incurred.

F-12

NOTE 2 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

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 depreciation, depletion and amortization (“DD&A”). Under the full cost method, all exploratory costs are capitalized while under the successful efforts method exploratory costs associated with unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under full cost accounting, DD&A is computed on cost centers represented by entire countries while under successful efforts cost centers are represented by properties, or some reasonable aggregation of properties with common geological structural features or stratigraphic condition, such as fields or reservoirs.

Transactions involving sales of unevaluated properties are recorded as adjustments to oil and gas properties and sales of reserves in place, unless extraordinarily large portions of reserves are involved, are recorded as adjustments to accumulated depreciation, depletion and amortization.

Effective January 1, 2003, management elected to change to the units of production (“UOP”) method of amortizing proved oil and gas property costs from the previously used future gross revenue method. Under the UOP method, the quarterly provision for DD&A is computed by dividing production volumes, instead of revenues, for the period by the total proved reserves, instead of future gross revenues, as of the beginning of the period, and similarly applying the respective rate to the net cost of proved oil and gas properties, including future development costs. Management believes that this change in method is preferable because it removes fluctuations in DD&A expense caused by product pricing volatility within a reporting period and is a method more widely used in the oil and gas industry. As a result of the change in accounting principle, we recognized a cumulative transition adjustment of $4,648, net of tax, as a charge against our 2003 net income.

On September 28, 2004, the SEC adopted Staff Accounting Bulletin (“SAB”) No. 106, which expressed its views regarding the application of SFAS No. 143 by oil and gas companies following the full cost accounting method. SAB No. 106 indicates that estimated dismantlement and abandonment costs that will be incurred as a result of future development activities on proved reserves are to be included in the estimated future cash flows in the full cost ceiling test. SAB No. 106 also indicates that these estimated costs are to be included in the costs to be amortized. We began applying SAB No. 106 prospectively in the third quarter of 2004.

Asset Retirement Obligations:

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” An asset retirement obligation (ARO) relates to the removal of facilities and tangible equipment at the end of a properties useful life. SFAS No. 143 requires that the fair value of a liability to retire an asset be recorded on the balance sheet and that the corresponding cost is capitalized in oil and gas properties. The ARO liability is accreted to its future value and the capitalized cost is depreciated consistent with the UOP method. See “Note 6 – Asset Retirement Obligations.”

Building and Land:

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

Fixed Assets:

Fixed assets at December 31, 2005 and 2004 included approximately $6,010 and $3,467, respectively, of computer hardware and software costs, net of accumulated depreciation. These costs are being depreciated on the straight-line method over an estimated useful life of five years.

F-13

NOTE 2 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

Earnings Per Common Share:

Earnings per common share were calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the year. Earnings per common share assuming dilution were calculated by dividing net income applicable to common stock by the weighted-average number of common shares outstanding during the year plus the weighted-average number of outstanding dilutive stock options and restricted stock granted to outside directors, officers and employees. There were approximately 293,000, 315,000 and 193,000 weighted-average dilutive shares for the years ending December 31, 2005, 2004 and 2003, respectively. Options that were considered antidilutive because the exercise price of the stock exceeded the average price for the applicable period totaled approximately 562,000, 786,000 and 1,021,000 shares during 2005, 2004 and 2003, respectively. During the years ended December 31, 2005, 2004 and 2003, approximately 483,000, 278,000 and 98,000 shares of common stock, respectively, were issued, from either authorized shares or shares held in treasury, upon the exercise of stock options and vesting of restricted stock by employees and non-employee directors and the awarding of employee bonus stock under the 2004 Amended and Restated Stock Incentive Plan.

Production Revenue:

Effective January 1, 2003, management elected to begin recognizing production revenue under the Entitlement method of accounting. Under this method, revenue is deferred for deliveries in excess of the company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sales price in effect at the time of production. The cumulative effect of the adoption of the Entitlement method recognized in 2003 was immaterial.

Prior to adopting the Entitlement method, we recorded as revenue only that portion of production sold and allocable to our ownership interest in the related well. Any production proceeds received in excess of our ownership interest were reflected as a liability in the accompanying balance sheet. Revenue relating to net undelivered production to which we are entitled but for which we had not received payment were not recorded in the financial statements until such amounts were received. These amounts at December 31, 2002 were immaterial.

Income Taxes:

Income taxes are accounted for in accordance with the SFAS No. 109, Accounting for Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures, including future abandonment costs, related to evaluated projects are capitalized and depreciated, depleted and amortized on the UOP method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code that allow capitalization of intangible drilling costs where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion, different reporting methods for sales of oil and gas reserves in place, and different reporting methods used in the capitalization of employee, general and administrative and interest expenses.

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. 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. The cash settlement of effective cash flow hedges is recorded in oil and gas revenue. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings as derivative expense (income). At December 31, 2005, our 2006 collar contracts were considered effective cash flow hedges. See Note 10 — “Hedging Activities.”

F-14

NOTE 2 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

Stock-Based Compensation:

In October 1995, the FASB issued SFAS No. 123, “Accounting for Stock-Based Compensation,” which became effective with respect to us in 1996. Under SFAS No. 123, companies can either record expense based on the fair value of stock-based compensation upon issuance or elect to remain under the current Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” method whereby no compensation cost is recognized upon grant if certain requirements are met. We have continued to account for our stock-based compensation under APB 25.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123,” to amend the disclosure requirements of SFAS No. 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effects of the method used on reported results. If the compensation expense for stock-based compensation plans had been determined consistent with the expense recognition provisions under SFAS No. 123 and assuming the straight-line method for recognition of expenses in the applicable vesting periods, our net income and earnings per common share and earnings per common share assuming dilution for the years presented would have approximated the pro forma amounts below:


	Year Ended December 31,
	2005			2004			2003
				(Restated)			(Restated)
				(Unaudited)
Net income, as reported	$	136,764		$	119,668		$	123,192
Add: Stock-based compensation expense included in net income, net of tax		2,019			40			—
Less: Stock-based compensation expense using fair value method, net of tax		(5,780	)		(5,569	)		(5,287	)

Pro forma net income	$	133,003		$	114,139		$	117,905


Earnings per common share	$	5.07		$	4.50		$	4.67
Pro forma earnings per common share		4.93			4.29			4.47

Earnings per common share assuming dilution	$	5.02		$	4.45		$	4.64
Pro forma earnings per common share assuming dilution		4.88			4.24			4.44

On December 16, 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment,” which is a revision of SFAS No. 123. SFAS No. 123(R) supersedes APB Opinion No. 25 and amends SFAS No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123; however, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, be recognized in the income statement based on their fair values. Pro forma disclosure will no longer be an alternative.

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

	1.		the “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date; or

	2.		the “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

In March 2005, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin (“SAB”) No. 107 which expressed the views of the SEC regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations. SAB No. 107 provides guidance related to the valuation of share-based payment arrangements for public companies, including assumptions such as expected volatility and expected term. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No. 123(R) for public companies. As a result, SFAS No. 123(R) will be effective for us on January 1, 2006.

Stone has elected to adopt the requirements of SFAS No. 123(R) using the “modified prospective” method. We have historically used the Black-Scholes option-pricing model for estimating stock compensation expense for disclosure purposes and intend to continue using such method upon adoption of SFAS No. 123(R).

F-15

NOTE 2 — ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)

We expect the implementation of SFAS No. 123(R) to impact our 2006 financial statements as follows:

	•		Expense amounts related to stock option issuances will be expensed in the income statement prospectively as opposed to the pro forma disclosures previously presented in prior periods. Expense amounts on stock options to be incurred in 2006 and future periods will be contingent upon several factors including the number of options issued and capitalization rates and therefore, prior pro forma amounts should not be assumed to be necessarily indicative of future expense amounts.

	•		Unearned Compensation and Additional Paid-In Capital balances related to our restricted stock issuances will be reversed.

	•		The tax benefits from the vesting of restricted stock and the exercise of stock options will no longer be recorded as an addition to Additional Paid-In Capital until we are in a current tax paying position. Presently, all of our income taxes are being deferred and we have substantial net operating losses available for carryover to future periods.

NOTE 3 — ACCOUNTS RECEIVABLE:

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


	As of December 31,
	2005		2004
Accounts Receivable:
Other co-venturers	$	10,224	$	11,187
Trade		107,855		94,046
Insurance receivable on hurricane claims		93,192		5,745
Officers and employees		2		12
Unbilled accounts receivable		412		408

	$	211,685	$	111,398

We have accrued insurance claims receivable related to Hurricanes Katrina and Rita to the extent we have concluded the insurance recovery is probable. The accrual is for all costs previously recorded in our financial statements including Asset Retirement Obligations and repair expenses including in Lease Operating Expenses. We have not accrued for costs to be incurred in future periods.

NOTE 4 — CONCENTRATIONS:

Sales to Major Customers

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


	December 31,
	2005			2004			2003
BP Energy Company		(a	)		12	%		(a	)
Cinergy Marketing and Trading		(a	)		11	%		12	%
Conoco, Inc.		10	%		13	%		(a	)
Duke Energy Trading and Marketing LLC		(a	)		(a	)		13	%
Equiva Trading Company		(a	)		11	%		10	%
Sequent Energy Management LP		10	%		—			—
Total Gas & Power North America, Inc.		12	%		12	%		—


(a)		Less than 10 percent

The maximum amount of credit risk exposure at December 31, 2005 relating to these customers amounted to $23,294.

F-16

NOTE 4 — CONCENTRATIONS: (Continued)

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

Production and Reserve Volumes

Approximately 76% (unaudited) of our estimated proved reserves at December 31, 2005 and 89% of our production during 2005 were associated with our Gulf Coast Basin properties.

Cash Deposits

Substantially all of our cash balances are in excess of federally insured limits.

NOTE 5 — INVESTMENT IN OIL AND GAS PROPERTIES:

The following table discloses certain financial data relative to our oil and gas producing activities located onshore and offshore the continental United States, which represents our only operating segment:


	Year Ended December 31,
	2005			2004			2003
				(Restated)			(Restated)
Oil and gas properties—
Balance, beginning of year	$	3,157,670		$	2,636,512		$	2,224,930
Costs incurred during the year:
Capitalized—
Acquisition costs, net of sales of unevaluated properties.		138,080			201,550			54,456
Exploratory costs		156,472			151,571			175,864
Development costs		149,890			125,161			109,507
Salaries, general and administrative costs and interest		35,939			23,395			22,274
Less: overhead reimbursements		(600	)		(469	)		(247	)
Asset retirement costs		53,687			19,950			49,728


Total costs incurred during year		533,468			521,158			411,582


Balance, end of year	$	3,691,138		$	3,157,670		$	2,636,512


Charged to expense—
Lease operating expenses	$	114,664		$	100,045		$	72,786
Production taxes		13,179			7,408			5,975
Accretion expense		7,159			5,852			6,292


	$	135,002		$	113,305		$	85,053


Unevaluated oil and gas properties—
Costs incurred during year:
Acquisition costs	$	87,486		$	43,268		$	19,708
Exploration costs		37,841			23,022			3,063
Capitalized interest		14,391			5,114			6,164

	$	139,718		$	71,404		$	28,935

F-17

NOTE 5 — INVESTMENT IN OIL AND GAS PROPERTIES: (Continued)


	Year Ended December 31,
	2005			2004			2003
				(Restated)			(Restated)
Accumulated depreciation, depletion and amortization—
Balance, beginning of year		($1,640,362	)		($1,420,371	)		($1,261,436	)
Provision for DD&A		(238,269	)		(208,043	)		(185,957	)
Asset retirement costs		—			—			34,736
Cumulative effect of change in accounting		—			—			(7,239	)
Sale of proved properties		(1,549	)		(11,948	)		(475	)


Balance, end of year		($1,880,180	)		($1,640,362	)		($1,420,371	)


Net capitalized costs (proved and unevaluated)	$	1,810,958		$	1,517,308		$	1,216,141


DD&A per Mcfe	$	2.87		$	2.36		$	1.92

The following table discloses financial data associated with unevaluated costs at December 31, 2005:


			Net Costs incurred (evaluated) during the
	Balance as of		year ended December 31,
	December 31,								2002
	2005		2005		2004		2003		and prior
Acquisition costs	$	182,720	$	87,486	$	38,899	$	9,599	$	46,736
Exploration costs		37,841		37,841		—		—		—
Capitalized interest		26,086		14,391		4,181		3,596		3,918

Total unevaluated costs	$	246,647		139,718	$	43,080	$	13,195	$	50,654

Of the total unevaluated costs at December 31, 2005 approximately $70,000 related to investment in the Williston Basin in Montana and North Dakota which we anticipate to be evaluated over the next 2¹/2 years. The excluded costs will be included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs capitalized on unevaluated properties during the years ended December 31, 2005, 2004 and 2003 totaled $14,877, $6,957 and $7,848, respectively.

NOTE 6 – ASSET RETIREMENT OBLIGATIONS:

In July 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” effective for fiscal years beginning after June 15, 2002. This statement requires us to record the fair value of liabilities related to future asset retirement obligations (“ARO”) in the period the obligation is incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment at the end of a property’s useful life. We adopted SFAS No. 143 on January 1, 2003, which requires that the fair value of a liability to retire an asset be recorded on the balance sheet and that the corresponding cost is capitalized in oil and gas properties. The ARO liability is accreted to its future value and the capitalized cost is depreciated consistent with the UOP method. Upon adoption, as restated, we recognized a gain for a cumulative transition adjustment of $6,747, net of tax, computed from the components below:


Initial ARO as a liability on our consolidated balance sheet, including accumulated accretion		($76,270	)
Increase in oil and gas properties for the cost to abandon our oil and gas properties		52,002
Accumulated depreciation on the additional capitalized costs included in oil and gas properties at adoption date		(20,892	)
Reversal of accumulated depreciation previously recorded related to abandonment costs		55,540

Cumulative effect of adoption		10,380
Tax effect		(3,633	)


Cumulative effect of adoption, net of tax effect	$	6,747

F-18

NOTE 6 – ASSET RETIREMENT OBLIGATIONS: (Continued)

In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs will be depreciated on a UOP basis. 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.

The change in our ARO during 2005 and 2004 is set forth below:


	2005			2004
				(Restated)
Asset retirement obligation as of the beginning of the year	$	106,091		$	80,288
Liabilities incurred		7,461			27,173
Liabilities settled		(3,741	)		(2,719	)
Accretion expense		7,159			5,852
Revision of estimates		49,967			(4,503	)

Asset retirement obligation as of the end of the year, including current portion	$	166,937		$	106,091

NOTE 7 — INCOME TAXES:

An analysis of our deferred taxes follows:


	As of December 31,
	2005			2004
				(Restated)
Net operating loss carryforward	$	42,109		$	38,800
Statutory depletion carryforward		5,278			5,302
Contribution carryforward		377			351
Capital loss carryforward		—			7
Alternative minimum tax credit carryforward		682			812
Temporary differences:
Oil and gas properties — full cost		(278,806	)		(203,406	)
Hedges		(2,631	)		5,001
Other		(1,240	)		41
Valuation allowance		(377	)		(358	)

		($234,608	)		($153,450	)

For tax reporting purposes, operating loss carryforwards totaled approximately $120,751 at December 31, 2005. If not utilized, such carryforwards would begin expiring in 2009 and would completely expire by the year 2025. In addition, we had approximately $15,741 in statutory depletion deductions available for tax reporting purposes that may be carried forward indefinitely. Recognition of a deferred tax asset associated with these carryforwards is dependent upon our evaluation that it is more likely than not that the asset will ultimately be realized.

As of December 31, 2005 a deferred tax liability of $2,646 was included in other current liabilities. At December 31, 2004 a deferred tax asset of $7,267 was included in other current assets.

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


	Year Ended December 31,
	2005			2004			2003
Income tax expense computed at the statutory federal income tax rate		35.0	%		35.0	%		35.0	%
State taxes and other		0.9			—			—

Effective income tax rate		35.9	%		35.0	%		35.0	%

Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges amounted to $7,615, ($282) and ($2,151) for the years ended December 31, 2005, 2004 and 2003, respectively.

F-19

NOTE 8 — LONG-TERM DEBT:

Long-term debt consisted of the following:


	As of December 31,
	2005		2004
8¹/4% Senior Subordinated Notes due 2011	$	200,000	$	200,000
6³/4% Senior Subordinated Notes due 2014		200,000		200,000
Bank debt		163,000		82,000

Total long-term debt	$	563,000	$	482,000

On April 30, 2004, we entered into a four-year $500,000 senior unsecured credit facility with a syndicated bank group. The new facility had an initial borrowing base of $425,000 and replaced the previous $350,000 credit facility. As a result, we recognized a charge for the early extinguishment of debt in the amount of $845, which relates to previously deferred financing costs associated with the old credit facility. On November 18, 2005, our borrowing base was reduced to $300,000 reflecting the impact of Hurricanes Katrina and Rita and our previously announced downward reserve revision. At December 31, 2005, we had $163,000 of borrowings outstanding with a weighted average interest rate of 6.0% under our bank credit facility. As of December 31, 2005, letters of credit totaling $13,084 had been issued under the credit facility, which reduce our availability for additional borrowings. These letters of credit have been issued in order to guarantee funding of plugging and abandonment obligations that were assumed through prior acquisitions of developed oil and gas properties.

The credit facility matures on April 30, 2008. At March 1, 2006 we had a borrowing base under the credit facility of $300,000 with availability of an additional $114,141 of borrowings. Interest rates are tied to LIBOR rates plus a margin that fluctuates based upon the ratio of aggregate outstanding borrowings and letters of credit exposure to the total borrowing base. Commitment fees are computed and payable quarterly at the rate of 50 basis points of borrowing availability. The borrowing base limitation is re-determined periodically and is based on a borrowing base amount established by the banks for our oil and gas properties.

Under the financial covenants of our credit facility, we must (i) maintain a ratio of consolidated debt to consolidated EBITDA, as defined in the amended credit agreement, for the preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a Consolidated Tangible Net Worth (as defined). 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. During 2005, the participating banks in our credit facility granted waivers from certain covenants regarding the filing of our financial statements until March 31, 2006. Additionally, we agreed to secure borrowings under the facility with a security interest in certain oil and gas properties. As of the date of this filing we had not completed the transfer of the security interests to the banks participating in the facility. If we are unable to complete this transaction by March 31, 2006, it is possible that the balance of the facility could become due at that time; however, we believe we could replace the facility if this were to occur.

On December 15, 2004, we issued $200,000 6³/4% Senior Subordinated Notes due 2014. The notes were sold at par value and we received net proceeds of $195,500 and are subordinated to our senior unsecured credit facility and rank pari passu with our 8¹/4% Senior Subordinated Notes. There is no sinking fund requirement and the notes are redeemable at our option, in whole but not in part, at any time before December 15, 2009 at a Make-Whole Amount. Beginning December 15, 2009, the notes are redeemable at our option, in whole or in part, at 103.375% of their principal amount and thereafter at prices declining annually to 100% on and after December 15, 2012. In addition, before December 15, 2007, we may redeem up to 35% of the aggregate principal amount of the notes issued with net proceeds from an equity offering at 106.75%. The notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. At December 31, 2005, $592 had been accrued in connection with the June 15, 2006 interest payment. We received notice of non-compliance from holders of over 25 percent of the outstanding principal amount of our $200,000 6³/4% Senior Subordinated Notes due 2014 relating to the non-issuance of financial statements. The receipt of notice of non-compliance started a 60 day period beginning February 15, 2006 in which to cure the default relating to the non-issuance of financial statements. As a consequence of these notices, we became unable to borrow additional funds under our bank credit facility until the default was cured. We believe the filing of this Form 10-K and our September 30, 2005 Form 10-Q has cured the default.

On December 5, 2001, we issued $200,000 8¹/4% Senior Subordinated Notes due 2011. The notes were sold at par value and we received net proceeds of $195,500 and are subordinated to our senior unsecured credit facility and rank pari passu with our 6³/4% Senior Subordinated Notes. There is no sinking fund requirement and the notes are redeemable at our option, in whole but not in part, at any time before December 15, 2006 at a Make-Whole Amount. Beginning December 15, 2006, the notes are redeemable at our option, in whole or in part, at 104.125% of their principal amount and thereafter at prices declining annually to 100% on and after December 15, 2009. The notes provide for certain covenants, which include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other restricted payments. At December 31, 2005, $721 had been accrued in connection with the June 15, 2006 interest payment.

F-20

NOTE 8 — LONG-TERM DEBT: (Continued)

Other assets at December 31, 2005 and 2004 included approximately $9,784 and $11,004, respectively, of deferred financing costs, net of accumulated amortization, related primarily to the issuance of the 8¹/4% notes, the 6³/4% notes and the new credit facility. The costs associated with the 8¹/4% notes and 6³/4% notes are being amortized over the life of the notes using a method that applies effective interest rates of 8.6% and 7.1%, respectively. The costs associated with the credit facility are being amortized on the straight-line method over the term of the facility.

On September 30, 2003, we redeemed our $100,000 outstanding 8³/4% Senior Subordinated Notes due 2007 at a call premium of 102.917%. The cash redemption payment was funded through a combination of available cash and $90,000 of borrowings under our bank credit facility. We recorded a pre-tax charge of $4,661 during 2003 for the early extinguishment of debt, which related to the call premium of $2,917 and the recognition of previously deferred financing costs and unamortized discounts associated with the issuance of the notes in 1997.

Total interest cost incurred on all obligations for the years ended December 31, 2005, 2004 and 2003 was $38,100, $23,800 and $27,700 respectively.

NOTE 9 — TRANSACTIONS WITH RELATED PARTIES:

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

Our interests in certain oil and gas properties are burdened by net profits interests and overriding royalty interests granted at the time of acquisition to certain of our present and former officers. Such net profit interest owners do not receive any cash distributions until we have recovered all acquisition, development, financing and operating costs. D. Peter Canty, a former director and former President and Chief Executive Officer, and James H. Prince, former Executive Vice President and Chief Financial Officer, remain net profit interest owners. Amounts paid to these former officers under the remaining net profits arrangement amounted to $915, $727 and $1,169 in 2005, 2004 and 2003, respectively. In addition, Michael E. Madden, our Vice President of Reserves, was granted an overriding royalty interest in some of our properties by an independent third party. At the time he was granted this interest, he was serving Stone as an independent engineering consultant. The amount paid to Michael E. Madden during 2005, 2004 and 2003 under the overriding royalty arrangement totaled $156, $101 and $94, respectively.

Pursuant to his retirement, we agreed to a consulting arrangement with Mr. Canty whereby he was paid $235 for consulting services for the period from April 1, 2004 through December 31, 2004. There is no agreement for consulting service with Mr. Canty for the year ended December 31, 2005.

The son of John P. Laborde, one of our directors, has an interest in several marine service companies, which provided services to us during 2005, 2004 and 2003 in the amount of $1,876, $1,534 and $2,978, respectively. John P. Laborde has no interest in these companies.

NOTE 10 — HEDGING ACTIVITIES:

We enter into hedging transactions to secure a price for a portion of future production that is acceptable at the time at which the transaction is entered. The primary objective of these activities is to reduce our exposure to the possibility of declining oil and natural gas prices during the term of the hedge. These hedges are designated as cash flow hedges upon entering into the contract. We do not enter into hedging transactions for trading purposes. Monthly settlements of these contracts are reflected in revenue from oil and gas production. Under generally accepted accounting principles, in order to consider these futures contracts as hedges, (i) we must designate the futures contract as a hedge of future production and (ii) the contract must be effective at reducing our exposure to the risk of changes in prices. Changes in the market values of futures contracts treated as hedges are not recognized in income until the hedged item is also recognized in income. If the above criteria are not met, we will record the market value of the contract at the end of each month and recognize a related increase or decrease in derivative expenses (income).

Stone has entered into zero-premium collars with various counterparties for a portion of our expected 2006 oil and natural gas production from the Gulf Coast Basin. The natural gas collar settlements are based on an average of New York Mercantile Exchange (“NYMEX”) prices for the last three days of a respective month. The oil collar settlements are based upon an average of the NYMEX closing price for West Texas Intermediate (“WTI”) during the entire calendar month. The contracts require payments to the counterparties if the average price is above the ceiling price or payment from the counterparties if the average price is below the floor price. Our collars are with Bank of America, N.A., Goldman Sachs and JP Morgan. Our 2006 collar contracts are considered effective hedges under SFAS No. 133 and all changes in fair value are recorded, net of taxes, in other comprehensive income prior to settlement.

F-21

NOTE 10 — HEDGING ACTIVITIES: (Continued)

During 2005 we utilized oil and gas collar contracts in the Gulf Coast Basin and fixed-price swaps to hedge a portion of our future gas production from our Rocky Mountain Region properties. Our swap contracts were with Bank of America and are based upon Inside FERC published prices for natural gas deliveries at Kern River. 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 last of these contracts terminated on December 31, 2005. One of our collar contracts for September, October and November 2005 became ineffective when curtailments of our oil production resulting from Hurricanes Katrina and Rita resulted in production levels less than hedged amounts. Settlements on these ineffective hedges in the amount of $3,388 are included in derivative expense for 2005.

During 2004 and 2003, a portion of our oil and natural gas production from the Gulf Coast Basin was hedged with put contracts. Put contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity futures market. The historical cost of the put contracts represents our maximum cash exposure. We are not obligated to make any further payments under the put contracts regardless of future commodity price fluctuations. Under put contracts, monthly payments are made to us if NYMEX prices fall below the agreed upon floor price, while allowing us to fully participate in commodity prices above that floor.

At December 31, 2005, we had accumulated other comprehensive income of $4,856, net of tax, which related to our 2006 collar contracts. We believe this amount approximates the estimated amount to be reclassified into earnings in the next twelve months.

In October 2002, we reached an agreement with Enron North America Corp. to purchase the portion of our fixed price natural gas swap contract settling subsequent to October 2002 for $5,917. We amortized $3,632 of derivative expenses during 2003 related to the balance of previously recorded other comprehensive loss from the swap contract.

During 2005, 2004 and 2003, we recognized $3,388, $4,099 and $8,711, respectively, of derivative expenses. The components of derivative expenses were as follows:


	Year Ended December 31,
	2005		2004		2003
Cost of put contracts settled	$	—	$	4,099	$	5,079
Settlements on ineffective oil collars		3,388		—		—
Effect of change in accounting treatment for swaps, net of tax		—		—		3,632

Total derivative expense	$	3,388	$	4,099	$	8,711

For the years ended December 31, 2005, 2004 and 2003, we realized net decreases in oil and gas revenue related to effective hedging transactions of $42,167, $10,122 and $1,576, respectively.

The following table shows our hedging positions as of March 1, 2006:


	Zero-Premium Collars
	Natural Gas						Oil
	Daily						Daily
	Volume		Floor		Ceiling		Volume		Floor		Ceiling
	(MMBtus/d)		Price		Price		(Bbls/d)		Price		Price
2006		10,000	$	8.00	$	14.28		3,000	$	55.00	$	76.40
2006		20,000		9.00		16.55		2,000		60.00		78.20
2006		20,000		10.00		16.40

F-22

NOTE 11 — COMMITMENTS AND CONTINGENCIES:

We lease office facilities in New Orleans, Louisiana, Houston, Texas and Denver, Colorado under the terms of long-term, non-cancelable leases expiring on various dates through 2010. We also lease automobiles under the terms of non-cancelable leases expiring at various dates through 2007. We also lease certain equipment on our oil and gas properties typically on a month-to-month basis. The minimum net annual commitments under all leases, subleases and contracts noted above at December 31, 2005 were as follows:


2006	$	580
2007		586
2008		476
2009		271
2010		271

Payments related to our lease obligations for the years ended December 31, 2005, 2004 and 2003 were approximately $876, $1,122 and $1,140, respectively. We subleased office space to third parties, and for the years ended 2005, 2004 and 2003, we recorded related receipts of $86, $832 and $816, respectively.

We are contingently liable to surety insurance companies in the aggregate amount of $73,950 relative to bonds issued on our behalf to the United States Department of the Interior Minerals Management Service (MMS), federal and state agencies and certain third parties from which we purchased oil and gas working interests. The bonds represent guarantees by the surety insurance companies that we will operate in accordance with applicable rules and regulations and perform certain plugging and abandonment obligations as specified by applicable working interest purchase and sale agreements.

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

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

In 2004 we entered into an exploration agreement with Kerr-McGee Oil and Gas Corp. covering several undeveloped leases in the Gulf of Mexico. Under the agreement, we acquired varying interests in these deep water and deep shelf leases and agreed to participate in five commitment wells. As of December 31, 2005 we had one well remaining on this commitment which will be drilled in 2006. In addition, we also intend to evaluate additional drilling opportunities on the respective leases in 2006.

In connection with our exploration efforts, specifically in the deep water of the Gulf of Mexico, we have committed to acquire seismic data from certain providers on multiple offshore blocks over the next three years. As of December 31, 2005, our seismic data purchase commitments totaled $94,390 to be incurred over the next three years.

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, plus accrued interest of $352 (calculated through December 15, 2004), for the franchise 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, plus accrued interest of $159 (calculated through December 15, 2004), for the franchise years 1999, 2000 and 2001. Further, 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 $2,605 plus accrued interest calculated through December 15, 2005 in the amount of $1,194. 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.

F-23

NOTE 11 — COMMITMENTS AND CONTINGENCIES: (Continued)

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 against Stone, David H. Welch, Kenneth H. Beer, D. Peter Canty and James H. 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 assert a putative class period commencing on June 17, 2005 and ending on October 6, 2005. All complaints contend 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 the Company 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 the Company’s proved reserves, assets and future net cash flows were materially overstated at all relevant times. A motion to consolidate these actions and to appoint a lead plaintiff will be heard on March 22, 2006. In addition, on or about December 16, 2005, Robert Farer filed a complaint in the United States District Court for the Western District of Louisiana alleging claims derivatively on behalf of Stone, and three similar complaints were filed soon thereafter in federal and state court. Stone is named as a nominal defendant, and certain current and former officers and directors are named as defendants in these actions, which allege breaches of the fiduciary duties owed to Stone, gross mismanagement, abuse of control, waste of corporate assets, unjust enrichment, and violations of the Sarbanes-Oxley Act of 2002. Stone intends to vigorously defend these lawsuits.

NOTE 12 — EMPLOYEE BENEFIT PLANS:

We have entered into deferred compensation and disability agreements with certain of our officers and former officers whereby we have purchased split-dollar life insurance policies to provide certain retirement and death benefits for certain of our officers and former officers and death benefits payable to us. The aggregate death benefit of the policies was $3,225 at December 31, 2005, of which $1,493 was payable to certain officers or former officers or their beneficiaries and $1,732 was payable to us. Total cash surrender value of the policies, net of related surrender charges at December 31, 2005, was approximately $1,120 and is recorded in other assets. Additionally, the benefits under the deferred compensation agreements vest after certain periods of employment, and at December 31, 2005, the liability for such vested benefits was approximately $770 and is recorded in other long-term liabilities.

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

	i.		The Annual Incentive Compensation Plan provided for an annual cash incentive bonus that ties incentives to the annual return on our common stock, to a comparison of the price performance of our common stock to the average quarterly returns on the shares of stock of a peer group of companies with which we compete and to the growth in our net earnings per share, net cash flows and net asset value. Incentive bonuses are awarded to participants based upon individual performance factors. This plan was terminated upon the approval and adoption of the Revised Annual Incentive Compensation Plan, discussed below.

			In February 2003 and February 2005, our board of directors approved and adopted the Revised Annual Incentive Compensation Plan. The revised plan provides for annual cash incentive bonuses that are tied to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. Stone incurred expenses of $1,252, $2,318 and $2,636, net of amounts capitalized, for each of the years ended December 31, 2005, 2004 and 2003, respectively, related to incentive compensation bonuses to be paid under the revised plan.

F-24

NOTE 12 — EMPLOYEE BENEFIT PLANS: (Continued)

	ii.		At the 2004 Annual Meeting of Stockholders, the stockholders approved the Plan, which provides for the granting of incentive stock options, restricted stock awards, bonus stock awards, or any combination as is best suited to the circumstances of the particular employee or nonemployee director. The Plan provides for 4,225,000 shares of common stock to be reserved for issuance pursuant to this plan. At the 2003 Annual Meeting of Stockholders, the stockholders approved, through proxy voting, an amendment that increased the aggregate number of shares of Common Stock reserved for issuance by 1,000,000 shares. Under the Plan, we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise price of not less than the fair market value of the common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire ten years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire ten years subsequent to award. In addition, the Plan provides that shares available under the Plan may be granted as restricted stock.

	iii.		The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employee’s deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the directions of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2005, 2004 and 2003, Stone contributed $974, $850 and $677, respectively, to the plan.

	iv.		The Stone Energy Corporation Deferred Compensation Plan provides eligible executives with the option to defer up to 100% of their compensation for a calendar year and we may, at our discretion, match a portion or all of the participant’s deferral based upon a percentage determined by the board of directors. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. During the year ended December 31, 2004, there were no matching contributions made by Stone. At December 31, 2005 plan assets of $901 were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities.

Stock Options. A summary of stock options as of December 31, 2005, 2004 and 2003 and changes during the years ended on those dates is presented below.


	Year Ended December 31,
	2005					2004					2003
				Wgtd.					Wgtd.					Wgtd.
	Number			Avg.		Number			Avg.		Number			Avg.
	of			Exer.		of			Exer.		of			Exer.
	Options			Price		Options			Price		Options			Price

Outstanding at beginning of year		2,541,135		$	39.47		2,735,559		$	37.92		2,419,557		$	37.68
Granted		85,500			49.54		282,250			46.16		571,600			36.63
Exercised		(486,127	)		29.00		(296,107	)		29.34		(127,600	)		21.20
Forfeited		(154,163	)		37.73		(180,567	)		42.97		(127,998	)		44.42
Expired		(84,283	)		56.43		—			—		—			—

Outstanding at end of year		1,902,062		$	41.99		2,541,135		$	39.47		2,735,559		$	37.92
Options exercisable at year-end		1,160,669			42.72		1,372,416			38.79		1,292,239			36.39
Weighted average fair value of
options granted during the year	$	20.81				$	20.12				$	16.57

The fair value of each stock option granted was estimated as of the date of grant using the Black-Scholes option-pricing model with the following assumptions:


	2005	2004	2003
Dividend yield	—	—	—
Expected volatility	36.47%	39.92%	41.89%
Risk-free interest rate	3.84%	3.90%	3.66%
Expected option life (1)	6.0 Years	6.0 Years	6.0 Years


(1)		The expected life of options granted to nonemployee directors was assumed to be four years.

F-25

NOTE 12 — EMPLOYEE BENEFIT PLANS: (Continued)

The following table summarizes information regarding stock options outstanding at December 31, 2005:


	Options Outstanding					Options Exercisable
Range of	Options		Wgtd. Avg.	Wgtd. Avg.		Options		Wgtd. Avg.
Exercise	Outstanding		Remaining	Exercise		Exercisable		Exercise
Prices	at 12/31/05		Contractual Life	Price		at 12/31/05		Price
$20 — $30		103,000	1.2 years	$	24.95		103,000	$	24.95
30 — 40		955,754	6.2 years		35.61		534,115		35.62
40 — 50		400,634	6.8 years		45.92		140,320		45.13
50 — 70		442,674	4.5 years		56.17		383,234		56.51

		1,902,062	5.7 years		41.99		1,160,669		42.72

Common stock issued upon the exercise of non-qualified stock options results in a tax deduction for us equivalent to the compensation income recognized by the option holder. For financial reporting purposes, the tax effect of this deduction is accounted for as a credit to additional paid-in capital rather than as a reduction of income tax expense. The exercise of stock options during 2005, 2004 and 2003 resulted in a tax benefit to us of approximately $3,796, $1,821 and $774, respectively.

At December 31, 2005, we had approximately 600,953 additional shares available for issuance pursuant to the 2004 Amended and Restated Stock Incentive Plan (the “Plan”). As discussed below, the Plan provides for the issuance of restricted shares. Any such issuance would reduce the number of shares available for future grants of stock options, restricted stock and stock bonus awards.

Restricted Stock. In addition, since 2004, the Plan provides that shares available for issuance may be granted as restricted stock. In accordance with APB No. 25, we record unearned compensation in connection with the granting of restricted stock equal to the fair value of our common stock on the date of grant. As the restrictions lapse (over two to five years), we reduce unearned compensation and recognize compensation expense. During 2005 and 2004, the Company granted 338,000 and 33,710 shares of restricted stock with a weighted average grant date fair value of $52.04 and $44.91 per share, and recognized compensation expense of $2,997 and $28 related to these shares. There were no shares of restricted stock granted during 2003 under the Plan.

F-26

NOTE 13 — OIL AND GAS RESERVE INFORMATION – UNAUDITED:

Our net proved oil and gas reserves at December 31, 2005 have been engineered and/or audited by engineering firms in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates.

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

The following table sets forth an analysis of the estimated quantities of net proved and proved developed oil (including condensate) and natural gas reserves, all of which are located onshore and offshore the continental United States:


							Oil and
				Natural			Natural
	Oil in			Gas in			Gas in
	MBbls			MMcf			MMcfe
Estimated proved reserves as of December 31, 2002 (restated)		40,735			376,236			620,644
Revisions of previous estimates		(1,936	)		(18,033	)		(29,649	)
Extensions, discoveries and other additions		7,776			73,994			120,650
Purchase of producing properties		3,731			10,647			33,033
Sale of reserves		(71	)		(28	)		(454	)
Production (1)		(5,727	)		(62,536	)		(96,898	)

Estimated proved reserves as of December 31, 2003 (restated)		44,508			380,280			647,326
Revisions of previous estimates		(1,625	)		(16,585	)		(26,335	)
Extensions, discoveries and other additions		3,830			66,501			89,481
Purchase of producing properties		1,819			44,976			55,890
Sale of reserves		(709	)		(5,726	)		(9,980	)
Production		(5,438	)		(55,544	)		(88,172	)

Estimated proved reserves as of December 31, 2004 (restated)		42,385			413,902			668,210
Revisions of previous estimates		(4,745	)		(50,881	)		(79,349	)
Extensions, discoveries and other additions		6,534			34,492			73,696
Purchase of producing properties		2,173			704			13,743
Production		(4,838	)		(54,129	)		(83,158	)


Estimated proved reserves as of December 31, 2005		41,509			344,088			593,142


Estimated proved developed reserves:
as of December 31, 2003 (restated)		36,046			293,540			509,816

as of December 31, 2004 (restated)		33,115			312,454			511,144

as of December 31, 2005		31,557			241,347			430,689


(1)		Excludes gas production volumes related to the volumetric production payment.

F-27

NOTE 13 — OIL AND GAS RESERVE INFORMATION – UNAUDITED: (Continued)

The following tables present the standardized measure of future net cash flows related to estimated proved oil and gas reserves together with changes therein, as defined by the FASB, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2005 in accordance with SFAS No. 143. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the table below, represent the fair value of our estimated oil and gas reserves. As required by the SEC, we determine estimated future net cash flows using period-end market prices for oil and gas without considering hedge contracts in place at the end of the period. The average 2005 year-end product prices for all of our properties were $57.17 per barrel of oil and $9.86 per Mcf of gas. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.


	Standardized Measure
	Year Ended December 31,
	2005				2004			2003
				(Restated)			(Restated)
Future cash inflows	$	5,766,726		$	4,457,716		$	3,802,331
Future production costs		(1,293,950	)		(851,926	)		(604,617	)
Future development costs		(678,212	)		(522,210	)		(404,372	)
Future income taxes		(987,901	)		(744,604	)		(675,281	)

Future net cash flows		2,806,663			2,338,976			2,118,061
10% annual discount		(873,684	)		(726,517	)		(653,985	)


Standardized measure of discounted future net cash flows	$	1,932,979		$	1,612,459		$	1,464,076


	Changes in Standardized Measure
	Year Ended December 31,
	2005			2004			2003
				(Restated)			(Restated)
Standardized measure at beginning of year	$	1,612,459		$	1,464,076		$	1,183,556

Sales and transfers of oil and gas produced, net of production costs		(508,397	)		(436,748	)		(429,544	)
Changes in price, net of future production costs		879,528			193,382			359,650
Extensions and discoveries, net of future production and development costs		269,742			267,760			445,969
Changes in estimated future development costs, net of development costs incurred during the period		(22,537	)		19,796			19,234
Revisions of quantity estimates		(402,974	)		(141,133	)		(157,881	)
Accretion of discount		207,148			187,795			145,504
Net change in income taxes		(173,079	)		(45,072	)		(142,395	)
Purchases of reserves in-place		44,940			232,450			104,957
Sales of reserves in-place		—			(19,558	)		(622	)
Changes in production rates due to timing and other		26,150			(110,289	)		(64,352	)

Net increase in standardized measure		320,521			148,383			280,520

Standardized measure at end of year	$	1,932,980		$	1,612,459		$	1,464,076

F-28

GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall apply to the indicated terms as used in this Form 10-K. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Active property. An oil and gas property with existing production.

BBtu. One billion Btus.

Bcf. One billion cubic feet of gas.

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

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

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

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

Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

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

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

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

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

Mcf. One thousand cubic feet of gas.

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

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

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

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

MMcfe/d. One million cubic feet of gas equivalent per day.

Make-Whole Amount. The greater of 104.125% of the principal amount of the 8¹/4% Notes and the sum of the present values of the remaining scheduled payments of principal and interest discounted to the date of redemption on a semiannual basis at the applicable treasury rate plus 50 basis points.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

Net profits interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production subject to production costs.

G-1

GLOSSARY OF CERTAIN INDUSTRY TERMS: (Continued)

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

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

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

Production payment. An obligation of the purchaser of a property to pay a specified portion of future gross revenues, less related production taxes and transportation costs, to the seller of the property.

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

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

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

Standardized measure of discounted future net cash flows. The standardized measure represents value-based information about an enterprise’s proved oil and gas reserves based on estimates of future cash flows, including income taxes, from production of proved reserves assuming continuation of year-end economic and operating conditions.

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

Volumetric production payment. An obligation of the purchaser of a property to deliver a specific volume of production, free and clear of all costs, to the seller of the property.

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

G-2

EXHIBIT INDEX


Exhibit
Number		Description
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	—	Restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).

3.3	—	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).

3.4	—	Amendment to restated Bylaws of the Registrant (incorporated by reference to Exhibit 3.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 001-12074)).

4.1	—	Rights Agreement, with exhibits A, B and C thereto, dated as of October 15, 1998, between Stone Energy Corporation and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A (File No. 001-12074)).

4.2	—	Amendment No. 1, dated as of October 28, 2000, to Rights Agreement dated as of October 15, 1998, between Stone Energy Corporation and ChaseMellon Shareholder Services, L.L.C., as Rights Agent (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-4 (Registration No. 333-51968)).

4.3	—	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)).

4.4	—	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.)

†4.5	—	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)).

†4.6	—	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)).

†10.1	—	Deferred Compensation and Disability Agreements between TSPC and D. Peter Canty dated July 16, 1981, and between TSPC and James H. Prince dated August 23, 1981 and September 20, 1981, respectively (incorporated by reference to Exhibit 10.8 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).

†10.2	—	Conveyances of Net Profits Interests in certain properties to D. Peter Canty and James H. Prince (incorporated by reference to Exhibit 10.9 to the Registrant’s Registration Statement on Form S-1 (Registration No. 33-62362)).

†10.3	—	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)).

†10.4	—	Stone Energy Corporation Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.14 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1993 (File No. 001-12074)).

†10.5	—	Stone Energy Corporation Amendment to the Annual Incentive Compensation Plan dated January 15, 1997 (incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 001-12074)).


†10.6	—	Stone Energy Corporation Revised Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.10 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 001-12074)).

†10.7	—	Stone Energy Corporation 2001 Amended and Restated Stock Option Plan (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8 (Registration No. 333-107440)).

10.8	—	Credit Agreement between the Registrant, the financial institutions named therein and Bank of America, N.A., as administrative agent, dated April 30, 2004. (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q, filed August 9, 2004 (File No. 001-12074)).

10.9	—	Amendment No. 1 to the Credit Agreement between the Registrant, the financial institutions named therein and Bank of America, N.A., as administrative agent, dated December 14, 2004 (incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)).

†10.10	—	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)).

†10.11	—	Stone Energy Corporation Revised (2005) 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)).

16.1	—	Letter of Arthur Andersen LLP, dated June 26, 2002, regarding change in certifying accountant (incorporated by reference to Exhibit 16.1 to the Registrant’s Form 8-K, filed June 27, 2002 (File No. 001-12074)).

18.1	—	Letter of Ernst & Young LLP, dated May 13, 2003, regarding change in accounting principles (incorporated by reference to Exhibit 18.1 to the Registrant’s Quarterly Report on Form 10-Q, for the period ended March 31, 2003 (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.

*23.3	—	Consent of Ryder Scott Company, L.P.

*23.4	—	Consent of Cawley, Gillespie & 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.


*		Filed herewith.

†		Identifies management contracts and compensatory plans or arrangements.

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


		Page No.
PART I
Item 1.	Business.		4
Item 1A.	Risk Factors.		9
Item 1B.	Unresolved Staff Comments.		14
Item 2.	Properties.		14
Item 3.	Legal Proceedings.		18
Item 4.	Submission of Matters to a Vote of Security Holders.		19
Item 4A.	Executive Officers of the Registrant.		19

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.		20
Item 6.	Selected Financial Data.		21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		22
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.		30
Item 8.	Financial Statements and Supplementary Data.		30
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.		31
Item 9A.	Controls and Procedures.		31
Item 9B.	Other Information.		32

PART III

Item 10.	Directors and Executive Officers of the Registrant.		34
Item 11.	Executive Compensation.		34
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.		34
Item 13.	Certain Relationships and Related Transactions.		34
Item 14.	Principal Accountant Fees and Services.		34

PART IV

Item 15.	Exhibits and Financial Statement Schedules.		35
	Index to Financial Statements.		F-1
	Glossary of Certain Industry Terms.		G-1
Subsidiaries of the Registrant
Consent of Independent Registered Public Accounting Firm
Consent of Netherland, Sewell & Associates, Inc.
Consent of Ryder Scott Company, L.P.
Consent of Cawley, Gillespie & Associates, Inc.
Certification of PEO Pursuant to Rule 13a-14(a)
Certification of PFO Pursuant to Rule 13a-14(a)
Certification of CEO & CFO Pursuant to Section 1350


	Three Months Ended
	March 31,		June 30,		Sept. 30,		Dec. 31,
	See Note		See Note		See Note		See Note
	Below		Below		Below		Below
2005
Operating revenue	$	156,153	$	185,238	$	159,275	$	135,574
Income from operations		56,519		72,334		55,689		47,924
Net income		33,424		43,967		32,977		26,395

Earnings common per share	$	1.25	$	1.64	$	1.22	$	0.97
Earnings common per share assuming dilution		1.24		1.62		1.20		0.96

2004
Operating revenue	$	133,580	$	142,224	$	128,306	$	140,091
Income from operations		51,779		54,742		37,349		55,437
Net income		31,408		31,796		21,945		34,519

Earnings common per share	$	1.19	$	1.20	$	0.82	$	1.29
Earnings common per share assuming dilution	$	1.17	$	1.18	$	0.82	$	1.28