SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

(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 12/31/06

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.

Burns & Levinson LLP

125 Summer Street, Boston, MA 02110

(617) 345-3000

(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:

38,811,130 Common Shares without Par Value



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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FORWARD-LOOKING STATEMENTS



Certain statements contained in this Annual Report on Form 40-F of Gentry Resources Ltd. (the Company) and the Exhibits included herein 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 Company 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 Report should not be unduly relied upon.



In particular, this Annual Report 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 Company 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 the Companys Annual Information Form for the year ended December 31, 2006 included herewith as Exhibit 1.



*      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 the Annual Information Form included herewith as Exhibit 1.



These factors should not be construed as exhaustive.  Except as required under applicable securities legislation, the Company undertakes no obligation to publicly update or revise forward-looking statements, whether as a result of new information, future events or otherwise.











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CURRENCY



Unless otherwise indicated, all dollar amounts in the Annual Report on Form 40-F are Canadian dollars.  On December 29, 2006, the noon buying rate in the City of New York for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was Canadian $1.00 = U.S. $0.8582, and on December 30, 2005, the rate was Canadian $1.00 = U.S. $0.8579.





PRINCIPAL DOCUMENTS



Annual Information Form



The Annual Information Form of Gentry Resources Ltd. (the Company) for the year ended December 31, 2006 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, 2006 and 2005, including the auditors report thereon dated March 20, 2007, are included herein as Exhibit 2.  Please refer to Note 11 to the audited consolidated financial statements for a reconciliation of the differences between Canadian and United States Generally Accepted Accounting Principles.



Managements Discussion and Analysis and Financial Review



The Companys Managements Discussion and Analysis for the year ended December 31, 2006 is included herein as Exhibit 3.





CONTROLS AND PROCEDURES



A.

Evaluation of Disclosure Controls and Procedures



As of December 31, 2006, 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







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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.

Managements Annual Report on Internal Control over Financial Reporting



The Companys management is responsible for establishing and maintaining adequate internal control over financial reporting.  Internal control over financial reporting is defined in Rule 13a-15(f) and Rule 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Companys principal executive and principal financial officers and effected by the Companys Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

The Companys management assessed the effectiveness of the Companys internal control over financial reporting as of December 31, 2006.  In making this assessment, it used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on the assessment, a deficiency in the control system has been identified.  As a small organization, and similar to other small organizations, the Companys staff and management is composed of a small number of individuals such that it is not economically feasible to achieve a complete segregation of duties.  As a result, the recording of certain financial transactions are not always subject to a complete independent review which in turn leads to an increased probability that an error or material misstatement to the annual or interim consolidated financial statements would not be prevented or detected.  As a result, management has determined that this control deficiency may constitute a material weakness and accordingly management has concluded that the Company did not maintain effective internal control over financial reporting as of December 31, 2006 based on the criteria set forth in the COSO framework.  Subsequent to December 31, 2006, the Company has hired additional staff which will assist with the financial transaction recording and review processes.

This annual report does not include an attestation report of the Companys registered public accounting firm regarding internal control over financial reporting.  Managements report was not subject to attestation by the Companys registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only managements report in this annual report.





C.

Changes in Internal Control over Financial Reporting



During the fiscal year ended December 31, 2006, 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 Michael Halvorson, A. Bruce Macdonald and Dean Prodan.  The Board has not designated a member of the Audit Committee as an Audit Committee Financial Expert as that term is defined under Section 407 of the Sarbanes-Oxley Act of 2002.  The Board believes that such a designation is not necessary at this time because the members of the Audit Committee are all financially literate as defined under Canadian regulations and each has current or prior experience serving on audit committees of publicly traded companies.  Accordingly, the Board believes that the Audit Committee as currently constituted has ample capability to discharge its advisory functions, duties and responsibilities as set forth in the Committees charter including financial statement review and responsibilities relating to the review and evaluation of the Companys external auditors.





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.











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PRINCIPAL ACCOUNTANT FEES AND SERVICES



The aggregate amounts billed by Collins Barrow Calgary LLP, Chartered Accountants (CBC) to the Company in each of the fiscal years ended December 31, 2006 and 2005 for audit fees, audit-related fees, tax fees and all other fees are set forth below:



Year Ended
December 31, 2006Year Ended
December 31, 2005Audit Fees (1)$  173,000$  115,300Audit-Related Fees (2)15,5004,654Tax Fees (3)--All Other Fees (4)-5,500Totals$  188,500$  125,454




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 corporate tax planning services.



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, 2006 were pre-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.













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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, 2006, under Contractual Obligations.





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



The Registrant has previously filed with the Commission a written irrevocable consent and power of attorney on Form F-X in connection with the filing of its Annual Report on Form 40-F for the year ended December 31, 2005.





EXHIBITS



The following exhibits are filed as part of this report:



1.

Annual Information Form for the year ended December 31, 2006



2.

Audited Consolidated Financial Statements for the years ended December 31, 2006 and 2005, together with the auditors report thereon dated March 20, 2007 (Note 11 to the audited consolidated financial statements relates to differences between Canadian and United States Generally Accepted Accounting Principles)



3.

Management Discussion and Analysis and Financial Review for the year ended December 31, 2006



4

Consent of Collins Barrow Calgary LLP, Chartered Accountants



5

Consent of Sproule Associates Limited



6.1

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









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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





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:

/s/ Ketan Panchmatia

Name:

Ketan Panchmatia

Title:

Chief Financial Officer





Date:

April 17, 2007







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Exhibit 1







[aif002.gif]









ANNUAL INFORMATION FORM









YEAR ENDED DECEMBER 31, 2006









March 28, 2007







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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

1

RECENT DEVELOPMENTS

3

DESCRIPTION OF THE BUSINESS

3

General

3

Principal Producing Properties

3

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

10

Reconciliation of Reserves

11

Reconciliation of Changes in Net Present Value of Future Net Revenue

11

Undeveloped Reserves

12

Future Development Costs

12

Oil and Natural Gas Wells and Properties

12

Unproved Properties

13

Exploration and Development Activities

13

Production Estimates

13

Quarterly Production History

14

Quarterly Netback History

14

Abandonment and Reclamation Costs

15

Tax Horizon

15

Costs Incurred

15

Environmental and Safety Matters

15

Insurance

16

Future Commitments

16

Human Resources

16

DIVIDENDS

17



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DESCRIPTION OF CAPITAL STRUCTURE

17

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

20

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

22

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

26

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;

"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;

"Sproule" means Sproule Associates Limited, an independent firm of Geological and Petroleum Engineering Consultants, Calgary, Alberta;

"Sproule Report" means the independent consultants' evaluation of Gentry's oil and natural gas properties prepared by Sproule dated March 02, 2007 and effective as of December 31, 2006; and

"TSX"means the Toronto Stock Exchange.

All information in the Annual Information Form is presented as at December 31, 2006 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                  | Encana Corporation 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 Sproule 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, 2006 and the information contained in the Annual Information Form has been prepared as of March 28, 2007.

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, 2006, 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, amongst 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, 2006

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.

On April 01, 2005, Gentry amalgamated with its wholly-owned subsidiaries, Gentry Resources (Saskatchewan) Ltd and Gentry Income Funds Inc and continued to operate as Gentry Resources Ltd.  Gentry currently has one wholly-owned inactive subsidiary, Gentry Resources (West Africa) Inc., which was incorporated under the ABCA.  As at December 31, 2006, Gentry also owns a 7.5% interest in the outstanding common equity of Stratic Energy Corporation ("Stratic"), a TSX Venture Exchange listed company which was continued under the Yukon Act.



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 and Saskatchewan.  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's Development over the Last Three Years

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 acquired 31 sections of land, of which the Corporation 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.



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In the Princess sub-area of Tide Lake/West Tide Lake, 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%.

Gentry closed two financings with underwriters and one with the management group in 2004.  In the first two financings, 9.5 million 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 total combined 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 upon to fund capital commitments as required.

Developments in 2005

In 2005, 48% of Gentrys production, or 1,580
boe/d, was derived from the Greater Princess area.  In January, a Gentry operated five
mmcf/d sweet gas plant came onstream at West Tide Lake, followed by the acquisition of a large oil facility which handles all of Gentrys Pekisko oil production from the area.  At Tilley, Gentry completed the construction of battery with a 10,000 bbl/d handling capacity.  In late 2005, construction was completed on a nine
mmcf/d third party sour gas plant adjacent to Gentrys Nisku field.  All of these capital projects helped alleviate production restrictions which have hindered production from the Greater Princess area over the past few years.

Gentry concluded two asset transactions in the Greater Princess area in 2005, the production from which are reflected in the above numbers.  At the end of the first quarter, Gentry acquired an additional 22% interest in the Tilley oil field for the sum of $8.08 million.  Production from the acquisition was approximately 195
boe/d net to Gentry and increased the Corporations interest in the field to approximately 72%.  In the second transaction, Gentry exchange its interest in a non core unit and two shallow gas wells for a battery and five sections of land at West Tide Lake.

At Sedalia, Gentry increased its landholdings to 80,248 acres and drilled 27 wells with a success rate of 92%.  The Corporation expanded out from its initial operational area to other properties with a view to drill deeper horizons targeting larger reservoirs and higher production rates.  Production of four mmcf/d at year-end was limited by capacity constraints although those restrictions eased such that Gentry flowed 5.5 mmcf/d to four separate third party processing facilities early in 2006.

Whitecourt is the Corporations higher risk, higher reward area.  Gentry participated in five wells resulting in two gas wells (0.5 net).  The most recent discovery well encountered a new gas pool and opened up a new play concept which was first identified on a 3D seismic survey which was shot in early 2005.  Production from the Whitecourt area averaged 187
boe/d net to Gentry.

The non-operated West Provost area saw the completion of an 18-well gas development drilling program in 2005.  Gas production from the area reached 1.2 mmcf/d net to Gentry once all the wells were been tied-in.

Developments in 2006

The Corporations activities were dominated by two farm-in agreements totalling 230 sections in the Princess area.  Gentry focused on meeting the commitments for these agreements, with first commitment of seven wells being completed within 60 days of signing.  The second commitment of 13 exploration wells is ongoing and expected to be completed by August, 2007.

The two agreements provide Gentry with an estimated 146,990 acres or 230 sections of petroleum and natural gas rights in the Mississippian aged Pekisko formation. Approximately 200 of those sections also include all rights in



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the Nisku formation. With this farm-in Gentry controls approximately 437 mostly contiguous sections with rights predominantly in the Pekisko and deeper formations in the Princess area.

Gentry received a licensed copy of the farmors proprietary 3D seismic covering an area of approximately 224 square miles, a vast majority of the farm-in lands. Costs of the seismic data are agreement specific and are discussed below.  Gentry owns or has access to 3D coverage over most of its entire 437 section block.

The first agreement, or development agreement, encompasses approximately 26.5 sections (16,960 acres) of development fairway.  These are lands that infill or are situated within 2 miles of existing Gentry-owned and operated infrastructure at Tilley and West Tide Lake.  Gentry drilled its seven commitment wells in the second quarter.  The earned lands have a five year term, after which any unearned lands will revert to the
farmor. All drill spacing units capable of production will remain with Gentry, subject to the farmors royalty.

The second agreement, or exploration agreement, encompasses approximately 203 sections (approximately 130,029 acres) and lies south of the West Tide Lake Pekisko oil pool and east of Gentrys Bantry block.  Under the terms of this agreement Gentry has agreed to drill 13 exploration wells, the last of which well must be drilled by August 31, 2007.  The agreement provides for rolling options to earn the remainder of the farm-in lands.  Each earning well will earn a six section block and each block will be chosen after the earning well is drilled and evaluated.  Each earned six section block will have a seven year term, after which the unearned lands will revert to the
farmor.  All drill spacing units capable of production will remain with Gentry, subject to the farmors royalty.

RECENT DEVELOPMENTS

Due to operational issues at Princess and Red Willow late in the fourth quarter of 2006 and early in the new year, Gentrys 2007 first quarter production is being impacted by approximately 700
boe/d, making current production roughly 3,700 boe/d.  First quarter 2007 drilling in the Princess area has resulted in discoveries which, when placed on stream late in the second quarter, should add approximately 700
boe/d net to the Corporation.



DESCRIPTION OF THE BUSINESS

General

The Corporation's principal properties are located in western Canada in the southern portions of Alberta and Saskatchewan.  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.

Principal Producing Properties

The following is a description of Gentry's principal producing oil and gas properties as of December 31, 2006.

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

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 4 bbls/d of oil and liquids and 226 mcf/d of gas in 2006.



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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. 2006 production averaged 893 bbls/d of oil and liquids and 8,084 mcf/d of gas.

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.  2006 production averaged 14 bbls/d and 1,587 mcf/d.

Red Willow North

The Red Willow North property is located approximately 100 kilometres east of Edmonton, Alberta.  Gentry owns interests varying from 40.4% to 75%.  The wells produced an average of 596 mcf/d of gas net to Gentry in 2006.

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 2006 averaged 48 bbls/d of oil and liquids and 3,855 mcf/d of gas.

West Provost

The West Provost area is located approximately 20 kilometres southeast of Coronation in east central Alberta.  Gentry owns a 27.34% interest in a Gas Unit and interests varying between 18.28% and 100% in the non-unit lands. For 2006, production averaged 72 bbls/d of oil and liquids and 1,072 mcf/d of gas.

Whitecourt

The Whitecourt lands are located west-central Alberta.  Gentry owns interests ranging between 20% and 50%.  Production in 2006 averaged 10 bbls/d of oil and 846 mcf/d of gas net to the Corporation.

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 33 bbls/d of crude oil in 2006.

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 2006 was approximately 74 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.  Gentrys share of production from these units averaged 86
bbls/d of crude oil and 11 mcf/d of gas in 2006.



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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.  Gentrys share of production from this unit was approximately 16
bbls/d of crude oil and 7 mcf/d of natural gas in 2006.

In the Steelman Unit 4, Gentry holds a 13.938% working interest in the Unit.  Gentrys share of production from this unit was approximately 74
bbls/d of crude oil and 55 mcf/d of natural gas in 2006.

In the Steelman Unit 5, Gentry holds a 19.927% working interest in the Unit. Gentrys share of production from this unit was approximately 22
bbls/d of crude oil and 8 mcf/d of natural gas in 2006.



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Summary of Production from Principal Producing Properties

During the year ended December 31, 2006, 91.1% of the Corporation's production was derived from Alberta and 8.9% from Saskatchewan.  The following table describes the Corporation's major properties and the averagedaily production from these properties during the year ended December 31, 2006.

|                 |                                     |                      |                
|---------------- | ----------------------------------- | -------------------- | ---------------
|                 | Product Type                       
|                 | Light & Medium Crude Oil
(bbls/day) | Natural Gas
Mcf/day) | Total
(boe/day)
|Alberta          |                                     |                      |                
|Joffre           | 4                                   | 226                  | 42             
|Princess         | 893                                 | 8,084                | 2,240          
|Red Willow       | 14                                  | 1,587                | 279            
|Red Willow North | -                                   | 596                  | 99             
|Sedalia          | 48                                  | 3,855                | 691            
|West Provost     | 72                                  | 1,072                | 251            
|Whitecourt       | 10                                  | 846                  | 151            
|Other            | 6                                   | 278                  | 52             
|                 |                                     |                      |                
|Saskatchewan     |                                     |                      |                
|Baldwinton       | 33                                  | -                    | 33             
|Benson           | 74                                  | -                    | 74             
|Dollard          | 86                                  | 11                   | 88             
|Steelman         | 112                                 | 70                   | 124            
|Other            | 46                                  | 33                   | 51             
|                 |                                     |                      |                
|TOTAL            | 1,398                               | 16,658               | 4,175          





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Marketing and Risk Management Arrangements

In 2006, 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 2006.  The Corporation does not currently have a hedging program in place for 2007.

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 Sproule Report, Sproule has evaluated all of the crude oil, NGLs and natural gas reserves associated with Gentry's properties effective as of December 31, 2006 in accordance with NI 51-101. There are no reserves evaluated or attributed to Gentry as a result of its investment in Stratic.

In preparing its report, Sproule 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 Sproule Report is based was obtained from public records, other operators and from Sproule'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 Sproule by third parties was accepted by Sproule as represented.

The following is a summary, as at December 31, 2006, 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 Sproule 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, 2006:



Forecast Prices and Costs



Summary of Oil & Gas Reserves

|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|-------------------------- | -------------------- | ----------- | ----------------------------------------- | ---------------------- | ------------------- | ---------- | ------------ | ---------- | ------------- | -----------
|                           | Light and Medium
Oil | Heavy Oil   | Natural Gas
(non-associated & associated) | Natural Gas
(solution) | Natural Gas Liquids
|Reserves Category          | Gross
(mbbls)        | Net
(mbbls) | Gross
(mbbls)                             | Net
(mbbls)            | Gross
(mmcf)        | Net
(mmcf) | Gross
(mmcf) | Net
(mmcf) | Gross
(mbbls) | Net
(mbbls)
|Proved                     |                      |             |                                           |                        |                     |            |              |            |               |            
|Developed Producing        | 2,682.7              | 2,388.1     | 9.0                                       | 7.2                    | 15,242              | 12,450     | 1,799        | 1,494      | 69.4          | 52.9       
|Developed Non-Producing    | 147.5                | 121.2       | -                                         | -                      | 965                 | 759        | 57           | 43         | 0.8           | 0.6        
|Undeveloped                | 97.3                 | 76.6        | -                                         | -                      | 3,932               | 3,105      | 98           | 72         | 17.6          | 13.3       
|Total Proved               | 2,927.5              | 2,585.9     | 9.0                                       | 7.2                    | 20,139              | 16,314     | 1,953        | 1,609      | 87.7          | 66.8       
|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|Probable                   | 1,086.6              | 903.9       | 1.2                                       | 1.0                    | 12,559              | 9,940      | 889          | 674        | 73.1          | 57.6       
|Total Proved Plus Probable | 4,014.1              | 3,489.8     | 10.2                                      | 8.2                    | 32,698              | 26,254     | 2,843        | 2,283      | 160.9         | 124.3      
|                           |                      |             |                                           |                        |                     |            |              |            |               |            



Net Present Values of Future Net Revenue

|                           |                                            |                                           |         |         |         |         |         |         |         |        
|-------------------------- | ------------------------------------------ | ----------------------------------------- | ------- | ------- | ------- | ------- | ------- | ------- | ------- | -------
|                           | Before Income Taxes
Discounted at (%/Year) | After Income Taxes
Discounted at (%/Year)
|Reserves Category          | 0
(M$)                                     | 5
(M$)                                    | 10
(M$) | 15
(M$) | 20
(M$) | 0
(M$)  | 5
(M$)  | 10
(M$) | 15
(M$) | 20
(M$)
|Proved                     |                                            |                                           |         |         |         |         |         |         |         |        
|Developed Producing        | 149,229                                    | 123,354                                   | 108,123 | 97,574  | 89,609  | 127,166 | 105,082 | 91,885  | 82,722  | 75,816 
|Developed Non-Producing    | 8,172                                      | 6,734                                     | 5,728   | 4,991   | 4,432   | 5,696   | 4,645   | 3,910   | 3,372   | 2,964  
|Undeveloped                | 16,065                                     | 13,492                                    | 11,483  | 9,884   | 8,588   | 11,237  | 9,245   | 7,704   | 6,485   | 5,504  
|Total Proved               | 173,466                                    | 143,580                                   | 125,333 | 112,449 | 102,630 | 144,098 | 118,971 | 103,498 | 92,579  | 84,284 
|                           |                                            |                                           |         |         |         |         |         |         |         |        
|Probable                   | 80,665                                     | 57,296                                    | 45,130  | 37,126  | 31,347  | 56,743  | 40,057  | 31,304  | 25,527  | 21,354 
|Total Proved Plus Probable | 254,131                                    | 200,875                                   | 170,463 | 149,575 | 133,977 | 200,841 | 159,028 | 134,802 | 118,106 | 105,638
|                           |                                            |                                           |         |         |         |         |         |         |         |        



|                                        |              |                |                      |                        |                             |                                             |                   |                                            | 
|--------------------------------------- | ------------ | -------------- | -------------------- | ---------------------- | --------------------------- | ------------------------------------------- | ----------------- | ------------------------------------------ | 
|Total Future Net Revenue (Undiscounted)
|Reserves Category                       | Revenue
(M$) | Royalties
(M$) | Operating Costs
(M$) | Development Costs
(M$) | Well Abandonment
Costs
(M$) | Future Net Revenue Before Income Taxes (M$) | Income Taxes (M$) | Future Net Revenue After Income Taxes (M$)
|                                        |              |                |                      |                        |                             |                                             |                   |                                           
|Proved                                  | 370,319      | 62,148         | 120,299              | 5,783                  | 8,623                       | 173,466                                     | 29,368            | 144,098                                   
|                                        |              |                |                      |                        |                             |                                             |                   |                                           
|Proved Plus Probable                    | 550,560      | 98,941         | 174,964              | 12,788                 | 9,736                       | 254,131                                     | 53,290            | 200,841                                   
|                                        |              |                |                      |                        |                             |                                             |                   |                                           









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Constant Prices and Costs



Summary of Oil & Gas Reserves

|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|-------------------------- | -------------------- | ----------- | ----------------------------------------- | ---------------------- | ------------------- | ---------- | ------------ | ---------- | ------------- | -----------
|                           | Light and Medium
Oil | Heavy Oil   | Natural Gas
(non-associated & associated) | Natural Gas
(solution) | Natural Gas Liquids
|Reserves Category          | Gross
(mbbls)        | Net
(mbbls) | Gross
(mbbls)                             | Net
(mbbls)            | Gross
(mmcf)        | Net
(mmcf) | Gross
(mmcf) | Net
(mmcf) | Gross
(mbbls) | Net
(mbbls)
|Proved                     |                      |             |                                           |                        |                     |            |              |            |               |            
|Developed Producing        | 2,765.5              | 2,466.8     | 10.7                                      | 8.6                    | 14,996              | 12,225     | 1,862        | 1,547      | 68.9          | 52.6       
|Developed Non-Producing    | 148.0                | 121.6       | -                                         | -                      | 963                 | 758        | 57           | 43         | 0.8           | 0.6        
|Undeveloped                | 99.2                 | 78.0        | -                                         | -                      | 3,926               | 3,100      | 99           | 74         | 17.6          | 13.4       
|Total Proved               | 3,012.7              | 2,666.4     | 10.7                                      | 8.6                    | 19,885              | 16,083     | 2,018        | 1,664      | 87.3          | 66.5       
|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|Probable                   | 1,131.7              | 941.4       | 2.8                                       | 2.2                    | 12,412              | 9,806      | 935          | 707        | 73.1          | 57.5       
|Total Proved Plus Probable | 4,144.3              | 3,607.8     | 13.5                                      | 10.8                   | 32,297              | 25,889     | 2,953        | 2,372      | 160.4         | 124.0      
|                           |                      |             |                                           |                        |                     |            |              |            |               |            



Net Present Values of Future Net Revenue

|                           |                                            |                                           |         |         |         |         |         |         |         |        
|-------------------------- | ------------------------------------------ | ----------------------------------------- | ------- | ------- | ------- | ------- | ------- | ------- | ------- | -------
|                           | Before Income Taxes
Discounted at (%/Year) | After Income Taxes
Discounted at (%/Year)
|Reserves Category          | 0
(M$)                                     | 5
(M$)                                    | 10
(M$) | 15
(M$) | 20
(M$) | 0
(M$)  | 5
(M$)  | 10
(M$) | 15
(M$) | 20
(M$)
|Proved                     |                                            |                                           |         |         |         |         |         |         |         |        
|Developed Producing        | 133,149                                    | 107,169                                   | 92,359  | 82,367  | 74,982  | 114,824 | 93,082  | 80,392  | 71,739  | 65,318 
|Developed Non-Producing    | 7,040                                      | 5,741                                     | 4,838   | 4,181   | 3,684   | 4,740   | 3,829   | 3,195   | 2,733   | 2,382  
|Undeveloped                | 11,314                                     | 9,320                                     | 7,765   | 6,530   | 5,533   | 7,658   | 6,116   | 4,928   | 3,993   | 3,244  
|Total Proved               | 151,503                                    | 122,230                                   | 104,962 | 93,078  | 84,199  | 127,222 | 103,027 | 88,515  | 78,465  | 70,944 
|                           |                                            |                                           |         |         |         |         |         |         |         |        
|Probable                   | 65,077                                     | 46,836                                    | 36,798  | 30,076  | 25,189  | 43,661  | 31,320  | 24,417  | 19,764  | 16,372 
|Total Proved Plus Probable | 216,580                                    | 169,065                                   | 141,760 | 123,154 | 109,388 | 170,884 | 134,347 | 112,932 | 98,229  | 87,316 
|                           |                                            |                                           |         |         |         |         |         |         |         |        





|                                        |              |                |                      |                        |                             |                                             |                   |                                           
|--------------------------------------- | ------------ | -------------- | -------------------- | ---------------------- | --------------------------- | ------------------------------------------- | ----------------- | ------------------------------------------
|Total Future Net Revenue (Undiscounted)
|Reserves Category                       | Revenue
(M$) | Royalties
(M$) | Operating Costs
(M$) | Development Costs
(M$) | Well Abandonment
Costs
(M$) | Future Net Revenue Before Income Taxes (M$) | Income Taxes (M$) | Future Net Revenue After Income Taxes (M$)
|                                        |              |                |                      |                        |                             |                                             |                   |                                           
|Proved                                  | 317,292      | 51,155         | 101,712              | 5,781                  | 7,142                       | 151,503                                     | 24,280            | 127,222                                   
|                                        |              |                |                      |                        |                             |                                             |                   |                                           
|Proved Plus Probable                    | 464,583      | 81,214         | 146,148              | 12,741                 | 7,899                       | 216,580                                     | 45,696            | 170,884                                   
|                                        |              |                |                      |                        |                             |                                             |                   |                                           











- 9 -





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Additional Information Concerning Future Net Revenue

The net present value of future net revenue by reserves category and production group as of December 31, 2006, using both constant and forecast prices and costs and discounted at 10% per year, is set forth below:



Future Net Revenue Before Income Taxes (Discounted at 10%/Year)

|                     |                                                                                |                                |                               
|-------------------- | ------------------------------------------------------------------------------ | ------------------------------ | ------------------------------
|Reserves Category    | Production Group                                                               | Constant Prices
and Costs
(M$) | Forecast Prices
and Costs
(M$)
|Proved               | Light and Medium Crude Oil (including solution gas and associated by-products) | 57,737                         | 59,331                        
|                     | Heavy Oil (including solution gas and associated by-products)                  | 14                             | 29                            
|                     | Natural Gas (including associated by-products)                                 | 47,211                         | 65,973                        
|Proved Plus Probable | Light and Medium Crude Oil (including solution gas and associated by-products) | 73,987                         | 75,377                        
|                     | Heavy Oil (including solution gas and associated by-products)                  | 23                             | 36                            
|                     | Natural Gas (including associated by-products)                                 | 67,750                         | 95,050                        





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 Sproule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 2006 was Cdn $57.86/bbl, while the gas price was Cdn $6.63/mcf.



|           |                                |                                       |                                    |                                          |                                         |                                     |                       |                         
|---------- | ------------------------------ | ------------------------------------- | ---------------------------------- | ---------------------------------------- | --------------------------------------- | ----------------------------------- | --------------------- | ------------------------
|           | Oil                            |                                       |                                    |                                          |                                         |                                    
|Year       | WTI Cushing Oklahoma
($US/bbl) | Edmonton Par Price 40° API
($Cdn/bbl) | Cromer Medium 29.3° API
($Cdn/bbl) | Natural Gas
AECO Gas
Prices
($Cdn/MMbtu) | Pentanes Plus FOB Field Gate
($Cdn/bbl) | Butanes F.O.B. Field Gat
($Cdn/bbl) | Inflation
Rate
(%/Yr) | Exchange Rate
($US/$Cdn)
|2007       | 65.73                          | 74.10                                 | 63.72                              | 7.72                                     | 75.88                                   | 55.23                               | 5.0                   | 0.870                   
|2008       | 68.82                          | 77.62                                 | 66.75                              | 8.59                                     | 79.49                                   | 57.85                               | 4.0                   | 0.870                   
|2009       | 62.42                          | 70.25                                 | 60.41                              | 7.74                                     | 71.94                                   | 52.36                               | 3.0                   | 0.870                   
|2010       | 58.37                          | 65.56                                 | 56.38                              | 7.55                                     | 67.14                                   | 48.87                               | 2.0                   | 0.870                   
|2011       | 55.20                          | 61.90                                 | 53.24                              | 7.72                                     | 63.40                                   | 46.14                               | 2.0                   | 0.870                   
|Thereafter | Generally 2% thereafter.      



The constant price and cost case assumes the continuance of produce prices at December 31, 2006 and operating costs projected for 2006, 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, 2006.



|                               |                                       |                                    |                                          |                                         |                                     |                         
|------------------------------ | ------------------------------------- | ---------------------------------- | ---------------------------------------- | --------------------------------------- | ----------------------------------- | ------------------------
|WTI Cushing Oklahoma
($US/bbl) | Edmonton Par Price 40° API
($Cdn/bbl) | Cromer Medium 29.3° API
($Cdn/bbl) | Natural Gas
AECO Gas
Prices
($Cdn/MMbtu) | Pentanes Plus FOB Field Gate
($Cdn/bbl) | Butanes F.O.B. Field Gat
($Cdn/bbl) | Exchange Rate
($US/$Cdn)
|61.05                          | 67.59                                 | 62.45                              | 6.13                                     | 71.51                                   | 54.00                               | 0.858                   





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Reconciliation of Reserves

The following table reconciles the Corporation's oil and natural gas reserves (on a net basis) from December 31, 2005 to December 31, 2006, using forecast prices and costs.



Reconciliation of Net Reserves



|                            |                      |                 |                                   |               |                 |                             |               |                 |                             |               |                 |                             
|--------------------------- | -------------------- | --------------- | --------------------------------- | ------------- | --------------- | --------------------------- | ------------- | --------------- | --------------------------- | ------------- | --------------- | ----------------------------
|                            | Light and Medium Oil | Heavy oil       | Associated and Non-Associated Gas | Totals       
|Factors                     | Proved
(Mbbl)        | Probable
(Mbbl) | Proved Plus Probable
(Mbbl)       | Proved
(Mbbl) | Probable
(Mbbl) | Proved Plus Probable
(Mbbl) | Proved
(mmcf) | Probable
(mmcf) | Proved Plus Probable
(mmcf) | Proved
(mboe) | Probable
(mboe) | Proved Plus Probable
(mmboe)
|December 31, 2005           | 2,260                | 1,403           | 3,663                             | -             | -               | -                           | 16,295        | 14,997          | 31,292                      | 4,976         | 3,903           | 8,878                       
|Extensions  and Discoveries | 628                  | 517             | 1,144                             | -             | -               | -                           | 5,449         | 6,777           | 12,226                      | 1,536         | 1,646           | 3,182                       
|Improved Recovery           | -                    | -               | -                                 | -             | -               | -                           | -             | -               | -                           | -             | -               | -                           
|Technical Revisions         | 356                  | (804)           | (447)                             | 17            | 1               | 21                          | 2,057         | (10,642)        | (8,587)                     | 716           | (2,576)         | (1,858)                     
|Acquisitions                | -                    | 22              | 22                                | -             | -               | -                           | -             | 24              | 24                          | -             | 26              | 26                          
|Dispositions                | (176)                | (72)            | (248)                             | -             | -               | -                           | (404)         | (264)           | (667)                       | (243)         | (116)           | (359)                       
|Economic Factors            | (13)                 | (105)           | (118)                             | -             | -               | (3)                         | (570)         | (277)           | (847)                       | (108)         | (151)           | (262)                       
|Production                  | (402)                | -               | (402)                             | (10)          | -               | (10)                        | (4,904)       | -               | (4,904)                     | (1,229)       | -               | (1,229)                     
|December 31, 2006           | 2,653                | 961             | 3,614                             | 7             | 1               | 8                           | 17,923        | 10,614          | 28,537                      | 5,647         | 2,731           | 8,378                       



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, 2005 to December 31, 2006 using constant prices and costs and discounted at 10% per year.



|                                                                                                 |             
|------------------------------------------------------------------------------------------------ | ------------
|Period and Factor                                                                                | ($thousands)
|Estimated Future Net Revenue at December 31, 2005                                                | 113,799     
|Sales and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production Costs and Royalties | (37,119)    
|Net Change in Prices, Production Costs and Royalties related to Future Production                | (27,625)    
|Changes in Previously Estimated Development Costs Incurred During the Period                     | (14,595)    
|Changes in Estimated Future Development Costs                                                    | (5,109)     
|Extension and Improved Recovery                                                                  | 26,115      
|Discoveries                                                                                      | -           
|Acquisitions of Reserves                                                                         | -           
|Disposition of Reserves                                                                          | (4,830)     
|Net Change Resulting from Revisions in Quantity Estimates                                        | 12,010      
|Economic Factors                                                                                 | (1,554)     
|Accretion of Discount                                                                            | 10,536      
|Net Change in Income Taxes for Current Period                                                    | 11,847      
|Net Change in Income Taxes for Future Forecast                                                   | 6,435       
|Miscellaneous Changes                                                                            | (1,396)     
|Estimated Future Net Revenue at December 31, 2006                                                | 88,515      







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Undeveloped Reserves

The following table discloses the gross volumes of undeveloped reserves, using constant prices and costs, of the Corporation as at December 31, 2006 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)            | Light and Medium Crude Oil
(mbbls) | Natural Gas
(mmcf)
|2005 | -                                  | -                             | 55                                 | 2,846             
|2006 | 117                                | 4,025                         | 437                                | 5,294             
|     | 117                                | 4,025                         | 492                                | 8,140             



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.



The Corporations undeveloped reserves are dominated by undeveloped gas reserves in Princess.  The Corporation anticipates drilling for these reserves soon after break-up in 2007.  The oil reserves are also in Princess and are expected to be drilled in 2007.



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           | Proved Plus Probable Reserves
|Year      | Undiscounted              | Discounted at 10% /year   | Undiscounted                  | Discounted at 10%/year | Undiscounted | Discounted at 10%/year
|2007      | 5,771                     | 5,502                     | 5,771                         | 5,502                  | 11,981       | 11,423                
|2008      | -                         | -                         | -                             | -                      | 683          | 592                   
|2009      | -                         | -                         | -                             | -                      | -            | -                     
|2010      | -                         | -                         | -                             | -                      | 112          | 80                    
|2011      | -                         | -                         | -                             | -                      | -            | -                     
|Remaining | 10                        | 6                         | 12                            | 7                      | 12           | 7                     
|          | 5,781                     | 5,508                     | 5,783                         | 5,510                  | 12,788       | 12,102                



The Corporation expects to fund these development costs through its internally generated cash flow and its existing credit facility.



Oil and Natural Gas Wells and Properties

The following table summarizes, as at December 31, 2006, 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   | Oil   | Natural Gas
|             | Gross           | Net           | Gross | Net         | Gross | Net | Gross | Net
|Alberta      | 83              | 54            | 141   | 74          | 78    | 68  | 121   | 88 
|Saskatchewan | 313             | 28            | -     | -           | 150   | 19  | -     | -  
|Total        | 396             | 82            | 141   | 74          | 228   | 87  | 121   | 88 



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 13.4.



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Unproved Properties

The following table summarizes Gentrys interests in developed and undeveloped properties:

|               |           |             |         |         |         |        
|-------------- | --------- | ----------- | ------- | ------- | ------- | -------
|               | Developed | Undeveloped | Total  
|               | Gross     | Net         | Gross   | Net     | Gross   | Net    
|Alberta        | 108,485   | 65,708      | 345,642 | 178,783 | 454,127 | 244,191
|Saskatchewan   | 13,697    | 5,361       | 1,280   | 472     | 14,977  | 5,833  
|Manitoba       | -         | -           | 160     | 160     | 160     | 160    
|Western Canada | 122,182   | 71,069      | 347,082 | 179,415 | 469,264 | 250,484
|Quebec         | -         | -           | 376,920 | 37,692  | 376,920 | 37,692 
|Total          | 122,182   | 71,069      | 724,002 | 217,107 | 846,184 | 288,176



Acreage that Gentry has rights to explore and develop that may expire prior to December 31, 2007 total approximately 15,000 net acres.  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.  Gentry anticipates that in 2007 it will continue leases totalling approximately 5,900 net acres by either making the necessary applications or performing the necessary work.

Exploration and Development Activities

During 2006, Gentry participated in the drilling of 51 gross wells (48.0 net) with a 90% success rate (91% net).  The majority of Gentry's 2006 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, 2006.



Number of Exploration WellsNumber of Development WellsTotal WellsCategory of WellGrossNetGrossNetGrossNetCrude oil wells98.3109.91918.2Natural gas wells1211.6108.92220.5Suspended wells22.032.854.8Service wells------Dry and abandoned wells54.5--54.5Total2826.42321.65148.0




Gentry 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.

Production Estimates

The following tables set out the volume of the Corporations production estimated for the year ended December 31, 2007, which is reflected in the estimate of future net revenue disclosed in the Summary of Reserves and Future Net Revenue section of this Annual Information Form.

Forecast Prices and Costs

|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|-------------------------- | -------------------- | ----------- | ----------------------------------------- | ---------------------- | ------------------- | ---------- | ------------ | ---------- | ------------- | -----------
|                           | Light and Medium
Oil | Heavy Oil   | Natural Gas
(non-associated & associated) | Natural Gas
(solution) | Natural Gas Liquids
|Reserves Category          | Gross
(mbbls)        | Net
(mbbls) | Gross
(mbbls)                             | Net
(mbbls)            | Gross
(mmcf)        | Net
(mmcf) | Gross
(mmcf) | Net
(mmcf) | Gross
(mbbls) | Net
(mbbls)
|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|Total Proved               | 580.0                | 460.6       | 4.0                                       | 3.2                    | 5,278               | 4,046      | 520          | 413        | 9.3           | 6.9        
|Total Proved Plus Probable | 656.1                | 518.6       | 4.1                                       | 3.3                    | 5,584               | 4,438      | 593          | 467        | 10.4          | 7.8        
|                           |                      |             |                                           |                        |                     |            |              |            |               |            





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Constant Prices and Costs

|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|-------------------------- | -------------------- | ----------- | ----------------------------------------- | ---------------------- | ------------------- | ---------- | ------------ | ---------- | ------------- | -----------
|                           | Light and Medium
Oil | Heavy Oil   | Natural Gas
(non-associated & associated) | Natural Gas
(solution) | Natural Gas Liquids
|Reserves Category          | Gross
(mbbls)        | Net
(mbbls) | Gross
(mbbls)                             | Net
(mbbls)            | Gross
(mmcf)        | Net
(mmcf) | Gross
(mmcf) | Net
(mmcf) | Gross
(mbbls) | Net
(mbbls)
|                           |                      |             |                                           |                        |                     |            |              |            |               |            
|Total Proved               | 579.2                | 459.9       | 4.0                                       | 3.2                    | 5,236               | 4,008      | 518          | 411        | 9.1           | 6.8        
|Total Proved Plus Probable | 655.5                | 518.1       | 4.1                                       | 3.3                    | 5,805               | 4,394      | 591          | 465        | 10.3          | 7.7        
|                           |                      |             |                                           |                        |                     |            |              |            |               |            

No individual field accounts for more than 20% of the estimated production disclosed.



Quarterly Production History

The following table sets forth Gentry's average daily production volumes, on a company interest basis, for each fiscal quarter in 2006 and for the entire year.



|                              |                              |                |               |                |       
|----------------------------- | ---------------------------- | -------------- | ------------- | -------------- | ------
|                              | Year Ended December 31, 2006
|                              | First Quarter                | Second Quarter | Third Quarter | Fourth Quarter | Total 
|Light and medium oil (bbls/d) | 1,317                        | 1,289          | 1,538         | 1,447          | 1,398 
|Natural gas (mcf/d)           | 16,792                       | 18,139         | 14,388        | 17,331         | 16,658
|Total (boe/d)                 | 4,116                        | 4,312          | 3,936         | 4,335          | 4,175 



Quarterly Netback History

The following tables set forth Gentry's average netbacks received for each fiscal quarter in 2006 and for the entire year.  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 pro-rated based on that wells production.



|                              |                              |                |               |                |        
|----------------------------- | ---------------------------- | -------------- | ------------- | -------------- | -------
|                              | Year Ended December 31, 2006
|Light and medium oil (bbls/d) | First Quarter                | Second Quarter | Third Quarter | Fourth Quarter | Total  
|Sales price                   | 51.43                        | 67.68          | 61.92         | 50.59          | 57.86  
|Royalties                     | (13.39)                      | (10.95)        | (12.59)       | (19.49)        | (14.20)
|Production costs(1)           | (9.13)                       | (8.46)         | (11.53)       | (15.51)        | (11.30)
|Netback                       | 28.91                        | 48.27          | 37.80         | 15.59          | 32.36  



|                    |                              |                |               |                |       
|------------------- | ---------------------------- | -------------- | ------------- | -------------- | ------
|                    | Year Ended December 31, 2006
|Natural gas (mcf/d) | First Quarter                | Second Quarter | Third Quarter | Fourth Quarter | Total 
|Sales price         | 7.65                         | 6.16           | 5.58          | 7.02           | 6.63  
|Royalties           | (1.56)                       | (1.75)         | (1.40)        | (1.75)         | (1.63)
|Production costs(1) | (1.64)                       | (1.14)         | (1.73)        | (2.19)         | (1.67)
|Netback             | 4.45                         | 3.27           | 2.45          | 3.08           | 3.33  



|                    |                              |                |               |                |        
|------------------- | ---------------------------- | -------------- | ------------- | -------------- | -------
|                    | Year Ended December 31, 2006
|Total (boe/d)       | First Quarter                | Second Quarter | Third Quarter | Fourth Quarter | Total  
|Sales price         | 47.67                        | 46.14          | 44.59         | 44.94          | 45.83  
|Royalties           | (10.64)                      | (10.64)        | (10.04)       | (13.49)        | (11.24)
|Production costs(1) | (9.62)                       | (7.32)         | (10.83)       | (13.92)        | (10.44)
|Netback             | 27.41                        | 28.18          | 23.72         | 17.53          | 24.15  





- 14 -





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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 320 net wells and 13.4 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 $9.8 million on an undiscounted basis and $3.4 million discounted at 10%.  The undiscounted amount is approximately $1.2 million higher than the abandonment figure used in the Sproule Report to calculate the future net revenue from proved reserves.  The Corporation anticipates that approximately $429,000 of abandonment and reclamation costs 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 Gentrys properties and the present worth of future net cash flows from such reserves contained in the Sproule Report (based on forecast prices and costs on an undiscounted basis) include expenditures of approximately $8.6 million associated with the abandonment of all wells that were assigned reserves but do not include any provision for surface lease reclamation or facility abandonment costs.

Tax Horizon

While Gentry is subject to the Saskatchewan Resource Surcharge, the Corporation anticipates, based on its current budget, that it may also be required to pay federal and provincial income taxes in the latter part of the 2007 taxation year.

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, 2006:



|                                      |             
|------------------------------------- | ------------
|                                      | ($thousands)
|Drilling and completions              | 18,131      
|Facilities and equipping              | 17,414      
|Land and seismic                      | 5,767       
|Capitalized expenses                  | 1,469       
|Other                                 | 65          
|Expenditures, before net acquisitions | 42,846      
|Acquisitions, net                     | (6,597)     
|Net expenditures                      | 36,249      



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.



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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".

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, 2006, the Corporation had the following contractual obligations under office leases and firm service transportation agreements:



|                            |      |      |      |      |      |            |      
|--------------------------- | ---- | ---- | ---- | ---- | ---- | ---------- | -----
|($thousands)                | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | Total
|Office lease                | 174  | 159  | -    | -    | -    | -          | 333  
|Firm service transportation | 40   | 12   | 69   | 69   | 12   | -          | 202  
|                            | 214  | 171  | 69   | 69   | 12   | -          | 535  



Human Resources

At December 31, 2006, the Corporation had 23 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, 2006, there were 38,811,130 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 September 27, 2006 Gentry announced that it intended to purchase up to 3,400,000 Common Shares, representing approximately 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 October 01, 2007 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 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 dispose of their Common Shares. From October 02, 2006 through to March 27, 2007, the Corporation has purchased 179,000 Common Shares at an average price of $4.37 per share under the current normal course



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issuer bid.  From September 12, 2005 to September 11, 2006, Gentry purchased, pursuant to a previous normal course issuer bid, 644,800 Common Shares at an average price of $5.47 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.



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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 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 for 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



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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.

In Alberta, in 2006, a producer of oil or natural gas was entitled to a credit against the royalties payable to the Crown by virtue of the ARTC program. The ARTC rate was based on a price-sensitive formula and varied 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 was 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 were generally not eligible for ARTC. The rate was established quarterly based on the average "par price", as determined by the Alberta Department of Energy for the previous quarterly period.  The ARTC program has been discontinued effective January 01, 2007.

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.

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



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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.

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



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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.

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.



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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, 2006, 38,811,130 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 2006.



|          |       |       |       |          
|--------- | ----- | ----- | ----- | ---------
|Month     | High  | Low   | Close | Volume   
|January   | $6.42 | $5.60 | $5.82 | 3,164,523
|February  | 6.16  | 5.05  | 5.50  | 3,331,111
|March     | 5.97  | 5.37  | 5.80  | 2,858,371
|April     | 5.95  | 5.50  | 5.76  | 1,833,940
|May       | 5.88  | 4.76  | 5.20  | 2,117,065
|June      | 5.40  | 4.25  | 4.53  | 1,926,018
|July      | 5.10  | 4.41  | 5.06  | 982,653  
|August    | 5.80  | 5.06  | 5.20  | 1,173,511
|September | 5.64  | 4.38  | 4.82  | 779,430  
|October   | 5.30  | 4.40  | 5.00  | 798,030  
|November  | 5.35  | 3.96  | 5.35  | 1,663,656
|December  | 5.40  | 4.72  | 4.87  | 796,877  



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  | 1,685,964(5)
157,483(5)                     | 275,000                   
|A.  Bruce Macdonald(1)(2)(4)
Calgary, Alberta, Canada
Director                                                      | Director, Jayhawk Resources Ltd, a private oil & gas company                                           | Nov. 13, 1995  | 256,450                                     | 292,500                   
|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  | 557,433                                     | 232,500                   
|Walter O'Donoghue(3)(4)
Calgary, Alberta, Canada
Director                                                           | Former Partner, Bennett Jones LLP, a law firm                                                          | May 29, 1998   | 183,126                                     | 232,500                   
|Dean G. Prodan (1)(3)
Calgary, Alberta, Canada
Director                                                             | Portfolio Manager, Canada Dominion Resources Limited Partnerships                                      | May 19, 2006   | 50,000                                      | 75,000                    
|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            | 239,490                                     | 275,000                   



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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
|R. Gordon McKay
Calgary, Alberta, Canada
Chief Operating Officer               | Chief Operating Officer of the Corporation              | N/A            | 248,403                                     | 275,000                   
|Robert J. Poole
Calgary, Alberta, Canada
Vice-President, Operations            | Vice-President, Operations of the Corporation           | N/A            | 254,800                                     | 215,000                   
|Lawrence B. Buzan
Calgary, Alberta, Canada
Vice-President, Land & Negotiations | Vice-President, Land & Negotiations, of the Corporation | N/A            | 16,095                                      | 165,000                   
|Harley Kempthorne
Calgary, Alberta Canada
Vice-President, Engineering          | Vice President, Engineering of the Corporation          | N/A            | 69,400                                      | 125,000                   

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 1,685,964 Common Shares are held directly by Mr. Ross.  The 157,483 Common Shares are directly owned by an associate of Mr. Ross.



As at March 28, 2007, the directors and officers of the Corporation beneficially owned, directly or indirectly, or exercised control or direction over, in the aggregate, 3,718,644 Common Shares, representing 9.6% 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.



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INTERESTS OF EXPERTS

Sproule prepared the Sproule Report dated March 02, 2007 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 Sproule Report, the partners, consultants, and associates of Sproule, 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.  None of the Collins Barrow Calgary LLP partners, principals, or designated professionals thereof, had any registered or beneficial interests, direct or indirect, in any securities or other property of the Corporation or our associates or affiliates either at the time they prepared their auditors report on the consolidated financial statements for the year ended December 31, 2006 or any time thereafter.



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 April 07, 2006 for its 2006 annual general 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, 2006.





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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, 2006. The reserves data consist of the following:

(a)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and

(ii)

the
  related
  estimated


 future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2006 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 attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us as of December 31, 2006, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Corporation's management and Board of Directors:

Independent Qualified Reserves Evaluator or AuditorDescription and Preparation Date of Evaluation ReportLocation of Reserves (Country)Net Present Value of Future Net Revenue
(10% discount rate)Audited (M$)Evaluated (M$)Reviewed (M$)Total (M$)Sproule Associates LimitedEvaluation of the P&NG Reserves of Gentry Resources Ltd., as of December 31, 2006, prepared December 2006 to March 2007CanadaNil170,463Nil170,463




5.

In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.

6.

We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after the preparation date.



A-1





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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:



Sproule Associates Limtied

Calgary, Alberta

March 2, 2007





Signed:Nora T. Stewart

Nora T. Stewart, P.Eng.

Associate





Signed:George Strother-Stewart

George Strother-Stewart, P.Geol.

Associate





Signed:Robert N. Johnson

Robert N. Johnson

Vice-President, Engineering





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)

(i)

proved and proved plus probable oil and gas reserves estimated as at December 31, 2006 using forecast prices and costs; and

(ii)

the
  related
   estimated


 future net revenue; and

(b)

(i)

proved oil and gas reserves estimated as at December 31, 2006 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 28, 2007.

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
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, 2007





B-2



---





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 Michael Halvorson (Chair), A. Bruce Macdonald and Dean Prodan.  Each member of the Audit Committee is financially literate within the meaning of Multilateral Instrument 52-110 and all are independent committee members.





C-2





---





Michael Halvorson

Michael H. Halvorson, a director of the Company, is President of  Halcorp Capital Ltd., a position he has held since September 1981.  Mr. Halvorson is also currently a director of Strathmore Minerals Corp., Orezone Resources Inc., Esperanza Silver Corporation, NovaGold Resources Inc., Radiant Resources Inc. and Pediment Exploration Ltd.  Past directorships include Western Silver Inc. and Viceroy Exploration Ltd. Mr. Halvorson is also currently on the audit committees for Strathmore Minerals Corp., Esperanza Silver Corporation and NovaGold Resources Inc.  He was also formerly on the audit committee for Orezone Resources Inc.



A. Bruce Macdonald

A director of Jayhawk Resources Ltd, a private oil and gas company, 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s Board, he was Executive Vice-President with Andex Oil Co. Ltd. and its successor company, EOG Resources. Mr. Macdonald was 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.



Dean Prodan

Mr. Prodan has over 20 years of experience in Canadian oil and gas capital markets, including advising some of the largest pension and mutual funds in North America.  He is currently the portfolio manager for Canada Dominion Resources Limited partnerships and serves as a director of Macro Enterprises Inc.  Mr. Prodan has previously served on the audit committees of Marauder Resources East Coast Inc and NQL Energy Services Inc.





EXTERNAL AUDITOR SERVICE FEES

The aggregate amounts billed by Collins Barrow Calgary LLP, Chartered Accountants to the Company in each of the fiscal years ended December 31, 2006 and 2005 for audit fees, audit-related fees, tax fees and all other fees are set forth below:

|                      |                              |                             
|--------------------- | ---------------------------- | ----------------------------
|                      | Year Ended
December 31, 2006 | Year Ended
December 31, 2005
|Audit Fees(1)         | $  173,000                   | $  115,300                  
|Audit-Related Fees(2) | 15,500                       | 4,654                       
|Tax Fees(3)           | -                            | -                           
|All Other Fees(4)     | -                            | 5,500                       
|Totals                | $188,500                     | $125,454                    



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 corporate tax planning services.







C-3













8



---

Exhibit 2



To the Shareholders of Gentry Resources Ltd.
We have audited the consolidated balance sheets of Gentry Resources Ltd. as at December 31, 2006 and 2005 and the consolidated statements of income and 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. 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, 2006 and 2005 and the results of its operations and cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.
Signed "Collins Barrow Calgary LLP"
Chartered Accountants
Calgary, Alberta
March 20, 2007

---





GENTRY RESOURCES LTD.

CONSOLIDATED BALANCE SHEETS

As at December 31, 2006 and 2005



|                                         |                |               
|---------------------------------------- | -------------- | --------------
|ASSETS                                  
|                                         | 2006           | 2005          
|CURRENT                                  |                |               
|Cash and cash equivalents                | $       18,406 | $       13,090
|Accounts receivable                      | 11,992,126     | 14,819,088    
|Prepaid expenses                         | 580,361        | 625,961       
|                                         | 12,590,893     | 15,458,139    
|                                         |                |               
|INVESTMENTS (NOTE 2[c])                  | 1,809,583      | 1,707,458     
|                                         |                |               
|PROPERTY AND EQUIPMENT (NOTE 3)          | 127,425,551    | 114,901,195   
|                                         |                |               
|                                         | $ 141,826,027  | $ 132,066,792 
|                                         |                |               
|                                        
|LIABILITIES & SHAREHOLDERS EQUITY      
|                                         |                |               
|CURRENT                                  |                |               
|Accounts payable and accrued liabilities | $  18,858,031  | $  20,179,163 
|Income taxes payable                     | 294,859        | 303,405       
|Bank debt (Note 4)                       | 40,750,000     | 34,150,000    
|                                         | 59,902,890     | 54,632,568    
|                                         |                |               
|ASSET RETIREMENT OBLIGATIONS (NOTE 5)    | 5,104,300      | 3,473,144     
|                                         |                |               
|FUTURE INCOME TAXES (NOTE 6[a])          | 12,393,282     | 11,897,016    
|                                         |                |               
|                                         | 77,400,472     | 70,002,728    
|                                         |                |               
|SHARE CAPITAL (NOTE 7)                   | 43,515,360     | 42,906,253    
|CONTRIBUTED SURPLUS (NOTE 7[d])          | 2,335,783      | 823,918       
|RETAINED EARNINGS                        | 18,574,412     | 18,333,893    
|                                         | 64,425,555     | 62,064,064    
|                                         |                |               
|                                         | $ 141,826,027  | $ 132,066,792 

Commitments (NOTE 10)

Please refer to the accompanying notes.

Approved by the board:Signed "Michael Halvorson"Michael Halvorson
DirectorSigned "Dean Prodan"Dean Prodan
Director





---

|
|



GENTRY RESOURCES LTD.

CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

For the years ended December 31, 2006 and 2005



|                                                                      |              |             
|--------------------------------------------------------------------- | ------------ | ------------
|                                                                      | 2006         | 2005        
|REVENUE                                                               |              |             
|Production                                                            | $ 69,832,337 | $ 64,665,175
|Less: royalties, net of Alberta Royalty Tax Credit                    | (17,132,839) | (11,870,924)
|                                                                      | 52,699,498   | 52,794,251  
|EXPENSES                                                              |              |             
|Depletion, depreciation & accretion                                   | 25,481,638   | 19,550,137  
|Production                                                            | 15,908,052   | 11,886,328  
|General & administrative                                              | 3,808,274    | 3,755,310   
|Interest on bank debt                                                 | 2,093,392    | 1,425,161   
|Stock-based compensation
    (NOTE 7[b] AND 7[d])                     | 1,835,971    | 643,882     
|                                                                      | 49,127,327   | 37,260,818  
|                                                                      |              |             
|INCOME BEFORE INCOME TAXES                                            | 3,572,171    | 15,533,433  
|                                                                      |              |             
|INCOME TAXES (NOTE 6[b])                                              |              |             
|Current                                                               | 318,695      | 534,757     
|Future                                                                | 496,266      | 4,796,238   
|                                                                      | 814,961      | 5,330,995   
|                                                                      |              |             
|NET INCOME                                                            | 2,757,210    | 10,202,438  
|Retained earnings, beginning of year                                  | 18,333,893   | 9,048,384   
|Less: excess of cost of shares acquired over stated value
(NOTE 7[c]) | (2,516,691)  | (916,929)   
|Retained earnings, end of year                                        | $ 18,574,412 | $ 18,333,893
|                                                                      |              |             
|NET INCOME PER SHARE                                                  |              |             
|Basic (Note 8)                                                        | $0.07        | $0.26       
|Diluted (Note 8)                                                      | $0.07        | $0.25       



Please refer to accompanying notes.







---

|
|



GENTRY RESOURCES LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2006 and 2005



|                                                 |                |               
|------------------------------------------------ | -------------- | --------------
|                                                 | 2006           | 2005          
|OPERATING ACTIVITIES                             |                |               
|Net income                                       | $    2,757,210 | $  10,202,438 
|Adjustments for:                                 |                |               
|Depletion, depreciation & accretion              | 25,481,638     | 19,550,137    
|Stock-based compensation                         | 1,835,971      | 643,882       
|Future income taxes                              | 496,266        | 4,796,238     
|Asset retirement expenditures                    | (126,137)      | (160,441)     
|                                                 | 30,444,948     | 35,032,254    
|Changes in non-cash working capital items        | 4,557,570      | 145,741       
|                                                 | 35,002,518     | 35,177,995    
|INVESTING ACTIVITIES                             |                |               
|Capital expenditures                             | (43,283,284)   | (53,854,150)  
|Dispositions of property and equipment           | 7,034,583      | -             
|Acquisition of investments                       | (102,125)      | -             
|Changes in non-cash working capital items        | (3,119,841)    | 2,426,446     
|                                                 | (39,470,667)   | (51,427,704)  
|FINANCING ACTIVITIES                             |                |               
|Proceeds from (repayments on) bank debt, net     | 6,600,000      | 16,930,000    
|Redemption of share capital                      | (3,195,388)    | (1,163,098)   
|Proceeds on issuance of share capital, net       | 963,697        | 539,071       
|Changes in non-cash working capital items        | 105,156        | (111,461)     
|                                                 | 4,473,465      | 16,194,512    
|                                                 |                |               
|INCREASE (DECREASE) IN CASH                      | 5,316          | (55,197)      
|                                                 |                |               
|CASH AND CASH EQUIVALENTS,
    beginning of year | 13,090         | 68,287        
|                                                 |                |               
|CASH AND CASH EQUIVALENTS,
    end of year       | $       18,406 | $       13,090
|                                                 |                |               
|SUPPLEMENTAL CASH FLOWS DISCLOSURE:              |                |               
|Interest paid                                    | $  2,093,392   | $  1,425,161  
|Income taxes paid                                | $     327,241  | $     278,092 



Please refer to the accompanying notes.









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                







1.

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



2.

Summary of significant accounting policiesThese financial statements have been prepared using accounting principles generally accepted in Canada which include:



a)

Principles of consolidationOn April 1, 2005, the Company amalgamated with its wholly owned subsidiaries, Gentry Resources (Saskatchewan) Ltd. and Gentry Income Funds Inc.



The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Gentry Resources (West Africa) Inc., which is inactive and has no production operations.



b)

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



c)

Investments The Company records its investment in Stratic Energy Corporation (Stratic), a corporation which was formerly related by virtue of common directors and officers, and its other investment using the cost method of accounting whereby the investments are initially recorded at cost.  Earnings are recognized only to the extent received or receivable.
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 expendituresThe 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.









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





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.



e)

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



f)

Income taxesIncome 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 obligationsThe 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, depreciation and accretion expense.  Actual restoration expenditures are charged to the accumulated obligation as incurred.



h)

Flow-through sharesThe 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.  This reduction to share capital and increase in future tax liability is recognized when the expenditures are renounced.



i)

Stock-based compensationThe Company has a stock option plan as described in Note 7(a).

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.  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.









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|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





j)

Net income per shareDiluted net income per share is calculated using the treasury stock method, whereby it is assumed that proceeds from the exercise of in-the-money stock options plus the unamortized portion of stock-based compensation are used by the Company to repurchase Company shares at the weighted average market price during the year.



k)

Revenue recognitionRevenue 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 translationThe Company follows the temporal method when translating foreign currency transactions and the financial statements of its integrated subsidiary.
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, depreciation and accretion, are translated at average exchange rates for the year.  Depletion, depreciation and accretion 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 accountingSubstantially 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 uncertaintyThe amounts recorded for depletion, depreciation and accretion, asset retirement 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 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.







---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





3.

Property and equipment

|                                                                                   |   |             |   |            
|---------------------------------------------------------------------------------- | - | ----------- | - | -----------
|                                                                                   |   | 2006        |   | 2005       
|Petroleum and natural gas properties including
exploration and development thereon | $ | 149,592,699 | $ | 128,195,327
|Production equipment and facilities                                                |   | 54,190,215  |   | 37,851,471 
|Other                                                                              |   | 973,488     |   | 907,947    
|                                                                                   |   | 204,756,402 |   | 166,954,745
|Accumulated depletion and depreciation                                             |   | 77,330,851  |   | 52,053,550 
|                                                                                   | $ | 127,425,551 | $ | 114,901,195
|                                                                                   |   |             |   |            



During the year, the Company capitalized $1,468,683 (2005 - $1,489,120) in general and administrative expenses.  No interest has been capitalized.
Costs of unproved petroleum and natural gas properties amounting to $22,054,459 (2005 - $20,584,330) have been excluded from the depletion calculation.



The Company prepared a ceiling test calculation at December 31, 2006 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
($US/bbl) | Edmonton Light Sweet 40° API
($Cdn/bbl) | AECO
Natural Gas
Spot Price
($Cdn/mmbtu)
|2007 | 65.73             | 74.10                                   | 7.72                                    
|2008 | 38.82             | 77.62                                   | 8.59                                    
|2009 | 62.42             | 70.25                                   | 7.74                                    
|2010 | 58.37             | 65.56                                   | 7.55                                    
|2011 | 55.20             | 61.90                                   | 7.72                                    
|2012 | 56.31             | 63.15                                   | 7.85                                    
|2013 | 57.43             | 34.42                                   | 7.99                                    
|2014 | 58.58             | 65.72                                   | 8.12                                    
|2015 | 59.75             | 67.04                                   | 8.26                                    
|2016 | 60.95             | 68.39                                   | 8.40                                    
|2017 | 62.17             | 69.76                                   | 8.54                                    



Prices increase at a rate of 2.00% thereafter.



4.

Bank debtThe Company has an uncommitted demand revolving credit facility to a maximum of $50,000,000.  The facility is available to the Company by way of prime rate based loans, bankers 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 $100,000,000 demand debenture with a floating charge over all assets with a Negative Pledge and Undertaking to provide fixed charges upon request.  Under the terms of the agreement, the Company is required to meet certain financial and other reporting requirements and may not breach certain financial tests without prior consent of the bank.
The credit facility is subject to review on a semi-annual basis.  The next review will be undertaken on or before May 31, 2007.







---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





5.

Asset retirement obligations



The following table summarizes changes in the asset retirement obligations for the years ended December 31, 2006 and 2005:

|                                                |   |           |   |          
|----------------------------------------------- | - | --------- | - | ---------
|                                                |   | 2006      |   | 2005     
|Asset retirement obligations, beginning of year | $ | 3,473,144 | $ | 2,671,657
|Liabilities incurred                            |   | 1,684,394 |   | 745,691  
|Liabilities settled                             |   | (126,137) |   | (160,441)
|Liabilities acquired                            |   | -         |   | 69,369   
|Liabilities disposed                            |   | (131,438) |   | -        
|Accretion expense                               |   | 204,337   |   | 146,868  
|Asset retirement obligations, end of year       | $ | 5,104,300 | $ | 3,473,144
|                                                |   |           |   |          



The inflated, undiscounted amount of the estimated future cash flows required to settle the obligations is $9,809,550 (2005 - $6,921,310).  These obligations are expected to be paid over the next several years with a weighted average life of approximately 11 years (2005 - 11 years).  The estimated future cash flows have been discounted at the credit-adjusted risk-free rate of 6.00% (2005  5.25%).  As at December 31, 2006 no funds have been set aside to settle these obligations.



6.

Income taxes



a)

Future Income Tax Liability

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



|                                                                                               |   |            |   |           
|---------------------------------------------------------------------------------------------- | - | ---------- | - | ----------
|                                                                                               |   | 2006       |   | 2005      
|Temporary differences related to property and 
     equipment and asset retirement obligations | $ | 12,728,414 | $ | 12,441,035
|Share issuance and financing costs                                                             |   | (233,014)  |   | (425,714) 
|Temporary differences related to investments                                                   |   | (102,118)  |   | (118,305) 
|                                                                                               | $ | 12,393,282 | $ | 11,897,016
|                                                                                               |   |            |   |           



b)

Income Taxes ExpenseIncome taxes expense differs from that which would be expected from applying the combined Canadian federal and provincial income tax rate of  35.00% (2005 - 39.10%) to income before income taxes.  The difference results from the following:



|                                                                 |   |             |   |            
|---------------------------------------------------------------- | - | ----------- | - | -----------
|                                                                 |   | 2006        |   | 2005       
|Expected Tax provision                                           | $ | 1,250,260   | $ | 6,073,572  
|Increases (decreases) resulting from:                            |   |             |   |            
|Resource allowance                                               |   | (1,052,048) |   | (2,507,882)
|Non-deductible crown payments, net of Alberta Royalty Tax Credit |   | 827,086     |   | 1,558,483  
|Change in tax rates                                              |   | (1,057,731) |   | (422,640)  
|Large corporation and capital taxes                              |   | 284,452     |   | 324,687    
|Non-deductible stock-based compensation                          |   | 604,756     |   | 217,736    
|Other                                                            |   | (41,814)    |   | 87,039     
|                                                                 | $ | 814,961     | $ | 5,330,995  









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





7.

Share capitalAuthorized   Unlimited number of voting common shares
   Unlimited number of non-voting preferred sharesIssued



|                                                      |            |              |            |             
|----------------------------------------------------- | ---------- | ------------ | ---------- | ------------
|Common shares:                                        | 2006       | 2005        
|                                                      | Number     | Stated Value | Number     | Stated Value
|Balance, beginning of year                            | 38,830,799 | $42,906,253  | 38,471,234 | $42,474,623 
|Stock options exercised for cash (Note 7[a])          | 551,102    | 855,598      | 546,167    | 452,058     
|Fair value of options excercised                      | -          | 216,008      | -          | 51,717      
|Issued under employee share purchase plan (Note 7[b]) | 41,529     | 216,198      | 36,298     | 174,025     
|Normal Course Issuer Bids (Note 7[c])                 | (612,300)  | (678,697)    | (222,900)  | (246,170)   
|Balance, end of year                                  | 38,811,130 | $43,515,360  | 38,830,799 | $42,906,253 



a)

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 5,000,000 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 cannot 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, 2006 and 2005 and changes during the years then ending are as follows:

20062005Number of OptionsWeighted Average Exercise PriceNumber of OptionsWeighted Average Exercise PriceOutstanding, beginning of year2,604,667$1.762,995,000$1.49Granted1,240,0005.60217,5003.28Exercised(551,102)1.55(546,167)0.84Cancelled(66,665)3.27(61,666)2.25Outstanding, end of year3,226,900$3.242,604,667$1.76Options exercisable at year-end2,001,896$2.331,805,226$1.39




The following table summarizes the stock options outstanding at December 31, 2006:



|                        |                     |                                 |                                             |                   |                                
|----------------------- | ------------------- | ------------------------------- | ------------------------------------------- | ----------------- | -------------------------------
|                        | Options Outstanding | Options Exercisable            
|Range of ExercisePrices | Number of Options   | Weighted Average Exercise Price | Weighted Average Remaining Contractual Life | Number of Options | Weighted Average Exercise Price
|$0.45                   | 217,500             | $0.45                           | 3.1                                         | 217,500           | $0.45                          
|$0.77                   | 275,000             | 0.77                            | 4.2                                         | 275,000           | 0.77                           
|$1.18 to $1.53          | 499,400             | 1.36                            | 1.2                                         | 499,400           | 1.36                           
|$2.30 to $2.75          | 865,000             | 2.31                            | 2.7                                         | 576,664           | 2.31                           
|$3.98 to $4.90          | 330,000             | 4.57                            | 4.2                                         | 86,666            | 4.14                           
|$5.24 to $5.74          | 1,040,000           | 5.73                            | 4.3                                         | 346,666           | 5.73                           
|Total                   | 3,226,900           | $3.24                           | 3.3                                         | 2,001,896         | 2.33                           
|                        |                     |                                 |                                             |                   |                                





























---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                







b)

Employee Share Purchase PlanThe Company maintains 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 222,698 have been issued to December 31, 2006.  Compensation costs of $108,098 (2005 - $87,012) have been expensed as part of stock-based compensation.



c)

Normal Course Issuer BidPursuant to Normal Course Issuer Bids, the Company acquired 612,300 (2005  222,900) common shares at an average price of $5.22 (2005 - $5.21) per share.  The excess of cost of reacquisition over stated value of $2,516,691 (2005 - $916,929) has been charged against retained earnings.  At December 31, 2006, a maximum of 3,316,500 common shares may be acquired by the Company until October 1, 2007 under the present Normal Course Issuer Bid.



d)

Stock-based Compensation ExpenseThe fair value of stock options granted during 2006 was estimated on the dates of grant using the Black-Scholes option-pricing method with the following assumptions:

Risk free interest rate of 3.79 to 4.26% (2005 - 3.12 to 3.48%)

Expected life of options of 3.5 to 4.5 years
(2005  - 3.5 to 4.5 years)

Expected volatility of 81.24 to 87.52%
(2005 - 67.47 to 70.69%)

Expected dividend rate of 0% (2005
  -  0%)

Weighted average fair value per option granted
   of $3.54 (2005 - $2.25)



Compensation costs of
$1,727,873 (2005 - $556,870) have been expensed resulting in the recognition of $1,727,873 (2005 - $556,870) of contributed surplus during 2006.



8.

Net income per share



Net income per share has been calculated based on the weighted average number of common shares outstanding during the year of 38,652,164 (2005  38,755,860).
A reconciliation of the denominators for the per share calculations is outlined below:



|                                 |            |           
|-------------------------------- | ---------- | ----------
|                                 | 2006       | 2005      
|Basic weighted average shares    | 38,652,164 | 38,755,860
|Effect of dilutive stock options | 1,127,898  | 1,789,440 
|Dilutive weighted average shares | 39,780,062 | 40,545,300
|                                 |            |           



The calculation of diluted net income per share does not include 1,165,000 (2005  Nil) stock options, as the inclusion of these options would have been
anti-dilutive.



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









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





9.

Financial instruments



a)

Fair ValuesThe 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, 2006 is $13,895,591 (2005 - $8,503,467).
The fair value of bank debt approximates its carrying value as it bears interest at market rates.



b)

Credit RiskThe majority of the Companys accounts receivable are due from joint venture partners in the oil and gas industry and from purchasers of the Companys oil and natural gas production.  The Company generally extends unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions.  Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit.  The Company has not experienced any credit loss in the collection of accounts receivable to date.



c)

Interest Rate RiskThe 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.



10.

Commitments



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



|     |         
|---- | --------
|2007 | $213,439
|2008 | 170,648 
|2009 | 69,496  
|2010 | 69,496  
|2011 | 11,583  



11.

United States accounting principles and reportingThe 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:









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





a)

Full Cost AccountingIn 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.

Depletion under U.S. GAAP is calculated by reference to proved reserves estimated using constant prices and costs.  Depletion under Canadian GAAP is calculated by reference to proved reserves estimated using future prices and costs.

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, 2006 and 2005.



b)

Income TaxesCanadian GAAP previously required the Company to record potential future taxes using the deferral method.  However, the Canadian Institute of Chartered Accountants
(CICA) 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 SharesU.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).  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 2006 is $Nil (2005 - $Nil).
When 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, when expenditures are incurred the future tax liability is recorded through a charge to income tax expense less the reversal of the Premium previously reported.









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





d)

InvestmentsUnder U.S. GAAP, the Company must classify investments in equity securities that have readily determinable fair values as either available for sale or held for 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 transactions 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)

Variable Interest Entities



The CICA issued a 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 U.S. Financial Accounting Standards Boards
(FASB) Interpretation No. 46 Consolidation of Variable Interest Entities.
At December 31, 2006, the Company did not have any interests in variable interest entities.



f)

Share-based Payments



Under Canadian GAAP, compensation costs have been recognized in the consolidated financial statements based on the fair value of stock options granted to employees, officers and directors which follows similar recommendations under FASB Statement of Financial Accounting Standards (FAS) 123(R).  Under FAS 123(R), 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 costs are required to be recognized over the requisite service period.  Forfeitures must be estimated.



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 costs over the vesting period.  Compensation costs are not recognized for equity instruments for which employees do not render the requisite service.



The Company elected to apply the modified prospective application in adopting FAS 123(R) on January 1, 2006.  Under the modified prospective application, FAS 123(R) applies to new awards and to awards modified, repurchased or cancelled after January 1, 2006.  The adoption of FAS 123(R) did not result in restatement of prior periods.





g)

Consolidated Statement of Cash Flows



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





h)

Consolidated Statement of Income



The Company presents the gross amount of petroleum and natural gas sales and the gross amount of royalty expenses.  Under U.S. GAAP, these items are combined and presented on a net basis.









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





i)

Recent Accounting Pronouncements



i)

Accounting Changes and Error Corrections



Effective January 1, 2006 the Company adopted, for U.S. GAAP purposes, FAS 154 Accounting Changes and Error Corrections, a replacement of Accounting Principles Board Opinion No. 20 and FAS 3.  FAS 154 requires retrospective application of changes in accounting principle to prior period financial statements, unless it is impracticable to do so.  Previously, Opinion 20 required that voluntary changes in accounting principles be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change.  This standard did not have an impact on the consolidated financial statements.



ii)

Uncertain Tax Positions



As of January 1, 2007, the Company will be required to adopt, for U.S. GAAP purposes, FASB Interpretation No. 48 Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 which specifies how tax benefits for uncertain tax positions are to be recognized, measured, and derecognized in financial statements and requires certain disclosures of uncertain tax matters.  The Company is currently assessing the impact of this interpretation.



iii)

Fair Value Measurements

As of January 1, 2008, the Company is required to adopt, for U.S. GAAP purposes, FAS 157 Fair Value Measurements.  FAS 157 defines fair value, establishes a framework in measuring fair value and provides disclosure guidance.  This statement is intended to increase the consistency and comparability of fair value measurements and eliminate different definitions of fair value under various U.S. standards.  The Company is currently assessing the impact of this standard.



iv)

Financial Instruments



On January 1, 2007, the Company is required to adopt, for Canadian GAAP purposes, CICA Handbook Section 3855, Financial Instruments  Recognition and Measurement.  This Section prescribes when a financial instrument is to be recognized on the balance sheet and at what amount.  It also specifies how financial instrument gains and losses are to be presented.  The Company is assessing the impact of this new standard on its consolidated financial statements.



v)

Hedges



On January 1, 2007, the Company is required to adopt, for Canadian GAAP purposes, CICA Handbook Section 3865, Hedges.  This Section provides guidance on how to designate qualifying transactions as hedges for accounting purposes by specifying how hedge accounting is applied and what disclosures are necessary when it is applied.  The Company is assessing the impact of this new standard on its consolidated financial statements.



vi)

Comprehensive Income



On January 1, 2007, the Company is required to adopt, for Canadian GAAP purposes, CICA Handbook Section 1530, Comprehensive Income.  This Section introduces a new requirement to temporarily present certain gains and losses from changes in fair value outside net income (similar to U.S. standards).  The Company is assessing the impact of this new standard on its consolidated financial statements.









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





j)

Summary of Significant Differences Between U.S. GAAP and Canadian GAAP



i)

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



|                                                       |            |             | 
|------------------------------------------------------ | ---------- | ----------- | 
|                                                       | 2006       | 2005       
|Net income under Canadian GAAP                         | $2,757,210 | $10,202,438
|U.S. GAAP adjustments                                  |            |            
|Depletion, depreciation & accretion                    | 266,454    | 286,161    
|Future tax expense on flow-through share renouncements | -          | (73,024)   
|Future income taxes                                    | (133,247)  | (529,616)  
|Net income under U.S. GAAP                             | $2,890,417 | $9,885,959 
|                                                       |            |            
|Net income per share                                   |            |            
|Basic                                                  | $0.07      | $0.26      
|Diluted                                                | $0.07      | $0.24      



ii)

Statements of Comprehensive Income



20062005Net income under U.S. GAAP$2,890,417$9,885,959Unrealized gain (loss) on investments, net of tax effect of $(690,146) (2005 - $36,333)4,599,853(172,359)Comprehensive income$7,490,270$9,713,600




iii)

Condensed Consolidated Balance Sheets



|                                       |               |              |               |             
|-------------------------------------- | ------------- | ------------ | ------------- | ------------
|                                       | 2006          | 2005        
|                                       | Canadian GAAP | U.S.
GAAP    | Canadian GAAP | U.S.
GAAP   
|                                       |               |              |               |             
|Current assets                         | $12,590,893   | $12,590,893  | $15,458,139   | $15,458,139 
|Investments                            | 1,809,583     | 13,895,591   | 1,707,458     | 8,503,467   
|Property and equipment                 | 127,425,551   | 126,253,266  | 114,901,195   | 113,462,456 
|                                       | $141,826,027  | $152,739,750 | $132,066,792  | $137,424,062
|                                       |               |              |               |             
|Current liabilities                    | $59,902,890   | $59,902,890  | $54,632,568   | $54,632,568 
|Asset retirement obligations           | 5,104,300     | 5,104,300    | 3,473,144     | 3,473,144   
|Future income taxes                    | 12,393,282    | 13,950,922   | 11,897,016    | 12,631,263  
|                                       | 77,400,472    | 78,985,112   | 70,002,728    | 70,736,975  
|                                       |               |              |               |             
|Share capital                          | 43,515,360    | 45,394,825   | 42,906,253    | 44,785,718  
|Contributed surplus                    | 2,335,783     | 2,335,783    | 823,918       | 823,918     
|Retained earnings                      | 18,574,412    | 15,838,353   | 18,333,893    | 15,464,627  
|Accumulated other comprehensive income | -             | 10,212,677   | -             | 5,612,824   
|                                       | 64,425,555    | 73,781,638   | 62,064,604    | 66,687,087  
|                                       | $141,826,027  | $152,739,750 | $132,066,792  | $137,424,062









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2006 AND 2005                





iv)

Non-cash working capital under U.S. GAAP



|                                         |                 |                
|---------------------------------------- | --------------- | ---------------
|                                         | 2006            | 2005           
|Cash provided by (used for)              |                 |                
|Accounts receivable                      | $ 2,826,962     | $ (2,010,806)  
|Prepaid expenses                         | 45,600          | 669,027        
|Accounts payable and accrued liabilities | (1,321,132)     | 3,549,166      
|Income taxes                             | (8,546)         | 253,339        
|Changes in non-cash working capital      | $     1,542,884 | $     2,460,726









9



---

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 funds flow from operations and operating netbacks.  These measures have no standardized meaning, are not defined by Canadian generally accepted accounting principles (GAAP), and accordingly are referred to as non-GAAP measures.  Gentry calculates funds flow from operations as cash provided by operating activities prior to changes in working capital, and operating netbacks as production revenue less royalties and production expenses.  These terms 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.  These terms 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s 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 prices, reserve estimates, reservoir performance, environmental concerns, industry competition, and the 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.



This MD&A has been prepared as of March 20, 2007.



Selected Annual Information



|                                       |                     |        |         |         |        |     
|-------------------------------------- | ------------------- | ------ | ------- | ------- | ------ | ----
|($thousands, except per share amounts) |                     |        |        
|                                       |                     |        |         | 2006    | 2005   | 2004
|Production revenue                     |                     | 69,832 | 64,665  | 31,717 
|Funds flow from operations             |                     | 30,445 | 35,032  | 13,274 
|                                       | per share - basic   |        | 0.79    | 0.90    | 0.42  
|                                       | per share - diluted |        | 0.77    | 0.86    | 0.40  
|Net income                             |                     |        | 2,757   | 10,202  | 3,402 
|                                       | per share - basic   |        | 0.07    | 0.26    | 0.11  
|                                       | per share - diluted |        | 0.07    | 0.25    | 0.10  
|Total assets                           |                     |        | 141,826 | 132,067 | 95,514
|Long-term financial liabilities        | 17,498              | 15,370 | 9,772  









---





Production and Pricing



The majority of Gentrys operations in 2006 were focused in Alberta.  Activities were primarily directed in the Greater Princess area (Princess) of southern Alberta where the Company was able to pursue both medium gravity crude as well as natural gas production.  Sedalia, another core area in southeastern Alberta, provided additional growth in gas production.



As a result of the growth in Alberta, the Companys production in Saskatchewan, which contributed 12% of volumes in 2005, accounted for only 9% in 2006.  Generally speaking, the Companys non-operated, long-life unitized interests in Saskatchewan are steady producers which have the focused attention of the operators managing their performance.



As the Company moves through 2007, gains in gas production are slated to come from Princess and Sedalia, while the driving force behind increased oil production will be Princess.



|              |                       |                 |              
|------------- | --------------------- | --------------- | -------------
|Oil & liquids | Revenue
($ thousands) | Volume
(bbls/d) | Price
($/bbl)
|2006          | 29,532                | 1,398           | 57.86        
|2005          | 25,589                | 1,330           | 52.71        
|2004          | 13,525                | 862             | 42.88        
|              |                       |                 |              
|Natural Gas   | Revenue
($ thousands) | Volume
(mcf/d)  | Price
($/mcf)
|2006          | 40,301                | 16,658          | 6.63         
|2005          | 39,076                | 11,699          | 9.15         
|2004          | 18,192                | 7,555           | 6.58         
|              |                       |                 |              
|Boe           | Revenue
($ thousands) | Volume
(boe/d)  | Price
($/boe)
|2006          | 69,832                | 4,175           | 45.83        
|2005          | 64,665                | 3,280           | 54.01        
|2004          | 31,717                | 2,121           | 40.86        
|              |                       |                 |              



Gross production revenue increased 8% in 2006 to $69.83 million from $64.67 million a year ago.  The change in revenue was attributable to an additional $17.87 million from increased sales volumes, partially offset by a loss of $12.71 million from reduced commodity prices.



Gentrys natural gas sales rose 42% to 16,658
mcf/d from 11,699 mcf/d in 2005.  This increase contributed $16.56 million to the change in revenue, while the 5% increase in crude oil and liquid sales to 1,398
bbls/d increased revenue by $1.31 million.



The change in gas pricing to $6.63/mcf from $9.15/mcf had the opposite effect on revenue, reducing it by $15.34 million.  This was only partially offset by the additional $2.63 million realized from the increase in oil and liquids pricing to $57.86/bbl from $52.71/bbl a year ago.



Gentry has not entered into any forward contracts for the sale of commodities since 2001 and none are in place for 2007.









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Royalties



Gentrys royalties, net of Alberta Royalty Tax Credit
(ARTC), increased to $17.13 million from $11.87 million in 2005.  Royalties were 24.5% of production on an oil, gas and boe basis in 2006. In 2005, royalties were 18.4% on a boe basis.  Increased royalties and mineral taxes on certain lands in Princess are the primary reasons for the overall increase in royalties.  While royalty rates fluctuate depending on lease terms, royalty holidays, capital cost allowances, and custom processing deductions, Gentry anticipates the royalty rates to decrease marginally in 2007.



|                     |        |        |      
|-------------------- | ------ | ------ | -----
|($thousands)         | 2006   | 2005   | 2004 
|Crown royalties      | 7,221  | 6,295  | 3,690
|Freehold royalties   | 7,095  | 4,015  | 2,129
|Overriding royalties | 3,187  | 2,061  | 886  
|Gross royalties      | 17,503 | 12,371 | 6,705
|ARTC                 | (370)  | (500)  | (440)
|Net royalties        | 17,133 | 11,871 | 6,265
|As a % of revenue    | 24.5%  | 18.4%  | 19.8%



Production Expenses



Production expenses increased to $15.91 million from $11.89 million in 2005.  On a barrel of equivalent basis, costs increased 5% to
$10.44/boe from $9.93/boe in 2005.  The high level of industry activity and tight oilfield services markets resulted in a general increase in field operating costs.  Also contributing to the rise in expenses were increased gas gathering and processing fees at third party facilities, and a significant workover program at the Companys non-operated Provost property.  These factors offset the savings realized from the electrification of certain facilities at Princess and the ownership of fluid handling batteries, also in the Princess area.



General and Administrative Expenses



Gentrys general and administrative expenses remained relatively flat at $3.81 million in 2006, when compared to the $3.76 million in 2005.  Staffing and compensation costs made up almost half of the 2006 expenses versus 43% in 2005.  As expected, on a barrel of oil equivalent basis, general and administrative expenses decreased, falling 20% to
$2.50/boe from $3.14/boe in 2005.  Looking forward to 2007, moderate increases to gross administrative costs are expected, however, as production increases, it is anticipated that per unit costs will decline.



|                     |         |         |        
|-------------------- | ------- | ------- | -------
|($thousands)         | 2006    | 2005    | 2004   
|Gross Expenses       | 5,767   | 5,616   | 4,715  
|Recoveries           | (490)   | (372)   | (376)  
|Capitalized          | (1,469) | (1,489) | (1,165)
|Net Expenses         | 3,808   | 3,755   | 3,174  
|Net Expenses ($/boe) | 2.50    | 3.14    | 4.09   







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Stock Based Compensation



In 2006, Gentrys stock based compensation expense was $1.84 million versus $644 thousand a year ago.  In the most recent year, $1.73 million related to the value of vested stock options while the remaining $108 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 $557 thousand from stock options and $87 thousand from the ESOP.  A greater number of higher valued options vesting in 2006 resulted in the higher charge.



Interest Expense



Gentrys interest expense increased to $2.09 million in 2006 from $1.43 million in 2005.  The primary reason for the higher cost was the increase in interest rates to an average of 5.8% in 2006 from 4.4% in 2005.  In addition, whereas Gentry began and ended 2005 with $17.22 million and $34.15 million in bank debt respectively, it ended 2006 with $40.75 million in bank debt as the Company had a higher utilization factor on its line of credit to fund its capital expenditure programs.



Depletion, Depreciation and Accretion



These charges for 2006 were $25.48 million compared with $19.55 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 $16.72/boe versus $16.33/boe in 2005.



Included in the above amounts is accretion expense, which is the amortization of the Companys asset retirement obligations.  For 2006, this expense amounted to $204 thousand, or
$0.13/boe, compared to $147 thousand, or $0.12/boe, a year ago.



The Companys depletion rate increased to 18.52% in 2006 from 16.59% in 2005 and is based on the ratio of annual production to proved reserves estimates.  While production increased 27%, reserves used for the depletion calculation increased 14%, which accounted for the higher rate.



Income Taxes



Gentry was liable for $319 thousand in current taxes in 2006, which was a 40% decrease from the $535 thousand recorded in 2005.  The biggest reason for the decrease was the elimination of the Large Corporations Tax in 2006.  On a unit of production basis, current taxes were $0.21/boe versus $0.45/boe a year ago.



Future taxes decreased substantially to $496 thousand in 2006 from $4.80 million in 2005.  On a unit of production basis, they equated to $0.33/boe in 2006 versus $4.00/boe in 2005. Future taxes were lower than anticipated due to a decline in the statutory tax rates and the greater increase in depletion charges as compared with the utilization of tax pools.









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At the end of 2006, Gentry had approximately $82.14 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       | $25,701           | 10                          
|Canadian development expense                | 16,576            | 30                          
|Canadian exploration expense                | 6,908             | 100                         
|Foreign exploration and development expense | 193               | 10                          
|Undepreciated capital cost                  | 31,956            | 20-100                      
|Cumulative eligible capital                 | 55                | 7                           
|Financing costs                             | 752               | 20                          
|Total                                       | $82,141           |                             



Funds Flow and Net Income



In 2006, funds flow from operations was $30.44 million versus $35.03 million in 2005.  The increase in gross production revenue was more than offset by the increased royalties and production expenses, resulting in the lower figure.



Net income fell to $2.76 million from $10.20 million in 2005.  In assessing the change, reduced funds flow of $4.59 million, coupled with an additional $5.93 million in depletion, depreciation, and accretion charges and $1.19 million in stock-based compensation expenses, were more than enough to offset the $4.30 million reduction in future taxes.



On a per share basis, funds flow was $0.79 per share ($0.77 diluted) in 2006 compared to $0.90 ($0.86 diluted) in 2005.  Net income was $0.07 per share ($0.07 diluted) versus $0.26 per share ($0.25 diluted) a year ago.



Operating Netbacks



|                        |         |        |       
|----------------------- | ------- | ------ | ------
|($/boe)                 | 2006    | 2005   | 2004  
|Selling price           | 45.83   | 54.01  | 40.86 
|Royalties (net of ARTC) | (11.24) | (9.91) | (8.07)
|Production expenses     | (10.44) | (9.93) | (9.37)
|Operating netbacks      | 24.15   | 34.17  | 23.42 









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Capital Expenditures



Excluding acquisitions and divestitures, capital expenditures decreased 7% to $42.85 million from $46.25 million in 2005.  In 2006, the Company drilled or participated in 51 wells (48.0 net) with a success rate of 90% (91% net), compared to 88 gross wells (57.9 net) and a success rate of 94% (92% net) in 2005.  The Company expended additional funds on facilities, equipping and tie-ins, primarily at Princess, which, going forward, should mean greater production and operational efficiencies.



On a net basis, capital expenditures were $36.25 million in 2006 versus $53.85 million a year ago.  In the fourth quarter of 2006, the Company disposed of approximately 98 boe/d of non-operated production for gross proceeds of $7.21 million.  This was in contrast to the 2005 net acquisition figures when the Company acquired approximately 195 boe/d of production for gross proceeds of $8.08 million.



|                         |         |        |       
|------------------------ | ------- | ------ | ------
|($thousands)             | 2006    | 2005   | 2004  
|Drilling and completions | 18,131  | 26,050 | 11,773
|Facilities and equipping | 17,414  | 13,171 | 6,403 
|Land and seismic         | 5,767   | 5,509  | 7,360 
|Capitalized expenses     | 1,469   | 1,489  | 1,165 
|Other                    | 65      | 28     | 129   
|Gross expenditures       | 42,846  | 46,247 | 26,830
|Acquisitions, net        | (6,597) | 7,607  | 16,571
|Net expenditures         | 36,249  | 53,854 | 43,401



Net Asset Value



At December 31, 2006, the Companys net asset value, based on a 10% discount factor, equated to $5.03 per share compared with $6.20 per share in 2005.  While the value of undeveloped land and seismic increased by 62%, it could not compensate for the reduction in value of the year end reserves.  The following is a summary of the Net Asset Value calculation, discounted at 10%:

|                                       |          |          |         
|-------------------------------------- | -------- | -------- | --------
|($thousands, except per share amounts) | 2006     | 2005     | 2004    
|Reserves                               | 170,463  | 235,376  | 129,322 
|Undeveloped land and seismic1          | 58,286   | 35,945   | 37,101  
|Investments2                           | 13,896   | 8,488    | 8,698   
|Net debt                               | (47,312) | (39,174) | (19,729)
|Net Asset Value                        | 195,333  | 240,635  | 155,392 
|                                       |          |          |         
|Common shares outstanding              | 38,811   | 38,831   | 38,471  
|                                       |          |          |         
|Net asset value per common share       | 5.03     | 6.20     | 4.04    

(1)

internal estimate

(2)

market value as at December 31



Liquidity and Capital Resources



As was the case in 2005, Gentry did not access the equity markets in 2006 as its capital programs were financed from funds flow and its credit facility.



Gentry began the year with 38,830,799 common shares issued and outstanding.  During 2006, the Company issued 551,102 shares on the exercise of incentive stock options ($1.55 per share); 41,529 shares pursuant to the Companys employee share purchase plan ($5.21 per share); and 612,300 shares were repurchased and cancelled pursuant to the Companys Normal Course Issuer Bid







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($5.22 per share).  As a result of these changes, Gentry ended the year with 38,811,130 common shares issued and outstanding.  As of the date of this MD&A, 38,849,110 common shares were outstanding and a further 3,129,167 shares were reserved for issuance pursuant to the exercise of outstanding incentive stock options (at an average price of $3.30 per share).



Gentrys year-end net debt was $47.31 million compared with $39.17 million at the end of 2005.  Gentrys credit limit stands at $50 million and is reviewed semi-annually.  The limit is currently being reviewed based upon the Companys December 31, 2006 Reserves Report.



Gentry owns 10.68 million common shares of Stratic Energy Corporation, a junior international exploration company.  Gentry monitors its investments on a regular basis and as at December 31, 2006, the market value of its Stratic holdings was $13.89 million.



Contractual Obligations



In the normal course of business, Gentry has entered into the following contractual obligations and commitments:



|                            |      |      |      |      |      |      
|--------------------------- | ---- | ---- | ---- | ---- | ---- | -----
|($thousands)                | 2007 | 2008 | 2009 | 2010 | 2011 | Total
|Office lease                | 174  | 159  | -    | -    | -    | 333  
|Firm service transportation | 40   | 12   | 69   | 69   | 12   | 202  
|                            | 214  | 171  | 69   | 69   | 12   | 535  



Fourth Quarter Results



Gentrys financial and operating highlights from the fourth quarter of 2006, as compared with the fourth quarter of 2005, are summarized below:



|                                      |         |        |         
|------------------------------------- | ------- | ------ | --------
|Three months ended December 31        | 2006    | 2005   | % change
|Financial($thousands)                 |         |        |         
|Production revenue                    | 17,924  | 22,165 | (19)    
|Royalties, net of ARTC                | 5,380   | 3,948  | 36      
|Production expenses                   | 5,552   | 3,474  | 60      
|General & administrative              | 1,413   | 1,537  | (8)     
|Interest                              | 607     | 379    | 60      
|Current taxes                         | 63      | 102    | (38)    
|Asset retirement expenditures         | 34      | 74     | (54)    
|Funds flow from operations            | 4,875   | 12,652 | (61)    
|Depletion, depreciation and accretion | 6,659   | 8,716  | (24)    
|Future taxes (recovery)               | (1,487) | 1,170  | (227)   
|Stock-based compensation              | 668     | 103    | 550     
|Net income (loss)                     | (931)   | 2,737  | (134)   
|Capital expenditures, net             | 3,603   | 19,743 | (82)    
|Production                            |         |        |         
|Oil & Liquids (bbls/d)                | 1,447   | 1,486  | (3)     
|Gas (mcf/d)                           | 17,331  | 14,189 | 22      
|Barrels of oil equivalent             | 4,335   | 3,851  | 13      
|Pricing                               |         |        |         
|Oil & Liquids ($/bbl)                 | 50.59   | 52.27  | (3)     
|Natural gas ($/mcf)                   | 7.02    | 11.50  | (39)    
|Barrel of oil equivalent ($/boe)      | 44.94   | 62.56  | (28)    







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In spite of the increased production volumes in the fourth quarter of 2006, production revenue was down due to the lower commodity pricing environment.  Royalties increased as a result of higher rates and the recording of adjustments to prior quarters calculation and accruals.  A portion of the rise in production expenses was attributable to the increased production, but increased costs associated with third party facilities was also a contributing factor as was a general increase due to the tight oilfield services market.  Based largely on the above reasons, funds flow from operations was down 61% over the comparative fourth quarter.



Depletion, depreciation and accretion decreased 24% in the fourth quarter of 2006.  The relatively larger additions to proved reserves in the fourth quarter helped reduce the depletion rate, resulting in the lower figure.  Stock-based compensation increased as the result of certain stock options becoming vested in the most recent quarter, while future income taxes fell significantly due to the reduced profitability of the Company as measured against the comparative quarter.



Deducting the depletion and stock-based compensation expenses from funds flow, and adding back the asset retirement expenditures and future income tax recovery, gives a net loss of $931 thousand in the fourth quarter of 2006.  The largest contributing factor to this loss is the reduced funds flow from operations.



Net capital expenditures decreased significantly to $3.60 million from $19.74 million a year ago, as the Company disposed of 98 boe/d for gross proceeds of $7.21 million.  Gentry also scaled back its capital programs in the most recent quarter as drilling and completions were $4.58 million versus $11.92 million the comparative quarter.  The Company participated in the drilling of seven wells (6.5 net) in the fourth quarter of 2006 versus 29 wells (19.6 net) in the fourth quarter of 2005.  Expenditures on facilities and equipping remained relatively flat at $5.34 million, with the bulk of that dedicated to pipelines, tie-ins and facilities at Princess.





Selected Quarterly Information



|                           |        |        |        |        |  |        |        |        |       
|-------------------------- | ------ | ------ | ------ | ------ |  | ------ | ------ | ------ | ------
|                           | 2006   |        | 2005  
|Three months ended         | Dec 31 | Sep 30 | Jun 30 | Mar 31 |  | Dec 31 | Sep 30 | Jun 30 | Mar 31
|Production                 |        |        |        |        |  |        |        |        |       
|bbls/d                     | 1,447  | 1,538  | 1,289  | 1,317  |  | 1,486  | 1,291  | 1,295  | 1,246 
|mcf/d                      | 17,331 | 14,388 | 18,139 | 16,792 |  | 14,189 | 11,177 | 10,512 | 10,889
|boe/d                      | 4,335  | 3,936  | 4,312  | 4,116  |  | 3,851  | 3,154  | 3,047  | 3,061 
|Financial                  |        |        |        |        |  |        |        |        |       
|Production revenue         | 17,924 | 16,147 | 18,105 | 17,656 |  | 22,165 | 17,685 | 12,832 | 11,984
|Funds flow from operations | 4,875  | 7,085  | 9,481  | 9,004  |  | 12,652 | 10,071 | 6,563  | 5,746 
|per share - basic          | 0.13   | 0.18   | 0.25   | 0.23   |  | 0.33   | 0.26   | 0.17   | 0.15  
|per share - diluted        | 0.12   | 0.18   | 0.23   | 0.22   |  | 0.31   | 0.25   | 0.16   | 0.14  
|Net income (loss)          | (931)  | 104    | 1,639  | 1,945  |  | 2,737  | 4,336  | 1,843  | 1,286 
|per share - basic          | (0.02) | -      | 0.04   | 0.05   |  | 0.07   | 0.11   | 0.05   | 0.03  
|per share - diluted        | (0.02) | -      | 0.04   | 0.05   |  | 0.07   | 0.11   | 0.05   | 0.03  





Production increases are typically stronger in the first and fourth quarters as wells drilled in previous quarters are tied in or begin to produce to single well batteries.  The second quarter is typically characterized by wet weather and break-up conditions, making access to certain locations difficult.  This can restrict exploration programs, field operations, and basic product transportation.  Volumes in the third quarter of 2006 were directly impacted by downtime at three third party operating facilities which curtailed production at both Princess and Sedalia.



Generally speaking, production revenue and funds flow are largely a function of production volumes and commodity prices.  In 2005, Gentrys average sales price rose from
$43.50/boe in the







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first quarter to
$62.56/boe in the fourth quarter, with the biggest jump coming in the third quarter.  In 2006, although both crude oil and gas prices were quite volatile, most of the change in production revenue was volume based, as Gentrys average sales price of
$45.83/boe did not vary by more than $2/boe in any one quarter.  Funds flow from operations was lower than expected in the fourth quarter of 2006 due to increased production expenses and additional royalties recorded in the period.



In the fourth quarter of 2005, net income dropped relative to prior quarters due to increased depletion charges and higher future income taxes.  The depletion charges increased as a result of a larger capital asset base and a higher depletion rate, while future income taxes went up as the Company utilized a greater proportion of its tax pools to reduce its taxable income and current taxes.  In the fourth quarter of 2006, the net loss was largely attributable to the reduced funds flow from operations.



2007 Outlook



Gentrys Board of Directors has approved a revised 2007 capital budget of $45 million, approximately 60% of which is slated for drilling and completions.  The remaining 40% will be spent on land, seismic, and facilities, including new construction and enhancements to existing infrastructure.  This budget will be funded from funds flow and the existing line of credit.



Critical Accounting Estimates



Gentry is required to make certain assumptions and estimates in the application of GAAP 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, exploration and development 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 depletion, depreciation and accretion as well as the ceiling test.  Revisions to reserve estimates could result in a higher or lower depletion, depreciation and accretion 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 Sproule Associates Limited.  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.









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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, depreciation and accretion expense.



Retirement obligations can have a material impact on 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 changes to the carrying value of property and equipment and the related liability, as well as the depletion, depreciation and accretion 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 abandonment, 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, administrative costs 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 and upcoming years, a number of changes to financial reporting requirements have been introduced. The following outlines the most notable changes and those which have, or may have, the greatest impact on Gentry.



Non-Monetary Transactions



The CICA introduced handbook section 3831  Non-Monetary Transactions which became effective for interim and fiscal periods beginning on or after January 1, 2006.  The standard requires that all non-monetary transactions be measured at fair values, rather than book values, if the transaction has commercial substance.  A transaction will have commercial substance if it causes an identifiable and measurable change in the economic circumstance of the entity.  For example, if a







---





Company swaps a producing asset for undeveloped land, there would be an identifiable and measurable change in economic circumstances and the transaction would be measured at fair value.  The impact of this standard cannot be measured until such time as Gentry completes a non-monetary transaction.



Financial Instruments  Recognition and Measurement



The CICA introduced handbook section 3855  Financial Instruments  Recognition and Measurement which becomes effective for interim and annual periods beginning on or after October 1, 2006 (with early adoption permitted).  The standard will require Gentry to classify its financial instruments as: held for trading, held to maturity, loans and receivables, or available for sale.  Gentrys investments will be classified as available for sale and measured at fair value with gains and losses recognized in Comprehensive Income (see new standard below) until the asset is derecognized or becomes impaired.  The Company will adopt this standard for its first quarterly reporting period beginning January 1, 2007.



Comprehensive Income



The CICA introduced handbook section 1530  Comprehensive Income which becomes effective for interim and annual periods beginning on or after October 1, 2006 (with early adoption permitted).  The standard will 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. At December 31, 2006, Gentry followed the cost method of accounting for its investments whereby no gains or losses on investments were recognized unless there had been a permanent decline in value.  The impact of this new standard to the Company will be dependent on the changes in market value of Gentrys investments.  The Company will adopt this standard for its first quarterly reporting period beginning January 1, 2007.



Hedging



The CICA issued handbook section 3865 - Hedges which becomes effective for interim and annual periods beginning on or after October 1, 2006 (with early adoption permitted).  The new standard is optional, but must be applied if an entity chooses to use hedge accounting.  Hedges must be designated as either fair value hedges, cash flow hedges, or hedges of a net investment in a self-sustaining foreign operation.  For a fair value hedge, the gain or loss is recognized in net income in the period of change and the carrying amount of the hedged item is adjusted for the hedged risk.  For other hedges, the effective portion of the hedging items gain or loss is initially reported in Other Comprehensive Income and subsequently reclassified to net income when the hedged item affects net income.  As Gentry had no hedges in place in 2006 and none are in place for 2007, these policy changes currently have no effect on the Company.  Gentry has not yet determined if it will follow this optional standard.



Business Risks and Uncertainties



Gentry, like all companies in the oil and gas industry, operates in an environment subject to inherent risks. Gentry groups these risks into three main areas  operational, financial, and regulatory.



Operational Risks



Gentrys operational activities are focused on the Western Canadian Sedimentary Basin, a competitive environment with a number of companies exploring for hydrocarbons.  The high level of activity has put pressure on the availability and pricing of supplies and materials as well as staff







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and field services.  Other operational risks include weather delays, mechanical or technical difficulties, and exploration risks associated with finding economically viable hydrocarbon reserves.  Gentry attempts to manage these risks by maintaining an inventory of certain critical equipment; conducting advance planning to manage its drilling programs in an efficient and cost effective manner; hiring experienced technical staff and personnel to conduct its exploration programs; and maintaining a broad base of interests in different areas of the Basin.



Gentrys field operations are also subject to health, safety and environmental risks.  Gentry maintains a Health, Safety and Environmental Policy and an Emergency Response Plan which are updated bi-annually or as needed to comply with current legislation.  Both are designed to protect the health and safety of all concerned persons in addition to respecting any environmental regulations.  Gentry also maintains insurance covering property, drilling, pollution, and commercial general liability.



Financial Risks



Financial risks faced by the Company include fluctuations in commodity prices, US/Canadian foreign exchange rates, interest rates, the ability to access capital and/or debt markets, and credit risks associated with its joint venture partners and purchasers.  While Gentry does not hedge its production, foreign exchange rates or interest rates, it does attempt to mitigate overall financial risks by maintaining a debt to forward years cash flow ratio of no more than 1:1, having a flexible capital program, and managing its reliance on joint venture partners.



Regulatory Risks



Gentry is subject to various policies and legislation governing the oil and gas industry.  Although these policies are out of Gentrys direct control, Gentry is a member of the Canadian Association of Petroleum Producers, which, amongst other things, is the voice of the upstream oil and gas industry in Canada. Gentry operates in a manner that is in compliance with applicable regulations and industry standards and must react to comply with changes as they occur.



Disclosure Controls and Procedures



Gentry has designed such disclosure controls and procedures to ensure that information required to be disclosed by the Company is accumulated and communicated to management as appropriate to allow for timely decisions regarding required disclosure. Based on their evaluation, the Companys Chief Executive Officer (CEO) and Chief Financial Officer (CFO) have concluded that Gentrys disclosure controls and procedures are effective to provide reasonable assurance that material information related to the Company is made known to them and that these controls and procedures were operating effectively as of December 31, 2006.  It should be noted that while the evaluation provides a reasonable level of assurance that the disclosure controls and procedures are effective, it does not guarantee that they will prevent all errors and fraud.  A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.



Internal Control Over Financial Reporting



In accordance with Multilateral Instrument 52-109, Gentry has, under the supervision of its CEO and CFO, designed a process of internal control over financial reporting. The process was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (GAAP).









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Based on the CEO and the CFOs review of the design of internal controls over financial reporting, a limitation in the control system has been identified. As a small organization, and similar to other small organizations, Gentrys staff and management is composed of a small number of key individuals such that it is not economically feasible to achieve a complete segregation of duties. As a result of this weakness, there is only reasonable, not absolute, assurance that a material misstatement would not be prevented or detected.  Management and Audit Committee reviews are utilized to mitigate the risk of material misstatement in the financial reporting process.  Additional accounting staff will be added as the Company grows and this is expected to remediate this issue.



It should be noted that while the design of internal control over financial reporting provides a reasonable level of assurance that a material misstatement would be prevented, it does not guarantee that it will prevent all errors and fraud.  A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.



















10



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Exhibit 4





[LETTERHEAD OF COLLINS BARROW CALGARY LLP]











CONSENT OF INDEPENDENT AUDITORS







We hereby consent to the inclusion in Gentry Resources Ltd.s Annual Report on Form 40-F for the year ended December 31, 2006, of our audit report dated March 20, 2007, on the consolidated balance sheets of Gentry Resources Ltd. as at December 31, 2006 and 2005, and the consolidated statements of income and retained earnings and cash flows for the years then ended, to be filed with the United States Securities and Exchange Commission.











/s/ Collins Barrow Calgary LLP

Collins Barrow Calgary LLP

Chartered Accountants

Calgary, Alberta, Canada



April 17, 2007









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Exhibit 5





[LETTERHEAD OF SPROULE ASSOCIATES LIMTED]







CONSENT OF SPROULE ASSOCIATES LIMITED



Reference is made to the Annual Report on Form 40-F for the year ended December 31, 2006 (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 02, 2007 entitled Evaluation of the P&NG Reserves Of Gentry Resources Ltd (As of December 31, 2006) which the Company used, or directly quoted from, in preparing summaries concerning its oil and natural gas reserves, which appear in such Annual Report.







Sproule Associates Limited





/s/
R. Keith MacLeod, P. Eng.



Name:  R.
Keith MacLeod, P. Eng.







April 17, 2007











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CERTIFICATIONExhibit 6.1



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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 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) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(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:  April 17, 2007



/s/ Hugh G. Ross

Hugh G. Ross, President and Chief Executive Officer











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CERTIFICATION

Exhibit 6.2



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)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) 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) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(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:  April 17, 2007



/s/ Ketan Panchmatia

Ketan Panchmatia, Vice President, Finance and Chief Financial Officer











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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, 2006, 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:  April 17, 2007





/s/ 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.













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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, 2006, 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:  April 17, 2007





/s/ 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.