SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F/A

(Check One)



___

Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

or

_X_

Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934



For the fiscal year ended 12/31/04

Commission File Number

0-29878







Gentry Resources Ltd.

(Exact Name of Registrant as Specified in its Charter)



Federally Incorporated in Canada

(Province or Other Jurisdiction of Incorporation or Organization)



101 6th Avenue S.W., Suite 2500

Calgary, Alberta, Canada T2P 3P4

(403) 264-6161

(Address and Telephone Number of Registrants Principal Executive Offices)



Susan K. Shapiro, Esq.

Perkins, Smith & Cohen, LLP

One Beacon Street, Boston, MA 02108

(617) 854-4000

(Name, Address and Telephone Number of Agent for Service in the United States)



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

Title of Each ClassName of Each Exchange
on Which Registered______N/A______N/A




Securities registered or to be registered pursuant to Section 12(g) of the Act:



_____Common Shares without Par Value_____

(Title of Class)



Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:



N/A

(Title of Class)



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For annual reports, indicate by check mark the information filed with this Form:



[X] Annual information form  [X] Audited annual financial statements



Indicate the number of outstanding shares of each of the issuers classes of capital or common stock as of the close of the period covered by the annual report:

38,850,168 Common Shares without Par Value





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Indicate by check mark whether the Registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the Exchange Act).  If Yes is marked, indicate the filing number assigned to the Registrant in connection with such Rule.



YES   NO X__



Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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.



YES X  NO __



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PRINCIPAL DOCUMENTS



Annual Information Form



The Annual Information Form of Gentry Resources Ltd. (the Company) for the year ended December 31, 2004 is included herein as Exhibit 1.



Audited Annual Financial Statements and

Management Discussion and Analysis



Audited Annual Financial Statements



The Companys audited consolidated financial statements for the years ended December 31, 2004 and 2003, including the auditors report thereon dated March 04, 2005, are included herein as Exhibit 2.  Please refer to Note 14 to the audited consolidated financial statements for a reconciliation of the differences between Canadian and United States Generally Accepted Accounting Principles.



Management Discussion and Analysis



The Companys Management Discussion and Analysisfor the year ended December 31, 2004 is included herein as Exhibit 3.



CONTROLS AND PROCEDURES



A.

Disclosure Controls and Procedures



As of December 31, 2004, an evaluation was carried out by the Companys Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Companys disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934, as amended).  Based on that evaluation, the Companys Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.



B.

Internal Control over Financial Reporting



During the fiscal year ended December 31, 2004, there were no changes in the Companys internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Companys internal control over financial reporting.





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NOTICES PURSUANT TO REGULATION BTR



None.



AUDIT COMMITTEE FINANCIAL EXPERT



The Company has an Audit and Risk Management Committee (the Audit Committee) established by the Board of Directors.  The members of the Audit Committee are George T. Hawes, A. Bruce Macdonald and Michael Halvorson.  The Board has designated Mr. Hawes as the Audit Committee Financial Expert as that term is defined under Section 407 of the Sarbanes-Oxley Act of 2002.  Mr. Hawes is independent as that term is defined under the rules of the American Stock Exchange.



CODE OF ETHICS



The Company has adopted a Code of Business Conduct and Ethics that applies to all directors, officers and employees, including its Chief Executive Officer and Chief Financial Officer.  The Company will provide to any person, without charge, upon request, a copy of such Code.  A person may request a copy by writing to the Company at 101 6th Avenue S.W., Suite 2500, Calgary, Alberta, Canada T2P 3P4.



PRINCIPAL ACCOUNTANT FEES AND SERVICES



The aggregate amounts billed by Collins Barrow Calgary LLP, Chartered Accountants (CBC) to the Company for each of the fiscal years ended December 31, 2004 and 2003 for audit fees, audit-related fees, tax fees and all other fees are set forth below:



|                       | Year Ended
December 31, 2004 (estimated) | Year Ended
December 31, 2003
|---------------------- | ---------------------------------------- | ----------------------------
|Audit Fees (1)         | $  80,000                                | $  75,975                   
|Audit-Related Fees (2) | 25,000                                   | 37,950                      
|Tax Fees (3)           | 5,000                                    | 3,800                       
|All Other Fees (4)     | -                                        | -                           
|Totals                 | $110,000                                 | $117,725                    



NOTES:

(1)  Audit Fees represent fees for the audit of the Companys annual financial statements, review of the Companys interim financial statements and review in connection with the Companys statutory and regulatory filings.

(2)  Audit-Related Fees represent fees for assurance and related services that are related to the performance of the audit, principally for US standards compliance, adoption of new accounting standards etc.

(3)  Tax Fees represent fees for tax compliance, tax advice and tax planning.

(4)  Other Fees represent fees for accounting research on new accounting policies.



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The Audit Committee has adopted procedures requiring Audit Committee review and approval in advance of all particular engagements for services provided by the Companys independent auditors.  Consistent with applicable laws, the procedures permit limited amounts of services, other than audit, review or attest services, to be approved by one or more members of the Audit Committee pursuant to authority delegated by the Audit Committee, provided the Audit Committee is informed of each particular service.  All of the engagements and fees for the year ended December 31, 2004 were approved by the Audit Committee.  The Audit Committee reviews with CBC whether the non-audit services to be provided are compatible with maintaining the auditors independence.



OFF-BALANCE SHEET ARRANGEMENTS



The Company has no off-balance sheet arrangements required to be disclosed in this Annual Report on Form 40-F.



TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS



The required disclosure is included in the section of this Annual Report on Form 40-F entitled Principal Documents, in Managements Discussion and Analysis for the year ended December 31, 2004, under Contractual Obligations.

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UNDERTAKING AND CONSENT TO SERVICE OF PROCESS



A.

Undertaking



The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to:  the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.



B.

Consent to Service of Process



Concurrently with the filing of this annual report on Form 40-F, the Registrant filed with the Commission a written irrevocable consent and power of attorney on Form F-X.



EXHIBITS



The following exhibits are filed as part of this report:



1.

Annual Information Form for the year ended December 31, 2004



2.

Audited Consolidated Financial Statements for the years ended December 31, 2004 and 2003, together with the auditors report thereon dated March 04, 2005 (Note 14 to the audited consolidated financial statements relates to differences between Canadian and United States Generally Accepted Accounting Principles)



3.

Management Discussion and Analysis for the year ended December 31, 2004



4

Consent of Collins Barrow Calgary LLP, Chartered Accountants



5

Consent of Martin & Brusset Associates



6.1

Certification of Chief Executive Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended



6.2

Certification of Chief Financial Officer Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended



7.1

Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002



7.2

Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES





Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.





GENTRY RESOURCES LTD.

Registrant







By:signed:Ketan Panchmatia



Name:  Ketan Panchmatia

Title:  Secretary/Treasurer





Date:

March 28, 2005

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Exhibit 1



























[aif002.gif]









ANNUAL INFORMATION FORM









YEAR ENDED DECEMBER 31, 2004









March 28, 2005









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TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS

iii

ABBREVIATIONS AND CONVERSION

iv

PRESENTATION OF GENTRY'S OIL AND NATURAL GAS RESERVES AND PRODUCTION INFORMATION

v

FORWARD LOOKING STATEMENTS

viii

CORPORATE STRUCTURE

1

GENERAL DEVELOPMENT OF THE BUSINESS

1

Gentry's Development over the Last Three Years

2

RECENT DEVELOPMENTS

3

DESCRIPTION OF THE BUSINESS

3

General

3

Principal Producing Properties

4

Summary of Production from Principal Producing Properties

6

Marketing and Risk Management Arrangements

7

Oil and Natural Gas Reserves

7

Summary of Reserves & Future Net Revenue

8

Additional Information Concerning Future Net Revenue

10

Pricing Assumptions

11

Reconciliation of Reserves

11

Reconciliation of Changes in Net Present Value of Future Net Revenue

12

Undeveloped Reserves

12

Future Development Costs

13

Oil and Natural Gas Wells and Properties

13

Unproved Properties

13

Exploration and Development Activities

14

Quarterly Production History

14

Quarterly Netback History

14

Abandonment and Reclamation Costs

15

Tax Horizon

15

Costs Incurred

16

Environmental and Safety Matters

16

Insurance

16

Future Commitments

16

Human Resources

16

DIVIDENDS

17

DESCRIPTION OF CAPITAL STRUCTURE

17

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Common Shares

17

Preferred Shares

17

Shareholder Rights Plan

17

Normal Course Issuer Bid

17

INDUSTRY CONDITIONS

18

Pricing and Marketing - Oil

18

Pricing and Marketing - Natural Gas

18

The North American Free Trade Agreement ("NAFTA")

18

Provincial Royalties and Incentives

19

Land Tenure

21

Environmental Regulation

21

RISK FACTORS

21

Industry Risks

21

Regulation of Industry

22

Possible Income Tax Changes

22

Need for Future Financings

22

Property Title

23

Recovery and Reserve Estimates

23

Competition

23

Conflicts of Interest

23

Reliance on Management

23

Absence of Dividends

23

MARKET FOR SECURITIES

24

DIRECTORS AND OFFICERS

24

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

25

INTERESTS OF EXPERTS

25

REGISTRAR AND TRANSFER AGENT

26

ADDITIONAL INFORMATION

26

EXHIBIT "A" -REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

A-1

EXHIBIT "B" - REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

B-1

EXHIBIT "C"  AUDIT COMMITTEE DISCLOSURE PURSUANT TO MULTILATERAL INSTRUMENT 52-110

C-1



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GLOSSARY OF TERMS AND ABBREVIATIONS

Terms used in this Annual Information Form and not otherwise defined have the meanings set forth below. Additional terms relating to oil and natural gas reserves and operations have the meanings set forth under Presentation of Gentrys Oil & Natural Gas Reserves and Production Information.

"ABCA" means the Business Corporations Act (Alberta), R.S.A. 2000, c. B-9, as amended, and the regulations thereunder, and any successor laws or regulations thereto.

"API" means American Petroleum Institute;

"ARTC" means Alberta Royalty Tax Credit;

"CBCA" means the Canada Business Corporations Act, R.S.C. 1985, c. C-44, as amended, and the regulations thereunder, and any successor laws or regulations thereto.

"Common Shares" means common shares in the share capital of the Corporation;

"Corporation" or "Gentry" means Gentry Resources Ltd., a corporation amalgamated under the CBCA;

"Martin" means Martin & Brusset Associates, an independent firm of petroleum consultants, Calgary, Alberta;

"Martin Report" means the independent consultants' evaluation of Gentry's oil and natural gas properties prepared by Martin dated March 7, 2005 and effective as of December 31, 2004;

"NGLs" means natural gas liquids, including condensate, propane, butane and pentane;

NI 51-101 means National Instrument 51-101, Standards of Disclosure of Oil and Gas Activities, adopted by the Canadian securities regulatory authorities;

"overriding royalty interest" means an interest in the gross production of oil and gas under a lease, free of any expense for exploration, drilling, development, operating and other costs incident to the production and sale of oil and gas produced from the lease;

"property" or "properties" means an oil and/or natural gas property or properties and related tangible equipment, including facilities for producing, gathering, storing, measuring, transporting or processing of oil and/or natural gas production from such property, as well as seismic data, if any; and

"TSX"means the Toronto Stock Exchange.

All information in the Annual Information Form is presented as at December 31, 2004 unless otherwise indicated.



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ABBREVIATIONS AND CONVERSION

In this Annual Information Form, the following abbreviations have the meanings set forth below.

|AECO                  | Alberta Energy Company interconnect with the Nova System, the Canadian benchmark for natural gas pricing purposes                                                                                                                                                                                                                                                                                         |       | GJ
Mbbls                        | gigajoules
one thousand barrels                                                                                                                                                                                                               
|--------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ----- | ------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|MBOE                  | one thousand barrels of oil equivalent                                                                                                                                                                                                                                                                                                                                                                   
|bbls                  | barrels, with each barrel representing 34.972                                                                                                                                                                                                                                                                                                                                                             |       | Mcf                             | one thousand cubic feet                                                                                                                                                                                                                       
|                      | Imperial gallons or 42 U.S. gallons                                                                                                                                                                                                                                                                                                                                                                       | Mcf/d | one thousand cubic feet per day
|bbls/d
Bcf            | barrels per day
billion cubic feet                                                                                                                                                                                                                                                                                                                                                                        |       | MMbbls                          | one million barrels                                                                                                                                                                                                                           
|MMBOE                 | one million barrels of oil equivalent                                                                                                                                                                                                                                                                                                                                                                    
|Bcf/d
BOE






BOE/d | billion cubic feet per day
barrels of oil equivalent converting 6 Mcf of natural gas to one barrel of oil equivalent and one barrel of natural gas liquids to one barrel of oil equivalent. The factor used to convert natural gas and natural gas liquids to oil equivalent is not based on either energy content or prices but is a commonly used industry benchmark.
barrels of oil equivalent per day |       | MMBTU
MMcf
MMcf/d
MW
NGLs
WTI   | one million British Thermal Units
one million cubic feet
one million cubic feet per day
megawatts of electricity
natural gas liquids
West Texas Intermediate at Cushing, Oklahoma, the benchmark for North American crude oil pricing purposes

In this Annual Information Form, unless otherwise indicated, all dollar amounts are in Canadian dollars and all references to "$" are to Canadian dollars.

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).

|To Convert From | To           | Multiply By
|--------------- | ------------ | -----------
|Mcf             | cubic metres | 28.317     
|cubic metres    | cubic feet   | 35.314     
|bbls            | cubic metres | 0.159      
|cubic metres    | bbls         | 6.290      
|feet            | metres       | 0.305      
|metres          | feet         | 3.281      
|miles           | kilometres   | 1.609      
|kilometres      | miles        | 0.621      
|acres           | hectares     | 0.4047     
|hectares        | acres        | 2.471      



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PRESENTATION OF GENTRY'S OIL AND NATURAL GAS RESERVES AND PRODUCTION INFORMATION



Disclosure of Information

In this Annual Information Form, all estimates of oil and natural gas reserves and production are presented on a "company interest" (as defined below) basis, unless indicated that they have been presented on a "gross" or "net" basis.  The Corporation's actual oil and natural gas reserves and production may be greater than or less than the estimates provided in this Annual Information Form. The estimated future net revenue from the production of the Corporation's oil and natural gas reserves do not represent the fair market value of the Corporation's reserves.

The United States Securities and Exchange Commission (the SEC) generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves net of royalties and interests of others that an issuer has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Canadian securities laws permit oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only Proved Reserves but also Probable Reserves (each as defined in NI 51-101 and described below), and to disclose reserves and production on a gross basis before deducting royalties. Probable Reserves are higher risk and general believed to be less likely to be accurately estimated or recovered than Proved Reserves. The Corporation has prepared this Annual Information Form in accordance with the Canadian disclosure requirement, and as a result, the Corporation has disclosed reserves designated as Probable Reserves and Proved plus Probable Reserves. The SECs guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. Moreover, the Corporation has determined and disclosed estimated future net revenue from its reserves using both constant and forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report.

The Corporation has adopted the standard of 6 Mcf = 1 BOE when converting natural gas to BOE.  BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf = 1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Note to Reader Regarding Oil and Natural Gas Information and National Instrument 51-101

The oil and natural gas operational and reserves information contained in this Annual Information Form contains the information required to be included in the Statement of Reserves Data and Other Oil and Gas Information pursuant to National Instrument 51-101 adopted by the Canadian securities regulatory authorities and is presented in accordance with Form 51-101F1.  Readers should also refer to the Report on Reserves Data by Martin attached hereto as Exhibit "A" and the Report of Management and Directors on Oil and Gas Disclosure attached hereto as Exhibit "B".  The effective date for the Statement of Reserves Data and Other Oil and Gas Information contained in this Annual Information Form is December 31, 2004 and the information contained in the Annual Information Form has been prepared as of March 23, 2005.

Certain of the following definitions and guidelines have been prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society).  Further information is contained in Section 5.4 of Volume 1 of the COGE Handbook (First Edition, June 30, 2002).  Readers should consult the COGE Handbook for additional explanation and guidance.  Certain other terms used in this Annual Information Form have the meanings assigned to them in National Instrument 51-101 and accompanying Companion Policy 51-101CP, adopted by the Canadian securities regulatory authorities.



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Interests in Reserves, Production, Wells and Properties

"company interest" means in relation to the Corporation's interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and including any royalty interests of the Corporation.

"gross" means:

(i)

in relation to the Corporation's interest in production or reserves, its working interest (operating or non-operating) share in its reserves, before deduction of royalties and without including any royalty interests of the Corporation;

(ii)

in relation to wells, the total number of wells in which the Corporation has an interest; and

(iii)

in relation to properties, the total area of properties in which the Corporation has an interest.

"net" means:

(i)

in relation to the Corporation's interest in production or reserves, its working interest (operating or non-operating) share after deduction of royalty obligations, plus the Corporation's royalty interests in those production or reserves;

(ii)

in relation to the Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells; and

(iii)

in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.

"working interest" means the percentage of undivided interest held by the Corporation in the oil and/or natural gas or mineral lease granted by the mineral owner, Crown or freehold, which interest gives the Corporation the right to "work" the property (lease) to explore for, develop, produce and market the leased substances.

Reserves Categories

"Proved Reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered will exceed the estimated Proved Reserves.

"Probable Reserves" are those additional reserves that are less certain to be recovered than Proved Reserves.  It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable Reserves.

"Possible Reserves" are those additional reserves that are less certain to be recovered than Probable Reserves.  It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated Proved plus Probable plus Possible Reserves.

Development and Production Status

Each of the reserves categories (Proved, Probable and Possible) may be divided into developed and undeveloped categories:

"Developed Reserves" are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production.  The developed category may be subdivided into Producing and Non-Producing.

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·

- "Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate.  These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
- "Developed Non-Producing Reserves" are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

"Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production.  They must fully meet the requirements of the reserves classification (Proved, Probable, Possible) to which they are assigned.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest-level sum of individual entity estimates for which reserves estimates are presented).  Reported reserves should target the following levels of certainty under a specific set of economic conditions:

- at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated Proved Reserves;
- at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable Reserves; and
- at least a 10 percent probability that the quantities actually recovered will equal the sum of the estimated Proved plus Probable plus Possible Reserves.

Description of Price and Cost Assumptions

"Constant prices and costs" means prices and costs used in an estimate that are:

(i)

the Corporation's prices and costs as at December 31, 2004, held constant throughout the estimated lives of the properties to which the estimate applies; and

(ii)

if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices or costs referred to in paragraph
(i).

"Forecast prices and costs" means future prices and costs that are:

(i)

generally accepted as being a reasonable outlook of the future; and

(ii)

if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices or costs referred to in paragraph
(i).

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FORWARD LOOKING STATEMENTS

Certain statements contained in this Annual Information Form constitute forward-looking statements. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Corporation believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual Information Form.

In particular, this Annual Information Form contains forward-looking statements pertaining to the following:

- the quantity of oil and natural gas reserves;
- crude oil, natural gas and natural gas liquids production levels;
- capital expenditure programs;
- projections of market prices and costs;
- supply and demand for crude oil, natural gas and natural gas liquids;
- expectations regarding the ability of the Corporation and its subsidiaries to raise capital and to continually add to reserves through acquisitions and development; and
- treatment under governmental regulatory regimes and tax laws.

The actual results of the Corporation and its subsidiaries could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Annual Information Form:·

- volatility in market prices for crude oil, natural gas and natural gas liquids;
- liabilities inherent in oil and natural gas operations;
- uncertainties associated with estimating oil and natural gas reserves;
- competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;
- incorrect assessments of the value of acquisitions;
- geological, technical, drilling and processing problems; and
- the other factors discussed under "Risk Factors" in this Annual Information Form.

These factors should not be construed as exhaustive.



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GENTRY RESOURCES LTD.Annual Information Form for the Year Ended December 31, 2004

CORPORATE STRUCTURE

Gentry was incorporated under the CBCA and was amalgamated under the CBCA on June 29, 1981 as Sasko Oil & Gas Limited. The name was changed to Gentry Resources Ltd. on October 29, 1990, at which time it consolidated its Common Shares on the basis of one post-consolidation share for every five pre-consolidation shares.  Gentry is extra-territorially incorporated in British Columbia, Alberta, Saskatchewan, and Manitoba.

On June 4, 1999, Gentry's shareholders approved a special resolution to amend Gentry's share capital structure.  In summary, the Class "A" shares, of which none were issued, were deleted; the Class "B" shares were reclassified to Common Shares having one vote per share (the "Common Shares"); and the Preferred Shares, Series 1, of which none were issued, were deleted.  The TSX, where Gentry's stock is listed for trading, approved the substitutional listing of the Common Shares, and to effect the change from Class "B" to Common Shares, Gentry's trading symbol was changed from "GNY.B" to "GNY".

The head office and registered office of Gentry is located at Suite 2500, 101  6th Avenue SW, Calgary, Alberta, T2P 3P4.

Gentry currently has one wholly-owned active subsidiary, Gentry Resources (Saskatchewan) Ltd., and two wholly-owned inactive subsidiaries, Gentry Resources (West Africa) Inc., and Gentry Income Funds Inc., all of which were incorporated under the ABCA.  Gentry also owns a 13% interest in the outstanding common equity of Stratic Energy Corporation ("Stratic"), a TSX Venture Exchange listed company which was continued under the Yukon Act.  The following chart outlines the corporate structure of Gentry.







GENERAL DEVELOPMENT OF THE BUSINESS

Gentry is an independent Alberta oil and gas company which carries on the business of exploring, developing, acquiring, and producing petroleum and natural gas reserves in Alberta, Saskatchewan and Manitoba.  Gentry's focus is to find high quality long life reserves which management believes have significant potential for increased production through infill drilling and enhanced recovery programs.  Its strategy is to engage in low to medium risk exploration and development activities complimented by selective acquisitions in the western Canadian sedimentary basin.  Gentry also participated, through its investment in Stratic, in medium to higher risk international exploration projects.

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Gentry's Development over the Last Three Years

Developments in 2002

During 2002, Gentry concentrated its exploration efforts on four core areas  Princess, Tide Lake, Sedalia and Whitecourt.  The first three areas are located in southeast Alberta, while Whitecourt is in the west central portion of Alberta.

Gentrys drilling programs at Princess yielded seven Pekisko pool discoveries, representing an 89% success rate.  Gentry then stepped out from Princess to an adjacent area known as Tide Lake where two new 3D surveys were approved to help delineate locations for a 2003 drilling program.

Another new Gentry-operated core area was created at Sedalia, about 80 kilometres north of Princess.  Gentry acquired interests in 22 sections of land at Sedalia along with access to a significant database of 2D seismic data.

Whitecourt, located in west-central Alberta, became the Corporations newest core area, established following a new oil pool discovery in December, in which Gentry holds a 50% working interest.

In December 2002, Gentry completed a private placement of 1,000,000 flow-through shares at a price of $1.65 per share and 1,000,000 units at $1.40 per unit for gross proceeds of $3,050,000.  Each unit consisted of one common share and one-half of a share purchase warrant, with each whole warrant entitling the holder to acquire an additional common share at a price of $1.75 per share until June 17, 2004.  These funds were utilized to help fund the Corporation's 2003 capital exploration program.

Developments in 2003

During 2003, Gentry continued to concentrate its exploration efforts on its four core areas  Princess, Tide Lake, Sedalia and Whitecourt.

At Princess, construction of an 11.2 kilometre pipeline to bring the Nisku discovery well on production at a rate of 2.2 mmcf/d began.  Gross production from the Pekisko project at year-end was 1,000 bbls/d and over 1.0 mmcf/d of associated gas from six wells.

At Tide Lake, two separate 3D programs were shot encompassing 70 sq. km. Gentry drilled six wells including a successful horizontal well into the Pekisko and two successful Mannville wells. An aggressive land acquisition gave Gentry control of 36 sections at working interests ranging from 50% to 100%.

At Sedalia, 15 wells (12.4 net) were drilled in 2003, resulting in 11 gas wells. Gentry aggressively moved forward to acquire land immediately offsetting the Sedalia area. Thirty-seven sections ranging from 50% to 100% working interest have been acquired west of the initial Sedalia activity, while another 19 sections came under Gentrys control east of Sedalia at a 25% to 100% working interest position.

At Whitecourt, 12 wells (4.5 net) were drilled in 2003 and into the first quarter of 2004, with nine yielding gas. Gentry controls 48 sections of land primarily in the Goodwin, Windfall and Blueridge sub-areas.

On October 30, 2003, Gentry completed an equity offering of 3,000,000 common shares at a price of $1.75 per common share for total gross proceeds of $5,250,000.  The proceeds from this financing were utilized to fund the continued exploration and development of Gentry's oil and natural gas properties, including acquisitions, and proceeds were used to temporarily reduce indebtedness until required for those purposes.

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Developments in 2004

Exploration success at Princess led to the development of two new fields in 2004, the Nisku gas field and the Tilley oil field.  Gentry increased its land position in Princess to 170 gross sections, largely through a $16.25 million acquisition in September that included approximately 275 boe/d of production and two large blocks of land totalling 155 sections.

The lands are Grant Landsand as such have no expiration of the mineral rights for lands that are not on production.  The lands are split between two land blocks. The larger of the two is at Bantry comprising 124 sections of land, of which the Company owns an average of 75% or 93 net sections.  The mineral interests held on these lands include rights below the basal Mannville, or more specifically, all Paleozoic rights.  The second land block is at Princess (just north of Bantry) where Gentry has acquired 31 sections of land, of which the Company controls an average of 86% or 27 net sections.  Similar to Bantry, the mineral rights included in the Princess area are rights below the basal Mannville.  The cost of this transaction was financed in part through the $12.5 million financing completed in the second quarter as well as through bank credit facilities.

In the Tide Lake/West Tide Lake area, Gentrys drilling program yielded two Pekisko oil pools as well as significant sweet gas production.  Construction of a sweet gas pipeline and a gas plant was completed in December to help alleviate facility restrictions that were plaguing the area in 2004.

Sedalia saw major expansion in 2004 as Gentry increased its landholdings to 115 sections, with an average working interest of 85%.  2004 production averaged 2.5 mmcf/d and was facility restricted at 3 to 3.5 mmcf/d at year-end.

In 2004, production from Whitecourt averaged 587 mcf/d.  A total of 60 sq. km. of 3D seismic data was acquired and eight wells (3.5 net) were drilled with a success rate of 75%.

RECENT DEVELOPMENTS

In November, 2004 the Corporation entered into a letter agreement to acquire certain oil and natural gas interests in the Princess area for $8.08 million.  The interests include approximately 195 boe/d of production, all of which is operated by Gentry.  The transaction closed on March 24, 2005.

DESCRIPTION OF THE BUSINESS

General

The Corporation's principal properties are located in western Canada in the southern portions of Alberta, Saskatchewan, and Manitoba.  Gentry's strategy is two-fold: first, to find high quality, long life reserves which management believes have significant potential for increased production through infill drilling and enhanced recovery programs; and second, to engage in low to medium risk exploration and development activities complimented by selective acquisitions in the Western Canadian Sedimentary Basin.

Gentry holds a 13% interest in Stratic, which participates in oil and gas exploration and development activities in Turkey, Africa, the U.K. North Sea, and Syria

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Principal Producing Properties

The following is a description of Gentry's principal producing oil and gas properties as of December 31, 2004.

Readers are directed to the definitions of "company interest," "gross," "net" and other defined terms and disclosure regarding the Corporation's operations and resources under "Presentation of Gentry's Oil and Natural Gas Reserves and Production Information" in this Annual Information Form.  In particular, unless otherwise indicated as "gross" or "net," all estimates of oil and natural gas reserves and production are presented on a "company interest" basis.

Alberta

Bantry

The Bantry area is located approximately nine kilometres north of Brooks in south-eastern Alberta.  Gentry owns a 50% interest in one well and a 38.67% interest in a second well.  Natural gas production for 2004 averaged approximately 111 mcf/d.

Joffre

The Joffre area is located approximately 10 kilometres southeast of Red Deer in south central Alberta.  Gentry owns interests varying between 10% to 40% in the area. Production from the area averaged 8 bbls/d and 173 mcf/d in 2004.

Princess

The Princess lands are located approximately 30 kilometres east of Brooks, in southeast Alberta.  Gentry owns interests ranging between 28% and 100%in the area. 2004 production averaged 279 bbls/d and 1,554 mcf/d.

Red Rock

The Red Rock area is located approximately 50 kilometres south of Grande Prairie, in west-central Alberta.  Gentry owns a 3.35564% working interest in the Red Rock Chinook Unit No. 1 plus various working interests ranging from a 0.78125% working interest to a 25.0% working interest in non-unit lands in the Red Rock area.  The Red Rock Chinook Unit No. 1 and non-unit lands produced an average of 8 bbls/d of crude oil and 87 mcf/d of natural gas in 2004.

Red Willow

The Red Willow lands are located approximately 270 kilometres northeast of Stettler, in east central Alberta.  Gentry owns interests ranging between 23.56% and 100% the area.  2004 production averaged 1.15 mmcf/d.

Red Willow North

The Red Willow North property is located approximately 25 kilometres southeast of Vegreville, Alberta.  Gentry owns a 40.4% interest in a producing gas well that produced an average of 259 mcf/d in 2004, despite being on production for less than half the year.

Sedalia

The Sedalia lands are located approximately 25 kilometres west of Oyen, in southeast Alberta.  Gentry owns interests ranging between 50% and 100% in the area.  Production in 2004 averaged 2.51
mmcf/d.



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Thornbury

The Thornbury area is located approximately 100 kilometres southwest of Fort McMurray in northeastern Alberta.  Gentry owns an 18.333% working interest in the area. Natural gas production for 2004 averaged approximately 218 mcf/d.

West Provost Viking Gas Unit

The West Provost Viking Gas Unit is located approximately 20 kilometres southeast of Coronation in east central Alberta.  Gentry owns a 27.34% interest in the Unit. For 2004, production averaged 609 mcf/d.

West Provost Non-Unit Lands

The West Provost Non-Unit Lands are located approximately 20 kilometres southeast of Coronation in east central Alberta.  Gentry owns interest varying between 18.275% to 45% in the area. Production from the area averaged approximately 61 bbls/d in 2004.

Whitecourt

The Whitecourt lands are located west-central Alberta.  Gentry owns interests ranging between 20% and 50%.  Production in 2004 averaged 587 mcf/d.

Saskatchewan

Baldwinton

The Baldwinton property is located approximately 70 kilometres southeast of Lloydminster. Gentry holds a 30.5% working interest in the area. Production from this area averaged approximately 126 bbls/d of crude oil in 2004.

Benson

The Benson area is located approximately 160 kilometres southeast of Regina.  Gentry has a 10.9153% working interest and a gross overriding royalty interest of 0.07% in the Benson Unit.Gentry also has royalty interests of 1.875% and 25% of 1/150 (5-15%) respectively in two wells just outside the Unit.  The wells in this Unit produce primarily from the Midale formation.  Production from this area in 2004 was approximately 84 bbls/d of crude oil.

Dollard

The Dollard area is located approximately 300 kilometres west-southwest of Regina.  Gentry has a 3.853% working interest in the Dollard Unit and a gross overriding royalty of approximately 1.5% in the East Dollard Voluntary Unit.  Production from these units averaged 89 bbls/d of crude oil in 2004.

Steelman

The Steelman area is located approximately 180 kilometres southeast of Regina.  Gentry owns interests in three units in the Steelman area, being units 1A, 4 and 5.

In the Steelman Unit 1A, Gentry holds a 2.707% working interest in the Unit. Production from this unit in 2004 was approximately 15 bbls/d of crude oil and 9 mcf/d of natural gas.

In the Steelman Unit 4, Gentry holds a 13.938% working interest in approximately the Unit.  Production from this unit was approximately 74 bbls/d of crude oil and 44 mcf/d of natural gas in 2004.

In the Steelman Unit 5, Gentry holds a 19.927% working interest in the Unit. Production from this unit was 23 bbls/d of crude oil and 11 mcf/d of natural gas in 2004.



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Manitoba

Virden Roselea

The Virden Roselea area is located in southwestern Manitoba.  Gentry owns a 10.629% working interest in the Virden Roselea Unit No. 1.  Gentrys share of production for the unit in 2004 averaged approximately 46 bbls/d of crude oil.

Summary of Production from Principal Producing Properties

During the year ended December 31, 2004, on a BOE basis, 75.7% of the Corporation's production was derived from Alberta, 22.1% from Saskatchewan and 2.2% from Manitoba.  The following table describes the Corporation's major properties and the averagedaily production from these properties during the year ended December 31, 2004.

|                             | Product Type                       
|---------------------------- | -----------------------------------
|                             | Light & Medium Crude Oil
(bbls/day)
|Alberta                      |                                    
|Bantry                       | -                                  
|Joffre                       | 8                                  
|Princess                     | 279                                
|Red Rock                     | 8                                  
|Red Willow                   | 4                                  
|Red Willow North             | -                                  
|Sedalia                      | -                                  
|Thornbury                    | -                                  
|West Provost Viking Gas Unit | 1                                  
|West Provost Non-Unit Lands  | 61                                 
|Whitecourt                   | 3                                  
|Other                        | 2                                  
|                             |                                    
|Saskatchewan                 |                                    
|Baldwinton                   | 126                                
|Benson                       | 84                                 
|Dollard                      | 89                                 
|Steelman                     | 113                                
|Other                        | 38                                 
|                             |                                    
|Manitoba                     |                                    
|Virden Roselea               | 46                                 
|                             |                                    
|TOTAL                        | 862                                



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Marketing and Risk Management Arrangements

In 2004, all of Gentry's sales occurred in the Canadian market. The price of oil and gas is deregulated and is negotiated between the producers and suppliers based upon domestic and international economic and market factors (including supply and demand, oil quality, prices for competing oils, distance to market, and value of refined products). Gentry utilizes the services and expertise of various oil and gas marketers to sell its production.  No production is contracted out on terms greater than one year.  Gentry may hedge a portion of its crude oil and/or natural gas production to manage its exposure to fluctuations in the price of the product, although it did not do so in 2004. The Corporation does not currently have a hedging program in place for 2005.

Gentry's operations in Canada render it subject to foreign currency fluctuations, which may materially affect its financial position and results.  Oil is generally sold at prices stated in U.S. dollars, while costs incurred are paid in the currency of the country in which the activities are undertaken.  At the present time, the Canadian dollar trades at a discount to the U.S. dollar, but any change in the exchange ratio could affect profitability.  Gentry does not expect to engage in currency hedging to offset any risk of currency fluctuations.

Oil and Natural Gas Reserves

In the Martin Report, Martin has evaluated all of the crude oil, NGLs and natural gas reserves associated with Gentry's properties effective as of December 31, 2004 in accordance with NI 51-101. There are no reserves evaluated or attributed to Gentrys as a result of its investment in Stratic.

In preparing its report, Martin obtained basic information from Gentry, which included land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts, financial data and future operating plans.  Other engineering, geological or economic data required to conduct the evaluation and upon which the Martin Report is based, was obtained from public records, other operators and from Martin's non-confidential files.  Information concerning the extent and character of ownership of Gentry's interests and the accuracy of all factual data supplied to Martin by third parties was accepted by Martin as represented.

The following is a summary, as at December 31, 2004, of the crude oil, NGLs and natural gas reserves of Gentry and the net present value of the estimated future net revenue ascribed to such reserves as evaluated in the Martin Report, based on both forecast and constant price and cost assumptions. All future net revenues are stated prior to provision for interest, future site restoration and reclamation costs, income taxes, general and administrative expenses and indirect costs and after deduction of royalties and estimated future capital expenditures. It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of Gentry's  crude oil, NGLs and natural gas reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. Readers should review the definitions and information contained in "Presentation of Gentry's Oil and Natural Gas Reserves and Production Information" in conjunction with the following tables and notes. Columns may not add due to rounding.



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Summary of Reserves & Future Net Revenue

The following is a summary of oil and natural gas reserves and net present values of future net revenue as of December 31, 2004:



Forecast Prices and Costs



|                                    | Light & Medium Oil | Natural Gas | Total       
|----------------------------------- | ------------------ | ----------- | ------------
|Reserves Category                   | Gross
(mbbls)      | Net
(mbbls) | Gross
(mmcf)
|Proved Reserves                     |                    |             |             
|Proved Developed Producing          | 2,195              | 1,891       | 14,597      
|Proved Developed Non-Producing      | 193                | 161         | 1,167       
|Proved Undeveloped Reserves         | 27                 | 22          | 210         
|Total Proved                        | 2,415              | 2,074       | 15,974      
|                                    |                    |             |             
|Probable Reserves                   |                    |             |             
|Probable Developed                  | 939                | 779         | 8,138       
|Probable Undeveloped                | 217                | 176         | 6,309       
|Total Probable                      | 1,156              | 955         | 14,447      
|                                    |                    |             |             
|Total Proved Plus Probable Reserves | 3,571              | 3,029       | 30,421      









| |  |  |  |  | 
| |  |  |  |  | 

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Constant Prices and Costs



|                                    | Light & Medium Oil | Natural Gas | Total       
|----------------------------------- | ------------------ | ----------- | ------------
|Reserves Category                   | Gross
(mbbls)      | Net
(mbbls) | Gross
(mmcf)
|Proved Reserves                     |                    |             |             
|Proved Developed Producing          | 2,242              | 1,941       | 14,629      
|Proved Developed Non-Producing      | 193                | 161         | 1,167       
|Proved Undeveloped Reserves         | 27                 | 22          | 215         
|Total Proved                        |                    |             |             
|                                    |                    |             |             
|Probable Reserves                   |                    |             |             
|Probable Developed                  | 890                | 751         | 8,143       
|Probable Undeveloped                | 217                | 177         | 6,308       
|Total Probable                      | 1,107              | 928         | 14,451      
|                                    |                    |             |             
|Total Proved Plus Probable Reserves | 3,569              | 3,052       | 30,461      





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Additional Information Concerning Future Net Revenue

The undiscounted total future net revenue by reserves categories as of December 31, 2004, using both constant and forecast prices and costs, is set forth below:



|                                       | Constant Prices & Costs | Forecast Prices & Costs      
|-------------------------------------- | ----------------------- | -----------------------------
|($thousands)                           | Proved Reserves         | Proved Plus Probable Reserves
|Revenue                                | 197,783                 | 335,017                      
|Royalties                              | (37,521)                | (66,697)                     
|Operating costs                        | (51,029)                | (73,915)                     
|Development Costs                      | (1,364)                 | (5,618)                      
|Abandonment and Reclamation Costs      | (1,568)                 | (1,795)                      
|Future Net Revenue Before Income Taxes | 106,301                 | 186,992                      
|Income Taxes                           | (19,476)                | (47,478)                     
|Future Net Revenue After Income Taxes  | 86,825                  | 139,514                      



The net present value of future net revenue by reserves category and production group as of December 31, 2004, using both constant and forecast prices and costs and discounted at 10% per year, is set forth below:



|                              |                               | Future Net Revenue
(Discounted at 10%/year)
|----------------------------- | ----------------------------- | -------------------------------------------
|Reserves Category             | Production Group              | Constant Prices and Costs ($000s)          
|Proved Reserves               | Light and Medium Crude Oil(a) | 29,533                                     
|                              | Natural Gas(b)                | 38,543                                     
|                              |                               |                                            
|Proved Plus Probable Reserves | Light and Medium Crude Oil(a) | 44,466                                     
|                              | Natural Gas(b)                | 82,939                                     



(a)

Includes solution gas and other by-products.

(b)

Includes by-products but excludes solution gas from oil wells.



The volume of gross Proved plus Probable production estimated by Martin for 2005 in preparing the estimated net present values of future net revenue is as follows.

|Product Type               | Aggregate Estimated
2005 Production | Daily Estimated
2005 Production
|-------------------------- | ----------------------------------- | -------------------------------
|Light and medium crude oil | 340 bbbls                           | 932 bbls/d                     
|Natural gas                | 3,041 mmcf                          | 8,332 mcf/d                    
|Total                      | 847 mboe                            | 2,321
    boe/d                



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Pricing Assumptions

The forecast price and cost case assumes the continuance of current laws and regulations. Oil prices attributable to Gentry have been adjusted from Martins reference prices below for quality while gas prices have been adjusted for heating values. Gentrys weighted average oil and liquids price realized in 2004 was Cdn $42.88/bbl, while the gas price was Cdn $6.58/mcf.



|           | Crude Oil                      | Natural Gas                           | Exchange Rate                      | Inflation Rate         
|---------- | ------------------------------ | ------------------------------------- | ---------------------------------- | -----------------------
|Year       | WTI Cushing Oklahoma
($US/bbl) | Edmonton Par Price 40° API
($Cdn/bbl) | Hardisty Medium 25° API
($Cdn/bbl) | Spot Price
($Cdn/mmbtu)
|2005       | 42.00                          | 51.83                                 | 45.98                              | 6.62                   
|2006       | 38.00                          | 47.10                                 | 41.40                              | 6.47                   
|2007       | 35.00                          | 43.90                                 | 38.30                              | 6.22                   
|2008       | 32.00                          | 40.00                                 | 34.50                              | 5.72                   
|2009       | 32.00                          | 40.00                                 | 34.50                              | 5.47                   
|2010       | 32.00                          | 40.00                                 | 34.50                              | 5.22                   
|2011       | 32.00                          | 40.00                                 | 34.50                              | 5.32                   
|2012       | 32.00                          | 40.00                                 | 34.50                              | 5.42                   
|2013       | 32.50                          | 40.70                                 | 35.20                              | 5.52                   
|2014       | 33.00                          | 41.30                                 | 35.80                              | 5.62                   
|2015       | 33.50                          | 41.90                                 | 36.40                              | 5.72                   
|Thereafter | 2.0%                           | 2.0%                                  | 2.0%                               | 2.0%                   



The constant price and cost case assumes the continuance of produce prices at December 31, 2004 and operating costs projected for 2005, and the continuance of current laws and regulations.  Product prices have not been escalated beyond this date nor have operating and capital costs been increased on an inflationary basis.  The future net revenue to be received from the production of the reserves was based on the following prices and assumptions in effect as of December 31, 2004.



|Crude Oil                      | Natural Gas                           | Exchange Rate                      | Inflation Rate         
|------------------------------ | ------------------------------------- | ---------------------------------- | -----------------------
|WTI Cushing Oklahoma
($US/bbl) | Edmonton Par Price 40° API
($Cdn/bbl) | Hardisty Medium 25° API
($Cdn/bbl) | Spot Price
($Cdn/mmbtu)
|43.65                          | 48.90                                 | 33.21                              | 5.94                   



Reconciliation of Reserves

The following tables reconcile the Corporation's oil and natural gas reserves (on both a gross and net basis) from December 31, 2003 to December 31, 2004, using forecast prices and costs.



Reconciliation of Gross Reserves



|                    | Light and Medium Crude Oil | Natural Gas      | Total                    
|------------------- | -------------------------- | ---------------- | -------------------------
|Factors             | Proved
(mbbls)             | Probable
(mbbls) | Proved & Probable
(mbbls)
|December 31, 2003   | 2,120                      | 1,027            | 3,147                    
|Acquisitions        | 222                        | 149              | 370                      
|Dispositions        | -                          | -                | -                        
|Extensions          | -                          | 69               | 69                       
|Technical Revisions | 228                        | (171)            | 57                       
|Discoveries         | 159                        | 82               | 241                      
|Economic Factors    | -                          | -                | -                        
|Improved Recovery   | -                          | -                | -                        
|Production          | (315)                      | -                | (315)                    
|December 31, 2004   | 2,415                      | 1,156            | 3,570                    





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Reconciliation of Net Reserves



|                    | Light and Medium Crude Oil | Natural Gas      | Total                    
|------------------- | -------------------------- | ---------------- | -------------------------
|Factors             | Proved
(mbbls)             | Probable
(mbbls) | Proved & Probable
(mbbls)
|December 31, 2003   | 1,831                      | 847              | 2,678                    
|Acquisitions        | 179                        | 121              | 300                      
|Dispositions        | -                          | -                | -                        
|Extensions          | -                          | 56               | 56                       
|Technical Revisions | 184                        | (139)            | 46                       
|Discoveries         | 128                        | 67               | 195                      
|Economic Factors    | -                          | -                | -                        
|Improved Recovery   | -                          | -                | -                        
|Production          | (248)                      | -                | (248)                    
|December 31, 2004   | 2,075                      | 952              | 3,028                    



Reconciliation of Changes in Net Present Value of Future Net Revenue

The following table sets forth a reconciliation of changes in the net present value of estimated future revenues associated with the Corporation's net Proved Reserves from December 31, 2003 to December 31, 2004 using constant prices and costs and discounted at 10% per year.



|Period and Factor                                                                                | ($thousands)
|------------------------------------------------------------------------------------------------ | ------------
|Estimated Future Net Revenue at December 31, 2003                                                | 33,643      
|Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties | (18,180)    
|Net Change in Prices, Production Costs and Royalties related to Future Production                | (25,185)    
|Changes in Previously Estimated Development Costs Incurred During the Period                     | 21          
|Changes in Estimated Future Development Costs                                                    | (910)       
|Extension and Improved Recovery                                                                  | -           
|Discoveries                                                                                      | 23,641      
|Acquisitions of Reserves                                                                         | 18,844      
|Disposition of Reserves                                                                          | (102)       
|Net Change Resulting from Revisions in Quantity Estimates                                        | 23,260      
|Accretion of Discount                                                                            | 3,205       
|Net Change in Income Taxes(1)                                                                    | (1,041)     
|Estimated Future Net Revenue at December 31, 2004                                                | 57,196      



Note:

(1)  The difference between forecast income taxes at beginning of period and forecast income taxes at end of period.



Undeveloped Reserves

The following table discloses the gross volumes of undeveloped reserves, using constant prices and costs, of the Corporation as at December 31, 2004 that were first attributable to the Corporation in the following years:



|     | Proved Undeveloped Reserves        | Probable Undeveloped Reserves
|---- | ---------------------------------- | -----------------------------
|     | Light and Medium Crude Oil
(mbbls) | Natural Gas
(mmcf)           
|2003 | -                                  | -                            
|2004 | 27                                 | 215                          
|     | 27                                 | 215                          



Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.





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The Corporations proved undeveloped reserves are generally developed within 12 months and as such, the Corporation anticipates the necessary expenditures to develop these reserves will be incurred prior to 2006.



The Corporations probable undeveloped reserves are dominated by the requirement for additional sour gas processing facilities in the Princess area. The Corporation anticipates additional sour capacity will be built in this area prior to 2006, thereby developing these reserves in 2005.



Future Development Costs

The amount of development costs deducted in the estimated net present value of future net revenue is as follows:



|($000s)   | Constant Prices and Costs | Forecast Prices and Costs
|--------- | ------------------------- | -------------------------
|          | Proved Reserves           | Proved Reserves          
|Year      | Undiscounted              | Discounted at 10% /year  
|2005      | 1,364                     | 1,240                    
|2006      | -                         | -                        
|2007      | -                         | -                        
|2008      | -                         | -                        
|2009      | -                         | -                        
|Remaining | -                         | -                        
|          | 1,364                     | 1,240                    



The Corporation expects to fund these development costs through its internally generated cash flow.



Oil and Natural Gas Wells and Properties

The following table summarizes, as at December 31, 2004, Gentry's interests in producing wells and in non-producing wells which were not producing, but may be capable of production.  Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the proportion of oil or natural gas production.



|             | Producing Wells | Shut-In Wells
|------------ | --------------- | -------------
|             | Oil             | Natural Gas  
|             | Gross           | Net          
|Alberta      | 35              | 25           
|Saskatchewan | 1,260           | 58           
|Manitoba     | 30              | 3            
|Total        | 1,325           | 86           



The Corporation also maintains varying interests in batteries, compressor stations and gas plants in the Princess, Sedalia and Red Willow areas.  The total number of net facilities owned by Gentry is 3.2.



Unproved Properties

The following table summarizes Gentrys interests in unproved properties:

|               | Developed | Undeveloped | Total  
|-------------- | --------- | ----------- | -------
|               | Gross     | Net         | Gross  
|Alberta        | 112,585   | 48,612      | 212,371
|Saskatchewan   | 11,758    | 5,659       | 4,043  
|Manitoba       | 320       | 241         | -      
|Western Canada | 124,663   | 54,512      | 216,414
|Quebec         | -         | -           | 376,920
|Total          | 124,663   | 54,512      | 593,334





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Gentry expects its rights to explore and develop on approximately Nil net acres to expire prior to December 31, 2005.  Gentry has no material work commitments on such properties and, where Gentry determines appropriate, it can continue the leases by either making the necessary applications or performing the necessary work.

Exploration and Development Activities

During 2004, Gentry participated in the drilling of 52 gross wells (33.5 net) with an 85% success rate (86% net).  The majority of Gentry's 2004 wells were drilled in Princess and Sedalia. The following table summarizes the number and type of wells that Gentry drilled or participated in the drilling of for the year ended December 31, 2004.



|                        | Number of Exploration Wells | Number of Development Wells | Total Wells
|----------------------- | --------------------------- | --------------------------- | -----------
|Category of Well        | Gross                       | Net                         | Gross      
|Crude oil wells         | 4                           | 3.0                         | 9          
|Natural gas wells       | 23                          | 15.7                        | 8          
|Capped Wells            | -                           | -                           | -          
|Dry and abandoned wells | 8                           | 4.7                         | -          
|Total                   | 35                          | 23.4                        | 17         



Gentry currently intends to focus its development activities in the Western Canadian Sedimentary Basin. Gentry's exploration and development activities are typically funded through debt, internally generated cash flow and issuances of Common Shares.

Quarterly Production History

The following table sets forth Gentry's average daily production volumes, on a company interest basis, for each fiscal quarter in 2004 and for the entire year.



|                              | Year Ended December 31, 2004
|----------------------------- | ----------------------------
|                              | First Quarter               
|Light and medium oil (bbls/d) | 870                         
|Natural gas (mcf/d)           | 6,919                       
|Total (boe/d)                 | 2,023                       



Quarterly Netback History

The following tables set forth Gentry's average netbacks received for each fiscal quarter in 2004 and for the entire year (excluding any hedging gains or losses). Netbacks are calculated on the basis of prices received before hedging on sales volumes, less related royalties and related production costs. For multiple product well types, production costs are entirely attributed to that wells principal product type.



|                              | Year Ended December 31, 2004
|----------------------------- | ----------------------------
|Light and medium oil (bbls/d) | First Quarter               
|Sales price                   | 39.07                       
|Royalties                     | (8.06)                      
|Production costs(1)           | (11.04)                     
|Netback                       | 19.97                       



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|                    | Year Ended December 31, 2004
|------------------- | ----------------------------
|Natural gas (mcf/d) | First Quarter               
|Sales price         | 6.31                        
|Royalties           | (1.04)                      
|Production costs(1) | (1.14)                      
|Netback             | 4.13                        



|                    | Year Ended December 31, 2004
|------------------- | ----------------------------
|Total (boe/d)       | First Quarter               
|Sales price         | 38.38                       
|Royalties           | (7.02)                      
|Production costs(1) | (8.64)                      
|Netback             | 22.72                       



Note:

(1)

Production costs are costs incurred to operate and maintain wells and related equipment and facilities, including operating costs of support equipment used in oil and gas activities and other costs of operating and maintaining those wells and related equipment and facilities.  Examples of productions costs include items such as field staff labour costs, costs of materials, supplies and fuel consumed and supplies utilized in operating the wells and related equipment (such as power, chemicals and lease rentals), repairs and maintenance costs, property taxes,
insurance costs, costs of work-overs, processing and treating fees, overhead fees, taxes (other than income and capital taxes) and other costs.

Abandonment and Reclamation Costs

The Corporation is liable for ongoing environmental obligations and for the ultimate abandonment and reclamation costs for its natural gas and petroleum properties (including surface leases, wells, facilities and pipelines) upon abandonment. The Corporation identifies obligations related to petroleum and natural gas properties by estimating the present value of expected future costs to reclaim and abandon these properties and the timing of the costs to be incurred in future periods.  These estimates are currently based on 165 net wells and 3.2 net facilities in respect of which the Corporation expects to incur such costs.  The Corporation anticipates the total inflated amount of such costs to be approximately $5.0 million on an undiscounted basis and $1.8 million discounted at 10%.  Of this amount, the Corporation anticipates that approximately $300,000 will be incurred in the next three financial years.

Ongoing environmental obligations will generally be funded out of cash flow.

The estimates of total Proved Reserves associated with the Principal Producing Properties and the present worth of future net cash flows from such reserves contained in the Martin Report (based on forecast prices and costs on an undiscounted basis) include expenditures of approximately $1.9 million associated with the abandonment of current producing and future wells but do not include any provision for non-producing wells or facility abandonment and site restoration costs.

Tax Horizon

The Corporations wholly owned subsidiary Gentry Resources (Saskatchewan) Ltd. was required to pay income taxes in 2004.  It is anticipated that Gentry Resources (Saskatchewan) Ltd. will be liable for income taxes in 2005.  Based on a model of reinvesting cash flow at industry average efficiency rates, the Corporation anticipates it will be required to pay income taxes in 2005.





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Costs Incurred

The following tables summarize capital expenditures (net of certain proceeds and including capitalized general and administrative expenses) related to the Corporations activities for the year ended December 31, 2004:



|                         | ($thousands)
|------------------------ | ------------
|Drilling and completions | 11,773.5    
|Facilities and equipping | 6,403.3     
|Land and seismic         | 7,349.9     
|Acquisitions, net        | 16,580.9    
|Capitalized expenses     | 1,165.3     
|Other                    | 128.5       
|Total                    | 43,401.4    



Environmental and Safety Matters

The Corporation and its subsidiaries conduct their operations with a commitment to the health of their employees and the public, as well as the long-term enhancement and protection of the environment.  The Corporation intends to perform all work safely and to comply with all corporate and regulatory requirements. The Corporation intends to continue to operate in a manner consistent with and, where applicable, build on its existing comprehensive safety, health and environment program, which outlines responsibilities and corporate and regulatory standards, as well as provides tools to assist employees and contractors to work safely and to meet or exceed regulatory requirements.

Insurance

The Corporation carries suitable insurance policies to provide protection for its working interest in its natural gas and petroleum properties. Insurance policies cover property damage and general liability. The ongoing level, type and maintenance of insurance will be determined by the Corporation based upon the availability and cost of such insurance and the Corporation's perception of the risk of loss. See "Risk Factors  Environmental Concerns".

Future Commitments

The Corporation does not currently use any type of financial instruments or fixed price physical sales contracts to manage the risk related to fluctuating commodity prices. Absent such hedging activities, all of the Corporations crude oil and NGLs and  natural gas production is sold into the open market at prevailing spot prices, which exposes the Corporation to the risks associated with commodity price fluctuations and foreign exchange rates. See "Risk Factors".



As at December 31, 2004, the Corporation had the following contractual obligations under office leases, flow-through commitments, firm service transportation agreements, and operating leases:



|($thousands)                | 2005  | 2006  | 2007  | 2008  | Thereafter | Total  
|--------------------------- | ----- | ----- | ----- | ----- | ---------- | -------
|Office lease                | 173.5 | 173.5 | 173.5 | 159.1 | -          | 679.6  
|Flow-through commitments    | 320.0 | -     | -     | -     | -          | 320.0  
|Firm service transportation | 56.9  | 56.9  | 56.9  | -     | -          | 170.7  
|Operating lease             | 23.0  | -     | -     | -     | -          | 23.0   
|                            | 573.4 | 230.4 | 230.4 | 159.1 | -          | 1,193.3



Human Resources

At December 31, 2004, the Corporation had 20 employees.





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DIVIDENDS

The Corporation has not paid dividends on the Common Shares and does not expect to pay any dividends in the foreseeable future as it intends to reinvest any earnings to fund the development and growth of its business.  Any future payment of dividends will depend upon the financial condition, capital requirements and earnings of the Corporation, as well as other factors the Corporation's board of directors may deem relevant. See Risk Factors  Absence of Dividends.

DESCRIPTION OF CAPITAL STRUCTURE

The authorized capital of the Corporation consists of an unlimited number of Common Shares and an unlimited number of Preferred Shares.  As at December 31, 2004, there were 38,471,234 Common Shares and no Preferred Shares issued and outstanding.

Common Shares

The holders of Common Shares are entitled to: (i) one vote for each Common Share held at all meetings of shareholders of the Corporation other than meetings of the holders of any class or series of shares meeting as a class or series; (ii) receive any dividends declared by the Corporation on the Common Shares; and (iii) subject to the rights of shares ranking prior to the Common Shares, to receive the remaining property of the Corporation on dissolution, after the payment of all liabilities.

Preferred Shares

The Preferred Shares are issuable in series and the designation of, and the rights or privileges, restrictions and conditions attached to any series of Preferred Shares are to be established by the board of directors of the Corporation prior to the issuance thereof.  The Preferred Shares have a preference over the Common Shares and any class of shares of the Corporation ranking junior to the Preferred Shares with respect to the payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up of the Corporation or any other distribution of the assets of the Corporation among its shareholders for the purpose of winding-up its affairs.

Shareholder Rights Plan

On May 28, 2004, Gentry entered into a Shareholder Rights Plan Agreement (the "Rights Plan") with Computershare Trust Company of Canada, as Rights Agent, which was approved by Gentry's shareholders at the 2004 annual general and special meeting of shareholders.  The Rights Plan generally provides that following any person or entity acquiring 20% or more of the issued and outstanding Common Shares (except pursuant to certain permitted or excepted transactions) and upon the occurrence of certain other events, each holder of Common Shares, other than such person or entity, shall be entitled to acquire Common Shares at a discounted price.  The Rights Plan is similar to other shareholder or unitholder rights plans adopted in the energy sector. A copy of the Rights Plan is available under the Corporations SEDAR profile at www.sedar.com.

Normal Course Issuer Bid

On August 25, 2004 Gentry announced that it intended to purchase up to 2,800,000 Common Shares, representing 10% of its public float, pursuant to a normal course issuer bid to be conducted over the facilities of the TSX.  The bid will expire August 26, 2005 and any Common Shares acquired pursuant to the bid will be cancelled.

Gentry's reasoning for the normal course issuer bid is that from time to time the market price of Gentry's Common shares may not reflect the underlying value of such shares and that, at such times, the purchase of Common Shares for cancellation will increase the proportionate interest of, and be advantageous to, all remaining shareholders.  In addition, any purchases made by Gentry will afford increased liquidity to those shareholders of the Corporation who may wish to



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dispose of their Common Shares. From August 27, 2004 through to March 28, 2005, the Corporation has purchased 147,500 Common Shares at an average price of $3.01 per share under the current normal course issuer bid.  From August 27, 2003 to August 26, 2004, Gentry purchased, pursuant to a previous normal course issuer bid, 292,500 Common Shares at an average price of $1.84 per share.  These shares were subsequently cancelled.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulation imposed by various levels of government. Regulatory approvals must be obtained before drilling wells or constructing facilities. Failure to obtain such approvals on a timely basis could result in delays or abandonment of projects and increased costs.  Although it is not expected that any of these controls or regulations will affect the Corporation's operations in a manner materially different than they would affect other Canadian oil and gas issuers of similar size, the controls and regulations should be considered carefully by investors in the oil and gas industry. All current legislation is a matter of public record and the Corporation is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in western Canada.

Pricing and Marketing - Oil

In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends, in part, on oil type and quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance and other contractual terms. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of light crude, and not exceeding two years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board (the "NEB").  Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

Pricing and Marketing - Natural Gas

In Canada, the price of natural gas sold in intraprovincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on natural gas quality, prices of competing natural gas and other fuels, distance to market, access to downstream transportation, length of contract term, weather conditions, the value of refined products and the supply/demand balance and other contractual terms.  Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 cubic metres per day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere, based on such factors as reserve availability, transportation arrangements and market considerations.

The North American Free Trade Agreement ("NAFTA")

On January 1, 1994, NAFTA became effective among the governments of Canada, the United States of America and Mexico. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; and (iii) disrupt normal channels of supply. All three countries are generally prohibited from imposing minimum export or import price requirements.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. NAFTA also contemplates clearer disciplines on regulators to ensure fair



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implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

Provincial Royalties and Incentives

General

In addition to federal regulations, each province in Canada has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown-owned lands are determined by negotiations between the freehold mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the working interest owners interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties or net profits or net carried interests.

From time to time, the federal and provincial governments in Canada have established incentive programs which have included royalty rate reductions (including far specific wells), royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects, although the trend is toward eliminating these types of programs in favour of long term programs which enhance predictability for producers.  If applicable, oil and natural gas royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers.

Alberta

Regulations made pursuant to the Mines and Minerals Act (Alberta) provide various incentives for exploring and developing oil reserves in Alberta. Oil produced from horizontal extensions commenced at least five years after the well was originally spudded may also qualify for a royalty reduction. A 24 month, 8,000 cubic metre exemption is available for production from a well that has not produced for a 12 month period, if resuming production after February 1, 1993. Additionally, oil production from eligible new field and new pool wildcat wells and deeper pool test wells spudded or deepened after September 30, 1992 is entitled to a 12 month royalty exemption (to a maximum of $1 million). Oil produced from low productivity wells, enhanced recovery schemes (such as injection wells) and experimental projects is also subject to royalty reductions.

In Alberta, the amount payable to the Alberta government as a royalty in respect of oil depends on the type of oil, the vintage of the oil, the quantity of oil produced in a month and the value of the oil. The vintage of oil is determined based on various criteria set out in the regulations, but is generally broken down into three categories being old oil, new oil and third tier oil (which is oil produced form pools discovered after September 30, 1992).  The royalty rate on old oil is between 10% and 35%, for new oil it is between 10% and 30%, and for third tier oil it is between 10% and 25%.

The royalty payable to the Alberta government in respect of natural gas is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the type of natural gas, the quantity produced in a given month and the vintage of the natural gas. The vintage of natural gas is based on various criteria set out in the regulations, but is generally determined based on when the natural gas pools were discovered and natural gas from such pools was recovered.  As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than non-associated natural gas. The royalty payable on natural gas varies between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas. Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 is eligible for a royalty exemption for a period of 12 months, up to a prescribed maximum amount.  Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well.



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In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC program. The ARTC rate is based on a price-sensitive formula and varies between 75% for prices at or below the royalty tax credit reference price of $100 per cubic metre decreasing to 25% for prices above the royalty tax credit reference price of $210 per cubic metre. The ARTC rate will be applied to a maximum annual amount of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlements to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average "par price", as determined by the Alberta Department of Energy for the previous quarterly period. On December 22, 1997, the Alberta Government announced that it would conduct a review of the ARTC program with the objective of setting out better-targeted objectives for a smaller program and to deal with administrative difficulties. On August 30, 1999, the Alberta Government announced that it would not be reducing the size of the program, but that it would introduce new rules to reduce the number of persons who qualify for the program. The new rules will preclude companies that pay less than $10,000 in royalties per year and non-corporate entities from qualifying from the program.

Saskatchewan

In Saskatchewan, the amount payable as a royalty in respect of oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month and the value of the oil. The royalty rate payable for old oil is between 20% and 45%, and for new oil and third tier oil is between 10% and 35%. The royalty payable on natural gas in Saskatchewan is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas and the vintage of the natural gas. As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than non-associated natural gas. The royalty rate payable for old gas is between 20% and 45%, and for new gas and third tier gas is between 15% and 35%.

Effective October 1, 2002, the Saskatchewan government revised its fiscal regime for the oil and gas industry. Some royalties on wells existing as of that date will remain unchanged and will therefore be subject to various periods of royalty/tax deduction. The changes include new lower royalty and tax structures applicable to both oil, natural gas and associated natural gas (natural gas produced from oil wells), a new system of volume incentives and a reduced corporation capital tax resource surcharge rate.

The new fiscal regime for the Saskatchewan oil and gas industry provides an incentive to encourage exploration and development through a revised royalty/tax structure for oil and natural gas wells with a finished drilling date on or after October 1, 2002 or incremental oil production due to a new or expanded waterflood project with a commencement date on or after October 1, 2002. This "fourth tier" Crown royalty rate, applicable to both oil and natural gas, is price sensitive and ranges from a minimum 5% at a base price to a maximum of 30% at a price above the base price. A fourth tier freehold tax structure, calculated by subtracting a production tax factor of 12.5 percentage points from the corresponding Crown royalty rates, has also been created which is applicable to conventional oil, incremental oil from new or expanded waterfloods and natural gas. The fourth tier royalty/tax structure is also applicable in respect of associated natural gas that is gathered for use or sale which is produced either from oil wells with a finished drilling date on or after October 1, 2002 and oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of more than 3,500 cubic metres of natural gas per cubic metre of oil. In addition, volume-based royalty/tax reduction incentives have been changed such that a maximum royalty of 2.5% now applies to various volumes of both oil and natural gas, depending on the depth and nature of the well (up to 16,000 cubic metres of oil in the case of deep exploratory wells and 25,000 cubic metres of natural gas produced from exploratory wells). The royalty/tax category with respect to re-entry and short sectional horizontal oil wells has been eliminated such that all horizontal oil wells with a finished drilling date on or after October 1, 2002 receive fourth tier royalty/tax rates and incentive volumes. Further changes include the reduction of the corporation capital tax resource surcharge rate from 3.6% to 2.0% and, subject to certain restrictions, the expansion of the deep oil well definition to include oil wells producing from a zone deeper than 1,700 meters.



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Land Tenure

Crude oil and natural gas located in the western Canadian provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying periods and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well, pipeline and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures.  A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations and civil liability for pollution damage.

In Alberta, environmental compliance is governed by the Environmental Protection and Enhancement Act (Alberta) and the Oil and Gas Conservation Act (Alberta), both of which impose certain environmental responsibilities on oil and natural gas operators and working interest holders in Alberta and impose penalties for violations. In Saskatchewan, environmental compliance is governed by the Environmental Management and Protection Act (Saskatchewan) and the Oil and Gas Conservation Act (Saskatchewan).

In 1994, the United Nations Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which will require participating countries, upon ratification, to reduce their emissions of carbon dioxide and other greenhouse gases.  Canada ratified the Kyoto Protocol in late 2002.  Although the Canadian federal government has not released details of any implementation plan, it has stated that it intends to limit the emission reduction targets for the industry and the cost of emission credits, which could result in increased capital expenditures and operating costs.

The Corporation believes that it is, and intends to continue to be, in material compliance with applicable environmental laws and regulations and is committed to meeting its responsibilities to protect the environment wherever it operates or holds working interests.  The Corporation anticipates that this compliance may result in increased expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment.  The Corporation believes that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards.

RISK FACTORS

Investors should consider the following risk factors prior to making an investment in the Common Shares or other securities of the Corporation.

Investment in the Common Shares should be considered to be speculative and involve a degree of risk, including, but not necessarily limited to, the risk factors listed below. Owners and prospective purchasers of the Common Shares should carefully consider, in addition to the other information in this Annual Information Form, the following risk factors inherent in and affecting the Corporation's business before making an investment decision.

Industry Risks

There are many risks inherent in the oil and gas industry which even a combination of experience, knowledge and careful evaluation may not be able to overcome.



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The Corporation's success will depend on its ability to select and acquire suitable producing properties or undeveloped exploration prospects.  The marketability of any oil and natural gas acquired or discovered by the Corporation will be affected by numerous factors beyond the control of the Corporation.  These factors include market fluctuations, the world price of crude oil, the continental price of natural gas, the supply and demand for oil and natural gas, the proximity and capacity of oil and natural gas pipelines and processing equipment and government regulations, including regulations relating to prices, taxes, royalties, land tenure, allowable production, the import and export of oil and natural gas and environmental protection.  The effect of these factors cannot be accurately predicted.

Hazards such as unusual or unexpected geological formations, pressures, blow-outs, fires or other conditions may be encountered in drilling and operating wells.  The Corporation will have the benefit of insurance maintained by it; however, the Corporation may become liable for damages arising from pollution, blowouts or other hazards against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons.  Oil and natural gas production operations are also subject to all of the risks typically associated with such operations, including premature decline of reservoirs and invasion of water into formations, which may hinder economic production.

Both oil and natural gas prices are unstable and are subject to fluctuation.  Any material drop in prices could result in a reduction of any future net production revenue of the Corporation.  The economics of producing from wells acquired or drilled by the Corporation may change as a result of lower commodity prices, which could result in a reduction in the volumes of economic reserves of the Corporation.  The Corporation might also elect not to produce from certain wells at lower prices.  Crude oil and natural gas prices are currently at very high levels and may be extremely volatile in the short term.  These factors could result in a material decrease in any future net production revenue of the Corporation, causing a reduction in the Corporation's oil and natural gas acquisition and development activities.

Regulation of Industry

The Corporation's activities are subject to complex and stringent energy, environmental and other governmental laws and regulations.  While management believes that the Corporation's business will be operated in accordance with applicable laws, the Corporation will remain subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce.  Existing laws and regulations may be revised or new laws and regulations may become applicable to the Corporation that may have a negative effect on the Corporation's business and the results of operations. Environmental regulation is becoming increasingly stringent and costs and expenses of regulatory compliance are increasing.  The Corporation expects that it will be able to fully comply with all regulatory requirements in this regard.

Possible Income Tax Changes

There can be no assurance that the income tax laws applicable to the Corporation or to the oil and natural gas industry generally will not be changed in a manner that adversely affects the Corporation or the holders of Common Shares.

Need for Future Financings

Additional financing for new development and operations may not be available on acceptable terms in the future.  Where additional financing is raised by the issuance of Common Shares or securities convertible into Common Shares from the Corporation's treasury, control of the Corporation may change and shareholders may suffer further dilution to their investment.  The issuance of debt may result among other things, in the encumbrance of certain of the Corporation's assets, impede the Corporation's ability to obtain additional bank financing, decrease the Corporation's liquidity and adversely affect the Corporation's ability to declare and pay dividends to its shareholders.





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Property Title

Although title reviews will be done according to industry standards prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of the Corporation, which could result in a reduction of the revenues received by the Corporation.

Recovery and Reserve Estimates

The recovery and reserve estimates of the Corporation's oil and natural gas reserves provided for herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, all of which may vary considerably from actual results.  The Corporation's actual production, revenues, taxes and development and operating expenses and results will vary from estimates contained in the evaluations, and such variations could be material. Actual reserves may be greater or less than the estimates. The Corporation has used both constant and escalated price and costs assumptions in calculating reserve quantities as required by securities disclosure legislation and policies in Canada.  Actual future net cash flows will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption of oil and natural gas, changes in government regulation or taxation and the impact of inflation on costs, among others.

Competition

Competition could adversely affect the Corporation's performance.  The oil and natural gas industry is characterized by intense competition and the Corporation competes directly with other companies that have greater resources. The industry also competes with other industries who supply non-petroleum energy products.

Conflicts of Interest

Certain of the directors of the Corporation may be engaged and will continue to be engaged in certain business interests on their own behalf and on behalf of other companies, and situations may arise where the directors and officers may be in direct competition with the Corporation.  Conflicts of interest, if any, which arise will be subject to and governed by the procedures prescribed by the CBCA.

Reliance on Management

Holders of securities of the Corporation must rely upon the experience and expertise of management.  The Corporation's continued success is dependent upon its ability to attract and retain experienced management.

Absence of Dividends

The Corporation does not anticipate that cash dividends will be paid on its Common Shares in the foreseeable future since the Corporation currently intends to retain any future earnings to finance the expansion and development of its business.  The declaration and payment in the future of any cash dividends will be at the discretion of the Corporation's board of directors and will depend upon the earnings, capital requirements and financial position of the Corporation, future loan covenants, general economic conditions and other pertinent factors.  No assurance can be given that the Corporation will pay any dividends in the future or with respect to the amount of any such.



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MARKET FOR SECURITIES

As at December 31, 2004, 38,471,234 Common Shares were issued and outstanding.  The outstanding Common Shares of the Corporation are listed and posted for trading on the TSX under the symbol GNY.  The following table sets forth certain trading information for the Common Shares of Gentry on the TSX during 2004.



|Month     | High  | Low   | Close | Volume   
|--------- | ----- | ----- | ----- | ---------
|January   | $2.29 | $2.02 | $2.13 | 1,483,647
|February  | $2.15 | $1.91 | $1.97 | 933,398  
|March     | $2.13 | $1.85 | $2.13 | 2,519,917
|April     | $2.19 | $1.95 | $2.00 | 3,360,906
|May       | $2.14 | $2.00 | $2.10 | 1,621,323
|June      | $2.15 | $1.99 | $2.04 | 1,347,625
|July      | $2.26 | $2.04 | $2.20 | 696,528  
|August    | $2.44 | $2.15 | $2.30 | 1,654,345
|September | $2.85 | $2.30 | $2.70 | 1,951,837
|October   | $2.87 | $2.63 | $2.70 | 2,892,654
|November  | $3.54 | $2.33 | $3.30 | 4,269,462
|December  | $3.59 | $2.98 | $3.49 | 2,623,702



DIRECTORS AND OFFICERS

The board of directors of the Corporation is comprised of five members. Each director is appointed to serve until the next annual meeting of the shareholders of the Corporation.  Set forth below for each director and officer of the Corporation is their name, residence, position with the Corporation, date of appointment as a director (if applicable), principal occupation for the past five years, number of Common Shares beneficially owned, directly or indirectly, or over which control or direction is exercised, and number of stock options to acquire Common Shares owned. The terms of each director expires at each annual meeting of the Corporations shareholders or when their successor is duly appointed.

|Name, Residence and Positions held with the Corporation            | Principal Occupation                                                                                   | Director Since | Number of 
Common Shares Beneficially Owned | Common Shares Under Option
|------------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------ | -------------- | ------------------------------------------- | --------------------------
|Hugh G. Ross
Calgary, Alberta, Canada, President, CEO and Director | President and Chief Executive Officer of the Corporation                                               | Feb. 23, 1987  | 1,910,459(5)
168,651(5)
157,483(5)          | 332,500                   
|A.  Bruce Macdonald(1)(2)(4)
Calgary, Alberta, Canada
Director     | President, Stoneyfell Investments Inc., a private oil & gas management consulting company              | Nov. 13, 1995  | 249,250                                     | 207,500                   
|George T. Hawes(1)(3)
Plandome, New York, U.S.A.
Director          | President, G. T. Hawes & Co., Inc. a private real estate company                                       | Dec. 3, 1999   | 729,000                                     | 275,000                   
|Michael Halvorson(1)(2)
Edmonton, Alberta, Canada
Director         | President of Halcorp Capital Ltd., a private company specializing in the raising of investment capital | Aug. 29, 1994  | 562,933                                     | 182,500                   
|Walter O'Donoghue(3)(4)
Calgary, Alberta, Canada
Director          | Former Partner, Bennett Jones LLP, a law firm                                                          | May 29, 1998   | 183,126                                     | 182,500                   



-
24 -

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|Name, Residence and Positions held with the Corporation                                                             | Principal Occupation                                                                         | Director Since | Number of 
Common Shares Beneficially Owned | Common Shares Under Option
|------------------------------------------------------------------------------------------------------------------- | -------------------------------------------------------------------------------------------- | -------------- | ------------------------------------------- | --------------------------
|Ketan Panchmatia
Calgary, Alberta, Canada
Chief Financial Officer, Vice-President, Finance, and Secretary/Treasurer | Chief Financial Officer, Vice-President, Finance, and Secretary/Treasurer of the Corporation | N/A            | 248,218                                     | 200,000                   
|R. Gordon McKay
Calgary, Alberta, Canada
Chief Operating Officer                                                    | Chief Operating Officer of the Corporation                                                   | N/A            | 241,649                                     | 200,000                   
|Robert Poole
Calgary, Alberta, Canada
Vice-President, Operations                                                    | Vice-President, Operations of the Corporation                                                | N/A            | 165,300                                     | 225,000                   
|George Magarian
Calgary, Alberta, Canada
Vice-President, Exploration                                                | Vice-President, Exploration, of the Corporation                                              | N/A            | 0                                           | 200,000                   



Notes:

(1)

Denotes member of Audit and Risk Management Committee.

(2)

Denotes member of Compensation and Human Resources Committee.

(3)

Denotes member of Corporate Governance Committee.

(4)

Denotes member of Reserve Evaluation Committee.

(5)

The 1,910,459 Common Shares are held directly by Mr. Ross. The 168,651 Common Shares are directly owned by Ross Resources Inc., a private company of which Mr. Ross owns 25%. The 157,483 Common Shares are directly owned by an associate of Mr. Ross.



As at March 23, 2005, the directors and officers of the Corporation beneficially owned, directly or indirectly, or exercised control or direction over, in the aggregate, 4,616,059 Common Shares, representing 12% of the issued and outstanding Common Shares of the Corporation.

There are potential conflicts of interest to which the directors and officers of Gentry will be subject to in connection with the operations of Gentry.  Some of the directors may be or may become engaged in other oil and gas industry interests on their own behalf and on behalf of other corporations with which they are associated, and situations may arise where the directors and officers will be in direct competition with Gentry.  Conflicts, if any, will be subject to the procedures and remedies under the CBCA. In accordance with the CBCA, directors who have a material interest in any person who is a party to a material contract or a proposed material contract with Gentry are required, subject to certain exceptions, to disclose that interest and abstain from voting on any resolution to approve the contract.  In addition, the directors are required to act honestly and in good faith with a view to the best interests of Gentry. See "Risk Factors - Conflicts of Interest".

The information regarding the Corporations Audit and Risk Management Committee required to be disclosed under Multilateral Instrument 52-110 of certain Canadian securities regulatory authorities is contained in Exhibit C to this Annual Information Form

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

To the knowledge of the directors and executive officers of the Corporation, none of the directors or executive officers of the Corporation, or any associate or affiliate of the foregoing, has had any material interest, direct or indirect, in any material transaction with the Corporation since January 1, 2002 or in any proposed transaction that has materially affected or will materially affect the Corporation.

INTERESTS OF EXPERTS

Martin prepared the Martin Report dated March 07, 2005 in respect of Gentry's oil and natural gas reserves, summaries of which are contained in this Annual Information Form.  As of the date of the Martin Report, the partners, consultants, and associates of Martin, as a group, beneficially owned, directly or indirectly, less than 1% of the outstanding shares of Gentry.

The auditors of Gentry are Collins Barrow Calgary LLP, Chartered Accountants, Calgary, Alberta. As of March 04, 2005, the date of Collins Barrow Calgary LLP's auditors' report on Gentry's audited consolidated financial statements for the year ended December 31, 2004, the partners of Collins Barrow Calgary LLP, as a group, beneficially owned, directly or indirectly, less than 1% of the outstanding shares of Gentry.



-
25 -

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REGISTRAR AND TRANSFER AGENT

The registrar and transfer agent for the Common Shares of Gentry is Computershare Trust Company of Canada, at its principal offices in Calgary, Alberta and Toronto, Ontario.

ADDITIONAL INFORMATION

Additional information relating to the Corporation may be found on the Corporations company profile on the SEDAR website at www.sedar.com or on the Corporations website at www.gentryresources.com. Additional information, including directors and officers remuneration and indebtedness, principal holders of the Corporation's securities and securities authorized for issuance under equity compensation plans, as applicable, is contained in the Corporation's information circular dated March 23, 2005 for its 2005 annual general and special meeting of Shareholders. Furthermore, additional financial information relating to the Corporation is provided in the Corporation's audited consolidated financial statements and managements discussion and analysis for the year ended December 31, 2004.



-
26 -

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EXHIBIT "A"

REPORT ON RESERVES DATA BY INDEPENDENT 
QUALIFIED RESERVES EVALUATOR OR AUDITOR

Terms to which a meaning is ascribed in Natural Instrument 51-101 have the same meaning herein.

To the board of directors of Gentry Resources Ltd. (the "Corporation"):

1.

We have evaluated the Corporation's reserves data as at December 31, 2004. The reserves data consist of the following:

(a)

i)

proved and proved plus probable oil and gas reserves estimated as at  December 31, 2004 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

ii)

proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and

(ii)

the related estimated future net revenue.

2.

The reserves data are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.

Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement.  An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4.

The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Corporation's board of directors:

|Description and Preparation Date of Evaluation Report | Location of Reserves (Country or Foreign Geographic Area) | New Present Value of future Net Revenue
(before income taxes, 10% discount rate, in $ thousands)
|----------------------------------------------------- | --------------------------------------------------------- | ------------------------------------------------------------------------------------------------
|Audited                                               | Evaluated                                                 | Reviewed                                                                                        
|March 07, 2005                                        | Canada                                                    | $Nil                                                                                            



5.

In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

6.

We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.





A-1

---





7.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

Signed:S. Neil Sedgwick



S. Neil Sedgwick, B.Sc., P.Eng.

Martin & Brusset Associates

Calgary, Alberta, Canada



Dated  March 28, 2005

A-2

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EXHIBIT "B"

REPORT OF MANAGEMENT AND DIRECTORS
ON RESERVES DATA AND OTHER INFORMATION

Terms to which a meaning is ascribed in Natural Instrument 51-101 have the same meaning herein.

Management of Gentry Resources Ltd. (the "Corporation") are responsible for the preparation and disclosure of information with respect to the Corporations oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a)

iii)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and

(ii)

the related estimated future net revenue; and

(b)

iv)

proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and

(ii)

the related estimated future net revenue.

An independent qualified reserves evaluator evaluated the Corporation's reserves data.  The report of the independent qualified reserves evaluator is presented as Exhibit "A" to the Annual Information Form of the Corporation dated March 23, 2005.

The Reserve Evaluation Committee of the board of directors of the Corporation has:

(a)

reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator;

(b)

met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c)

reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserve Evaluation Committee of the board of directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserve Evaluation Committee, approved

(a)

the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;

(b)

the filing of the report of the independent qualified reserves evaluator on the reserves data; and

(c)

the content and filing of this report.



B-1

---





Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

|GENTRY RESOURCES LTD.


Signed:Hugh G. Ross

Hugh G. Ross
President, Chief Executive Officer and Director


Signed:R. Gordon McKay

R. Gordon McKay
Vice-President, Exploration and Operations and
Chief Operating Officer


Signed:Ketan Panchmatia

Ketan Panchmatia
Vice-President, Finance and
Chief Financial Officer


Signed:A. Bruce Macdonald

A. Bruce Macdonald
Director
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





March 28, 2005



B-2

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EXHIBIT "C"

AUDIT COMMITTEE DISCLOSURE PURSUANT

TO MULTILATERAL INSTRUMENT 52-110

THE AUDIT COMMITTEES CHARTER

1.

The objectives of the Committee are:

a)

helping directors discharge their duties and responsibilities, especially accountability;

b)

providing better communication between directors and the external auditor;

c)

enhancing the external auditors independence;

d)

ensuring the credibility and objectivity of financial reports; and

e)

strengthening the role of the external directors by facilitating in depth discussions between the Committee, senior management and the external auditor.

2.

The Committee shall be charged with the following advisory functions, duties and responsibilities:

a)

Review the annual audited financial statements with senior management and the external auditor prior to their submission to the Board for approval.

b)

Review annually the results of the external auditors review of the Corporation's financial records, including the management letter, and report to the Board any matter remaining unresolved and their approval of statements.

c)

Review annually the results of the reports of the external auditor with respect to the state of the Corporations internal control systems and report to the Board the results of the review.

d)

Review, prior to issue or review by the Board, all continuous disclosure and other documents of the Corporation that include financial statements specifically, without limitation, all prospectuses, annual information forms, management discussion and analysis and annual reports.

e)

Review any report from senior management of any outstanding litigation or claims and report to the Board as appropriate.

f)

Review the quality of service and performance of the external auditor and external audit fees and costs and recommend annually to the Board the appointment or reappointment of an external auditor.

g)

Review at least annually and report to the Board on the insurable risks and insurance coverages of the Corporation, including directors and officers liability insurance.

h)

Review quarterly and report to the Board on the hedging, financial risk management and derivatives position of the Corporation.

i)

Review and report to the Board on the compliance reports by senior management.

j)

Review at least annually and report to the Board on senior managements recommendations with respect to the Corporations maintenance of safety, health and environmental policies, procedures and practices in the conduct of its operations, directed to preventing injury to its employees, the public and the environment.

k)

Review at least annually in conjunction with the Corporate Governance Committee and report to the Board on the adequacy of the Committee's terms of reference.

3.

The Committee shall be charged with the following decision-making functions, duties and responsibilities:

a)

Review the unaudited quarterly financial statements with senior management and recommend to the Board to approve the same.

b)

Review the press release and shareholders report issued to accompany the unaudited quarterly financial statements with senior management and recommend to the Board to approve the same.

C-1



---

If, in order to properly discharge its functions, duties and responsibilities, it is necessary, in the opinion of the Committee, that the Committee obtain the advice and counsel of internal and/or external advisors, the Chairman shall, at the request of the Committee (and subject to the approval of the Board in the case of external advisors only), engage the necessary advisors.

4.

Constitution

a)

The Committee shall be composed of a minimum of three (3) directors.

b)

The members of the Committee shall be appointed or reappointed at the meeting of the Board immediately following each annual meeting of the shareholders of the Corporation.  Each member of the Committee shall continue to be a member thereof until his successor is appointed, unless he shall resign or be removed by the Board or he shall otherwise cease to be a director of the Corporation.  Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board and shall be filled by the Board if the membership of the Committee is less than three directors as a result of the vacancy.

c)

The Board or, in the event of its failure to do so, the members of the Committee, shall appoint a chairman (the "Chairman") from amongst their number.  If the Chairman of the Committee is not present at any meeting of the Committee, the Chairman of the meeting shall be chosen by the Committee from among the members present.  The Chairman presiding at any meeting of the Committee shall have a casting vote in case of deadlock.  The Committee shall also appoint a Secretary who need not be director or officer of the Corporation.

5.

Meetings and Minutes

a)

The time and place of meetings of the Committee and the procedure at such meetings shall be determined from time to time by the members thereof provided that:

i)

a quorum for meetings shall be two (2) members, neither of which is an officer or employee of the Corporation, present in person or by telephone or other telecommunication device that permit all persons participating in the meeting to speak and hear each other;

ii)

the Committee shall meet at least quarterly;

iii)

notice of the time and place of every meeting shall be given to each member of the Committee, and, if requested or required, the external auditor of the Corporation, at least 48 hours prior to the time fixed for such meeting, provided, however, that a member may in any manner waive a notice of a meeting and attendance of a member at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called;

iv)

the external auditor shall be entitled to attend each meeting at the request of the Committee and at the expense of the Corporation;

v)

a meeting of the Committee may be called by the Secretary of the Committee on the direction of the Chairman of the Committee, the Chairman of the Board or the Chief Executive Officer of the Corporation or by any two (2) members of the Committee or the external auditor; and

vi)

the Committee shall at all times have the right to determine who shall and shall not be present at any part of the meetings of the Committee.

b)

All deliberations, recommendations and decisions of the Committee shall be recorded by the Secretary in the minutes of the meetings of the Committee. A verbal report on such meeting shall be made by the Chairman of the Committee to the Board at the next Board meeting and the minutes of such meeting shall be circulated to the Committee and the Board prior to the next following Committee and Board meetings respectively.

COMPOSITION OF THE AUDIT COMMITTEE

The members of the Audit Committee are George T. Hawes (Chair), Michael Halvorson and A. Bruce Macdonald. Each member of the Audit Committee is financially literate within the meaning of Multilateral Instrument 52-110 and Messrs. Hawes and Halvorson are independent committee members.

C-2

---

George T. Hawes

Mr. Hawes achieved a B.B.A. in Accountancy from the University of Notre Dame and subsequently amassed over 30 years experience in business and international finance. He has served with such companies as Avon Products Ltd. and Hurdman and Cranston Certified Public Accountants (now part of KPMG).  Mr. Hawes has considerable investment and financial experience and  is the Chairman of Gentrys Audit Committee as well as being Chairman for the Audit Committee of Midway Gold Corp., a TSX-Venture issuer.  He also serves on the Audit Committee for Proginet Corp., a U.S.-based public company.



Michael Halvorson

Mr. Halvorson has been involved in various aspects of the securities industry since 1967. Since 1980, he has been the president of Halcorp Capital Ltd., a private corporation specializing in corporate finance and corporate development within the resource industry. Mr. Halvorson serves as a director for a number of natural resource companies and is on the Audit Committees for several public companies, including NovaGold Resources Inc., Orezone Resources Inc. and Viceroy Exploration Ltd.



A. Bruce Macdonald

The President of Stoneyfell Investments, Mr. Macdonald earned his Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. His 40 plus years of experience in the oil and gas industry was gained in Canada, the United States and Australia. Before joining Gentry, he was Executive Vice-President with Andex Oil Co. Ltd. and its successor company, EOG Resources. Mr. Macdonald is Chairman of the Audit Committee for Stratic Energy Corporation, an international oil and gas exploration company listed on the TSX-Venture Exchange, and was a member of the Audit Committee for Sloane Petroleums Inc., a public company acquired by the Corporation in 2001.



EXTERNAL AUDITOR SERVICE FEES

The aggregate amounts billed by Collins Barrow Calgary LLP, Chartered Accountants to the Company for each of the fiscal years ended December 31, 2004 and 2003 for audit fees, audit-related fees, tax fees and all other fees are set forth below:

|                      | Year Ended
December 31, 2004 (estimated) | Year Ended
December 31, 2003
|--------------------- | ---------------------------------------- | ----------------------------
|Audit Fees(1)         | $  80,000                                | $  75,975                   
|Audit-Related Fees(2) | 25,000                                   | 37,950                      
|Tax Fees(3)           | 5,000                                    | 3,800                       
|All Other Fees(4)     | -                                        | -                           
|Totals                | $110,000                                 | $117,725                    



NOTES:

1.

Audit Fees represent fees for the audit of the Companys annual financial statements, review of the Companys interim financial statements and review in connection with the Companys statutory and regulatory filings.

2.

Audit-Related Fees represent fees for assurance and related services that are related to the performance of the audit, principally for US standards compliance, adoption of new accounting standards etc.

3.

Tax Fees represent fees for tax compliance, tax advice and tax planning.

4.

Other Fees represent fees for accounting research on new accounting policies.



C-3



---

|[auditorsletter001.jpg] | Collins
      Barrow Calgary LLP
      1400
      First Alberta Place
      777
      - 8th Avenue S.W.
      Calgary,
      Alberta, Canada
      T2P
      3R5
|----------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------
|                        | T.
       (403) 298-1500
      F.
       (403) 298-5814
      e-mail:
      calgary@collinsbarrow.com                                                           

AUDITORS'
REPORT



To the Shareholders

Gentry
Resources Ltd.

We have audited the
consolidated balance sheets of Gentry Resources Ltd. as at December 31, 2004 and
2003 and the consolidated statements of income, retained earnings and cash flows
for the years then ended.  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 Canadian generally accepted auditing standards and in
accordance with the standards of the Public Company Accounting Oversight Board
(United States).  Those standards require that we plan and perform an audit
to obtain reasonable assurance 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.



In our opinion, these
consolidated financial statements present fairly, in all material respects, the
financial position of the Company as at December 31, 2004 and 2003 and the
results of its operations and cash flows for the years then ended in accordance
with Canadian generally accepted accounting principles.



Canadian generally
accepted accounting principles vary in certain significant respects from
accounting principles generally accepted in the United States of America.
 Application of accounting principles generally accepted in the United
States of America would have affected results of operations for the years ended
December 31, 2004 and 2003 and shareholders' equity as at December 31, 2004
and 2003, to the extent summarized in note 14 to the consolidated financial
statements.



(signed)
"Collins Barrow Calgary LLP"

CHARTERED
ACCOUNTANTS

Calgary, Alberta

Canada

March 4, 2005



COMMENTS
BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES



In the United States of
America, reporting standards for auditors require the addition of an explanatory
paragraph (following the opinion paragraph) when there is a change in accounting
principles that has a material effect on the comparability of the Company's
financial statements, such as the changes described in Notes 2(g), (h) and (i)
to the consolidated financial statements.  Our report to the shareholders
dated March 4, 2005 is expressed in accordance with Canadian reporting standards
which do not require a reference to such a change in accounting principles in
the Auditors' report when the change is properly accounted for and adequately
disclosed in the financial statements.

(signed)
"Collins Barrow Calgary LLP"

CHARTERED
ACCOUNTANTS

Calgary, Alberta

Canada

March 4, 2005



---



Exhibit 2






**GENTRY
  RESOURCES LTD.**


**CONSOLIDATED
  BALANCE SHEETS**


**As
  at December 31, 2004 and 2003**









**ASSETS****2004**
      
      **2003**CurrentCash
          and cash equivalents
      
      $
      68,287
      
      $
      194,119Accounts
          receivable
      
      
      12,808,282
      
      
      7,461,796Prepaid
          expenses
      
      
      1,294,988
      
      
      210,38714,171,557
      
      
      7,866,302Investments
          (Note 4)
      
      
      1,707,458
      
      
      1,544,058Property
          and Equipment (Note 5)
      
      
      79,635,253
      
      
      44,062,285$
      95,514,268
      
      $
      53,472,645**LIABILITIES
          & SHAREHOLDERS' EQUITY**CurrentAccounts
          payable and accrued liabilities
      
      $
      16,629,997
      
      $
      8,866,288Income
          taxes payable
      
      
      50,066
      
      
      479,240Bank
          debt (Note 6)
      
      
      17,220,000
      
      
      11,964,01033,900,063
      
      
      21,309,538Asset
          Retirement Obligations (Note 7)
      
      
      2,671,657
      
      
      1,563,555Future
          Income Taxes (Note 8)
      
      
      7,100,776
      
      
      6,140,99243,672,496
      
      
      29,014,085Share
          Capital (Note 9)
      
      
      42,474,623
      
      
      18,373,169Contributed
          Surplus (Note 9[f])
      
      
      318,765
      
      
      22,067Retained
          Earnings
      
      
      9,048,384
      
      
      6,063,32451,841,772
      
      
      24,458,560$
      95,514,268
      
      $
      53,472,645


Director:signed:*"George Hawes"*
  
  Director:signed:*"Bruce Macdonald"*
  
  
  
  
  **GENTRY
    RESOURCES LTD.**


**CONSOLIDATED
  STATEMENTS OF INCOME**


**For
  the years ended December 31, 2004 and 2003**









**2004**
      
      **2003**RevenueProduction
      
      $
      31,717,038
      
      $
      24,679,805Less:
          royalties, net of Alberta Royalty Tax Credit
      
      
      (6,265,037
      )
      
      (5,067,096
      )25,452,001
      
      
      19,612,709ExpensesDepletion,
          depreciation & accretion
      
      
      9,046,840
      
      
      7,079,953Production
      
      
      7,271,849
      
      
      5,564,700General
          & administrative
      
      
      3,174,091
      
      
      2,277,607Interest
          on bank debt
      
      
      697,887
      
      
      484,069Stock-based
          compensation
      
      
      375,704
      
      
      174,94720,566,371
      
      
      15,581,276Income
          From Operations
      
      
      4,885,630
      
      
      4,031,433Other
          Income (Loss)Interest
          and other
      
      
      -
      
      
      40,641Share
          of loss of affiliate
      
      
      -
      
      
      (3,985
      )-
      
      
      36,656Income
          Before Income Taxes
      
      
      4,885,630
      
      
      4,068,089Income
          Taxes (Note 8)Current
      
      
      923,657
      
      
      940,785Future
      
      
      560,363
      
      
      86,7951,484,020
      
      
      1,027,580Net
          Income
      
      $
      3,401,610
      
      $
      3,040,509Net
          Income Per ShareBasic
          (Note 10)
      
      $
      0.11
      
      $
      0.12Diluted
          (Note 10)
      
      $
      0.10
      
      $
      0.12











**GENTRY
  RESOURCES LTD.**


**CONSOLIDATED
  STATEMENTS OF RETAINED EARNINGS**


**For
  the years December 31, 2004 and 2003**









**2004**
      
      **2003**Retained
          earnings, beginning of year as previously stated
      
      $
      6,063,324
      
      $
      2,867,417Restatement,
          change in accounting policy (Note 3)
      
      
      -
      
      
      482,639Retained
          earnings, beginning of year restated
      
      
      6,063,324
      
      
      3,350,056Net
          income
      
      
      3,401,610
      
      
      3,040,509Less:
          excess of cost of shares acquired over stated value (Note 9[e])
      
      
      (416,550
      )
      
      (327,241
      )Retained
          earnings, end of year
      
      $
      9,048,384
      
      $
      6,063,324
















**GENTRY
  RESOURCES LTD.**


**CONSOLIDATED
  STATEMENTS OF CASH FLOWS**


**For
  the years ended December 31, 2004 and 2003**









**2004**
      
      **2003**Operating
          ActivitiesNet
          income
      
      $
      3,401,610
      
      $
      3,040,509Add
          (deduct) items not requiring cashDepletion,
          depreciation & accretion
      
      
      9,046,840
      
      
      7,079,953Stock-based
          compensation
      
      
      375,704
      
      
      174,947Share
          of loss of affiliate
      
      
      -
      
      
      3,985Future
          income taxes
      
      
      560,363
      
      
      86,79513,384,517
      
      
      10,386,189Changes
          in non-cash working capital items
      
      
      (2,829,261
      )
      
      (564,546
      )Asset
          retirement costs
      
      
      (110,328
      )
      
      (112,643
      )10,444,928
      
      
      9,709,000Investing
          ActivitiesCapital
          expenditures
      
      
      (43,401,378
      )
      
      (21,653,477
      )Acquisition
          of investments, net
      
      
      (163,400
      )
      
      -Changes
          in non-cash working capital items
      
      
      3,734,398
      
      
      1,799,810(39,830,380
      )
      
      (19,853,667
      )Financing
          ActivitiesProceeds
          on issuance of share capital, net
      
      
      24,632,617
      
      
      5,828,070Proceeds
          from bank debt, net
      
      
      5,255,990
      
      
      4,973,983Redemption
          of share capital
      
      
      (627,298
      )
      
      (679,785
      )Changes
          in non-cash working capital items
      
      
      (1,689
      )
      
      40,60329,259,620
      
      
      10,162,871Increase
          (Decrease) In Cash
      
      
      (125,832
      )
      
      18,204Cash
          And Cash Equivalents, beginning of year
      
      
      194,119
      
      
      175,915Cash
          And Cash Equivalents, end of year
      
      $
      68,287
      
      $
      194,119Supplemental
          cash flows disclosure:Interest
          paid
      
      $
      697,887
      
      $
      484,069Income
          taxes paid
      
      $
      1,352,831
      
      $
      855,285













**1.**
      **Company
          activities**





The
  Company's activities are the exploration for and development of petroleum and
  natural gas properties in Canada.





**2.**
      **Summary
          of significant accounting policies**





These
  financial statements have been prepared using accounting principles generally
  accepted in Canada which include:





*a)*
      *Principles
          of consolidation*





The
  consolidated financial statements include the accounts of the Company and its
  wholly-owned subsidiaries, Gentry Resources (Saskatchewan) Ltd., Gentry Income
  Funds Inc. and Gentry Resources (West Africa) Inc. Both Gentry Income Funds
  Inc. and Gentry Resources (West Africa) Inc. are inactive and have no
  production operations.





*b)*
      *Cash
          and cash equivalents*





Cash
  and cash equivalents consist of amounts on deposit with banks and broker
  accounts.





*c)*
      *Investments*





During
  2003, the Company ceased to exert significant influence on its investment in
  Stratic Energy Corporation ("Stratic").





Prior
  to October 1, 2003, the Company recorded its investment in Stratic using the
  equity method of accounting, whereby the investment was initially recorded at
  cost and the carrying value was adjusted thereafter to include the Company's
  pro-rata share of earnings and losses. Profit distributions received or
  receivable were recorded as a reduction to the amount of the investment.





The
  Company records its investment in Stratic subsequent to October 1, 2003, and
  its other investment, using the cost method of accounting whereby the
  investment is initially recorded at cost. Earnings are recognized only to the
  extent received or receivable. The carrying value of the investment under the
  equity method of accounting on the date that the Company ceased to exert
  significant influence becomes its carrying value under the cost method of
  accounting.





Where
  there has been a permanent or other than temporary decline in value, the
  investments are stated at estimated net realizable value.





*d)*
      *Petroleum
          and natural gas exploration and development expenditures*





The
  Company follows the Canadian full cost method of accounting whereby all costs
  related to the exploration for and the development of petroleum and natural
  gas reserves are initially capitalized and accumulated in cost centres by
  country. Costs capitalized include land acquisition costs, geological and
  geophysical expenditures, costs of drilling productive and non-productive
  wells, together with overhead and interest directly related to exploration and
  development activities and lease and well equipment. Gains or losses are not
  recognized upon disposition of petroleum and natural gas properties unless
  such a disposition would significantly alter the related cost centre's rate
  of depletion and depreciation. A significant disposition is defined as causing
  a change of 20% or more in the annual depletion rate.




















Costs
  capitalized are depleted and depreciated using the unit-of-production method
  by cost centre based upon gross proved petroleum and natural gas reserves as
  determined by independent engineers. For purposes of the calculation,
  petroleum and natural gas reserves are converted to a common unit of measure
  on the basis of their relative energy content, whereby one barrel of oil is
  equivalent to six thousand cubic feet of natural gas.





The
  costs of significant unproved properties are excluded from the depletion and
  depreciation base until it is determined whether proved reserves are
  attributable to the properties, or impairment has occurred.





As
  of January 1, 2004, the Company adopted the new Canadian Institute of
  Chartered Accountants' Accounting Guideline 16, "Oil and Gas Accounting -
  Full Cost" on impairment recognition for oil and gas assets. As permitted
  under the standard, the Company tests impairment against undiscounted future
  net revenues from proved reserves using expected future product prices and
  costs. Impairment is recognized when the carrying amount is greater than the
  undiscounted future net revenues, at which time assets are written down to the
  fair value of proved and probable reserves plus the cost of unproved
  properties, net of impairment allowances. Fair value is determined using
  expected future product prices and costs, and amounts are discounted using a
  risk free interest rate.





The
  current ceiling test differs from the test under the prior guideline as under
  the old guideline the prices and costs were based upon the period end prices
  and costs and were not discounted. Estimated future general and administrative
  costs, financing charges and income taxes were deducted from the estimated
  future cash flows.





There
  were no changes to net income, property and equipment or any other reported
  amounts in the consolidated financial statements as a result of adopting
  Accounting Guideline 16.





*e)*
      *Depreciation*





Other
  assets are depreciated using the declining balance method at annual rates of
  20% to 100%.





*f)*
      *Income
          taxes*





Income
  taxes are accounted for using the liability method of income tax allocation.
  Under the liability method, income tax assets and liabilities are recorded to
  recognize future income tax inflows and outflows arising from the settlement
  or recovery of assets and liabilities at the carrying values. Income tax
  assets are also recognized for the benefits from tax losses and deductions
  that cannot be identified with particular assets or liabilities, provided
  those benefits are more likely than not to be realized. Future income tax
  assets and liabilities are determined based on the tax laws and rates that are
  anticipated to apply in the year of realization.





*g)*
      *Asset
          retirement obligations*





Effective
  January 1, 2003, the Company has adopted retroactively, with restatement of
  prior periods, the Canadian Institute of Chartered Accountants' new standard
  on Asset Retirement Obligations. This new section requires liability
  recognition for retirement obligations associated with long-lived assets,
  which would include abandonment of oil and natural gas wells, related
  facilities, compressors and gas plants, removal of equipment from leased
  acreage and returning such land to its original condition.

















Under
  the new standard, the estimated fair value of each asset retirement obligation
  is recorded in the period a well or related asset is drilled, constructed or
  acquired. Fair value is estimated using the present value of the estimated
  future cash outflows to abandon the asset at the Company's credit-adjusted
  risk-free interest rate. The obligation is reviewed regularly by Company
  management based upon current regulations, costs, technologies and industry
  standards. The discounted obligation is initially capitalized as part of the
  carrying amount of the related oil and natural gas properties and a
  corresponding liability is recognized. The increase in oil and natural gas
  properties is depleted and depreciated on the same basis as the remainder of
  the oil and natural gas properties. The liability is accreted against income
  until it is settled or the property is sold and is included as a component of
  depletion and depreciation expense. Actual restoration expenditures are
  charged to the accumulated obligation as incurred.





Prior
  to 2003, the Company estimated costs of dismantlement, removal and site
  restoration and recorded them over the remaining life of the proved reserves
  on the unit-of-production basis. The annual provision was included in
  depletion and depreciation expense and was accrued as a site restoration
  liability on the balance sheet. Actual restoration expenditures were charged
  to the accumulated obligation as incurred.





*h)*
      *Flow-through
          shares*





The
  Company, from time to time, issues flow-through shares to finance a portion of
  its capital expenditure program. Pursuant to the terms of the flow-through
  share agreements, the tax deductions associated with the expenditures are
  renounced to the subscribers. Accordingly, share capital is reduced and a
  future tax liability is recorded equal to the estimated amount of future
  income taxes payable by the Company as a result of the renunciations.





Effective,
  March 19, 2004 the Canadian Institute of Chartered Accountants provided new
  guidance that this reduction to share capital and increase in future tax
  liability should occur when the expenditures are renounced. Prior to this, the
  Company recorded the reduction to share capital and increase in future tax
  liability when the expenditures were made.





*i)*
      *Stock-based
          compensation*





The
  Company has a stock option plan as described in Note 9(c).





On
  October 1, 2003, the Company prospectively adopted the Canadian Institute of
  Chartered Accountants' new standard with respect to accounting for
  stock-based compensation arrangements relating to stock options granted to
  employees, officers and directors. Stock-based compensation expense is
  recorded for all options granted on or after January 1, 2003, with a
  corresponding increase recorded to contributed surplus. The compensation
  expense is recognized over the vesting period. No compensation expense is
  recorded for stock options awarded and outstanding prior to adoption of the
  new accounting standard. The fair value of options granted are estimated at
  the date of grant using the Black-Scholes valuation model. Upon the exercise
  of stock options, consideration paid by employees or directors together with
  the amount previously recognized in contributed surplus is recorded as an
  increase to share capital.





Under
  the transitional provisions of the standard, stock options granted to
  employees, officers and directors after the effective date of January 1, 2003
  are accounted for using the fair value method. As a result of this change,
  general and administrative expense increased by $112,543, property and
  equipment increased by $19,861 and contributed surplus increased by $132,404,
  all of which have been recorded in 2003, subsequent to September 30, 2003. The
  Company will continue to disclose the pro-forma results for stock options
  issued to employees, officers and directors which were issued in 2002 in Note
  9(g).








*j)*
      *Net
          income per share*





Diluted
  net income per share is calculated using the treasury stock method, whereby it
  is assumed that proceeds from the exercise of stock options and warrants are
  used by the Company to repurchase Company shares at the weighted average
  market price during the year.





*k)*
      *Revenue
          recognition*





Revenue
  from the sale of petroleum and natural gas is recognized based on volumes
  delivered to customers at contractual delivery points and rates. The costs
  associated with the delivery, including operating and maintenance costs,
  transportation, and production based royalty expenses are recognized in the
  same period in which the related revenue is earned and recorded.





*l)*
      *Foreign
          currency translation*





The
  Company follows the temporal method when translating foreign currency
  transactions and the financial statements of its integrated subsidiaries.





Under
  this method, foreign currency denominated assets and liabilities are
  translated at the exchange rate prevailing at the balance sheet date for
  monetary items and at the transaction date for non-monetary items. Revenues
  and expenses, except depletion and depreciation, are translated at average
  exchange rates for the year. Depletion and depreciation are translated at the
  same rate as the related assets. Exchange gains or losses on translation of
  current and non-current monetary items are included in the determination of
  net income.





*m)*
      *Joint
          venture accounting*





Substantially
  all of the Company's exploration and production activities are conducted
  jointly with others, and accordingly, these financial statements reflect only
  the Company's proportionate interest in such activities.





*n)*
      *Measurement
          uncertainty*





The
  amounts recorded for depletion and depreciation, asset retirement costs and
  obligations and the ceiling test are based on estimated proved reserves,
  production rates, future petroleum and natural gas prices and future costs. By
  their nature, these estimates are subject to measurement uncertainty and the
  effect of changes in such estimates in future periods could be significant.





The
  amounts used to estimate fair values of stock options issued, and the
  resultant pro-forma income effects (Notes 9[f] and [g]) are based on estimates
  of future volatility of the Company's share price, expected lives of the
  options, expected dividends to be paid by the Company and other relevant
  assumptions. By their nature, these estimates are subject to measurement
  uncertainty and the effect of changes in such estimates on the financial
  statements of future periods could be significant.





*o)*
      *Comparative
          financial statements*





Certain
  figures in the comparative financial statements have been reclassified to
  conform with the current year presentation.







**3.**
      **Change
          in accounting policy**





The
  effects of the change in policy for asset retirement obligations for the year
  ended December 31, 2003 is as follows:





**2003**Increase
            in property and equipment
        
        $
        1,351,899Increase
            in accumulated depletion
        
        
        535,722Increase
            (decrease) in liability for site restoration/asset retirement
        
        
        24,108Increase
            in future income taxes liability
        
        
        273,563Increase
            in opening retained earnings
        
        
        482,639Decrease
            in depletion, depreciation & accretion expense
        
        
        (62,399
        )Increase
            in future income taxes expense
        
        
        26,532
  There
  is no change in the basic or diluted net income per share as a result of these
  changes.




**4.**
      **Investments**





At
  December 31, 2004, the Company owned 13.24% (2003 - 18.99%) of the common
  shares of Stratic. The Company is related to Stratic by virtue of common
  directors and officers.




**2004**
      
      **2003**Stratic
          Energy Corporation, at cost
      
      $
      1,689,458
      
      $
      1,526,058Other,
          at cost
      
      
      18,000
      
      
      18,000$
      1,707,458
      
      $
      1,544,058




**5.**
      **Property
          and equipment**




**2004**
        
        **2003**Petroleum
            and natural gas properties, including exploration and development
            thereon
        
        $
        89,802,565
        
        $
        52,872,302Production
            equipment and facilities
        
        
        21,603,127
        
        
        14,143,839Other
        
        
        879,842
        
        
        751,307112,285,534
        
        
        67,767,448Accumulated
            depletion and depreciation
        
        
        (32,650,281
        )
        
        (23,705,163
        )$
        79,635,253
        
        $
        44,062,285


During
  the year, the Company capitalized $1,165,303 (2003 - $848,043) of a total of
  $4,339,394 (2003 - $3,125,650) in general and administrative expenses. No
  interest has been capitalized.





Costs
  of unproved petroleum and natural gas properties amounting to $20,198,754
  (2003 - $3,206,210) have been excluded from the depletion calculation.














The
  Company prepared a ceiling test calculation at December 31, 2004 to assess the
  recoverability of its petroleum and natural gas properties. The ceiling test
  was based upon a valuation of the petroleum and natural gas properties
  prepared by an independent engineering firm based upon future oil and gas
  benchmark prices and adjusted for commodity price differentials specific to
  the Company. The following table summarizes the benchmark references prices
  used in the ceiling test calculation:





**WTI
          Oil**
        **($US/bbl)**
      
      **Edmonton
          Light Sweet 40o API**
        **($Cdn/bbl)**
      
      **Hardity
          Medium Oil 25o API**
        **($Cdn/bbl)**
      
      **AECO
          Natural Gas Spot Price**
        **($Cdn/mmbtu)**2005
      
      $
      42.00
      
      $
      51.83
      
      $
      45.98
      
      $
      6.622006
      
      
      38.00
      
      
      47.10
      
      
      41.40
      
      
      6.472007
      
      
      35.00
      
      
      43.90
      
      
      38.30
      
      
      6.222008
      
      
      32.00
      
      
      40.00
      
      
      34.50
      
      
      5.722009
      
      
      32.00
      
      
      40.00
      
      
      34.50
      
      
      5.47





Prices
  remain constant between 2009 and 2012 and increase at a rate of approximately
  2.00% thereafter.





**6.**
      **Bank
          debt**





The
  Company has an uncommitted demand revolving credit facility to a maximum of
  $35,000,000. The facility is available to the Company by way of prime rate
  based loans, bankers acceptances and letters of credit. Interest is payable
  monthly at the bank's prime lending rate. The facility is secured by a
  general assignment of book debts, a $50,000,000 demand debenture with a
  floating charge over all assets with a Negative Pledge and Undertaking to
  provide fixed charges upon request.





The
  credit facility is subject to review on a semi-annual basis. The next review
  will be undertaken on or before April 30, 2005.





**7.**
      **Asset
          retirement obligations**





The
  following table summarizes changes in the asset retirement obligations for the
  years ended December 31, 2004 and 2003:





**2004**
      
      **2003**Asset
          retirement obligations, beginning of year
      
      $
      1,563,555
      
      $
      1,299,681Liabilities
          incurred
      
      
      1,116,708
      
      
      359,036Liabilities
          settled
      
      
      (110,328
      )
      
      (112,643
      )Accretion
          expense
      
      
      101,722
      
      
      76,292Revisions
          in estimated cash flows
      
      
      -
      
      
      (58,811
      )Asset
          retirement obligations, end of year
      
      $
      2,671,657
      
      $
      1,563,555





The
  inflated, undiscounted amount of the estimated future cash flows required to
  settle the obligations is $4,972,730 (2003 - $2,926,612). These obligations
  are expected to be paid over the next several years with a weighted average
  life of approximately 11 years (2003 - 11 years). The estimated future cash
  flows have been discounted at the credit-adjusted risk free rate of 5.25%. As
  at December 31, 2004, no funds have been set aside to settle these
  obligations.








**8.**
      **Income
          taxes**




*a)*
      *Future
          Income Tax Liability*





Significant
  components of the future income tax liability are as follows:


**2004**
        
        **2003**Temporary
            differences related to property and equipment and asset retirement
            obligations
        
        $
        7,818,381
        
        $
        6,456,832Share
            issuance and financing costs
        
        
        (599,300
        )
        
        (193,580
        )Temporary
            differences related to investments
        
        
        (118,305
        )
        
        (122,260
        )$
        7,100,776
        
        $
        6,140,992




*b)*
      *Income
          Tax Expense*





Income
  taxes expense differs from that which would be expected from applying the
  combined Canadian federal and provincial income tax rate of 40.11% (2003 -
  42.52%) to income before income taxes. The difference results from the
  following:





**2004**
        
        **2003**Expected
            tax provision
        
        $
        1,959,626
        
        $
        1,729,752Increases
            (decreases) resulting from:Resource
            allowance
        
        
        (1,201,457
        )
        
        (1,265,836
        )Non-deductible
            crown payments, net of Alberta Royalty Tax Credit
        
        
        1,065,066
        
        
        1,060,806Change
            in tax rates
        
        
        (503,672
        )
        
        (596,959
        )Large
            corporate and capital taxes
        
        
        52,115
        
        
        73,444Non-deductible
            stock-based compensation
        
        
        150,695
        
        
        47,853Reduced
            tax rates for resource allowance and capital gains
        
        
        (25,770
        )
        
        3,788Other
        
        
        (12,583
        )
        
        (25,268
        )$
        1,484,020
        
        $
        1,027,580









**9.**
      **Share
          capital**





*Authorized*


Unlimited
  number of voting common shares


Unlimited
  number of non-voting preferred shares





*Issued*


Common
          shares:
      
      **2004**
      
      **-2003****Number**
      
      **Stated
          Value**
      
      **Number**
      
      **Stated
          Value**Balance,
          beginning of year
      
      
      27,352,508
      
      $
      18,373,169
      
      
      23,783,263
      
      $
      13,262,522Issued
          for cash (Note 9[a])
      
      
      9,500,000
      
      
      22,825,000
      
      
      3,000,000
      
      
      5,250,000Flow-through
          shares issued (Note 9[a])
      
      
      1,080,000
      
      
      2,820,000
      
      
      -
      
      
      -Share
          purchase warrants exercised (Note 9[b])
      
      
      150,000
      
      
      262,500
      
      
      350,000
      
      
      612,500Stock
          options exercised (Note 9[c])
      
      
      580,000
      
      
      320,650
      
      
      585,000
      
      
      303,350Issued
          under employee share purchase plan (Note 9[d])
      
      
      68,826
      
      
      158,013
      
      
      76,045
      
      
      124,808Normal
          Course Issuer Bids (Note 9[e])
      
      
      (260,100
      )
      
      (210,748
      )
      
      (441,800
      )
      
      (242,207
      )Total
          issued
      
      
      38,471,234
      
      
      44,548,584
      
      
      27,352,508
      
      
      19,310,973Less:Reduction
          due to income tax deductions renounced to subscribers (Note 9[a])
      
      
      -
      
      
      (981,924
      )
      
      -
      
      
      (676,164
      )Share
          issuance costs (net of income taxes of $582,503 [2003 - $138,544])
      
      
      -
      
      
      (1,092,037
      )
      
      -
      
      
      (261,640
      )Balance,
          end of year
      
      
      38,471,234
      
      $
      42,474,623
      
      
      27,352,508
      
      $
      18,373,169





*a)*
      *Financings*





During
  the year ended December 31, 2004, the Company issued 9,500,000 common shares
  (2003 - 3,000,000) at an average price of $2.40 per share (2003 - $1.75) for
  gross proceeds of $22,825,000 (2003 - $5,250,000).





In
  addition, the Company issued 1,000,000 flow-through common shares at a price
  of $2.50 per share and 80,000 flow-through common shares at a price of $4.00
  per share (2003 - Nil). Income tax exploration deductions in the amount of
  $2,820,000 were renounced to subscribers effective December 31, 2004.
  Qualifying expenditures in the amount of $2,500,000 were incurred to December
  31, 2004 and $320,000 must be incurred in 2005.





*b)*
      *Warrants*





During
  the year ended December 31, 2004, 150,000 common shares (2003 - 350,000) at a
  price of $1.75 per share (2003 - $1.75) were issued upon the exercise of
  150,000 share purchase warrants (2003 - 350,000). There are no share purchase
  warrants outstanding as at December 31, 2004.











*c)*
      *Stock
          Option Plan*





Under
  the Company's stock option plan, the Company may grant options to its
  directors, officers, employees, and consultants. The maximum number of shares
  which may be reserved for issuance under the plan is 4,000,000 common shares.
  The maximum number of shares which may be reserved for issuance to any one
  person under the plan is 5% of the issued common shares. The plan also
  provides that the price at which options may be granted can not be less than
  the market price of the common shares at the time the option is granted.
  Options granted under the plan will have a term not exceeding ten years. The
  vesting period is set by the Board of Directors at the time the options are
  granted.





A
  summary of the status of the Company's stock option plan, as of December 31,
  2004 and 2003 and changes during the years then ending are as follows:





**2004**
      
      **2003****Number
          of Options**
      
      **Weighted
          Average Exercise Price**
      
      **Number
          of Options**
      
      **Weighted
          Average Exercise Price**Outstanding,
          beginning of year
      
      
      2,460,000
      
      $
      0.90
      
      
      2,330,000
      
      $
      0.65Granted
      
      
      1,115,000
      
      
      2.32
      
      
      720,000
      
      
      1.37Exercised
      
      
      (580,000
      )
      
      0.55
      
      
      (585,000
      )
      
      0.52Cancelled
      
      
      -
      
      
      -
      
      
      (5,000
      )
      
      1.31Outstanding,
          end of year
      
      
      2,995,000
      
      $
      1.49
      
      
      2,460,000
      
      $
      0.90Options
          exercisable at year-end
      
      
      1,636,655
      
      $
      0.95
      
      
      1,935,002
      
      $
      0.77





The
  following table summarizes the stock options outstanding at December 31, 2004:





**Options
          Outstanding**
      
      **Options
          Exercisable****Range
          of Exercise Prices**
      
      **Number
          of Options**
      
      **Weighted
          Average Exercise Price**
      
      **Weighted
          Average Remaining Contractual Life**
      
      **Number
          of Options**
      
      **Weighted
          Average Exercise Price**$0.45
          to $0.52
      
      
      335,000
      
      $
      0.45
      
      
      5.1
      
      
      335,000
      
      $
      0.45$0.77
          to $0.95
      
      
      635,000
      
      
      0.80
      
      
      4.8
      
      
      635,000
      
      
      0.80$1.18
          to $1.62
      
      
      910,000
      
      
      1.34
      
      
      3.0
      
      
      666,665
      
      
      1.33$2.30
          to $2.75
      
      
      1,115,000
      
      
      2.32
      
      
      4.7
      
      
      -
      
      
      -Total
      
      
      2,995,000
      
      
      
      
      
      
      
      
      1,636,665




*d)*
      *Employee
          share purchase plan*





On
  January 1, 2003, the Company initiated an employee share purchase plan (the
  "Plan"), whereby the Company is authorized to match employees' purchases
  under the Plan from a minimum of two percent to a maximum of five percent of
  the employees' regular gross earnings, through the issuance of common shares
  of the Company, for all full-time employees. Compensation expense is
  recognized when shares are issued under the Plan and an equal amount is
  recorded as share capital. Shares are issued from Treasury to employees at the
  weighted average market price for the month immediately preceding the date of
  purchase of the Company's shares. The maximum number of common shares which
  can be issued under the plan is 500,000, of which 144,871 have been issued to
  December 31, 2004.









*e)*
      *Normal
          Course Issuer Bid*





Pursuant
  to Normal Course Issuer Bids, the Company acquired 260,100 (2003 - 441,800)
  common shares at an average price of $2.41 (2003 - $1.54) per share. The
  excess of cost of reacquisition over stated value of $416,550 (2003 -
  $327,241) has been charged against retained earnings with the remaining $Nil
  (2003 - $110,337) charged to contributed surplus. At December 31, 2004, a
  maximum of 2,672,500 common shares may be acquired by the Company until August
  26, 2005 under the present Normal Course Issuer Bid.





*f)*
      *Stock-based
          compensation expense*





The
  fair value of stock options granted during 2004 was estimated on the dates of
  grant using the Black-Scholes option-pricing method with the following
  assumptions:





Risk
  free interest rate of 3.67 to 3.73% (2003 - 3.85%)


Expected
  life of options of 3.5 to 4.5 years (2003 - 3.5 to 4.5 years)


Expected
  volatility of 30.91 to 31.72% (2003 - 59.19%)


Expected
  dividend rate of 0% (2003 - 0%)


Fair
  value per option granted of $0.69 to $0.78 (2003 - $0.66)





Compensation
  costs of $296,698 (2003 - $112,543) have been expensed and $Nil (2003 -
  $19,860) has been capitalized, resulting in the recognition of $296,698 (2003
  - $132,404) of contributed surplus during 2004.





*g)*
      *Pro-forma
          stock-based compensation expense*





If
  the compensation costs for the Company's stock option plan had been
  determined using the fair value method for options granted from January 1,
  2002 to December 31, 2002, the Company's pro-forma net income and retained
  earnings for 2004 would be reduced by $16,396 (2003 - $20,423). There would be
  no change in net income per share or diluted net income per share.





The
  assumptions used to determine the fair value of each option granted on the
  date of grant using the Black-Scholes option-pricing model are as follows:





Risk
  free interest rate of 4.1%


Expected
  life of options of 3.5 years


Expected
  volatility of 65.50%


Expected
  dividend rate of 0%


Fair
  value per option granted of $0.60





**10.**
      **Income
          per share**





Net
  income per share has been calculated based on the weighted average number of
  common shares outstanding during the year of 31,614,549 (2003 - 24,564,151).





A
  reconciliation of the denominators for the per share calculations is outlined
  below:





**2004**
      
      **2003**Basic
          weighted average shares
      
      
      31,614,549
      
      
      24,564,151Effect
          of dilutive stock options and warrants
      
      
      1,394,406
      
      
      1,380,699Dilutive
          weighted average shares
      
      
      33,008,955
      
      
      25,944,850





There
  is no change in the numerator in the calculation of diluted net income per
  share for either year.









**11.**
      **Financial
          instruments**





*a)*
      *Fair
          values*





The
  fair values of the Company's accounts receivable and accounts payable and
  accrued liabilities approximate their carrying values due to the short-term
  nature of these financial instruments. The fair value of investments at
  December 31, 2004 is $8,712,159 (2003 - $3,833,014).





The
  fair value of bank debt approximates its carrying value as it bears interest
  at market rates.





*b)*
      *Credit
          risk*





Virtually
  all of the Company's accounts receivables are with customers in the
  petroleum and natural gas industry and are subject to normal industry credit
  risks.





*c)*
      *Interest
          rate risk*





The
  Company is exposed to interest rate cash flow risk to the extent that its bank
  debt is at a floating rate of interest.





*d)*
      *Commodity
          price risk*





The
  nature of the Company's operations results in exposure to fluctuations in
  commodity prices. Management monitors commodity prices and initiates
  instruments to manage exposure to these risks when it deems appropriate.
  Currently, no such instruments have been initiated.





*e)*
      *Currency
          risk*





The
  Company is exposed to foreign currency fluctuations as crude oil and natural
  gas prices are referenced to U.S. dollar denominated prices.





**12.**
      **Commitments**





The
  Company has obligations under operating leases for office space,
  transportation obligations and equipment rentals as follows:





2005
      
      $
      253,6512006
      
      
      230,4012007
      
      
      230,4012008
      
      
      159,0652009
      
      
      -





**13.**
      **Subsequent
          Event**





On
  November 24, 2004, the Company entered into a letter of agreement to acquire
  certain oil and gas interest in the Princess area of Southern Alberta for the
  sum of $8,079,000. The transaction, which is anticipated to close by the end
  of March 2005, is subject to certain rights of first refusal and as such it is
  still not yet known what the final interest or cost accruing to the Company
  will be. The sum of $807,900 was advanced as a deposit and is included in
  Prepaid Expenses on the Consolidated Balance Sheet.





**14.**
      **United
          States accounting principles and reporting**





The
  Company's consolidated financial statements have been prepared in Canadian
  dollars and in accordance with Canadian generally accepted accounting
  principles ("Canadian GAAP"), which in most respects conform to
  accounting principles generally accepted in the United States ("U.S. GAAP").
  Significant differences between Canadian and U.S. GAAP are described in this
  note:








*a)*
      *Full
          cost accounting*





In
  accordance with U.S. GAAP, a ceiling test is applied to ensure the unamortized
  capitalized costs in each cost centre do not exceed the sum of the present
  value, discounted at 10 percent, of the estimated unescalated future net
  operating revenue from proved reserves plus unimpaired unproved property costs
  less future development costs, related production costs, asset retirement
  obligations and applicable taxes. Under Canadian GAAP, a similar ceiling test
  calculation is performed with the exception that future revenues are
  undiscounted and use forecast pricing to determine whether an impairment
  exists and are on a before tax basis. Any impairment amount is measured using
  the fair value of proved and probable reserves.





In
  computing consolidated net income for U.S. GAAP purposes, the Company recorded
  additional depletion in prior years as a result of the application of the
  ceiling test. These charges were not required under the Canadian GAAP ceiling
  test. As a result, the depletion base of unamortized capitalized costs is less
  for U.S. GAAP purposes. No ceiling test write-down is required under Canadian
  GAAP or U.S. GAAP as at December 31, 2004 and 2003.





Effective
  January 1, 2004, the Canadian Accounting Standard's Board amended the Full
  Cost Accounting Guideline. Under Canadian GAAP, depletion charges are
  calculated by reference to proved reserves estimated using estimated future
  prices and costs. Under U.S. GAAP, depletion charges are calculated by
  reference to proved reserves estimated using constant prices.





*b)*
      *Income
          taxes*





Canadian
  GAAP previously required the Company to record potential future taxes using
  the deferral method. However, the Canadian Institute of Chartered Accountants'
  accounting standard is now similar to U.S. GAAP.





Upon
  implementation of the new Canadian standard, retained earnings was decreased
  for temporary differences that had not previously been recognized. Under U.S.
  GAAP, these temporary differences would have already been reflected in
  property and equipment, therefore further differences in depletion and
  depreciation expense results in subsequent years.





Under
  U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas under
  Canadian GAAP, substantively enacted tax rates are used.





*c)*
      *Flow-through
          shares*





U.S.
  GAAP requires the stated capital on flow-through share issuances to be equal
  to the estimated fair market value of the shares on the date of issue. The
  difference between the gross proceeds received on the issuance of the shares
  and the estimated fair market value of the shares is recorded as a liability ("the
  Premium") until the renunciation of expenditures has occurred. Under
  Canadian GAAP, the gross proceeds received on flow-through share issuances are
  initially recorded as share capital. The Premium recorded as a current
  liability under U.S. GAAP for 2004 is $38,400 (2003 - $Nil).





When
  the expenditures are incurred and the tax deductions are renounced to
  subscribers, Canadian GAAP requires that the stated capital be reduced by and
  a future tax liability be recorded for the estimated future income taxes
  payable as a result of the renouncement. Under U.S. GAAP, the future tax
  liability is recorded through a charge to income tax expense less the reversal
  of the Premium previously reported.








*d)*
      *Investments*





On
  October 1, 2003, the Company began accounting for its investment in Stratic
  using the cost method (Note 2[c]). Under U.S. GAAP, the carrying value of the
  investment under the equity method of accounting becomes its carrying value as
  of the date of loss of significant influence which is identical under Canadian
  GAAP.





Additionally,
  under U.S. GAAP, the Company must classify investments in equity securities
  that have readily determinable fair values as either available for sale or
  trading. The Company's investments are classified as available for sale as
  they were not acquired and are not held principally for the purposes of
  selling them in the near term. These available for sale investments are
  revalued at the end of each period based on their fair values and any
  unrealized gain or loss is recorded, net of tax effects, as a component of
  other comprehensive income in the period.





Additionally,
  U.S. GAAP requires the disclosure, as other comprehensive income, of changes
  in equity during the period from transaction and other events from non-owner
  sources. Canadian GAAP does not require similar disclosure. Comprehensive
  income for U.S. purposes arose on valuing the Company's investments at their
  fair market value.





*e)*
      *Stock-based
          compensation*





Effective
  January 1, 2003, the Company prospectively adopted the Canadian Institute of
  Chartered Accountants' new standard with respect to accounting for
  stock-based compensation arrangements relating to stock options granted to
  employees, officers and directors. Hence, under Canadian GAAP, compensation
  costs have been recognized in the financial statements for stock options
  granted to employees, officers and directors in 2004. For the effect of
  stock-based compensation on the financial results under Canadian GAAP in 2004,
  which would be the same adjustment under U.S. GAAP, see Note 9(f).





U.S.
  Statement of Financial Accounting Standards ("SFAS") No. 123, "Accounting
  for Stock-Based Compensation" establishes financial accounting and reporting
  standards for stock-based employee compensation plans under U.S. GAAP. The
  Statement requires disclosure of the pro-forma net income and net income per
  share as if the fair value based accounting method had been used to account
  for stock-based compensation costs in advance of the equivalent Canadian
  standard. The effects of the fair value disclosures under U.S. GAAP are as
  follows:





**2004**
      
      **2003****As
          Reported**
      
      **ProForma**
      
      **As
          Reported**
      
      **ProForma**Net
          Income
      
      $
      3,540,553
      
      $
      3,530,702
      
      $
      2,824,623
      
      $
      2,748,216Net
          income per share   - Basic
      
      $
      0.11
      
      $
      0.11
      
      $
      0.11
      
      $
      0.11-
          Diluted
      
      $
      0.11
      
      $
      0.11
      
      $
      0.11
      
      $
      0.11





The
  fair value of the options issued by the Company during 2003 was estimated
  under U.S. GAAP using the same assumptions as under Canadian GAAP, as
  disclosed in Note 9(f).





*f)*
      *Asset
          retirement obligations*





Effective
  January 1, 2003, the Company early adopted the Canadian Institute of Chartered
  Accountant's new standard on Asset Retirement Obligations (Note 2[g]). This
  standard is equivalent to U.S. SFAS No. 143, "Accounting for Asset
  Retirement Obligations", which is effective for fiscal periods beginning on
  or after January 1, 2003. Early adopting the Canadian standard eliminated a
  U.S. GAAP reconciling item with respect to accounting for the obligations.
  However, differences in accounting methodology for changes in accounting
  policies necessitate additional disclosures under U.S. GAAP.











U.S.
  GAAP requires that the cumulative impact of a change in accounting policy be
  presented in the current year Consolidated Statement of Income and prior
  periods are not restated.





Net
  income under U.S. GAAP for the year ended December 31, 2003 increased by
  $446,346 due to the change in accounting policy.





*g)*
      *Consolidated
          statement of cash flows*





Under
  U.S. GAAP, separate subtotals within cash flow from operating activities are
  not presented.





*h)*
      *Recent
          accounting pronouncements*





i)
      Variable
          Interest Entities





The
  Canadian Institute of Chartered Accountants has issued a new standard
  effective for all periods beginning on or after November 1, 2004. This
  standard requires variable interest entities to be consolidated by their
  primary beneficiary which is similar to the Financial Accounting Standards
  Board's ("FASB") Interpretation No. 46 "Consolidation of Variable
  Interest Entities."





At
  December 31, 2004, the Company did not have any variable interests in
  variable-interest entities.





ii)
      Share-Based
          Payment





In
  2004, FASB issued revised FAS 123 "Share-Based Payment". This amended
  statement eliminates the alternative to use Accounting Principles Board ("APB")
  Opinion No. 25's intrinsic value method of accounting, as was provided in
  the originally issued Statement 123.





As
  a result, public entities are required to use the grant-date fair value of the
  award in measuring the cost of employee services received in exchange for an
  equity award of equity instruments. Compensation cost is required to be
  recognized over the requisite service period.





For
  liability awards, entities are required to re-measure the fair value of the
  award at each reporting date up until the settlement date. Changes in fair
  value of liability awards during the requisite service period are required to
  be recognized as compensation cost over the vesting period. Compensation cost
  is not recognized for equity instruments for which employees do not render the
  requisite service.





This
  amended statement is effective the beginning of the first interim or annual
  reporting period that begins after June 15, 2005. The Company is currently
  assessing the impact of this amendment.





iii)
      Exchange
          of Non-monetary Assets





In
  2004, FASB issued FAS 153 "Exchange of Non-monetary Assets". This
  statement is an amendment of APB Opinion No. 29 "Accounting for Non-monetary
  Transactions". Based on the guidance in APB Opinion No. 29, exchanges of
  non-monetary assets are to be measured based on the fair value of the assets
  exchanged. Furthermore, APB Opinion No. 29 previously allowed for certain
  exceptions to this fair value principle. FAS 153 eliminates APB Opinion No. 29's
  exception to fair value for non-monetary exchanges of similar productive
  assets and replaces this with a general exception for exchanges of
  non-monetary assets which do not have commercial substance. For purposes of
  this statement, a non-monetary exchange is defined as having commercial
  substance when the future cash flows of an entity are expected to change
  significantly as a result of the exchange





The
  provisions of this statement are effective for non-monetary asset exchanges
  which occur in fiscal periods beginning after June 15, 2005 and are to be
  applied prospectively. Earlier application is permitted for non-monetary asset
  exchanges which occur in fiscal periods beginning after the issue date of this
  statement.








Currently,
  this statement does not have an impact on the Company; however, this may
  result in a future impact to the Company if it enters into any non-monetary
  asset exchanges.





*i)*
      *Summary
          of significant differences between U.S. GAAP and Canadian GAAP*





i)
      Reconciliation
          of Consolidated Net Income Under Canadian GAAP to U.S. GAAP





**2004**
      
      **2003**Net
          income under Canadian GAAP
      
      $
      3,401,610
      
      $
      3,040,509U.S.
          GAAP adjustmentsDepletion,
          depreciation & accretion
      
      
      252,743
      
      
      336,202Future
          tax expense on flow-through share renouncements
      
      
      (370,500
      )
      
      (442,232
      )Future
          income taxes
      
      
      256,700
      
      
      (614,523
      )Interest
          capitalized
      
      
      -
      
      
      22,028Net
          income before cumulative change in account policy under US GAAP
      
      
      3,540,553
      
      
      2,341,984Cumulative
          effect of change in accounting policy, net of income taxes
      
      
      -
      
      
      482,639Net
          income under U.S. GAAP
      
      $
      3,540,553
      
      $
      2,824,623Net
          income per share before change in accounting policy under US GAAP-
          Basic
      
      $
      0.11
      
      $
      0.10-
          Diluted
      
      $
      0.11
      
      $
      0.09Net
          income per share including cumulative change in accounting policy
          under U. S. GAAP-
          Basic
      
      $
      0.11
      
      $
      0.11-
          Diluted
      
      $
      0.11
      
      $
      0.11





ii)
      Statements
          of Comprehensive Income


**2004**
      
      **2003**Net
          income under U.S. GAAP
      
      $
      3,540,553
      
      $
      2,824,623Unrealized
          gain on investments, net of tax effect of $823,300 (2003 - $396,218)
      
      
      3,892,445
      
      
      1,892,738Comprehensive
          income
      
      $
      7,432,998
      
      $
      4,717,361










iii)
      Condensed
          Consolidated Balance Sheets


**2004**
      
      **2003****Canadian
          GAAP**
      
      **U.S.**
        **GAAP**
      
      **Canadian
          GAAP**
      
      **U.S.**
        **GAAP**AssetsCurrent
          assets
      
      $
      14,171,557
      
      $
      14,171,557
      
      $
      7,866,302
      
      $
      7,866,302Investments
      
      
      1,707,458
      
      
      8,712,159
      
      
      1,544,058
      
      
      3,833,014Property
          and equipment
      
      
      79,635,253
      
      
      77,910,353
      
      
      44,062,285
      
      
      42,084,642$
      95,514,268
      
      $
      100,794,069
      
      $
      53,472,645
      
      $
      53,783,958Liabilities
          and Shareholders' EquityCurrent
          liabilities
      
      $
      33,900,063
      
      $
      33,938,463
      
      $
      21,309,538
      
      $
      21,309,538Asset
          retirement obligations
      
      
      2,671,657
      
      
      2,671,657
      
      
      1,563,555
      
      
      1,563,555Future
          income taxes
      
      
      7,100,776
      
      
      7,230,316
      
      
      6,140,992
      
      
      5,815,35643,672,496
      
      
      43,840,436
      
      
      29,014,085
      
      
      28,688,449Share
          capital
      
      
      42,474,623
      
      
      44,354,088
      
      
      18,373,169
      
      
      19,809,110Contributed
          surplus
      
      
      318,765
      
      
      318,765
      
      
      22,067
      
      
      22,067Retained
          earnings
      
      
      9,048,384
      
      
      6,495,597
      
      
      6,063,324
      
      
      3,371,594Accumulated
          other comprehensive income
      
      
      -
      
      
      5,785,183
      
      
      -
      
      
      1,892,73851,841,772
      
      
      56,953,633
      
      
      24,458,560
      
      
      25,095,509$
      95,514,268
      
      $
      100,794,069
      
      $
      53,472,645
      
      $
      53,783,958




iv)
      Non-cash
          working capital under U.S. GAAP:




**2004**
      
      **2005**Cash
          provided by (used for)Accounts
          receivable
      
      $
      (5,346,486
      )
      $
      (2,105,292
      )Prepaid
          expenses
      
      
      (1,084,601
      )
      
      26,373Accounts
          payable and accrued liabilities
      
      
      7,763,709
      
      
      3,279,368Income
          taxes
      
      
      (429,174
      )
      
      75,418Changes
          in non-cash working capital
      
      $
      903,448
      
      $
      1,275,867
















---

Exhibit 3



The
    following Management's Discussion and Analysis ("MD&A") should be
    read in conjunction with the Consolidated Financial Statements of the
    Company.
 
 Reported
    production represents Gentry's ownership share before the deduction of
    royalties. Where amounts are expressed on a barrel of oil equivalent (boe)
    basis, natural gas has been converted at a ratio of six thousand cubic feet
    to one boe. Boe's may be misleading, particularly if used in isolation. A
    boe conversion ratio of six thousand cubic feet to one barrel is based on an
    energy equivalent conversion method primarily applicable at the burner tip
    and does not represent a value equivalency at the wellhead.
 
 Included
    in the MD&A are references to financial measures commonly used in the
    oil and gas industry such as cash flow and cash flow per share. These
    measures have no standardized meaning, are not defined by Canadian generally
    accepted accounting principles, and accordingly are referred to as non-GAAP
    measures. Cash flow and cash flow per share are used by the Company to
    assess operating results between years and between peer companies. Gentry's
    reported amounts may not be comparable to similarly titled measures reported
    by other companies. Cash flow should not be considered an alternative to, or
    more meaningful than, cash provided by operating, investing, and financing
    activities or net income as determined by Canadian GAAP as an indicator of
    the Company's performance or liquidity.
 
 Certain
    figures in the comparative financial statements and MD&A have been
    reclassified to conform with the current year presentation.
 
 Certain
    disclosure in this MD&A contains forward-looking statements that involve
    risks and uncertainties. Such information, although considered reasonable by
    Gentry at the time of preparation, may prove to be incorrect and actual
    results may differ materially from those anticipated in the statements made.
    For this purpose, any statements contained herein that are not statements of
    historical fact may be deemed to be forward-looking statements. Such risks
    and uncertainties include, but are not limited to, risks associated with
    operations, loss of market, regulatory matters, commodity price risk,
    environmental risks, industry competition, and ability to access sufficient
    capital from internal and external sources.
 
 Additional
    information relating to the Company, including the Company's Annual
    Information Form, can be found at www.sedar.com.
 
 The
    date of this MD&A is March 22, 2005.
 
 **Selected
    Annual Information**
 
 *($thousands,
            except per share amounts)***2004**
        
        **2003**
        
        **2002**Production
            revenue
        
        $
        31,717.0
        
        $
        24,679.8
        
        $
        19,355.6Cash
            flow from operations
        
        $
        13,384.5
        
        $
        10,386.2
        
        $
        7,417.4per
            share - basic
        
        $
        0.42
        
        $
        0.42
        
        $
        0.34per
            share - diluted
        
        $
        0.41
        
        $
        0.40
        
        $
        0.32Net
            income
        
        $
        3,401.6
        
        $
        3,040.5
        
        $
        2,435.5per
            share - basic
        
        $
        0.11
        
        $
        0.12
        
        $
        0.11per
            share - diluted
        
        $
        0.10
        
        $
        0.12
        
        $
        0.10Total
            assets
        
        $
        95,514.3
        
        $
        53,472.6
        
        $
        36,422.7Long-term
            financial liabilities
        
        $
        9,772.4
        
        $
        7,704.5
        
        $
        6,816.3
 
  
  **Production
    and Pricing**
 
 The
    majority of Gentry's activities and a growing amount of its oil and gas
    production are from Alberta. Previously, most of the Company's oil
    production had been derived from Saskatchewan while the majority of its gas
    production was generated in Alberta. Whereas the Saskatchewan crude varies
    from medium to light gravity in the southeast of the province to a heavier
    blend in the central area, the new Alberta crude is a medium gravity oil.
    Gentry's growth in 2004 gas production came largely from the southern
    portions of Alberta, particularly at Princess and Sedalia. Gains in 2005 gas
    production are slated to come primarily from the Princess and Whitecourt
    areas, while the driving force behind increased oil production is Princess.
 
 Oil
              & Liquids
          
          **Revenue**
            **($
              thousands)**
          
          **Volume**
            **(bbls/d)**
          
          **Price**
            **($/bbl)**2004
          
          
          13,525.0
          
          
          862
          
          
          42.882003
          
          
          11,860.4
          
          
          897
          
          
          36.222002
          
          
          12,139.8
          
          
          991
          
          
          33.55
  Natural
                Gas
            
            **Revenue**
              **($
                thousands)**
            
            **Volume**
              **(mcf/d)**
            
            **Price**
              **($/mcf)**2004
            
            
            18,192.0
            
            
            7,555
            
            
            6.582003
            
            
            12,819.4
            
            
            5,330
            
            
            6.592002
            
            
            7,215.8
            
            
            4,741
            
            
            4.17
  Boe
            
            **Revenue**
              **($
                thousands)**
            
            **Volume**
              **(boe/d)**
            
            **Price**
              **($/boe)**2004
            
            
            31,717.0
            
            
            2,121
            
            
            40.862003
            
            
            24,679.8
            
            
            1,785
            
            
            37.872002
            
            
            19,355.6
            
            
            1,781
            
            
            29.77
 
 Gross
    production revenue increased 29% in 2004 to $31.72 million from $24.68
    million a year ago. The majority of this increase was a result of higher
    natural gas sales which showed a marked improvement.
 
 Gentry's
    natural gas sales rose 42% to 7,555 mcf/d from 5,330 mcf/d in 2003. This
    increase contributed $5.40 million to the change in revenue which more than
    offset the $434 thousand lost due to the 4% reduction of oil sales to 862
    bbls/d from 897 bbls/d a year ago.
 
 Changes
    in oil and liquids pricing had a positive effect on revenues as the increase
    from $36.22/bbl to $42.88/bbl increased revenues $2.10 million. The
    negligible $0.01 reduction in gas prices to $6.58/mcf in 2004 only reduced
    revenue by $28 thousand when compared to the comparative period.
 
 Gentry
    has not had any forward contracts for the sale of commodities since 2001 and
    none are in place for 2005.
 
  
  **Royalties**
 
 Gentry's
    royalties, net of Alberta Royalty Tax Credit (ARTC), increased 24% to $6.27
    million from $5.07 million in 2003. Expressed as a percentage of production,
    oil royalties were 21.2% in 2004 versus 22.6% in 2003. Gas royalties were
    unchanged at 18.6% of gas production. On a boe basis, the percentages were
    19.8% in 2004 and 20.5% in 2003. The shift in production weighting from
    Saskatchewan to Alberta, which generally has a more favorable royalty regime
    for the Company's assets, is the primary reason for the overall decrease
    in royalties as a percentage of revenues.
 
 *($thousands)*
        
        **2004**
        
        **2003**
        
        **2002**Crown
            royalties
        
        
        3,689.5
        
        
        3,054.7
        
        
        2,225.3Freehold
            royalties
        
        
        2,128.7
        
        
        1,821.7
        
        
        1,634.3Overriding
            royalties
        
        
        886.3
        
        
        502.2
        
        
        528.9Gross
            royalties
        
        
        6,704.5
        
        
        5,378.6
        
        
        4,388.5ARTC
        
        
        (439.5
        )
        
        (311.5
        )
        
        (163.3
        )Net
            royalties
        
        $
        6,265.0
        
        $
        5,067.1
        
        $
        4,225.2As
            a % of revenue
        
        
        19.8
        %
        
        20.5
        %
        
        21.8
        %
 
 **Production
    Expenses**
 
 Gross
    production expenses increased 31% to $7.27 million from $5.56 million in
    2003. On a barrel of equivalent basis, costs increased 10% to $9.37/boe from
    $8.54/boe in 2003. Increased gathering, compression and processing costs at
    Sedalia and higher processing fees and interruptions associated with new
    production at Princess were the two leading factors behind this increase.
    Gentry is reviewing facility issues at Sedalia, while at Princess, the
    Company has recently completed the construction of a large oil battery as
    well as finished the electrification of certain other facilities in the area
    which should result in an immediate decline in unit production costs.
 
 **General
    and Administrative Expenses**
 
 Gentry's
    general and administrative expenses increased 39% to $3.17 million in 2004
    from $2.28 million in 2003. 41% of this increase was due to additional staff
    and compensation requirements as the Company continued to expand its
    activities. Higher professional and consulting fees, due in large part to
    increased regulatory compliance costs, accounted for a 38% rise in expenses.
    On a barrel of oil equivalent basis, general and administrative expenses
    increased 17% to $4.09/boe from $3.50/boe in 2003. Going forward, moderate
    increases to gross administrative costs are expected, however, as production
    increases, it is anticipated that per unit costs will decline.
 
  
  **Stock
    Based Compensation**
 
 In
    2004, Gentry's stock based compensation expense was $376 thousand versus
    $175 thousand a year ago. In the most recent year, $297 thousand related to
    the value of vested incentive stock options while the remaining $79 thousand
    was the value of Gentry's portion of the shares issued under the Company's
    Employee Share Ownership Plan (ESOP). This compares to the prior year
    figures of $113 thousand from stock options and $62 thousand from the ESOP.
 
 **Interest
    Expense**
 
 Gentry's
    interest expense increased to $698 thousand in 2004 from $484 thousand in
    2003. While interest rates fell from an average of 4.7% in 2003 to 4.0% in
    2004, the greater interest cost resulted from of a higher utilization of the
    Company's credit facilities to fund its capital exploration programs.
 
 **Depletion,
    Depreciation and Accretion**
 
 These
    charges for 2004 were $9.05 million compared with $7.08 million in the
    previous year. This trend is expected to continue as the Company increases
    its asset base through its capital programs. On a barrel of oil equivalent
    basis, costs increased to $11.65/boe versus $10.86/boe in 2003.
 
 Included
    in the above amounts is accretion expense, which is the amortization of the
    Company's asset retirement obligations. For 2004, this expense amounted to
    $102 thousand, or $0.13/boe, compared to $76 thousand, or $0.12/boe, a year
    ago.
 
 The
    Company's depletion rate fell to 12.78% in 2004 from 14.54% in 2003 and is
    based on the ratio of annual production to proved reserves estimates. While
    production increased 19%, reserves increased 36%, which accounted for the
    lower rate.
 
 **Income
    Taxes**
 
 Gentry
    was liable for $924 thousand in current taxes in 2004 which was a negligible
    decrease from $941 thousand in 2003. On a unit of production basis, however,
    current taxes were $1.19/boe versus $1.44/boe a year ago.
 
 Future
    taxes increased substantially to $560 thousand in 2004 from $87 thousand in
    2003. On a unit of production basis, future taxes for 2004 equated to $0.72/boe
    versus $0.13/boe in 2003. The increase was largely due to the use of more
    tax deductions to keep current taxes at lower levels.
 
 As
    a result of flow-through financings in 2004, Gentry agreed to renounce $2.82
    million of Canadian Exploration Expenditures (CEE) in 2004. $2.50 million
    was incurred prior to year-end and the remaining $320 thousand has occurred
    in 2005.
 
  
  At
    the end of 2004, Gentry has approximately $55.85 million of accumulated tax
    pools available for deduction against income in future years.
 
 *($thousands)*
        
        **Available
            balance**
        
        **Maximum
            Annual deduction**Canadian
            oil and gas property expense
        
        $
        26,362.6
        
        
        10
        %Canadian
            development expense
        
        
        5,241.9
        
        
        30
        %Canadian
            exploration expense
        
        
        10,249.1
        
        
        100
        %Foreign
            exploration and development expense
        
        
        237.9
        
        
        10
        %Undepreciated
            capital cost
        
        
        11,987.3
        
        
        20-100
        %Cumulative
            eligible capital
        
        
        64.0
        
        
        7
        %Financing
            costs
        
        
        1,706.4
        
        
        20
        %Total
        
        $
        55,849.2
 
 **Cash
    Flow and Net Income**
 
 In
    2004, cash flow from operations reached a record high of $13.38 million, an
    increase of 29% from $10.39 million in 2003. This increase was largely
    achieved from higher net revenues as a result of increases in production and
    commodity prices.
 
 Net
    income increased 12% to $3.40 million from $3.04 million in 2003. In
    assessing the change in net income, the positive impact of the extra $3
    million in cash flow was greatly reduced by the additional $1.97 million in
    depletion and depreciation charges and $474 thousand in future taxes.
 
 On
    a per share basis, cash flow was $0.42 per share ($0.41 diluted) in 2004
    compared to $0.42 ($0.40 diluted) in 2003. Net income was $0.11 per share
    ($0.10 diluted) versus $0.12 per share ($0.12 diluted) a year ago. The
    greater number of shares issued pursuant to financings to acquire additional
    undeveloped interests in the Princess area caused the per share amounts to
    remain constant.
 
 **Corporate
    Netbacks**
 
 *($/boe)*
        
        **2004**
        
        **2003**
        
        **2002**Selling
            price
        
        
        40.86
        
        
        37.87
        
        
        29.77Royalties
            (net of ARTC)
        
        
        (8.07
        )
        
        (7.78
        )
        
        (6.50
        )Production
            expenses
        
        
        (9.37
        )
        
        (8.54
        )
        
        (6.86
        )Operating
            netbacks
        
        
        23.42
        
        
        21.55
        
        
        16.41Administration
        
        
        (4.09
        )
        
        (3.50
        )
        
        (3.17
        )Interest
        
        
        (0.90
        )
        
        (0.74
        )
        
        (0.63
        )Current
            taxes
        
        
        (1.19
        )
        
        (1.44
        )
        
        (1.46
        )Other
            income
        
        
        -
        
        
        0.07
        
        
        0.26Cash
            flow
        
        
        17.24
        
        
        15.94
        
        
        11.41Depletion
            and depreciation
        
        
        (11.65
        )
        
        (10.86
        )
        
        (6.57
        )Future
            taxes
        
        
        (0.72
        )
        
        (0.13
        )
        
        (1.00
        )Non-cash
            compensation
        
        
        (0.49
        )
        
        (0.27
        )
        
        -Other
            expenses
        
        
        -
        
        
        (0.01
        )
        
        (0.09
        )Net
            income
        
        
        4.38
        
        
        4.67
        
        
        3.75
 
  
  **Capital
    Expenditures**
 
 Net
    capital expenditures increased 100% in 2004 to $43.40 million from $21.65
    million in 2003. The increase was due to a record level of activity for the
    Company as it continued to increase drilling in all of its core exploration
    areas; pursue an aggressive land acquisition program to facilitate further
    exploration activities; and to acquire and build additional infrastructure
    to bring new volumes onstream.
 
 *($thousands)*
        
        **2004**
        
        **2003**
        
        **2002**Drilling
            and completions
        
        $
        11,773.5
        
        $
        9,723.8
        
        $
        5,113.1Facilities
            and equipping
        
        
        6,403.3
        
        
        4,208.4
        
        
        1,298.4Land
            and seismic
        
        
        7,359.8
        
        
        4,160.4
        
        
        1,355.6Acquisitions,
            net
        
        
        16,571.0
        
        
        2,503.6
        
        
        -Capitalized
            Expenses
        
        
        1,165.3
        
        
        848.0
        
        
        796.3Other
        
        
        128.5
        
        
        209.3
        
        
        57.5$
        43,401.4
        
        $
        21,653.5
        
        $
        8,620.9
 
 The
    acquisition costs included the $16.25 million purchase of interests in the
    Princess and Bantry areas of Southern Alberta. The acquisition, which closed
    in September, included approximately 275 boe/d of production net to Gentry
    and 155 sections (120 net) of undeveloped land split between two blocks.
 
 The
    Company participated in 52 gross wells (33.5 net) in 2004 for a success rate
    of 85% (86% net). This compares to 55 gross wells (27.7 net) and a success
    rate of 71% (73% net) in 2003.
 
 **Net
    Asset Value**
 
 At
    December 31, 2004, the Company's net asset value, based on a 10% discount
    on future cash flow, equated to $4.04 per share compared with $2.17 per
    share in 2003. The following is a summary of the Net Asset Value
    calculation, discounted at 10%:
 *($thousands,
            except per share amounts)*
        
        **2004**
        
        **2003**
        
        **2002**Reserves
        
        $
        129,322
        
        $
        59,048
        
        $
        48,027Undeveloped
            land and seismic1
        
        
        37,101
        
        
        9,960
        
        
        5,475Investments2
        
        
        8,698
        
        
        3,827
        
        
        4,028Net
            debt
        
        
        (19,729
        )
        
        (13,443
        )
        
        (7,225
        )Net
            Asset Value
        
        $
        155,392
        
        $
        59,392
        
        $
        50,305Common
            shares outstanding
        
        
        38,471
        
        
        27,353
        
        
        23,783Net
            asset value per common share
        
        $
        4.04
        
        $
        2.17
        
        $
        2.12
 (1)
        internal
            estimate
 (2)
        market
            value as at December 31
 
 **Liquidity
    and Capital Resources**
 
 In
    2004, Gentry closed two financings with underwriters and one financing with
    the management group. In the first two financings, 9.5 million common shares
    were issued at a weighted average price of $2.40 per share and one million
    shares were issued on a flow-through basis at $2.50 per share for gross
    proceeds of $25.33 million. The management group financing consisted of
    80,000 shares issued on a flow-through basis at $4.00 per share. The
    proceeds from each financing were initially applied to Gentry's bank
    indebtedness and then drawn on to fund capital commitments as required.
 
 
 Gentry
    began the year with 27,352,508 common shares issued and outstanding. During
    2004, 10,580,000 shares were issued pursuant to the aforementioned
    financings; 150,000 shares were issued on the exercised of previously issued
    share purchase warrants ($1.75 per share); 580,000 shares were issued on the
    exercise of incentive stock options ($0.55 per share); 68,826 shares were
    issued pursuant to the Company's employee share purchase plan ($2.30 per
    share); and 260,100 shares were repurchased and cancelled pursuant to the
    Company's Normal Course Issuer Bid ($2.41 per share). As a result of these
    changes, Gentry ended the year with 38,471,234 common shares issued and
    outstanding. As of the date of this MD&A, 38,850,168 common shares are
    outstanding and a further 2,698,000 shares are reserved for issuance
    pursuant to the exercise of outstanding incentive stock options (at an
    average price of $1.69 per share).
 
 Gentry's
    year-end net debt was $19.73 million compared with $13.44 million at the end
    of 2003. Gentry's credit limit stands at $35 million and is reviewed
    semi-annually. The limit is currently being reviewed based upon the Company's
    December 31, 2004 Reserves Report.
 
 **Contractual
    Obligations**
 
 In
    the normal course of business, Gentry has entered into the following
    contractual obligations and commitments:
 
 *($thousands)*
        
        **2005**
        
        **2006**
        
        **2007**
        
        **2008**
        
        **Thereafter**
        
        **Total**Office
            lease
        
        $
        173.5
        
        $
        173.5
        
        $
        173.5
        
        $
        159.1
        
        
        -
        
        $
        679.6Flow-through
            commitments
        
        
        320.0
        
        
        -
        
        
        -
        
        
        -
        
        
        -
        
        
        320.0Firm
            service transportation
        
        
        56.9
        
        
        56.9
        
        
        56.9
        
        
        -
        
        
        -
        
        
        170.7Operating
            lease
        
        
        23.0
        
        
        -
        
        
        -
        
        
        -
        
        
        -
        
        
        23.0$
        573.4
        
        $
        230.4
        
        $
        230.4
        
        $
        159.1
        
        
        -
        
        $
        1,193.3
 
 **Off-Balance
    Sheet Arrangements**
 
 Gentry
    has no off-balance sheet arrangements.
 
 **Related
    Party Transactions**
 
 A.
    Bruce Macdonald, a director of the Company, is a shareholder, director and
    officer of Hawkeye Resources Ltd., which provides management advisory and
    consulting services to Gentry. These management services are in addition to
    Mr. Macdonald's duties and responsibilities as a director of the Company. In
    2004, Hawkeye received $77,250 in consulting fees from the Company.
 
  
  **Fourth
    Quarter Results**
 
 Gentry's
    financial and operating highlights from the fourth quarter of 2004, as
    compared with the fourth quarter of 2003, are summarized below:
 
 *Three
            months ended December 31*
        
        **2004**
        
        **2003**
        
        **%
            change****Financial***($thousands)*Gross
            revenue
        
        **$**
        **9,193.1**
        
        $
        6,695.5
        
        
        37
        %Royalties,
            net of ARTC
        
        
        **1,917.2**
        
        
        1,418.4
        
        
        35
        %Production
            expenses
        
        
        **2,682.1**
        
        
        1,768.9
        
        
        52
        %Administrative
        
        
        **1,054.5**
        
        
        649.5
        
        
        62
        %Current
            taxes
        
        
        **213.8**
        
        
        243.2
        
        
        (12
        )%Cash
            flow
        
        
        **3,028.8**
        
        
        2,469.6
        
        
        23
        %Depreciation
            and depletion
        
        
        **2,934.9**
        
        
        2,893.9
        
        
        1
        %Future
            taxes (recovery)
        
        
        **(556.0**
        **)**
        
        (857.0
        )
        
        (35
        )%Net
            income
        
        
        **501.2**
        
        
        302.5
        
        
        66
        %Capital
            expenditures, net
        
        **$**
        **11,095.0**
        
        $
        6,369.5
        
        
        74
        %**Production**Oil
            & Liquids (bbls/d)
        
        
        **960**
        
        
        958
        
        
        -Gas
            (mcf/d)
        
        
        **8,869**
        
        
        6,865
        
        
        29
        %Barrels
            of oil equivalent
        
        
        **2,439**
        
        
        2,103
        
        
        16
        %**Pricing**Oil
            & Liquids ($/bbl)
        
        **$**
        **43.34**
        
        $
        33.62
        
        
        29
        %Natural
            gas ($/mcf)
        
        **$**
        **6.57**
        
        $
        5.91
        
        
        11
        %Boe
            ($/boe)
        
        **$**
        **40.98**
        
        $
        34.61
        
        
        18
        %
 
 The
    37% growth in production revenue in the fourth quarter of 2004, when
    compared to the fourth quarter of 2003, came from increased gas volumes as
    well as increased pricing for both gas and oil and liquids. As expected,
    royalty expense increased by slightly less than the same percentage, for the
    same reasons as described on the annual basis.
 
 Cash
    flow was up 23% over the comparative fourth quarter. Somewhat mitigating the
    effect of the higher revenue were higher production expenses and general and
    administrative costs. Production expenses included an adjustment to prior
    estimates while higher professional fees and compensation costs made up the
    majority of the increase to administrative costs.
 
 Depletion
    and depreciation remained relatively flat in the fourth quarters of 2004 and
    2003. The fourth quarter expenses contain adjustments to reconcile the
    previous nine-month provision to the annual provision, which is based on the
    updated independent engineering evaluation.
 
 Based
    largely on the foregoing, net income increased to $501 thousand from the
    $303 thousand recorded in the fourth quarter of 2003.
 
 Capital
    expenditures increased significantly, to $11.09 million from $6.37 million a
    year ago. Drilling and completions were up 58% to $6.40 million while
    facilities and equipping was up 117% to $3.21 million as construction began
    on the Company's oil battery at Princess.
 
  
  **Selected
    Quarterly Information**
 
 2004
        
        2003Quarter
            ended Dec 31
        
        Quarter
            ended Sep 30
        
        Quarter
            ended Jun 30
        
        Quarter
            ended Mar 31
        
        Quarter
            ended Dec 31
        
        Quarter
            ended Sep 30
        
        Quarter
            ended Jun 30
        
        Quarter
            ended Mar 31Productionbbls/d
        
        
        960
        
        
        808
        
        
        808
        
        
        870
        
        
        958
        
        
        857
        
        
        903
        
        
        869mcf/d
        
        
        8,869
        
        
        7,753
        
        
        6,663
        
        
        6,919
        
        
        6,865
        
        
        5,713
        
        
        4,154
        
        
        4,557boe/d
        
        
        2,439
        
        
        2,100
        
        
        1,919
        
        
        2,023
        
        
        2,103
        
        
        1,810
        
        
        1,595
        
        
        1,628FinancialProduction
            revenue
        
        
        9,193.1
        
        
        8,019.9
        
        
        7,438.0
        
        
        7,066.0
        
        
        6,695.5
        
        
        5,866.8
        
        
        5,354.5
        
        
        6,763.0Cash
            flow from operations
        
        
        3,028.8
        
        
        3,870.5
        
        
        3,330.5
        
        
        3,154.7
        
        
        2,469.6
        
        
        2,741.7
        
        
        1,917.0
        
        
        3,257.9per
            share - basic
        
        
        0.09
        
        
        0.11
        
        
        0.11
        
        
        0.12
        
        
        0.09
        
        
        0.11
        
        
        0.08
        
        
        0.14per
            share - diluted
        
        
        0.08
        
        
        0.11
        
        
        0.10
        
        
        0.11
        
        
        0.09
        
        
        0.11
        
        
        0.08
        
        
        0.13Net
            income
        
        
        501.2
        
        
        1,114.7
        
        
        1,128.0
        
        
        657.6
        
        
        302.5
        
        
        616.8
        
        
        515.2
        
        
        1,606.0per
            share - basic
        
        
        0.01
        
        
        0.03
        
        
        0.04
        
        
        0.02
        
        
        0.01
        
        
        0.03
        
        
        0.02
        
        
        0.07per
            share - diluted
        
        
        0.01
        
        
        0.03
        
        
        0.04
        
        
        0.02
        
        
        0.01
        
        
        0.02
        
        
        0.02
        
        
        0.07
 
 **Proposed
    Transactions**
 
 In
    November, Gentry entered into a letter agreement to acquire certain oil and
    natural gas interests in the Princess area for $8.08 million. The interests
    include approximately 195 boe/d of production, all of which is currently
    operated by Gentry. The transaction, anticipated to close by the end of
    March or early April, is subject to certain rights of first refusal and as
    such, it is not yet known what the final interest or cost accruing to Gentry
    will be.
 
 **Critical
    Accounting Estimates**
 
 Gentry
    is required to make certain assumptions and estimates in the application of
    generally accepted accounting principles that may have a significant impact
    on the financial results of the Company. The following is a discussion of
    the estimates that are critical to Gentry's consolidated financial
    statements.
 
 *Oil
    and Natural Gas Reserves and Full Cost Accounting*
 
 Gentry
    follows the full cost method of accounting for its oil and gas properties
    and equipment as prescribed by the Canadian Institute of Chartered
    Accountants (CICA). Accordingly, all costs associated with the acquisition,
    development and exploration of oil and natural gas reserves are capitalized
    and then depleted using the unit-of-production method based on estimated
    proved reserves. A ceiling test ensures the carrying value of a long-life
    asset can be recovered from its undiscounted future cash flows.
 
 Reserve
    estimates can have a significant impact on net income and the carrying value
    of property and equipment as they are the key component in the calculation
    of both depletion and depreciation and the ceiling test. Revisions to
    reserve estimates could result in a higher or lower depletion and
    depreciation expense being charged to net income while downward revisions to
    reserve estimates could result in a write down of property and equipment
    based on the ceiling test.
 
 100%
    of Gentry's reserves are evaluated by the independent engineering firm of
    Martin Brusset and Associates. This evaluation requires significant
    estimates to be made on various engineering data as well as future
    production rates, capital expenditures, and commodity prices, all of which
    are subject to a number of uncertainties and various interpretations. The
    Company expects that over time its estimates of reserves will be revised,
    either upwards or downwards, based on future drilling, testing, production
    rates and commodity forecasts.
 
 
  *Asset
    Retirement Obligations*
 
 Gentry
    estimates the fair value of each asset retirement obligation. The obligation
    is based on current regulations, costs, technologies, and industry standards
    and is calculated using estimates for the timing of abandonment, inflation,
    and a credit-adjusted risk-free interest rate. The discounted obligation is
    initially capitalized as part of the carrying amount of the property and
    equipment and a corresponding liability is recognized. The increase in
    property and equipment is depleted and depreciated on the same basis as the
    remainder of the property and equipment. The liability is accreted against
    income, until it is settled or the property is sold, and is included as a
    component of depletion and depreciation expense.
 
 Retirement
    obligations can have a material impact on the both the consolidated balance
    sheets and consolidated statements of income of the Company. Revisions to
    any or all of the aforementioned factors and estimates used in calculating
    the obligation may result in a changes to the carrying value of property and
    equipment and the related liability, as well as the depletion and
    depreciation expense charged to net income. The Company expects that over
    time its estimate of its asset retirement obligations will be revised,
    either upwards or downwards, based on future regulations, costs,
    technologies, industry standards, timing of abandonments, and interest and
    inflation rates.
 
 *Stock-based
    Compensation*
 
 Gentry
    follows the fair value method of accounting for its stock-based compensation
    arrangements relating to stock options grants. The Company recognizes a
    compensation expense based on the fair value of the options on the date of
    grant using the Black-Scholes option-pricing method and amortizes the
    expense over the vesting period of the options. The Black-Scholes method
    requires estimates for the volatility of the Company's stock, a risk free
    interest rate, an expected dividend rate, and the expected life of the
    options. Changes in these estimates will change the fair value of the option
    and affect the compensation expense recorded in the consolidated financial
    statements.
 
 *Other
    Accounting Estimates*
 
 Gentry
    follows the accrual method of accounting which requires the Company to
    incorporate certain estimates in its financial and operating results. This
    includes estimates of revenues, royalties, production expenses and capital
    items for specific reporting periods for which actual results have not yet
    been received. Gentry ensures that the personnel with the most knowledge of
    the relevant activities are responsible for the estimates, which are then
    reviewed for reasonableness. Past estimates are also compared to actual
    results in order to make more informed decisions when accruing future
    amounts.
 
 
 **New
    Accounting Standards**
 
 During
    the past year, a number of changes to financial reporting requirements have
    been introduced. The following outlines the most notable changes and those
    which have the greatest impact on Gentry.
 
 *Full
    Cost Accounting*
 
 Effective
    for fiscal years beginning on or after January 1, 2004, the Canadian
    Institute of Chartered Accountants (CICA) issued Accounting Guideline 16 -
    "Oil and Gas Accounting - Full Cost" which changes the calculation of
    the ceiling test. The new standard requires that an impairment be recognized
    if the carrying value of a long-life asset can not be recovered from its
    undiscounted future cash flows. An impairment, if required, is then
    determined as the difference between the carrying value and the fair value
    of the asset, such fair value to be based on the present value of the
    expected future discounted cash flows. Gentry performed this ceiling test
    calculation as at December 31, 2004 and 2003 and there was no impact on the
    Company under the new guideline.
 
 
  *Asset
    Retirement Obligations*
 
 The
    CICA introduced handbook section 3110 - "Asset Retirement Obligations"
    which became effective January 1, 2004, although early adoption was
    encouraged. Under this section, the Company is required to record the fair
    value of a liability for an asset retirement obligation in the period in
    which it is incurred. When the liability is first recorded, it is added at
    fair value to property and equipment. It is then amortized against income as
    a component of depletion and depreciation expense using the
    unit-of-production method. The Company elected to adopt this policy
    effective January 1, 2003, with restatement of prior periods, and a summary
    of the effects of this new policy is contained in Note 3 of the Consolidated
    Financial Statements.
 
 *Stock-based
    Compensation*
 
 On
    October 1, 2003, and with effect from January 1, 2003, the Company
    prospectively adopted the CICA's new standard with respect to accounting
    for stock-based compensation arrangements relating to stock options granted
    to employees, officers and directors. Under the transitional provisions of
    the standard, stock options granted to employees, officers and directors
    after the effective date of January 1, 2003 are accounted for using the fair
    value method. As a result of this change, Gentry increased stock based
    compensation costs by $297 thousand in 2004 and $113 thousand in 2003. A
    summary of the assumptions used in calculating the stock-based compensation
    expense in contained in Note 9(f) of the Consolidation Financial Statements.
 
 *Hedging
    Relationships*
 
 The
    CICA issued Accounting Guideline 13 - "Hedging Relationships", which is
    effective for the Company's fiscal year beginning January 1, 2004. The new
    standard requires the identification, designation, documentation and
    measurement of hedging relationships in order to apply hedge accounting.
    Additional changes are also being proposed for interim and annual financial
    statements beginning on or after October 1, 2006, however as Gentry had no
    hedges in place in 2004 and none for 2005, these policy changes currently
    have no effect on the Company.
 
 *Flow-through
    Shares*
 
 This
    new guideline, in effect for all flow-through share transactions initiated
    after March 19, 2004, requires that the income tax effect of expenditures
    renounced on flow-through shares be recognized on the date the Company
    renounces the expenditures. Previously, the Company recognized the income
    tax effect when the expenditures were incurred. This pronouncement has no
    material effect on the Company.
 
 *Earnings
    per Share*
 
 The
    CICA introduced handbook section 3500 - "Earnings per Share" which
    became effective for interim and fiscal years beginning on or after January
    1, 2005. The main feature of this section, as it currently pertains to
    Gentry, is that the number of incremental shares included in year-to-date
    diluted Earnings per Share (EPS) is to be computed using the average market
    price of common shares for the year-to-date period, rather than on a
    quarterly basis, as Gentry computed it in 2004. This change is not expected
    to have material effect on the Company's diluted EPS.
 
  
  *Comprehensive
    Income*
 
 The
    CICA is expected to issue a new standard for interim and annual financial
    statements beginning on or after October 1, 2006 (with early adoption
    permitted) regarding Comprehensive Income. The standard, if instituted,
    would require Gentry to recognize gains and losses arising from the
    fluctuation of the share price of its investments and include these gains
    and losses as a separate component in the Income Statement with the
    accumulated gains and losses shown as a separate component of Shareholders
    Equity. Currently, Gentry follows the cost method of accounting for its
    investment whereby no gains or losses on investments are recognized unless
    there has been a permanent decline in value.
 
 **Business
    Risks and Uncertainties**
 
 Gentry,
    like all companies in the oil and gas industry, operates in an environment
    subject to inherent risks. Many such uncertainties are beyond the ability of
    a company to control - particularly those associated with exploring for, and
    developing, economic quantities of hydrocarbons; volatile commodity prices;
    issues related to global supply and demand; governmental regulations; and
    environmental matters. The Company's business is affected by these risks
    to the same degree as any other participant in the upstream Canadian oil and
    gas industry. Gentry has implemented risk protection through such means as
    maintaining a broad base of interests in core areas of the Western Canadian
    Sedimentary Basin that have long-term production and reserves. In addition,
    through its investment in Stratic, the Company participates in selected
    international exploration ventures of high potential that nonetheless add
    certain political and technical business risks. Such risks are mitigated by
    operating in politically and economically stable countries, and by aligning
    with joint venture companies that have significant international experience.


---

Exhibit 4





|[gentry40f001.jpg] |                                                                                                                                                                                    
|------------------ | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                   |                                                                                                                                                                                    
|                   | Collins Barrow Calgary LLP
1400 First Alberta Place
777  8th Avenue S.W.
Calgary, Alberta, Canada
T2P 3R5

T.  (403) 298-1500
F.  (403) 298-5814
e-mail: calgary@collinsbarrow.com

March 28, 2005

U.S. Securities and Exchange Commission

Dear Sir or Madam:

Re:

Gentry Resources Ltd.

We consent to the use of our report dated March 4, 2005, with respect to the consolidated financial statements of Gentry Resources Ltd. included in this Annual Report on Form 40-F for the year ended December 31, 2004, filed with the U.S. Securities and Exchange Commission.

Yours very truly,

(signed) Collins Barrow Calgary LLP

CHARTERED ACCOUNTANTS

Calgary, Alberta

Canada

March 24, 2005



---

Exhibit 5











Consent of Martin & Brusset Associates



Reference is made to the Annual Report on Form 40-F for the year ended December 31, 2004 (the Annual Report) of Gentry Resources Ltd. (the Company), filed with the U.S. Securities and Exchange Commission.



We hereby consent to the references to our name under the heading Oil and Natural Gas Reserves in the Companys Annual Information Form and to all other references to our name included or incorporated by reference in the Annual Report, and we further consent to the reliance in the Annual Report on our independent technical report dated March 7, 2005 entitled Evaluation of the Oil and Gas Reserves Owned by Gentry Resources Ltd. Effective January 1, 2005 which the Company used, or directly quoted from, in preparing summaries concerning its oil and natural gas reserves, which appear in such Annual Report.







Martin & Brusset Associates



(signed) S. Neil Sedgwick

S. Neil Sedgwick, B.Sc., P. Eng.

Principal - Manager





March 28, 2005





---

Exhibit 6.1



CERTIFICATION

I, Hugh G. Ross, certify that:



1.  I have reviewed this annual report on Form 40-F of Gentry Resources Ltd.;



2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;



4.  The companys other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) [omitted pursuant to Transition Period provisions at Section III of Release 34-47986 of the Securities and Exchange Commission entitled Managements Reports on Internal Control over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports] for the company and have:



(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b) [omitted pursuant to Transition Period provisions at Section III of Release 34-47986 of the Securities and Exchange Commission entitled Managements Reports on Internal Control over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports];



(c) Evaluated the effectiveness of the companys disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d) Disclosed in this report any change in the companys internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the companys internal control over financial reporting; and



5.  The companys other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the companys auditors and the audit committee of the companys board of directors (or persons performing the equivalent functions):



(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the companys ability to record, process, summarize and report financial information; and



(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the companys internal control over financial reporting.



Date:  March 28, 2005



Signed:Hugh G. Ross



Hugh G. Ross, President and Chief Executive Officer

---



Exhibit 6.2

CERTIFICATION

I, Ketan Panchmatia, certify that:



1.  I have reviewed this annual report on Form 40-F of Gentry Resources Ltd.;



2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;



4.  The companys other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) [omitted pursuant to Transition Period provisions at Section III of Release 34-47986 of the Securities and Exchange Commission entitled Managements Reports on Internal Control over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports] for the company and have:



(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b) [omitted pursuant to Transition Period provisions at Section III of Release 34-47986 of the Securities and Exchange Commission entitled Managements Reports on Internal Control over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports];



(c) Evaluated the effectiveness of the companys disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d) Disclosed in this report any change in the companys internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the companys internal control over financial reporting; and



5.  The companys other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the companys auditors and the audit committee of the companys board of directors (or persons performing the equivalent functions):



(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the companys ability to record, process, summarize and report financial information; and



(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the companys internal control over financial reporting.



Date:  March 28, 2005



Signed:Ketan Panchmatia



Ketan Panchmatia, Vice President, Finance and Chief Financial Officer

---

Exhibit 7.1



CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002



In connection with the annual report on Form 40-F of Gentry Resources Ltd. for the year ended December 31, 2004, as filed with the Securities and Exchange Commission, I hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:



1.  The annual report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and



2.  The information contained in the annual report fairly presents, in all material respects, the financial condition and results of operations of the registrant.





Date:  March 28, 2005





Signed:Hugh G. Ross



Hugh G. Ross, President and Chief Executive Officer





A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.



---

Exhibit 7.2



CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002



In connection with the annual report on Form 40-F of Gentry Resources Ltd. for the year ended December 31, 2004, as filed with the Securities and Exchange Commission, I hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:



1.  The annual report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and



2.  The information contained in the annual report fairly presents, in all material respects, the financial condition and results of operations of the registrant.





Date:  March 28, 2005





Signed:Ketan Panchmatia



Ketan Panchmatia

Vice President, Finance and Chief Financial Officer







A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.