Stone Energy (SGY) CORRESP Correspondence with SEC

Via FAX & Federal Express

August 9, 2006

Karl Hiller
Branch Chief
U. S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549-7010

Re:	Stone Energy Corporation
	Form 10-K for the fiscal year ended December 31, 2005
	Filed March 13, 2006
	File No. 001-12074

Dear Mr. Hiller:

     Pursuant to your request, Stone Energy Corporation (“Stone”) is hereby providing (i) written responses to the comments contained in your letter, dated July 31, 2006, and (ii) the materials requested in said letter or referenced in the responses below.

Form 10-K for the Fiscal Year Ended December 31, 2005

Comment 1:

We note that you did not comply with prior comment 2, advising that presentation of asset retirement costs as a separate line item within the table of capitalized costs is not consistent with SFAS 143 or SFAS 69. We continue to believe such costs should be characterized as acquisition, exploration or development. We re-issue prior comment 2.

Response 1:

We respectfully disagree with your interpretations of SFAS 143 and SFAS 69 in regards to this matter. However, we propose to comply with your request in an amended 10-K filing, by reclassifying asset retirement costs to the related cost category to which the asset retirement obligations relate as you have requested.

U. S. Securities and Exchange Commission
August 9, 2006
Page 2

We also propose to disclose the details of this allocation as additional information to the reader of the financial statements.

Comment 2:

You explain in response to comment 6 that you believe no revision to the captions of the tables is necessary because you state in the opening paragraph that “...All period to period comparisons are based on restated amounts...” We continue to believe that even though you discuss the restatement in an explanatory note at the beginning of the document, and state that “the information herein reflects the restatements described above...” you should label tables with restated information as restated. We reissue prior comment 6.

Response 2:

We will comply with your request to label tables with restated information as “restated” in an amended 10-K filing.

Comment 3:

We note your response to comment 9, explaining that your approach in presenting error correction disclosures for the quarterly information is consistent with those of other companies in similar reporting situations, and that you discussed your approach with the Staff prior to filing. Unfortunately, the view we endeavored to convey was not sufficiently understood. Accepting disclosures of restated quarterly information in an annual report, in lieu of filing amendments to the quarterly reports, is an accommodation offered with the understanding that such disclosures would provide detail comparable to that which would be available in amendments to quarterly reports, specifically as they relate to the line items and periods covered, which should include the six and nine month interim periods in addition to the individual quarters. We reissue prior comment 9.

Response 3:

We will comply with your request for the additional information in an amended 10-K filing. This information will be inserted in Note-1 after the discussion of the various line items which have been restated. The additional information will include restated balance sheets as of June 30, 2005, March 31, 2005, September 30, 2004, June 30, 2004 and March 31, 2004; restated income statements and statements of comprehensive income for the quarters and year-to-date periods ended June 30, 2005, March 31, 2005, September 30, 2004, June 30, 2004, March 31, 2004, September 30, 2003, June 30, 2003 and March 31, 2003; and restated statements of cash flows for the year-to-date periods ended June 30, 2005, March 31, 2005, September 30, 2004, June 30, 2004, March 31, 2004, September 30, 2003, June 30, 2003 and March 31, 2003.

U. S. Securities and Exchange Commission
August 9, 2006
Page 3

Comment 4:

We note your response to prior comment 13 explaining that you plan to revise your disclosures to replace the termengineeredwithpreparedwhen describing the compilation of reserve information by certain engineering firms. We also note that you intend to include the definition ofauditedpublished by the Society of Petroleum Engineers along with your disclosure indicating Netherland, Sewell & Associates, Inc. audited 72.6 percent of your total reserves. We have considered your references to audited reserve information and the guidance included in the document Auditing Standards for Reserves that is published by the Society of Petroleum Engineers, and require further information. Please address the following points.

Comment 4(a):

Tell us the nature of the audit procedures that were performed, and describe the relevancy of these procedures in relation to any limitations identified.

Response 4(a):

Netherland, Sewell & Associates, Inc. (NSAI) performed an audit of substantially all of our Gulf Coast Basin reserves (the remainder being estimated by Cawley Gillespie & Associates, Inc.). As part of the basis for their audit conclusions, NSAI prepared an estimate for 71% of the reserves on which they issued an audit report. Enclosed are two reports from NSAI that were previously provided to you on March 13, 2006. These reports provide the nature of the procedures performed and any limitations on the scope of their procedures. It should be noted that the reserves in the estimate prepared by NSAI in their report dated February 7, 2006 are a subset of the reserves included in their audit report dated February 8, 2006.

Comment 4(b):

Advise on the extent to which the engineering auditor verified the accuracy and completeness of information and data furnished by you with respect to ownership interests in the properties for which reserves are being audited; and the related oil and gas production, historical costs of operation and development, product prices and agreements relating to current and future operations and sales of production.

Response 4(b):

NSAI verified the accuracy and reasonableness of production data, lease operating expense, and pricing adjustments and differentials by examining Stone’s Lease Operating Statements for the audited properties. They did not verify ownership interests or examine joint operating agreements or marketing contracts.

U. S. Securities and Exchange Commission
August 9, 2006
Page 4

Comment 4(c):

If the engineering audit did not cover this or other information that is also critical to the preparation of reserve information, explain to us the relevancy of such data so that the effect of the procedural limitations imposed by the scope of the audit on the conclusions are clear.

Response 4(c):

It is customary for independent engineering firms to not examine ownership interests and rely on company procedures. Our procedures for determining ownership interests are part of the significant processes tested for purposes of our compliance with Sarbanes Oxley 404 and there have been no significant deficiencies or material weaknesses noted in this area of reserve reporting. Additionally, even though NSAI did not review any marketing contracts, Stone markets all of its production on contracts whereby pricing is established on a month-to-month basis.

Comment 4(d):

Disclose the findings of the engineering auditor.

Response 4(d):

We propose to disclose the audit report issued by NSAI by including the report as an exhibit in an amended 10-K filing and referencing the report in Item 2.- Properties.

Comment 4(e):

Tell us the nature and extent of your relationship with your engineering auditor, Netherland, Sewell & Associates, Inc. Describe all financial and business interests and transactions, contingent fee arrangements, and services unrelated to the audit provided during any of the periods covered by the reserve information or subsequently.

Response 4(e):

NSAI is an independent consulting firm which Stone has retained to perform geologic and engineering services on an as-requested basis. This primarily involves the estimating and/or auditing of proved reserves on an annual basis. Additionally, we have periodically solicited their assistance in evaluating reserves of potential acquisitions and contracted with them to provide due diligence

U. S. Securities and Exchange Commission
August 9, 2006
Page 5

assistance in our recent merger evaluations. We have no contingent fee arrangements with NSAI and they attest to that fact in their audit report.

Comment 4(f):

If you did not prepare the reserve information that was subject to the audit, advise us on any relationship between the preparer and engineering auditor. If the reserve information was also prepared by Netherland, Sewell & Associates, please ensure that you disclose this arrangement prominently.

Response 4(f):

As noted in Response 4(a), NSAI prepared an estimate for 71% of the reserves for which it provided an audit opinion. The remainder was prepared by Stone with no third party input. We will disclose these facts in Item 2.-Properties of the amended filing.

Comment 4(g):

Provide us with details about the specific reserve information that you have disclosed which has been subject to the engineering audit. Identify the properties audited, either individually, by region, or with other description; and specify the related quantities of proved developed and undeveloped reserves, and the applicable portion of the standardized measure of discounted future net cash flows relating to the proved oil and gas reserve quantities that were audited.

Response 4(g):

As noted in Response 4(a), the reserves audited were entirely in the Gulf Coast region and consisted of the following:

Proved Developed Reserves	328 Bcfe
Proved Undeveloped Reserves	103 Bcfe
Standardized Measure	$1.6 billion

Comment 4(h):

Submit for our review the engineering audit report, including the schedules detailing the information covered by the report.

Response 4(h):

As noted in Response 4(a), a copy of the entire report has been previously provided to you and is enclosed.

U. S. Securities and Exchange Commission
August 9, 2006
Page 6

In connection with responding to your comments, Stone Energy Corporation acknowledges that:

(i)	the company is responsible for the adequacy and accuracy of the disclosure in the filing;
(ii)	staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and
(iii)	the company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

     We will be providing to you, under separate cover, a draft of the amended 10-K to facilitate your review. We anticipate that our cover letter for this transmittal will provide an adequate indexing system from which you can trace the changes to comments you have made.

     We understand that you may have additional comments after reviewing our responses to your comments. Please contact me at (337) 237-0410 with any questions.

Sincerely,

/s/ Kenneth H. Beer

Kenneth H. Beer

Senior Vice President

and Chief Financial Officer

KHB/pm
Enclosures

	Chairman Emeritus	Executive Committee
WORLDWIDE PETROLEUM CONSULTANTS	Clarence M.Netherland	G.Lance Binder -Dallas
ENGINEERING • GEOLOGY • GEOPHYSICS • PETROPHYSICS		DannyD.Simmons -Houston
	Chairman & CEO Frederic D.Sewell	P.ScottFrost -Dallas Dan Paul Smith-Dallas
		JosephJ.Spellman -Dallas
	President& COO	Thomas J.TellaII -Dallas
	C.H.(Scott) Rees III

February 7, 2006

Stone Energy Corporation
625 East Kaliste Saloom Road
Lafayette, Louisiana 70508

Gentlemen:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2005, to the Stone Energy Corporation (Stone) interest in certain oil and gas properties located in Louisiana and in the Gulf of Mexico, as listed in the accompanying tabulations. This report has been prepared using constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of reserves and future revenue in this report conform to the guidelines of the Securities and Exchange Commission (SEC).

As presented in the accompanying summary projections, Tables I through IV, we estimate the net reserves and future net revenue to the Stone interest in these properties, as of December 31, 2005, to be:

	Net Reserves				Future Net Revenue (M$)
	Oil		Gas				Present Worth
Category	(MBBL)		(MMCF)		Total		at 10%
Proved Developed Producing		4,053.3		25,001.7		256,158.5		245,153.1
Non-Producing		14,382.1		104,075.0		1,367,614.5		996,771.2
Proved Undeveloped		4,987.6		36,894.0		470,398.9		277,481.3
Total Proved(1)		23,423.0		165,970.8		2,094,171.9		1,519,405.6

⁽¹⁾ Totals may not add because of rounding.

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. In accordance with SEC guidelines, our estimates do not include any probable or possible reserves that may exist for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Definitions of all reserve categories are presented immediately following this letter. As shown in the Table of Contents, for each reserve category this report includes a summary projection of reserves and revenue along with one-line summaries of reserves, economics, and basic data by lease.

Future gross revenue to the Stone interest is prior to deducting state production taxes. Future net revenue is after deductions for these taxes, future capital costs, operating expenses, and abandonment costs but before consideration of federal income taxes. In accordance with SEC guidelines, the future net revenue has been discounted at an annual rate of 10 percent to determine its “present worth.” The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.

4500 Thanksgiving Tower • 1601 Elm Street • Dallas, Texas 75201-4754 • Ph: 214-969-5401 • Fax: 214-969-5411	nsai@nsai-petro.com
1221 Lamar Street, Suite 1200 • Houston, Texas 77010-3072 • Ph: 713-654-4950 • Fax: 713-654-4951	netherlandsewell.com

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and their related facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability. Our estimates of future revenue do not include any salvage value for the lease and well equipment but do include Stone’s estimates of the costs to abandon the wells, platforms, and production facilities. Abandonment costs are included as capital costs.

Oil prices used in this report are based on a December 31, 2005, West Texas Intermediate posted price of $57.75 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials. Gas prices used in this report are based on regional spot market prices in effect on December 31, 2005, and are adjusted by lease for energy content, transportation fees, and infield price differentials. As a reference, the December 31, 2005, Henry Hub spot market price was $10.08 per MMBTU. All prices are held constant in accordance with SEC guidelines. A table of the regional gas index prices by field or lease is presented immediately following the definitions.

Lease and well operating costs used in this report are based on operating expense records of Stone. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease- and field-level costs. For all properties, headquarters general and administrative overhead expenses of Stone are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs are included as required for workovers, new development wells, and production equipment.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Stone interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Stone receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. The reserves may or may not be recovered; if they are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. A substantial portion of these reserves are for behind pipe zones, non-producing zones, undeveloped locations, and producing wells that lack sufficient production history upon which performance-related estimates of reserves can be based. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. Because such reserve estimates are usually subject to greater revision than those based on substantial production and pressure data, it may be necessary to revise these estimates as additional performance data become available. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report. Also, estimates of reserves may increase or decrease as a result of future operations.

In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

The titles to the properties have not been examined by Netherland, Sewell & Associates, Inc., nor has the actual degree or type of interest owned been independently confirmed. The data used in our estimates were obtained from Stone Energy Corporation, public data sources, and the nonconfidential files of Netherland, Sewell &

Associates, Inc. and were accepted as accurate. Supporting geologic, field performance, and work data are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties and are not employed on a contingent basis.

Very truly yours,
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees
	C.H. (Scott) Rees III, P.E.
	President and Chief Operating Officer

	[SEAL]		[SEAL]
By:	/s/ Danny D. Simmons	By:	/s/ Mike K. Norton
	Danny D. Simmons, P.E.		Mike K. Norton, P. G.
	Executive Vice President		Senior Vice President
Date Signed: February 7, 2006		Date Signed: February 7, 2006
DDS:SRM

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

The following definitions of proved reserves are set forth in Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included (in italics) are certain subsequent interpretations set forth in the SEC’s Corporate Finance Accounting Interpretations and Guidance [SEC Interpretations]; SEC Staff Accounting Bulletins: Topic 12 [SEC Topic 12]; and the 1997 reserves definitions approved by the Society of Petroleum Engineers and World Petroleum Council [SPE/WPC Definitions].

Proved Oil and Gas Reserves.Proved oil and gas reserves are 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, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

     The determination of reasonable certainty is generated by supporting geological and engineering data. There must be data available which indicate that assumptions such as decline rates, recovery factors, reservoir limits, recovery mechanisms and volumetric estimates, gas-oil ratios or liquid yield are valid. If the area in question is new to exploration and there is little supporting data for decline rates, recovery factors, reservoir drive mechanisms etc., a conservative approach is appropriate until there is enough supporting data to justify the use of more liberal parameters for the estimation of proved reserves. The concept of reasonable certainty implies that, as more technical data becomes available, a positive, or upward, revision is much more likely than a negative, or downward, revision.

     Existing economic and operating conditions are the product prices, operating costs, production methods, recovery techniques, transportation and marketing arrangements, ownership and/or entitlement terms and regulatory requirements that are extant on the effective date of the estimate. An anticipated change in conditions must have reasonable certainty of occurrence; the corresponding investment and operating expense to make that change must be included in the economic feasibility at the appropriate time. These conditions include estimated net abandonment costs to be incurred and duration of current licenses and permits.

     If oil and gas prices are so low that production is actually shut-in because of uneconomic conditions, the reserves attributed to the shut-in properties can no longer be classified as proved and must be subtracted from the proved reserve data base as a negative revision. Those volumes may be included as positive revisions toasubsequent year’s proved reserves only upon their return to economic status. [SEC Interpretations]

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

     Proved reserves may be attributed to a prospective zone if a conclusive formation test has been performed or if there is production from the zone at economic rates. It is clear to the SEC staff that wireline recovery of small volumes (e.g. 100 cc) or production of a few hundred barrels per day in remote locations is not necessarily conclusive. Analyses of open-hole well logs which imply that an interval is productive are not sufficient for attribution of proved reserves. If there is an indication of economic producibility by either formation test or production, the reserves in the legal and technically justified drainage area around the well projected down to a known fluid contact or the lowest known hydrocarbons, or LKH may be considered to be proved.

     In order to attribute proved reserves to legal locations adjacent to such a well (i.e. offsets), there must be conclusive, unambiguous technical data which supports reasonable certainty of production of such volumes and sufficient legal acreage to economically justify the development without going below the shallower of the fluid contact or the LKH. In the absence of a fluid contact, no offsetting reservoir volume below the LKH from a well penetration shall be classified as proved.

Definitions — Page 1 of 4

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

     Upon obtaining performance history sufficient to reasonably conclude that more reserves will be recovered than those estimated volumetrically down to LKH, positive reserve revisions should be made. [SEC Interpretations]

     Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. [SEC Topic 12]

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

     If an improved recovery technique which has not been verified by routine commercial use in the area is to be applied, the hydrocarbon volumes estimated to be recoverable cannot be classified as proved reserves unless the technique has been demonstrated to be technically and economically successful by a pilot project or installed program in that specific rock volume. Such demonstration should validate the feasibility study leading to the project. [SEC Interpretations]

Estimates of proved reserves do not include the following:

(A)	oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;
(B)	crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
(C)	crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
(D)	crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

     Geologic and reservoir characteristic uncertainties such as those relating to permeability, reservoir continuity, sealing nature of faults, structure and other unknown characteristics may prevent reserves from being classified as proved. Economic uncertainties such as the lack of a market (e.g. stranded hydrocarbons), uneconomic prices and marginal reserves that do not show a positive cash flow can also prevent reserves from being classified as proved. Hydrocarbons “manufactured” through extensive treatment of gilsonite, coal and oil shales are mining activities reportable under Industry Guide 7. They cannot be called proved oil and gas reserves. However, coal bed methane gas can be classified as proved reserves if the recovery of such is shown to be economically feasible.

     In developing frontier areas, the existence of wells with a formation test or limited production may not be enough to classify those estimated hydrocarbon volumes as proved reserves. Issuers must demonstrate that there is reasonable certainty that a market exists for the hydrocarbons and that an economic method of extracting, treating and transporting them to market exists or is feasible and is likely to exist in the near future. A commitment by the company to develop the necessary production, treatment and transportation infrastructure is essential to the attribution of proved undeveloped reserves. Significant lack of progress on the development of such reserves may be evidence of a lack of such commitment. Affirmation of this commitment may take the form of signed sales contracts for the products; request for proposals to build facilities; signed acceptance of bid proposals; memos of understanding between the appropriate organizations and governments; firm plans and timetables established; approved authorization for expenditures to build facilities;

Definitions — Page 2 of 4

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

approved loan documents to finance the required infrastructure; initiation of construction of facilities; approved environmental permits etc. Reasonable certainty of procurement of project financing by the company is a requirement for the attribution of proved reserves. An inordinately long delay in the schedule of development may introduce doubt sufficient to preclude the attribution of proved reserves.

     The history of issuance and continued recognition of permits, concessions and commerciality agreements by regulatory bodies and governments should be considered when determining whether hydrocarbon accumulations can be classified as proved reserves. Automatic renewal of such agreements cannot be expected if the regulatory body has the authority to end the agreement unless there is a long and clear track record which supports the conclusion that such approvals and renewal are a matter of course. [SEC Interpretations]

     Companies should report reserves of natural gas liquids which are net to their leasehold interests, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instructions to Item 3 of Securities Act Industry Guide 2 and report such reserves separately and describe the nature of the ownership. [SEC Topic 12]

Proved Developed Oil and Gas Reserves.Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

     Currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or bore hole stimulation treatment would be examples of properties with proved developed reserves since the majority of the expenditures to develop the reserves has already been spent.

     Proved developed reserves from improved recovery techniques can be assigned after either the operation of an installed pilot program shows a positive production response to the technique or the project is fully installed and operational and has shown the production response anticipated by earlier feasibility studies. In the case with a pilot, proved developed reserves can be assigned only to that volume attributable to the pilot’s influence. In the case of the fully installed project, response must be seen from the full project before all the proved developed reserves estimated can be assigned. If a project is not following original forecasts, proved developed reserves can only be assigned to the extent actually supported by the current performance. An important point here is that attribution of incremental proved developed reserves from the application of improved recovery techniques requires the installation of facilities and a production increase. [SEC Interpretations]

     Proved Developed Producing Reserves.Reserves subcategorized as producing are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

     Proved Developed Non-Producing Reserves.Reserves subcategorized as non-producing include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. [SPE/WPC Definitions]

Proved Undeveloped Reserves.Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units

Definitions — Page 3 of 4

DEFINITIONS OF OIL AND GAS RESERVES
Adapted from Securities and Exchange Commission Regulation S-X Rule 4-10(a)

can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

     The SEC staff points out that this definition contains no mitigating modifier for the word certainty. Also, continuity of production requires more than the technical indication of favorable structure alone (e.g. seismic data) to meet the test for proved undeveloped reserves. Generally, proved undeveloped reserves can be claimed only for legal and technically justified drainage areas offsetting an existing productive well (but structurally no lower than LKH). If there are at least two wells in the same reservoir which are separated by more than one legal location and which show communication (reservoir continuity), proved undeveloped reserves could be claimed between the two wells, even though the location in question might be more than an offset well location away from any of the wells. In this illustration, seismic data could be used to help support this claim by showing reservoir continuity between the wells, but the required data would be the conclusive evidence of communication from production or pressure tests. The SEC staff emphasizes that proved reserves cannot be claimed more than one offset location away from a productive well if there are no other wells in the reservoir, even though seismic data may exist. The use of high-quality, well calibrated seismic data can improve reservoir description for performing volumetrics (e.g. fluid contacts). However, seismic data is not an indicator of continuity of production and, therefore, can not be the sole indicator of additional proved reserves beyond the legal and technically justified drainage areas of wells that were drilled. Continuity of production would have to be demonstrated by something other than seismic data.

     In a new reservoir with only a few wells, reservoir simulation or application of generalized hydrocarbon recovery correlations would not be considered a reliable method to show increased proved undeveloped reserves. With only a few wells as data points from which to build a geologic model and little performance history to validate the results with an acceptable history match, the results of a simulation or material balance model would be speculative in nature. The results of such a simulation or material balance model would not be considered to be reasonably certain to occur in the field to the extent that additional proved undeveloped reserves could be recognized. The application of recovery correlations which are not specific to the field under consideration is not reliable enough to be the sole source for proved reserve calculations.

     Reserves cannot be classified as proved undeveloped reserves based on improved recovery techniques until such time that they have been proved effective in that reservoir or an analogous reservoir in the same geologic formation in the immediate area. An analogous reservoir is one having at least the same values or better for porosity, permeability, permeability distribution, thickness, continuity and hydrocarbon saturations.

(g)	Topic 12 of Accounting Series Release No. 257 of the Staff Accounting Bulletins states:
	In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test.

     If the combination of data from open-hole logs and core analyses is overwhelmingly in support of economic producibility and the indicated reservoir properties are analogous to similar reservoirs in the same field that have produced or demonstrated the ability to produce on a conclusive formation test, the reserves may be classified as proved. This would probably be a rare event especially in an exploratory situation. The essence of the SEC definition is that in most cases there must at least be a conclusive formation test in a new reservoir before any reserves can be considered to be proved. [SEC Interpretations]

Definitions — Page 4 of 4

	Chairman Emeritus	Executive Committee
WORLDWIDE PETROLEUM CONSULTANTS	Clarence M.Netherland	G.Lance Binder -Dallas
ENGINEERING • GEOLOGY • GEOPHYSICS • PETROPHYSICS		DannyD.Simmons -Houston
	Chairman & CEO Frederic D.Sewell	P.ScottFrost -Dallas Dan Paul Smith-Dallas
		JosephJ.Spellman -Dallas
	President& COO	Thomas J.TellaII -Dallas
	C.H.(Scott) Rees III

February 8, 2006

Stone Energy Corporation
625 East Kaliste Saloom Road
Lafayette, Louisiana 70508

Gentlemen:

In accordance with your request, we have audited the estimates prepared by Stone Energy Corporation (Stone), as of December 31, 2005, of the proved reserves and future revenue to the Stone interest in certain oil and gas properties located in Louisiana and in the Gulf of Mexico. These estimates are based on constant prices and costs, as discussed in subsequent paragraphs of this letter. The estimates of reserves and future revenue conform to the guidelines of the Securities and Exchange Commission (SEC). We have examined the estimates with respect to reserve quantities, future producing rates, future net revenue, and the present value of such future net revenue. We have also examined the estimates with respect to reserve categorization, using the definitions for proved reserves set forth in the SEC Regulation S-X Rule 4-10(a) and subsequent staff interpretations and guidance.

The following table sets forth Stone’s estimates of the net reserves and future net revenue, as of December 31, 2005, for the audited properties:

	Net Reserves				Future Net Revenue (M$)
	Oil		Gas				Present Worth
Category	(MBBL)		(MMCF)		Total		at 10%
Proved Developed
Producing		4,523.0		32,623.6		261,056.7		258,654.0
Non-Producing		18,018.0		159,811.5		1,874,145.7		1,394,493.4
Proved Undeveloped		6,307.1		65,043.0		704,218.3		432,543.5
Total Proved		28,848.1		257,478.1		2,839,420.7		2,085,690.9

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a field-by-field basis, some of the estimates of Stone are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. However, in our opinion the estimates of Stone’s proved reserves and future revenue shown herein are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. These principles are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. We are satisfied with the methods and procedures used by Stone in preparing the December 31, 2005, reserve and future revenue estimates, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Stone.

The estimates shown herein are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. Stone’s estimates do not include probable or possible reserves that may exist for these properties, nor do they include any consideration of undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Oil prices used by Stone are based on a December 31, 2005, West Texas Intermediate posted price of $57.75 per barrel and are adjusted by lease for quality, transportation fees, and regional price differentials Gas prices used by Stone are based on a December 31, 2005, Henry Hub spot market price of $10.08 per MMBTU and are

4500 Thanksgiving Tower • 1601 Elm Street • Dallas, Texas 75201-4754 • Ph: 214-969-5401 • Fax: 214-969-5411	nsai@nsai-petro.com
1221 Lamar Street, Suite 1200 • Houston, Texas 77010-3072 • Ph: 713-654-4950 • Fax: 713-654-4951	netherlandsewell.com

adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant in accordance with SEC guidelines.

Lease and well operating costs used by Stone are based on historical operating expense records. For nonoperated properties, these costs include the per-well overhead expenses allowed under joint operating agreements, along with estimates of costs to be incurred at and below the district and field levels. As requested, lease and well operating costs for the operated properties include only direct lease- and field-level costs. For all properties, headquarters general and administrative overhead expenses of Stone are not included. Lease and well operating costs are held constant in accordance with SEC guidelines. Stone’s estimates of capital costs are included as required for workovers, new development wells, and production equipment.

It should be understood that our audit does not constitute a complete reserve study of the oil and gas properties of Stone. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of major properties making up approximately 81 percent of the company’s total proved reserves and accounting for approximately 84 percent of the present worth for those reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Stone with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Stone’s overall reserves management processes and practices.

In evaluating the information at our disposal concerning this audit, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geologic. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geologic data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Stone, are on file in our office. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists with respect to Stone Energy Corporation as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. We do not own an interest in these properties and are not employed on a contingent basis.

Very truly yours,
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ C.H. (Scott) Rees III
	C.H. (Scott) Rees III, P.E.
	President and Chief Operating Officer

[SEAL]		[SEAL]
By:	/s/ Danny D. Simmons,	By:	/s/ Mike K. Norton
	Danny D. Simmons, P.E.		Mike K. Norton, P.G.
	Executive Vice President		Senior Vice President
Date Signed: February 8, 2006		Date Signed: February 8, 2006
DDS:SRM