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 12/31/05

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 Class | Name 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:

38,830,799 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.  These statements speak only as of the date of this Annual Report.



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, 2005 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 30, 2005, 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. $0.8579, and on December 31, 2004, the rate was Canadian $1.00 = U.S. $0.8310.





PRINCIPAL DOCUMENTS



Annual Information Form



The Annual Information Form of Gentry Resources Ltd. (the Company) for the year ended December 31, 2005 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, 2005 and 2004, including the auditors report thereon dated March 24, 2006, are included herein as Exhibit 2.  Please refer to Note 12 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, 2005 is included herein as Exhibit 3.





CONTROLS AND PROCEDURES



A.

Disclosure Controls and Procedures



As of December 31, 2005, an evaluation was carried out by the Companys Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Companys disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e)) under the Securities Exchange Act of 1934, as amended).  Based on that evaluation, the Companys Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.



2

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B.

Internal Control over Financial Reporting



During the fiscal year ended December 31, 2005, 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.





NOTICES PURSUANT TO REGULATION BTR



None.





AUDIT COMMITTEE FINANCIAL EXPERT



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





CODE OF ETHICS



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





PRINCIPAL ACCOUNTANT FEES AND SERVICES



The aggregate amounts billed by Collins Barrow Calgary LLP, Chartered Accountants (CBC) to the Company in each of the fiscal years ended December 31, 2005 and 2004 for audit fees, audit-related fees, tax fees and all other fees are set forth below:



|                       |                              |                             
|---------------------- | ---------------------------- | ----------------------------
|                       | Year Ended
December 31, 2005 | Year Ended
December 31, 2004
|Audit Fees (1)         | $  115,300                   | $  74,050                   
|Audit-Related Fees (2) | 4,654                        | 41,251                      
|Tax Fees (3)           | -                            | 3,800                       
|All Other Fees (4)     | 5,500                        | -                           
|Totals                 | $  125,454                   | $119,101                    





3

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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 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, 2005 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.





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, 2005, under Contractual Obligations.





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UNDERTAKING AND CONSENT TO SERVICE OF PROCESS



A.

Undertaking



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



B.

Consent to Service of Process



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





EXHIBITS



The following exhibits are filed as part of this report:



1.

Annual Information Form for the year ended December 31, 2005



2.

Audited Consolidated Financial Statements for the years ended December 31, 2005 and 2004, together with the auditors report thereon dated March 24, 2006 (Note 12  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, 2005



4

Consent of Collins Barrow Calgary LLP, Chartered Accountants



5

Consent of Martin & Brusset Associates



6.1

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



6.2

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



7.1

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



7.2

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



5



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SIGNATURES







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





GENTRY RESOURCES LTD.

Registrant







By:

/s/ Ketan Panchmatia

Name:

Ketan Panchmatia

Title:

Chief Financial Officer





Date:

March 31, 2006





6



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Exhibit 1













[aif002.gif]





















ANNUAL
INFORMATION FORM









YEAR
ENDED DECEMBER 31, 2005









March 27, 2006





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TABLE
OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS

ABBREVIATIONS AND CONVERSION

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

FORWARD LOOKING STATEMENTS

CORPORATE STRUCTURE

GENERAL DEVELOPMENT OF THE BUSINESS

Gentry's
Development over the Last Three Years

RECENT DEVELOPMENTS

DESCRIPTION OF THE BUSINESS

General

Principal
Producing Properties

Summary
of Production from Principal Producing Properties

Marketing
and Risk Management Arrangements

Oil
and Natural Gas Reserves

Summary
of Reserves & Future Net Revenue

Additional
Information Concerning Future Net Revenue

Pricing
Assumptions

Reconciliation
of Reserves

Reconciliation
of Changes in Net Present Value of Future Net Revenue

Undeveloped
Reserves

Future
Development Costs

Oil
and Natural Gas Wells and Properties

Unproved
Properties

Exploration
and Development Activities

Quarterly
Production History

Quarterly
Netback History

Abandonment
and Reclamation Costs

Tax
Horizon

Costs
Incurred

Environmental
and Safety Matters

Insurance

Future
Commitments

Human
Resources

DIVIDENDS

DESCRIPTION OF CAPITAL STRUCTURE



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Common
Shares

Preferred
Shares

Shareholder
Rights Plan

Normal
Course Issuer Bid

INDUSTRY CONDITIONS

Pricing
and Marketing - Oil

Pricing
and Marketing - Natural Gas

The
North American Free Trade Agreement ("NAFTA")

Provincial
Royalties and Incentives

Land
Tenure

Environmental
Regulation

RISK FACTORS

Industry
Risks

Regulation
of Industry

Possible
Income Tax Changes

Need
for Future Financings

Property
Title

Recovery
and Reserve Estimates

Competition

Conflicts
of Interest

Reliance
on Management

Absence
of Dividends

MARKET FOR SECURITIES

DIRECTORS AND OFFICERS

INTEREST OF MANAGEMENT AND OTHERS
IN MATERIAL TRANSACTIONS

INTERESTS OF EXPERTS

REGISTRAR AND TRANSFER AGENT

ADDITIONAL INFORMATION

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

A-1

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

B-1

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

C-1



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GLOSSARY
OF TERMS AND ABBREVIATIONS

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

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

"API"
means American Petroleum Institute;

"ARTC"
means Alberta Royalty Tax Credit;

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

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

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

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

"Martin
Report" means the independent consultants' evaluation of Gentry's oil
and natural gas properties prepared by Martin dated March 23, 2006 and effective
as of December 31, 2005;

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

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

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

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

"TSX"means the Toronto Stock Exchange.

All
information in the Annual Information Form is presented as at December 31, 2005
unless otherwise indicated.





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ABBREVIATIONS
AND CONVERSION

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

|                                                                      |                                                                                                                                                                                                                                                                                                                                                                                                                                                                 |       |                                                             |                                                                                                                                                                                                                                                                                                                       
|--------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ----- | ----------------------------------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|AECO                                                                  | Alberta
      Energy Company interconnect with the Nova System, the Canadian benchmark
      for natural gas pricing purposes                                                                                                                                                                                                                                                                                                                                   |       | GJ
      Mbbls                                              | gigajoules
      one thousand barrels                                                                                                                                                                                                                                                                                 
|MBOE                                                                  | one
      thousand barrels of oil equivalent                                                                                                                                                                                                                                                                                                                                                                                                                   
|bbls                                                                  | barrels,
      with each barrel representing 34.972                                                                                                                                                                                                                                                                                                                                                                                                             |       | Mcf                                                         | one
      thousand cubic feet                                                                                                                                                                                                                                                                                         
|                                                                      | Imperial
      gallons or 42 U.S. gallons                                                                                                                                                                                                                                                                                                                                                                                                                       | Mcf/d | one
      thousand cubic feet per day                      
|bbls/d
      Bcf                                                      | barrels
      per day
      billion
      cubic feet                                                                                                                                                                                                                                                                                                                                                                                                            |       | MMbbls                                                      | one
      million barrels                                                                                                                                                                                                                                                                                             
|MMBOE                                                                 | one
      million barrels of oil equivalent                                                                                                                                                                                                                                                                                                                                                                                                                    
|Bcf/d
      BOE
      
      
      
      
      
      
      BOE/d | billion
      cubic feet per day
      barrels
      of oil equivalent converting 6 Mcf of natural gas to one barrel of
      oil equivalent and one barrel of natural gas liquids to one barrel of oil
      equivalent. The factor used to convert natural gas and natural gas liquids
      to oil equivalent is not based on either energy content or prices but is a
      commonly used industry benchmark.
      barrels
      of oil equivalent per day |       | MMBTU
      MMcf
      MMcf/d
      MW
      NGLs
      WTI | one
      million British Thermal Units
      one
      million cubic feet
      one
      million cubic feet per day
      megawatts
      of electricity
      natural
      gas liquids
      West Texas Intermediate
      at Cushing, Oklahoma, the benchmark for North American crude oil pricing
      purposes

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

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

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







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



Disclosure
of Information

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

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

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

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

The
oil and natural gas operational and reserves information contained in this
Annual Information Form contains the information required to be included in the
Statement of Reserves Data and Other Oil and Gas Information pursuant to
National Instrument 51-101 adopted by the Canadian securities regulatory
authorities and is presented in accordance with Form 51-101F1.  Readers
should also refer to the Report on Reserves Data by Martin attached hereto as
Exhibit "A" and the Report of Management and Directors on Oil and Gas
Disclosure attached hereto as Exhibit "B".  The effective date
for the Statement of Reserves Data and Other Oil and Gas Information contained
in this Annual Information Form is December 31, 2005 and the information
contained in the Annual Information Form has been prepared as of March 27, 2005.

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





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Interests
in Reserves, Production, Wells and Properties

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

"gross"
means:

(i)

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

(ii)

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

(iii)

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

"net"
means:

(i)

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

(ii)

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

(iii)

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

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

Reserves
Categories

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

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

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

Development
and Production Status

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

"Developed
Reserves" are those reserves that are expected to be recovered from
existing wells and installed facilities or, if facilities have not been
installed, that would involve a low expenditure (for example, when compared





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to
the cost of drilling a well) to put the reserves on production.  The
developed category may be subdivided into Producing and Non-Producing.

·

"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, 2005, 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.







- viii -

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GENTRY
RESOURCES LTD.Annual Information Form for
the Year Ended December 31, 2005

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.  Gentry also owns an 8% 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 also indirectly participates, through
its investment in Stratic, in medium to higher risk international exploration
projects.

Gentry's
Development over the Last Three Years

Developments
in 2003

During
2003, Gentry concentrated its exploration efforts on its three core areas -
Princess, Sedalia and Whitecourt.

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

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

At
Sedalia, 15 wells (12.4 net) were drilled in 2003, resulting in 11 gas wells.
Gentry aggressively moved forward to acquire land immediately offsetting the
Sedalia area.  37 sections ranging from 50% to 100% working interest have
been acquired west of the initial Sedalia activity, while another 19 sections
came under Gentry's control east of Sedalia at a 25% to 100% working interest
position.





- 1 -

---







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

On
October 30, 2003, Gentry completed an equity offering of three million
common shares at a price of $1.75 per common share for total gross proceeds of
$5.25 million.  The proceeds from this financing were utilized to fund the
continued exploration and development of Gentry's oil and natural gas
properties, including acquisitions, and proceeds were used to temporarily reduce
indebtedness until required for those purposes.

Developments
in 2004

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

The
lands are "Grant Lands"and as such have no expiration of the mineral
rights for lands that are not on production.  The lands are split between
two land blocks. The larger of the two is at Bantry comprising 124 sections of
land, of which the Company owns an average of 75% or 93 net sections.  The
mineral interests held on these lands include rights below the basal Mannville,
or more specifically, all Paleozoic rights.  The second land block is at
Princess (just north of Bantry) where Gentry has acquired 31 sections of land,
of which the 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.

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 are helping 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





- 2 -

---







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 are easing and Gentry is now flowing 5.5 mmcf/d to four separate
third party processing facilities.

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.  It is anticipated that gas production from the
area will reach 1.4 mmcf/d net to Gentry once all the wells have been tied-in.



RECENT
DEVELOPMENTS

In
February, 2006 the third party sour gas plant at Princess began processing two
mmcf/d of Gentry's Nisku gas from Princess.  This production is expected
to double after plant expansion, currently scheduled for the second quarter of
2006.



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.

Gentry
holds an 8% interest in Stratic, which participates in oil and gas exploration
and development activities in Turkey, Morocco, the U.K. North Sea, and Syria.

Principal
Producing Properties

The
following is a description of Gentry's principal producing oil and gas
properties as of December 31, 2005.

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.





- 3 -

---







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 8 bbls/d of oil and liquids and 155
mcf/d of gas in 2005.

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. 2005 production averaged 834 bbls/d of oil and liquids and 4,474 mcf/d
of gas.

Red
Rock

The
Red Rock area is located approximately 50 kilometres south of Grande Prairie, in
west-central Alberta.  Gentry owns a 3.35564% working interest in the Red
Rock Chinook Unit No. 1 plus various working interests ranging from a 0.78125%
working interest to a 25.0% working interest in non-unit lands in the Red Rock
area.  The Red Rock Chinook Unit No. 1 and non-unit lands produced an
average of 9 bbls/d of crude oil and 83 mcf/d of natural gas in 2005.

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.  2005 production averaged 7 bbls/d and 786 mcf/d.

Red
Willow North

The
Red Willow North property is located approximately 100 kilometres east of
Edmonton, Alberta.  Gentry owns interests in five gas wells varying in
interest from 40.4% to 62.5%.  The wells produced an average of 869 mcf/d
of gas net to Gentry in 2005.

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 2005 averaged 2,976 mcf/d of gas.

Thornbury

The
Thornbury area is located approximately 100 kilometres southwest of Fort
McMurray in northeastern Alberta.  Gentry owns an 18.333% working interest
in the area. Natural gas production for 2005 averaged approximately 158 mcf/d.

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 45% in the non-unit lands. For 2005,
production averaged 75 bbls/d of oil and liquids and 735 mcf/d of gas.





- 4 -

---





Whitecourt

The
Whitecourt lands are located west-central Alberta.  Gentry owns interests
ranging between 20% and 50%.  Production in 2005 averaged 9 bbls/d of oil
and 1,067 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 50 bbls/d of crude oil in 2005.

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 2005 was approximately 77 bbls/d
of crude oil.

Dollard

The
Dollard area is located approximately 300 kilometres west-southwest of Regina.
 Gentry has a 3.853% working interest in the Dollard Unit and a gross
overriding royalty of approximately 1.5% in the East Dollard Voluntary Unit.
 Production from these units averaged 93 bbls/d of crude oil and 10 mcf/d
of gas in 2005.

Steelman

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

In
the Steelman Unit 1A, Gentry holds a 2.707% working interest in the Unit.
Production from this unit in 2004 was approximately 17 bbls/d of crude oil and 8
mcf/d of natural gas.

In
the Steelman Unit 4, Gentry holds a 13.938% working interest in the Unit.
 Production from this unit was approximately 77 bbls/d of crude oil and 49
mcf/d of natural gas in 2005.

In
the Steelman Unit 5, Gentry holds a 19.927% working interest in the Unit.
Production from this unit was 23 bbls/d of crude oil and 10 mcf/d of natural gas
in 2005.





- 5 -

---







Summary
of Production from Principal Producing Properties

During
the year ended December 31, 2005, 87.6% of the Corporation's production was
derived from Alberta, 11.9% from Saskatchewan and 0.5% from Manitoba (the
Corporation sold its interests in Manitoba in the first half of 2005).  The
following table describes the Corporation's major properties and the averagedaily
production from these properties during the year ended December 31, 2005.

|                       |                                                 |                                  |                      
|---------------------- | ----------------------------------------------- | -------------------------------- | ---------------------
|                       | Product
      Type                             
|                       | Light
      & Medium Crude Oil
      (bbls/day) | Natural
      Gas
      Mcf/day) | Total
      (boe/day)
|Alberta                |                                                 |                                  |                      
|Joffre                 | 8                                               | 155                              | 34                   
|Princess               | 834                                             | 4,474                            | 1,580                
|Red
      Rock         | 9                                               | 83                               | 23                   
|Red
      Willow       | 7                                               | 786                              | 138                  
|Red
      Willow North | -                                               | 869                              | 145                  
|Sedalia                | -                                               | 2,976                            | 496                  
|Thornbury              | -                                               | 158                              | 26                   
|West
      Provost     | 75                                              | 735                              | 198                  
|Whitecourt             | 9                                               | 1,067                            | 187                  
|Other                  | -                                               | 285                              | 47                   
|                       |                                                 |                                  |                      
|Saskatchewan           |                                                 |                                  |                      
|Baldwinton             | 50                                              | -                                | 50                   
|Benson                 | 77                                              | -                                | 77                   
|Dollard                | 93                                              | 10                               | 95                   
|Steelman               | 117                                             | 67                               | 128                  
|Other                  | 36                                              | 34                               | 41                   
|                       |                                                 |                                  |                      
|Manitoba               |                                                 |                                  |                      
|Virden
      Roselea   | 15                                              | -                                | 15                   
|                       |                                                 |                                  |                      
|TOTAL                  | 1,330                                           | 11,699                           | 3,280                





- 6 -

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Marketing
and Risk Management Arrangements

In
2005, 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 2005. The
Corporation does not currently have a hedging program in place for 2006.

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

Oil
and Natural Gas Reserves

In
the Martin Report, Martin has evaluated all of the crude oil, NGLs and natural
gas reserves associated with Gentry's properties effective as of December 31,
2005 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, Martin obtained basic information from Gentry, which
included land data, well information, geological information, reservoir studies,
estimates of on-stream dates, contract information, current hydrocarbon product
prices, operating cost data, capital budget forecasts, financial data and future
operating plans.  Other engineering, geological or economic data required
to conduct the evaluation and upon which the Martin Report is based was obtained
from public records, other operators and from Martin's non-confidential files.
 Information concerning the extent and character of ownership of Gentry's
interests and the accuracy of all factual data supplied to Martin by third
parties was accepted by Martin as represented.

The following
is a summary, as at December 31, 2005, of the crude oil, NGLs and natural gas
reserves of Gentry and the net present value of the estimated future net revenue
ascribed to such reserves as evaluated in the Martin Report, based on both
forecast and constant price and cost assumptions. All future net revenues are
stated prior to provision for interest, future site restoration and reclamation
costs, income taxes, general and administrative expenses and indirect costs and
after deduction of royalties and estimated future capital expenditures. It
should not be assumed that the present worth of estimated future cash flows
shown below is representative of the fair market value of the reserves. There is
no assurance that such price and cost assumptions will be attained and variances
could be material. The recovery and reserve estimates of Gentry's crude oil,
NGLs and natural gas reserves provided herein are estimates only. Actual
reserves may be greater than or less than the estimates provided herein. Readers
should review the definitions and information contained in "Presentation of
Gentry's Oil and Natural Gas Reserves and Production Information" in
conjunction with the following tables and notes. Columns may not add due to
rounding.





- 7 -

---







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, 2005:



Forecast
Prices and Costs



|                                          |                          |                   |                    |                  |                    |                  |  | 
|----------------------------------------- | ------------------------ | ----------------- | ------------------ | ---------------- | ------------------ | ---------------- |  | 
|                                          | Light
      & Medium Oil | Natural
      Gas | Total             
|Reserves
      Category                   | Gross
      (mbbls)      | Net
      (mbbls) | Gross
      (mmcf) | Net
      (mmcf) | Gross
      (mboe) | Net
      (mboe)
|Proved
      Reserves                     |                          |                   |                    |                  |                    |                 
|Proved
      Developed Producing          | 2,592                    | 2,199             | 16,283             | 13,521           | 5,306              | 4,453           
|Proved
      Developed Non-Producing      | 55                       | 45                | 3,028              | 2,398            | 560                | 445             
|Proved
      Undeveloped Reserves         | 21                       | 15                | 435                | 376              | 94                 | 78              
|Total
      Proved                        | 2,667                    | 2,259             | 19,746             | 16,295           | 5,958              | 4,975           
|                                          |                          |                   |                    |                  |                    |                 
|Probable
      Reserves                   |                          |                   |                    |                  |                    |                 
|Probable
      Developed                  | 1,295                    | 1,095             | 10,752             | 8,702            | 3,087              | 2,545           
|Probable
      Undeveloped                | 361                      | 309               | 7,567              | 6,295            | 1,622              | 1,358           
|Total
      Probable                      | 1,654                    | 1,403             | 18,318             | 14,997           | 4,707              | 3,903           
|                                          |                          |                   |                    |                  |                    |                 
|Total
      Proved Plus Probable Reserves | 4,321                    | 3,663             | 38,064             | 31,291           | 10,665             | 8,878           



|                                          |                                                            |         |         |         |        
|----------------------------------------- | ---------------------------------------------------------- | ------- | ------- | ------- | -------
|                                          | Net
      Present Values of Future Net Revenue($thousands)
|                                          | Before
      Income Taxes, Discounted at (%/year)         
|Reserves
      Category                   | 0                                                          | 5       | 10      | 15      | 20     
|Proved
      Reserves                     |                                                            |         |         |         |        
|Proved
      Developed Producing          | 172,740                                                    | 141,826 | 124,342 | 112,460 | 103,532
|Proved
      Developed Non-Producing      | 18,503                                                     | 16,803  | 15,461  | 14,361  | 13,436 
|Proved
      Undeveloped Reserves         | 1,858                                                      | 1,214   | 835     | 580     | 398    
|Total
      Proved                        | 193,101                                                    | 159,843 | 140,638 | 127,402 | 117,366
|                                          |                                                            |         |         |         |        
|Probable
      Reserves                   |                                                            |         |         |         |        
|Probable
      Developed                  | 101,458                                                    | 74,816  | 61,574  | 52,984  | 46,740 
|Probable
      Undeveloped                | 48,112                                                     | 39,407  | 33,164  | 28,496  | 24,881 
|Total
      Probable                      | 149,570                                                    | 114,224 | 94,738  | 81,480  | 71,621 
|                                          |                                                            |         |         |         |        
|Total Proved Plus
      Probable Reserves | 342,671                                                    | 274,067 | 235,376 | 208,882 | 188,987



|                                          |                                                            |         |         |         |        
|----------------------------------------- | ---------------------------------------------------------- | ------- | ------- | ------- | -------
|                                          | Net
      Present Values of Future Net Revenue($thousands)
|                                          | After
      Income Taxes, Discounted at (%/year)          
|Reserves
      Category                   | 0                                                          | 5       | 10      | 15      | 20     
|Proved
      Reserves                     |                                                            |         |         |         |        
|Proved
      Developed Producing          | 139,439                                                    | 113,651 | 99,191  | 89,424  | 82,123 
|Proved
      Developed Non-Producing      | 12,273                                                     | 11,030  | 10,060  | 9,273   | 8,616  
|Proved
      Undeveloped Reserves         | 1,239                                                      | 773     | 497     | 311     | 178    
|Total
      Proved                        | 152,951                                                    | 125,454 | 109,748 | 99,008  | 90,917 
|                                          |                                                            |         |         |         |        
|Probable
      Reserves                   |                                                            |         |         |         |        
|Probable
      Developed                  | 67,356                                                     | 49,474  | 40,805  | 35,174  | 31,053 
|Probable
      Undeveloped                | 32,257                                                     | 26,079  | 21,657  | 18,356  | 15,805 
|Total
      Probable                      | 99,613                                                     | 75,553  | 62,462  | 53,530  | 46,858 
|                                          |                                                            |         |         |         |        
|Total Proved Plus
      Probable Reserves | 252,564                                                    | 201,007 | 172,210 | 152,538 | 137,775





- 8 -

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Constant
Prices and Costs



|                                          |                          |                   |                    |                  |                    |                  |  | 
|----------------------------------------- | ------------------------ | ----------------- | ------------------ | ---------------- | ------------------ | ---------------- |  | 
|                                          | Light
      & Medium Oil | Natural
      Gas | Total             
|Reserves
      Category                   | Gross
      (mbbls)      | Net
      (mbbls) | Gross
      (mmcf) | Net
      (mmcf) | Gross
      (mboe) | Net
      (mboe)
|Proved
      Reserves                     |                          |                   |                    |                  |                    |                 
|Proved
      Developed Producing          | 2,604                    | 2,212             | 16,288             | 13,453           | 5,319              | 4,454           
|Proved
      Developed Non-Producing      | 55                       | 45                | 3,030              | 2,354            | 560                | 437             
|Proved
      Undeveloped Reserves         | 21                       | 15                | 438                | 375              | 94                 | 78              
|Total
      Proved                        | 2,679                    | 2,272             | 19,756             | 16,182           | 5,972              | 4,969           
|                                          |                          |                   |                    |                  |                    |                 
|Probable
      Reserves                   |                          |                   |                    |                  |                    |                 
|Probable
      Developed                  | 1,296                    | 1,097             | 10,774             | 8,649            | 3,092              | 2,539           
|Probable
      Undeveloped                | 361                      | 309               | 7,575              | 6,282            | 1,624              | 1,356           
|Total
      Probable                      | 1,656                    | 1,406             | 18,349             | 14,932           | 4,714              | 3,895           
|                                          |                          |                   |                    |                  |                    |                 
|Total
      Proved Plus Probable Reserves | 4,334                    | 3,679             | 38,105             | 31,113           | 10,685             | 8,865           



|                                          |                                                            |         |         |         |        
|----------------------------------------- | ---------------------------------------------------------- | ------- | ------- | ------- | -------
|                                          | Net
      Present Values of Future Net Revenue($thousands)
|                                          | Before
      Income Taxes, Discounted at (%/year)         
|Reserves Category                         | 0                                                          | 5       | 10      | 15      | 20     
|Proved Reserves                           |                                                            |         |         |         |        
|Proved
      Developed Producing          | 187,156                                                    | 151,322 | 130,316 | 115,959 | 105,263
|Proved
      Developed Non-Producing      | 18,539                                                     | 16,501  | 14,939  | 13,693  | 12,666 
|Proved
      Undeveloped Reserves         | 2,590                                                      | 1,718   | 1,192   | 842     | 595    
|Total Proved                              | 208,285                                                    | 169,540 | 146,448 | 130,494 | 118,525
|                                          |                                                            |         |         |         |        
|Probable Reserves                         |                                                            |         |         |         |        
|Probable
      Developed                  | 114,580                                                    | 85,373  | 69,417  | 58,831  | 51,146 
|Probable
      Undeveloped                | 57,453                                                     | 46,039  | 38,050  | 32,171  | 27,680 
|Total Probable                            | 172,033                                                    | 131,412 | 107,466 | 91,002  | 78,826 
|                                          |                                                            |         |         |         |        
|Total
      Proved Plus Probable Reserves | 380,318                                                    | 300,952 | 253,914 | 221,497 | 197,350



|                                          |                                                            |         |         |         |        
|----------------------------------------- | ---------------------------------------------------------- | ------- | ------- | ------- | -------
|                                          | Net
      Present Values of Future Net Revenue($thousands)
|                                          | After
      Income Taxes, Discounted at (%/year)          
|Reserves
      Category                   | 0                                                          | 5       | 10      | 15      | 20     
|                                          |                                                            |         |         |         |        
|Proved Reserves                           | 149,393                                                    | 120,208 | 103,327 | 91,868  | 83,363 
|Proved
      Developed Producing          | 12,322                                                     | 10,849  | 9,731   | 8,843   | 8,115  
|Proved
      Developed Non-Producing      | 1,747                                                      | 1,118   | 741     | 490     | 314    
|Proved
      Undeveloped Reserves         | 163,462                                                    | 132,175 | 113,799 | 101,201 | 91,792 
|Total Proved                              |                                                            |         |         |         |        
|                                          |                                                            |         |         |         |        
|Probable Reserves                         | 76,523                                                     | 56,779  | 46,200  | 39,181  | 34,066 
|Probable
      Developed                  | 39,084                                                     | 32,706  | 28,051  | 24,526  | 21,773 
|Probable
      Undeveloped                | 115,607                                                    | 89,485  | 74,251  | 63,707  | 55,839 
|Total Probable                            |                                                            |         |         |         |        
|Total
      Proved Plus Probable Reserves | 279,069                                                    | 221,660 | 188,050 | 164,908 | 147,631







- 9 -

---





Additional
Information Concerning Future Net Revenue

The
undiscounted total future net revenue by reserves categories as of December 31,
2005, using both constant and forecast prices and costs, is set forth below:



|                                             |                               |                                     |                       |                                    
|-------------------------------------------- | ----------------------------- | ----------------------------------- | --------------------- | -----------------------------------
|                                             | Constant
      Prices & Costs | Forecast
      Prices & Costs      
|($thousands)                                 | Proved
      Reserves         | Proved
      Plus Probable Reserves | Proved
      Reserves | Proved
      Plus Probable Reserves
|Revenue                                      | 345,950                       | 621,688                             | 340,249               | 597,531                            
|Royalties                                    | (69,801)                      | (125,790)                           | (68,881)              | (120,739)                          
|Operating
      costs                        | (62,757)                      | (100,264)                           | (72,712)              | (118,123)                          
|Development
      Costs                      | (3,113)                       | (12,984)                            | (3,127)               | (13,003)                           
|Abandonment
      and Reclamation Costs      | (1,994)                       | (2,332)                             | (2,428)               | (2,995)                            
|Future
      Net Revenue Before Income Taxes | 208,285                       | 380,318                             | 193,101               | 342,671                            
|Income
      Taxes                           | (44,823)                      | (101,249)                           | (40,150)              | (90,107)                           
|Future
      Net Revenue After Income Taxes  | 163,462                       | 279,069                             | 152,951               | 252,564                            



The
net present value of future net revenue by reserves category and production
group as of December 31, 2005, using both constant and forecast prices and costs
and discounted at 10% per year, is set forth below:



|                                    |                                     |                                                               |                                        
|----------------------------------- | ----------------------------------- | ------------------------------------------------------------- | ---------------------------------------
|                                    |                                     | Future
      Net Revenue
      (Discounted
      at 10%/year)
|Reserves
      Category             | Production
      Group              | Constant
      Prices and Costs ($000s)                       | Forecast
      Prices and Costs ($000s)
|Proved
      Reserves               | Light and
      Medium Crude Oil(a) | 57,399                                                        | 52,840                                 
|                                    | Natural
      Gas(b)                | 87,257                                                        | 86,221                                 
|                                    |                                     |                                                               |                                        
|Proved
      Plus Probable Reserves | Light and
      Medium Crude Oil(a) | 100,455                                                       | 91,476                                 
|                                    | Natural
      Gas(b)                | 150,954                                                       | 141,712                                



(a)

Includes
solution gas and other by-products.

(b)

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



The volume of
gross Proved plus Probable production estimated by Martin for 2006 in preparing
the estimated net present values of future net revenue is as follows.

|                                 |                                                       |                                                  
|-------------------------------- | ----------------------------------------------------- | -------------------------------------------------
|Product
      Type               | Aggregate
      Estimated
      2006
      Production | Daily
      Estimated
      2006
      Production
|Light
      and medium crude oil | 634
      mbbls                                       | 1,737
      bbls/d                               
|Natural
      gas                | 7,882
      mmcf                                      | 21,595 mcf/d                                     
|Total                            | 1,948
      mboe                                      | 5,337
      boe/d                                







- 10 -

---







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 the reference
prices below for quality while gas prices have been adjusted for heating values.
The reference prices are the average prices derived from the internet websites
of Gilbert Lausten Jung Associated Ltd, McDaniel & Associates Consultants
Ltd and Sproule Associates Limited.  Gentry's weighted average oil and liquids price realized in 2005 was Cdn
$52.71/bbl, while the gas price was Cdn $9.15/mcf.



|           |                                            |                                                   |                                                             |                                     |            |          | 
|---------- | ------------------------------------------ | ------------------------------------------------- | ----------------------------------------------------------- | ----------------------------------- | ---------- | -------- | 
|           | Crude
      Oil                            | Natural
      Gas                                 | Exchange
      Rate                                         | Inflation
      Rate               
|Year       | WTI
      Cushing Oklahoma
      ($US/bbl) | Edmonton
      Par Price 40o API
      ($Cdn/bbl) | Bow
      River Stream
      25o
      API
      ($Cdn/bbl) | Spot
      Price
      ($Cdn/mmbtu) | ($US/$Cdn) | (%/year)
|2006       | 58.44                                      | 67.64                                             | 45.32                                                       | 10.68                               | 0.86       | 0       
|2007       | 57.34                                      | 66.40                                             | 45.20                                                       | 9.63                                | 0.85       | 2       
|2008       | 52.70                                      | 60.89                                             | 42.74                                                       | 8.23                                | 0.83       | 2       
|2009       | 49.23                                      | 56.83                                             | 40.79                                                       | 7.33                                | 0.83       | 2       
|2010       | 47.05                                      | 54.25                                             | 39.48                                                       | 6.98                                | 0.83       | 2       
|2011       | 47.19                                      | 54.41                                             | 40.16                                                       | 6.99                                | 0.83       | 2       
|2012       | 47.83                                      | 55.12                                             | 40.77                                                       | 7.09                                | 0.83       | 2       
|2013       | 48.81                                      | 56.20                                             | 41.66                                                       | 7.23                                | 0.83       | 2       
|2014       | 49.75                                      | 57.32                                             | 42.55                                                       | 7.40                                | 0.83       | 2       
|2015       | 50.77                                      | 58.53                                             | 43.53                                                       | 7.58                                | 0.83       | 2       
|2016       | 51.79                                      | 59.66                                             | 44.43                                                       | 7.73                                | 0.83       | 2       
|Thereafter | 2.0%                                       | 2.0%                                              | 2.0%                                                        | 2.0%                                | 0.83       | 2       



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



|                                           |                                                   |                                                 |                                     |            |         
|------------------------------------------ | ------------------------------------------------- | ----------------------------------------------- | ----------------------------------- | ---------- | --------
|Crude
      Oil                            | Natural
      Gas                                 | Exchange
      Rate                             | Inflation
      Rate               
|WTI
      Cushing Oklahoma
      ($US/bbl) | Edmonton
      Par Price 40o API
      ($Cdn/bbl) | Bow
      River Medium 25o API
      ($Cdn/bbl) | Spot
      Price
      ($Cdn/mmbtu) | ($US/$Cdn) | (%/year)
|61.04                                      | 68.05                                             | 45.05                                           | 9.25                                | 0.86       | 0       



Reconciliation
of Reserves

The following
tables reconcile the Corporation's oil and natural gas reserves (on both a gross
and net basis) from December 31, 2004 to December 31, 2005, using forecast
prices and costs.



Reconciliation
of Gross Reserves



|                          |                                  |                        |                                       |                     |                       |                                      |                     |                       |                                      
|------------------------- | -------------------------------- | ---------------------- | ------------------------------------- | ------------------- | --------------------- | ------------------------------------ | ------------------- | --------------------- | -------------------------------------
|                          | Light
      and Medium Crude Oil | Natural
      Gas      | Total                                
|Factors                   | Proved
      (mbbls)             | Probable
      (mbbls) | Proved
      & Probable
      (mbbls) | Proved
      (mmcf) | Probable
      (mmcf) | Proved
      & Probable
      (mmcf) | Proved
      (mboe) | Probable
      (mboe) | Proved
      & Probable
      (mmboe)
|December
      31, 2004   | 2,415                            | 1,156                  | 3,570                                 | 15,974              | 14,446                | 31,421                               | 5,078               | 3,564                 | 8,642                                
|Acquisitions              | 400                              | 206                    | 606                                   | 696                 | 341                   | 1,037                                | 509                 | 259                   | 768                                  
|Dispositions              | (155)                            | (70)                   | (225)                                 | (23)                | (16)                  | (39)                                 | (155)               | (71)                  | (226)                                
|Extensions                | -                                | -                      | -                                     | -                   | -                     | -                                    | -                   | -                     | -                                    
|Technical
      Revisions | 22                               | (79)                   | (57)                                  | 2,520               | (1,588)               | 932                                  | 447                 | (345)                 | 102                                  
|Discoveries               | 471                              | 441                    | 912                                   | 4,849               | 5,135                 | 9,984                                | 1,276               | 1,300                 | 2,576                                
|Economic
      Factors    | -                                | -                      | -                                     | -                   | -                     | -                                    | -                   | -                     | -                                    
|Improved
      Recovery   | -                                | -                      | -                                     | -                   | -                     | -                                    | -                   | -                     | -                                    
|Production                | (486)                            | -                      | (486)                                 | (4,270)             | -                     | (4,270)                              | (1,197)             | -                     | (1,197)                              
|December
      31, 2005   | 2,667                            | 1,654                  | 4,321                                 | 19,746              | 18,318                | 38,064                               | 5,958               | 4,707                 | 10,665                               





- 11 -

---







Reconciliation
of Net Reserves



|                          |                                  |                        |                                       |                     |                       |                                      |                     |                       |                                      
|------------------------- | -------------------------------- | ---------------------- | ------------------------------------- | ------------------- | --------------------- | ------------------------------------ | ------------------- | --------------------- | -------------------------------------
|                          | Light
      and Medium Crude Oil | Natural
      Gas      | Total                                
|Factors                   | Proved
      (mbbls)             | Probable
      (mbbls) | Proved
      & Probable
      (mbbls) | Proved
      (mmcf) | Probable
      (mmcf) | Proved
      & Probable
      (mmcf) | Proved
      (mboe) | Probable
      (mboe) | Proved
      & Probable
      (mmboe)
|December
      31, 2004   | 2,075                            | 952                    | 3,028                                 | 13,281              | 11,543                | 24,824                               | 4,289               | 2,876                 | 7,116                                
|Acquisitions              | 320                              | 165                    | 485                                   | 575                 | 282                   | 857                                  | 416                 | 212                   | 628                                  
|Dispositions              | (124)                            | (56)                   | (180)                                 | (19)                | (13)                  | (32)                                 | (127)               | (58)                  | (185)                                
|Extensions                | -                                | -                      | -                                     | -                   | -                     | -                                    | -                   | -                     | -                                    
|Technical
      Revisions | 18                               | (63)                   | (46)                                  | 2,083               | (1,313)               | 796                                  | 365                 | (282)                 | 82                                   
|Discoveries               | 361                              | 405                    | 766                                   | 3,905               | 4,498                 | 8,403                                | 1,012               | 1,155                 | 2,167                                
|Economic
      Factors    | -                                | -                      | -                                     | -                   | -                     | -                                    | -                   | -                     | -                                    
|Improved
      Recovery   | -                                | -                      | -                                     | -                   | -                     | -                                    | -                   | -                     | -                                    
|Production                | (389)                            | -                      | (389)                                 | (3,530)             | -                     | (3,530)                              | (978)               | -                     | (978)                                
|December
      31, 2005   | 2,260                            | 1,403                  | 3,663                                 | 16,295              | 14,997                | 31,291                               | 4,976               | 3,903                 | 8,878                                



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, 2004 to December 31, 2005 using constant prices and costs and
discounted at 10% per year.



|                                                                                                             |             
|------------------------------------------------------------------------------------------------------------ | ------------
|Period
      and Factor                                                                                      | ($thousands)
|Estimated
      Future Net Revenue at December 31, 2004                                                      | 57,196      
|Sales
      and Transfers of Oil, Natural Gas and NGLs Produced, Net of Production
      Costs and Royalties | (40,908)    
|Net
      Change in Prices, Production Costs and Royalties related to Future
      Production                | 6,781       
|Changes
      in Previously Estimated Development Costs Incurred During the Period                           | (200)       
|Changes
      in Estimated Future Development Costs                                                          | (2,917)     
|Extension
      and Improved Recovery                                                                        | -           
|Discoveries                                                                                                  | 63,807      
|Acquisitions
      of Reserves                                                                               | 26,229      
|Disposition
      of Reserves                                                                                | (2,060)     
|Net
      Change Resulting from Revisions in Quantity Estimates                                              | 23,014      
|Accretion
      of Discount                                                                                  | 4,692       
|Net
      Change in Income Taxes(1)                                                                          | (21,835)    
|Estimated
      Future Net Revenue at December 31, 2005                                                      | 113,799     



Note:

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



Undeveloped
Reserves

The following
table discloses the gross volumes of undeveloped reserves, using constant prices
and costs, of the Corporation as at December 31, 2005 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)
|2004 | 0                                              | 0                                   | 54                                             | 4,729                         
|2005 | 21                                             | 438                                 | 307                                            | 2,846                         
|     | 21                                             | 438                                 | 361                                            | 7,575                         



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.





- 12 -

---







The
Corporation's proved undeveloped reserves are generally developed within 12
months and as such, the Corporation anticipates the necessary expenditures to
develop these reserves will be incurred prior to 2007.



The Corporation's probable
undeveloped reserves are dominated by the requirement for additional sour gas
processing facilities in the Princess area.  Additional sour capacity has
been built in the first quarter of 2006 and will be expanded in the second
quarter, thereby developing these reserves in 2006 and 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
|2006      | 2,928                           | 2,662                           | 2,928                               | 2,662                        | 12,673       | 11,521                      
|2007      | 43                              | 36                              | 44                                  | 36                           | 110          | 91                          
|2008      | 29                              | 22                              | 30                                  | 23                           | 87           | 65                          
|2009      | 29                              | 20                              | 31                                  | 21                           | 31           | 21                          
|2010      | 22                              | 14                              | 23                                  | 14                           | 23           | 14                          
|Remaining | 62                              | 35                              | 71                                  | 40                           | 79           | 45                          
|          | 3,113                           | 2,788                           | 3,127                               | 2,796                        | 13,003       | 11,757                      



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



Oil
and Natural Gas Wells and Properties

The following
table summarizes, as at December 31, 2005, 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      | 50                    | 39                  | 73    | 58                | 15    | 12  | 14    | 12 
|Saskatchewan | 1,250                 | 57                  | 390   | 8                 | 96    | 15  | 15    | 8  
|Total        | 1,300                 | 96                  | 463   | 66                | 111   | 27  | 29    | 20 



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 12.4.



Unproved
Properties

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

|                     |           |             |         |         |         |        
|-------------------- | --------- | ----------- | ------- | ------- | ------- | -------
|                     | Developed | Undeveloped | Total  
|                     | Gross     | Net         | Gross   | Net     | Gross   | Net    
|Alberta              | 136,996   | 65,888      | 204,638 | 155,231 | 341,604 | 221,119
|Saskatchewan         | 30,952    | 6,426       | 31,240  | 2,273   | 62,192  | 8,699  
|Western
      Canada | 167,918   | 72,314      | 235,878 | 157,504 | 403,796 | 229,818
|Quebec               | -         | -           | 376,920 | 37,692  | 376,920 | 37,692 
|Total                | 167,918   | 72,314      | 612,798 | 195,196 | 780,716 | 267,510





- 13 -

---







Acreage
that Gentry has rights to explore and develop that may expire prior to December
31, 2006 total approximately 11,200 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 2006 it will continue
leases totalling more than 8,000 net acres by either making the necessary
applications or performing the necessary work.

Exploration
and Development Activities

During 2005,
Gentry participated in the drilling of 88 gross wells (57.9 net) with a 94%
success rate (92% net).  The majority of Gentry's 2005 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, 2005.



|                              |                                   |                                   |                   |      |       |     
|----------------------------- | --------------------------------- | --------------------------------- | ----------------- | ---- | ----- | ----
|                              | Number
      of Exploration Wells | Number
      of Development Wells | Total
      Wells
|Category
      of Well        | Gross                             | Net                               | Gross             | Net  | Gross | Net 
|Crude
      oil wells         | 1                                 | 0.7                               | 16                | 14.2 | 17    | 14.9
|Natural
      gas wells       | 27                                | 21.8                              | 29                | 9.5  | 56    | 31.3
|Capped
      Wells            | 7                                 | 5.0                               | 3                 | 2.2  | 10    | 7.2 
|Dry
      and abandoned wells | 4                                 | 3.8                               | 1                 | 0.7  | 5     | 4.5 
|Total                         | 39                                | 31.3                              | 49                | 26.6 | 88    | 57.9



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.

Quarterly
Production History

The following
table sets forth Gentry's average daily production volumes, on a company
interest basis, for each fiscal quarter in 2005 and for the entire year.



|                                    |                                    |                      |                     |                      |       
|----------------------------------- | ---------------------------------- | -------------------- | ------------------- | -------------------- | ------
|                                    | Year
      Ended December 31, 2005
|                                    | First
      Quarter                | Second
      Quarter | Third
      Quarter | Fourth
      Quarter | Total 
|Light
      and medium oil (bbls/d) | 1,246                              | 1,295                | 1,291               | 1,486                | 1,330 
|Natural
      gas (mcf/d)           | 10,889                             | 10,512               | 11,177              | 14,189               | 11,699
|Total (boe/d)                       | 3,061                              | 3,047                | 3,154               | 3,851                | 3,280 



Quarterly
Netback History

The following
tables set forth Gentry's average netbacks received for each fiscal quarter in
2005 and for the entire year (excluding any hedging gains or losses). Netbacks
are calculated on the basis of prices received before hedging on sales volumes,
less related royalties and related production costs. For multiple product well
types, production costs are pro-rated based on that well's production.



|                                    |                                    |                      |                     |                      |        
|----------------------------------- | ---------------------------------- | -------------------- | ------------------- | -------------------- | -------
|                                    | Year
      Ended December 31, 2005
|Light and medium oil
      (bbls/d) | First
      Quarter                | Second
      Quarter | Third
      Quarter | Fourth
      Quarter | Total  
|Sales
      price                   | 46.37                              | 47.30                | 64.54               | 52.27                | 52.71  
|Royalties                           | (8.56)                             | (11.92)              | (11.69)             | (9.83)               | (10.50)
|Production
      costs(1)           | (11.25)                            | (11.17)              | (11.37)             | (10.45)              | (11.04)
|Netback                             | 26.56                              | 24.21                | 41.48               | 31.99                | 31.17  







- 14 -

---







|                          |                                    |                      |                     |                      |       
|------------------------- | ---------------------------------- | -------------------- | ------------------- | -------------------- | ------
|                          | Year
      Ended December 31, 2005
|Natural gas (mcf/d)       | First
      Quarter                | Second
      Quarter | Third
      Quarter | Fourth
      Quarter | Total 
|Sales
      price         | 6.92                               | 7.59                 | 9.74                | 11.50                | 9.15  
|Royalties                 | (1.54)                             | (0.85)               | (1.80)              | (1.99)               | (1.59)
|Production
      costs(1) | (1.24)                             | (1.53)               | (1.76)              | (1.57)               | (1.53)
|Netback                   | 4.14                               | 5.12                 | 6.18                | 7.94                 | 6.03  



|                          |                                    |                      |                     |                      |       
|------------------------- | ---------------------------------- | -------------------- | ------------------- | -------------------- | ------
|                          | Year
      Ended December 31, 2005
|Total (boe/d)             | First
      Quarter                | Second
      Quarter | Third
      Quarter | Fourth
      Quarter | Total 
|Sales
      price         | 43.5                               | 46.27                | 60.95               | 62.56                | 54.01 
|Royalties                 | (8.95)                             | (7.99)               | (11.17)             | (11.14)              | (9.91)
|Production
      costs(1) | (8.98)                             | (10.02)              | (10.89)             | (9.80)               | (9.93)
|Netback                   | 25.57                              | 28.26                | 38.89               | 41.62                | 34.17 



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 226 net wells and
12.4 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 $6.9 million on an undiscounted basis and $2.4 million
discounted at 10%.  Of this amount, the Corporation anticipates that
approximately $405,000 will be incurred in the next three financial years.

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

The
estimates of total Proved Reserves associated with the Principal Producing
Properties and the present worth of future net cash flows from such reserves
contained in the Martin Report (based on forecast prices and costs on an
undiscounted basis) include expenditures of approximately $2.4 million
associated with the abandonment of current producing and future wells but do not
include any provision for non-producing wells or facility abandonment and site
restoration costs.

Tax
Horizon

While
Gentry is subject to the Large Corporations Tax and Saskatchewan Resource
Surcharge, the Corporation anticipates, based on its current budget, that it may
also be required to pay federal and provincial income taxes beginning midway
through the 2006 taxation year.





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Costs
Incurred

The
following tables summarize capital expenditures (net of certain proceeds and
including capitalized general and administrative expenses) related to the
Corporation's activities for the year ended December 31, 2005:



|                               |             
|------------------------------ | ------------
|                               | ($thousands)
|Drilling
      and completions | 26,050.4    
|Facilities
      and equipping | 13,170.9    
|Land
      and seismic         | 5,508.9     
|Acquisitions,
      net        | 7,606.8     
|Capitalized
      expenses     | 1,489.1     
|Other                          | 28.1        
|Total                          | 53,854.2    



Environmental
and Safety Matters

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

Insurance

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

Future
Commitments

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



As at
December 31, 2005, the Corporation had the following contractual obligations
under office leases and firm service transportation agreements:



|                                  |       |       |       |      |      |            |      
|--------------------------------- | ----- | ----- | ----- | ---- | ---- | ---------- | -----
|($thousands)                      | 2006  | 2007  | 2008  | 2009 | 2010 | Thereafter | Total
|Office
      lease                | 173.5 | 173.5 | 159.1 | -    | -    | -          | 506.1
|Firm
      service transportation | 46.5  | 46.5  | 12.3  | 73.8 | 73.8 | 12.3       | 265.2
|                                  | 220.0 | 220.0 | 171.4 | 73.8 | 73.8 | 12.3       | 771.3



Human
Resources

At
December 31, 2005, the Corporation had 21 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,
2005, there were 38,830,799 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 09, 2005 Gentry announced that it intended to purchase up to 3,469,500
Common Shares, representing 10% of its public float, pursuant to a normal course
issuer bid to be conducted over the facilities of the TSX.  The bid will
expire September 11, 2006 and any Common Shares acquired pursuant to the
bid will be cancelled.

Gentry's
reasoning for the normal course issuer bid is that from time to time the market
price of Gentry's Common shares may not reflect the underlying value of such
shares and that, at such times, the purchase of Common Shares for cancellation
will increase the proportionate interest of, and be advantageous to, all
remaining shareholders.  In addition, any purchases made by Gentry will
afford increased liquidity to those shareholders of the Corporation who may wish
to dispose of their Common Shares. From September 12, 2005 through to March 27,
2006, the



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Corporation
has purchased 379,900 Common Shares at an average price of $5.78 per share under
the current normal course issuer bid.  From August 27, 2004 to
August 26, 2005, Gentry purchased, pursuant to a previous normal course
issuer bid, 234,400 Common Shares at an average price of $3.45 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.





- 18 -

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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





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exploratory
natural gas wells spudded or deepened after July 31, 1985 and before June 1,
1988 is eligible for a royalty exemption for a period of 12 months, up to a
prescribed maximum amount.  Natural gas produced from qualifying intervals
in eligible natural gas wells spudded or deepened to a depth below 2,500 meters
is also subject to a royalty exemption, the amount of which depends on the depth
of the well.

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

Saskatchewan

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

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

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





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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 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.





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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 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





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-

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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.

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, 2005, 38,830,799 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
2005.



|          |       |       |       |          
|--------- | ----- | ----- | ----- | ---------
|Month     | High  | Low   | Close | Volume   
|January   | $3.99 | $3.18 | $3.90 | 4,257,399
|February  | $4.25 | $3.65 | $4.21 | 4,166,505
|March     | $5.19 | $4.26 | $4.70 | 6,287,025
|April     | $4.80 | $3.63 | $4.23 | 2,804,294
|May       | $4.65 | $3.91 | $4.56 | 1,935,215
|June      | $5.10 | $4.45 | $4.75 | 1,682,147
|July      | $5.24 | $4.71 | $5.10 | 1,486,164
|August    | $5.63 | $4.90 | $5.24 | 2,557,006
|September | $5.92 | $5.00 | $5.48 | 2,703,543
|October   | $5.70 | $4.90 | $5.60 | 2,966,994
|November  | $6.70 | $5.44 | $6.31 | 2,102,521
|December  | $6.75 | $5.90 | $6.08 | 2,185,120



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  | 1,791,205(5)
      168,651(5)
      157,483(5)         | 257,500                         
|A.
       Bruce Macdonald(1)(2)(4)
      Calgary,
      Alberta, Canada
      Director | President,
      Stoneyfell Investments Inc., a private oil & gas management consulting
      company              | Nov.
      13, 1995  | 256,450                                                | 207,500                         
|George
      T. Hawes(1)(3)
      Plandome,
      New York, U.S.A.
      Director      | President,
      G. T. Hawes & Co., Inc. a private real estate company                                             | Dec.
      3, 1999   | 54,600                                                 | 100,000                         
|Michael
      Halvorson(1)(2)
      Edmonton,
      Alberta, Canada
      Director     | President
      of Halcorp Capital Ltd., a private company specializing in the raising of
      investment capital | Aug.
      29, 1994  | 507,433                                                | 182,500                         
|Walter
      O'Donoghue(3)(4)
      Calgary,
      Alberta, Canada
      Director      | Former
      Partner, Bennett Jones LLP, a law firm                                                                | May
      29, 1998   | 183,126                                                | 182,500                         





- 24
-

---







|                                                                                                                                                  |                                                                                                          |     |                          |        
|------------------------------------------------------------------------------------------------------------------------------------------------- | -------------------------------------------------------------------------------------------------------- | --- | ------------------------ | -------
|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 | 241,127                  | 200,000
|R.
      Gordon McKay
      Calgary,
      Alberta, Canada
      Chief
      Operating Officer                                                    | Chief
      Operating Officer of the Corporation                                                         | N/A | 241,447                  | 200,000
|Robert
      J. Poole
      Calgary,
      Alberta, Canada
      Vice-President,
      Operations                                                 | Vice-President,
      Operations of the Corporation                                                      | N/A | 165,300                  | 225,000
|A.
      George Magarian
      Calgary,
      Alberta, Canada
      Vice-President,
      Exploration                                             | Vice-President,
      Exploration, of the Corporation                                                    | N/A | 20,750(6)
      1,000(6) | 180,000
|Lawrence
      B. Buzan
      Calgary,
      Alberta, Canada
      Vice-President,
      Land & Negotiations                                      | Vice-President,
      Land & Negotiations, of the Corporation                                            | N/A | 18,131                   | 180,000

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
1,791,205 Common Shares are held directly by Mr. Ross. The 168,651 Common Shares
are directly owned by Ross Resources Inc., a private company of which Mr. Ross
owns 25%. The 157,483 Common Shares are directly owned by an associate of Mr.
Ross.

(6)

The
20,750 Common Shares are held directly by Mr. Magarian. The 1,000 Common Shares
are directly owned by an associate of Mr. Magarian.



As
at March 27, 2006, the directors and officers of the Corporation beneficially
owned, directly or indirectly, or exercised control or direction over, in the
aggregate, 3,821,703 Common Shares, representing 9.9% 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.





- 25
-

---





INTERESTS
OF EXPERTS

Martin
prepared the Martin Report dated March 23, 2006 in respect of Gentry's oil and
natural gas reserves, summaries of which are contained in this Annual
Information Form.  As of the date of the Martin Report, the partners,
consultants, and associates of Martin, as a group, beneficially owned, directly
or indirectly, less than 1% of the outstanding shares of Gentry.

The
auditors of Gentry are Collins Barrow Calgary LLP, Chartered Accountants,
Calgary, Alberta.  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, 2005 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 March 23, 2005 for its
2005 annual general and special meeting of Shareholders. Furthermore, additional
financial information relating to the Corporation is provided in the
Corporation's audited consolidated financial statements and management's
discussion and analysis for the year ended December 31, 2005.





- 26
-

---







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, 2005. The
reserves data consist of the following:

(a)

(i)

proved
and proved plus probable oil and gas reserves estimated as at  December 31,
2005 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, 2005 using constant prices and
costs; and

(ii)

the
related estimated future net revenue.

2.

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

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

3.

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

4.

The
following table sets forth the estimated future net revenue (before deduction of
income taxes) attributed to proved plus probable reserves, estimated using
forecast prices and costs and calculated using a discount rate of 10 percent,
included in the reserves data of the Corporation evaluated by us for the year
ended December 31, 2005, and identifies the respective portions thereof that we
have audited, evaluated and reviewed and reported on to the Corporation's board
of directors:

|                                                            |                                                                 |                                                                                                              |          |      |         
|----------------------------------------------------------- | --------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------ | -------- | ---- | --------
|Description
      and Preparation Date of Evaluation Report | Location
      of Reserves (Country or Foreign Geographic Area) | New
      Present Value of future Net Revenue
      (before income taxes, 10% discount rate, in $ thousands)
|Audited                                                     | Evaluated                                                       | Reviewed                                                                                                     | Total   
|March
      23, 2005                                        | Canada                                                          | $Nil                                                                                                         | $235,376 | $Nil | $235,376



5.

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

6.

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



A-1

---







7.

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

Executed
as to our report referred to above:

Signed:"S. Neil Sedgwick"

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

Martin
& Brusset Associates

Calgary,
Alberta, Canada



Dated
 March 27, 2006



A-2

---





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, 2005
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, 2005 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 27, 2006.

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 27,
2006







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





C-2

---







George T.
Hawes

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



Michael Halvorson

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



A. Bruce Macdonald

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



EXTERNAL
AUDITOR SERVICE FEES

The
aggregate amounts billed by Collins Barrow Calgary LLP, Chartered Accountants to
the Company in each of the fiscal years ended December 31, 2005 and 2004 for
audit fees, audit-related fees, tax fees and all other fees are set forth below:

|                      |                                                |                                               
|--------------------- | ---------------------------------------------- | ----------------------------------------------
|                      | Year
      Ended
      December
      31, 2005 | Year
      Ended
      December
      31, 2004
|Audit Fees(1)         | $
       115,300                               | $
       74,050                               
|Audit-Related Fees(2) | 4,654                                          | 41,251                                        
|Tax Fees(3)           | -                                              | 3,800                                         
|All Other Fees(4)     | 5,500                                          | -                                             
|Totals                | $125,454                                       | $119,101                                      



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 planning services.







C-3













---

Exhibit 2

AUDITORS' REPORT
TO THE SHAREHOLDERS OF GENTRY RESOURCES LTD.
We have audited the consolidated balance sheets of Gentry Resources Ltd. as at December 31, 2005 and 2004 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, 2005 and 2004 and the results of its operations and cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.
Signed
/s/Collins Barrow Calgary LLP
Chartered Accountants
Calgary, Alberta
March 24, 2006



---



GENTRY RESOURCES LTD.

CONSOLIDATED BALANCE SHEETS

As at December 31, 2005 and 2004



|                                         |                |               
|---------------------------------------- | -------------- | --------------
|ASSETS                                  
|                                         | 2005           | 2004          
|CURRENT                                  |                |               
|Cash and cash equivalents                | $       13,090 | $       68,287
|Accounts receivable                      | 14,819,088     | 12,808,282    
|Prepaid expenses                         | 625,961        | 1,294,988     
|                                         | 15,458,139     | 14,171,557    
|                                         |                |               
|INVESTMENTS
    (NOTE 3)                 | 1,707,458      | 1,707,458     
|                                         |                |               
|PROPERTY AND EQUIPMENT (NOTE 4)          | 114,901,195    | 79,635,253    
|                                         |                |               
|                                         | $ 132,066,792  | $ 95,514,268  
|                                         |                |               
|                                        
|LIABILITIES & SHAREHOLDERS EQUITY      
|                                         |                |               
|CURRENT                                  |                |               
|Accounts payable and accrued liabilities | $  20,179,163  | $ 16,629,997  
|Income taxes payable                     | 303,405        | 50,066        
|Bank debt (Note 5)                       | 34,150,000     | 17,220,000    
|                                         | 54,632,568     | 33,900,063    
|                                         |                |               
|ASSET RETIREMENT OBLIGATIONS (NOTE 6)    | 3,473,144      | 2,671,657     
|                                         |                |               
|FUTURE INCOME TAXES (NOTE 7)             | 11,897,016     | 7,100,776     
|                                         |                |               
|                                         | 70,002,728     | 43,672,496    
|                                         |                |               
|SHARE CAPITAL (NOTE 8)                   | 42,906,253     | 42,474,623    
|CONTRIBUTED SURPLUS (NOTE 8[f])          | 823,918        | 318,765       
|RETAINED EARNINGS                        | 18,333,893     | 9,048,384     
|                                         | 62,064,064     | 51,841,772    
|                                         |                |               
|                                         | $ 132,066,792  | $ 95,514,268  

Commitments(NOTE 11)

Please refer to the accompanying notes.







---





GENTRY RESOURCES LTD.

CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

For the years ended December 31, 2005 and 2004



|                                                          |                    |                  
|--------------------------------------------------------- | ------------------ | -----------------
|                                                          | 2005               | 2004             
|REVENUE                                                   |                    |                  
|Production                                                | $ 64,665,175       | $ 31,717,038     
|Less: royalties, net of Alberta Royalty Tax Credit        | (11,870,924)       | (6,265,037)      
|                                                          | 52,794,251         | 25,452,001       
|EXPENSES                                                  |                    |                  
|Depletion, depreciation & accretion                       | 19,550,137         | 9,046,840        
|Production                                                | 11,886,328         | 7,271,849        
|General & administrative                                  | 3,755,310          | 3,174,091        
|Interest on bank debt                                     | 1,425,161          | 697,887          
|Stock-based compensation                                  | 643,882            | 375,704          
|                                                          | 37,260,818         | 20,566,371       
|INCOME BEFORE INCOME TAXES                                | 15,533,433         | 4,885,630        
|                                                          |                    |                  
|INCOME TAXES (NOTE 7)                                     |                    |                  
|Current                                                   | 534,757            | 923,657          
|Future                                                    | 4,796,238          | 560,363          
|                                                          | 5,330,995          | 1,484,020        
|                                                          |                    |                  
|NET INCOME                                                | 10,202,438         | 3,401,610        
|Retained earnings, beginning of year                      | 9,048,384          | 6,063,324        
|Less: excess of cost of shares acquired over stated value | (916,929)          | (416,550)        
|Retained earnings, end of year                            | $  
    18,333,893 | $ 
     9,048,384
|                                                          |                    |                  
|NET INCOME PER SHARE                                      |                    |                  
|Basic (Note 9)                                            | $0.26              | $0.11            
|Diluted (Note 9)                                          | $0.25              | $0.10            

Please refer to accompanying notes.







---





GENTRY RESOURCES LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2005 and 2004



|                                             |                 |               
|-------------------------------------------- | --------------- | --------------
|                                             | 2005            | 2004          
|OPERATING ACTIVITIES                         |                 |               
|Net income                                   | $  10,202,438   | $  3,401,610  
|Add (deduct) items not requiring cash        |                 |               
|Depletion, depreciation & accretion          | 19,550,137      | 9,046,840     
|Stock-based compensation                     | 643,882         | 375,704       
|Future income taxes                          | 4,796,238       | 560,363       
|                                             | 35,192,695      | 13,384,517    
|Changes in non-cash working capital items    | 145,741         | (2,829,261)   
|Asset retirement costs                       | (160,441)       | (110,328)     
|                                             | 35,177,995      | 10,444,928    
|INVESTING ACTIVITIES                         |                 |               
|Capital expenditures                         | (53,854,150)    | (43,401,378)  
|Acquisition of investments                   | -               | (163,400)     
|Changes in non-cash working capital items    | 2,426,446       | 3,734,398     
|                                             | (51,427,704)    | (39,830,380)  
|FINANCING ACTIVITIES                         |                 |               
|Proceeds from (repayments on) bank debt, net | 16,930,000      | 5,255,990     
|Redemption of share capital                  | (1,163,098)     | (627,298)     
|Proceeds on issuance of share capital, net   | 539,071         | 24,632,617    
|Changes in non-cash working capital items    | (111,461)       | (1,689)       
|                                             | 16,194,512      | 29,259,620    
|                                             |                 |               
|INCREASE (DECREASE) IN CASH                  | (55,197)        | (125,832)     
|                                             |                 |               
|CASH AND CASH EQUIVALENTS, beginning of year | 68,287          | 194,119       
|                                             |                 |               
|CASH AND CASH EQUIVALENTS, end of year       | $       13,090  | $       68,287
|                                             |                 |               
|SUPPLEMENTAL CASH FLOWS DISCLOSURE:          |                 |               
|Interest paid                                | $     1,425,161 | $     697,887 
|Income taxes paid                            | $  278,092      | $  1,352,831  

Please refer to the accompanying notes.









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                







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 its 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) and its other investment, using the cost method of accounting whereby the investment is initially recorded at cost.  Earnings are recognized only to the extent received or receivable.
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.





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|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





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

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

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 and depreciation expense.  Actual restoration expenditures are charged to the accumulated obligation as incurred.





---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





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

i)

Stock-based compensationThe Company has a stock option plan as described in Note 8(c).

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.

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





---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





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 and depreciation, asset retirement costs and obligations and the ceiling test are based on estimated proved reserves, production rates, future petroleum and natural gas prices and future costs.  By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates in future periods could be significant.
The amounts used to estimate fair values of stock options issued, and the resultant pro-forma income effects (Notes 8[f] and [g]) are based on estimates of future volatility of the Company's share price, expected lives of the options, expected dividends to be paid by the Company and other relevant assumptions.  By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates on the financial statements of future periods could be significant.

3.

Investments

At December 31, 2005, the Company owned 7.75% (2004  13.24%) of the common shares of
Stratic.  The Company is related to Stratic by virtue of common directors and officers.

|                                    |             |            
|----------------------------------- | ----------- | -----------
|                                    | 2005        | 2004       
|Stratic Energy Corporation, at cost | $ 1,689,458 | $ 1,689,458
|Other, at cost                      | 18,000      | 18,000     
|                                    | $ 1,707,458 | $ 1,707,458



4.

Property and equipment

20052004Petroleum and natural gas properties, including exploration and
    development thereon$   128,195,327$ 89,802,565Production equipment and facilities37,851,47121,603,127Other907,947879,842166,954,745112,285,534Accumulated depletion and depreciation(52,053,550)(32,650,281)$   114,901,195$ 79,635,253






During the year, the Company capitalized $1,489,120 (2004 - $1,165,303) of a total of $5,244,430 (2004 - $4,339,394) in general and administrative expenses.  No interest has been capitalized.
Costs of unproved petroleum and natural gas properties amounting to $20,584,330 (2004 - $20,198,754) have been excluded from the depletion calculation.







---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





The Company prepared a ceiling test calculation at December 31, 2005 to assess the recoverability of its petroleum and natural gas properties.  The ceiling test was based upon a valuation of the petroleum and natural gas properties prepared by an independent engineering firm based upon future oil and gas benchmark prices and adjusted for commodity price differentials specific to the Company.  The following table summarizes the benchmark references prices used in the ceiling test calculation:



WTI Oil
($US/bbl)Edmonton Light Sweet 40o API
($Cdn/bbl)Bow River Medium Oil 25o API
($Cdn/bbl)AECO Natural Gas Spot Price
($Cdn/mmbtu)2006$58.44$67.64$45.32$10.68200757.3466.4045.209.63200852.7060.8942.748.23200949.2356.8340.797.33201047.0554.2539.486.98




Prices increase at a rate of approximately 0.3% in 2011, 1.3% in 2012 and approximately 2.0% thereafter.



5.

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, bankers acceptances and letters of credit.  Interest is payable monthly at the banks prime lending rate. The facility is secured by a general assignment of book debts, a $50,000,000 demand debenture with a floating charge over all assets with a Negative Pledge and Undertaking to provide fixed charges upon request.  On January 20, 2006, the demand debenture was increased to $100 million.  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 April 30, 2006.

6.

Asset retirement obligationsThe following table summarizes changes in the asset retirement obligations for the years ended December 31, 2005 and 2004:

20052004Asset retirement obligations, beginning of year$ 2,671,657$ 1,563,555Liabilities incurred745,6911,116,708Liabilities settled(160,441)(110,328)Liabilities acquired69,369-Accretion expense146,868101,722Asset retirement obligations, end of year$ 3,473,144$ 2,671,657


The inflated, undiscounted amount of the estimated future cash flows required to settle the obligations is $6,921,310 (2004 - $4,972,730).  These obligations are expected to be paid over the next several years with a weighted average life of approximately 11 years (2004 - 11 years).  The estimated future cash flows have been discounted at the credit-adjusted risk free rate of 5.25% (2004  5.25%).  As at December 31, 2005 no funds have been set aside to settle these obligations.





---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





7.

Income taxes



a)

Future Income Tax LiabilitySignificant components of the future income tax liability are as follows:

|                                                                                         |              |            
|---------------------------------------------------------------------------------------- | ------------ | -----------
|                                                                                         | 2005         | 2004       
|Temporary differences related to property and
equipment and asset retirement obligations | $ 12,441,035 | $ 7,818,381
|Share issuance and financing costs                                                       | (425,714)    | (599,300)  
|Temporary differences related to investments                                             | (118,305)    | (118,305)  
|                                                                                         | $ 11,897,016 | $ 7,100,776



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 39.10% (2004 - 40.11%) to income before income taxes.  The difference results from the following:



|                                                                 |             |            
|---------------------------------------------------------------- | ----------- | -----------
|                                                                 | 2005        | 2004       
|Expected tax provision                                           | $6,073,572  | $1,959,626 
|Increases (decreases) resulting from:                            |             |            
|Resource allowance                                               | (2,507,882) | (1,201,457)
|Non-deductible crown payments, net of Alberta
Royalty Tax Credit | 1,558,483   | 1,065,066  
|Change in tax rates                                              | (422,640)   | (503,672)  
|Large corporate and capital taxes                                | 324,687     | 52,115     
|Non-deductible stock-based compensation                          | 217,736     | 150,695    
|Reduced tax rates for resource allowance and
capital gains       | -           | (25,770)   
|Other                                                            | 87,039      | (12,583)   
|                                                                 | $5,330,995  | $1,484,020 









---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





8.

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

Common shares:2005­2004NumberStated ValueNumberStated ValueBalance, beginning of year38,471,234$42,474,62327,352,508$18,373,169Issued for cash (Note 8[a])--9,500,00022,825,000Flow-through shares issued (Note 8[a])--1,080,0002,820,000Share purchase warrants exercised (Note 8[b])--150,000262,500Stock options exercised (Note 8[c])546,167503,775580,000320,650Issued under employee share purchase plan
(Note 8[d])36,298174,02568,826158,013Normal Course Issuer Bids (Note 8[e])(222,900)(246,170)(260,100)(210,748)Total issued38,830,79942,906,25338,471,23444,548,584Less:Reduction due to income tax deductions
renounced to subscribers (Note 8[a])---(981,924)Share issuance costs (net of income taxes of
$Nil [2004 - $582,503])---(1,092,037)Balance, end of year38,830,799$42,906,25338,471,234$42,474,623




a)

FinancingsDuring the year ended December 31, 2004, the Company issued 9,500,000 common shares at an average price of $2.40 per share for gross proceeds of $22,825,000. 
In addition, the Company issued 1,000,000 flow-through common shares at a price of $2.50 per share and 80,000 flow-through common shares at a price of $4.00 per share.  Income tax exploration deductions in the amount of $2,820,000 were renounced to subscribers effective December 31, 2004.

b)

WarrantsDuring the year ended December 31, 2004, 150,000 common shares at a price of $1.75 per share were issued upon the exercise of 150,000 share purchase warrants.  There are no share purchase warrants outstanding as at December 31, 2005.







---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





c)

Stock Option PlanUnder 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 can not be less than the market price of the common shares at the time the option is granted.  Options granted under the plan will have a term not exceeding ten years.  The vesting period is set by the Board of Directors at the time the options are granted. 
A summary of the status of the Company's stock option plan, as of December 31, 2005 and 2004 and changes during the years then ending are as follows:

20052004Number of OptionsWeighted Average Exercise PriceNumber of OptionsWeighted Average Exercise PriceOutstanding, beginning of year2,995,000$1.492,460,000$0.90Granted217,5003.281,115,0002.32Exercised(546,167)0.84(580,000)0.55Cancelled(61,666)(2.25)--Outstanding, end of year2,604,667$1.762,995,000$1.49Options exercisable at year-end1,805,226$1.391,935,002$0.95


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



Options OutstandingOptions ExercisableRange of ExercisePricesNumber of OptionsWeighted Average Exercise PriceWeighted Average Remaining Contractual LifeNumber of OptionsWeighted Average Exercise Price$0.45217,500$0.454.1217,500$0.45$0.77 to $0.95382,5000.824.0382,5000.82$1.18 to $1.62818,0001.352.0814,6671.35$2.30 to $2.751,021,6672.333.7340,5582.33$3.98 to $5.24165,0004.254.350,0014.15Total2,604,667$1.763.31,805,2261.39




d)

Employee Share Purchase PlanOn January 1, 2003, the Company initiated an employee share purchase plan (the Plan), whereby the Company is authorized to match employees purchases under the Plan from a minimum of two percent to a maximum of five percent of the employees regular gross earnings, through the issuance of common shares of the Company, for all full-time employees.  Compensation expense is recognized when shares are issued under the Plan and an equal amount is recorded as share capital.  Shares are issued from Treasury to employees at the weighted average market price for the month immediately preceding the date of purchase of the Companys shares.  The maximum number of common shares which can be issued under the plan is 500,000, of which 181,169 have been issued to December 31, 2005.  Compensation costs of $87,012 (2004 - $ 79,006) has been expensed during the year.





---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





e)

Normal Course Issuer BidPursuant to Normal Course Issuer Bids, the Company acquired 222,900 (2004  260,100) common shares at an average price of $5.21 (2004 - $2.41) per share.  The excess of cost of reacquisition over stated value of $916,929  (2004 - $416,550) has been charged against retained earnings.  At December 31, 2005, a maximum of 3,353,500 common shares may be acquired by the Company until September 11, 2006 under the present Normal Course Issuer Bid.

f)

Stock-based Compensation ExpenseThe fair value of stock options granted during 2005 was estimated on the dates of grant using the Black-Scholes option-pricing method with the following assumptions:

Risk free interest rate of 3.12 to 3.48% (2004 - of 3.67 to 3.73%)

Expected life of options of 3.5 to 4.5 years (2004 - 3.5 to 4.5 years)

Expected volatility of 67.47% to 70.69% (2004 - 30.91 to 31.72%)

Expected dividend rate of 0% (2004 - 0%)

Weighted average fair value per option granted of $2.25 (2004 - $0.70)

Compensation costs of $556,870 (2004 - $296,698) have been expensed resulting in the recognition of $556,870 (2004 - $296,698) of contributed surplus during 2005.



g)

Pro-forma Stock-based Compensation ExpenseIf the compensation costs for the Companys stock option plan had been determined using the fair value method for options granted from January 1, 2002 to December 31, 2002, the Companys pro-forma net income and retained earnings for 2005 would be reduced by $Nil (2004 - $16,396).  There would be no change in net income per share or diluted net income per share.
The assumptions used to determine the fair value of each option granted on the date of grant using the
Black-Scholes option-pricing model are as follows:

Risk free interest rate of 4.1%

Expected life of options of 3.5 years

Expected volatility of 65.50%

Expected dividend rate of 0%

Fair value per option granted of $0.60



9.

Income per shareNet income per share has been calculated based on the weighted average number of common shares outstanding during the year of 38,755,860 (2004  31,614,549).
A reconciliation of the denominators for the per share calculations is outlined below:

20052004Basic weighted average shares38,755,86031,614,549Effect of dilutive stock options and warrants1,789,4401,394,406Dilutive weighted average shares40,545,30033,008,955


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, 2005 AND 2004                





10.

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, 2005 is $8,503,467 (2004 - $8,712,159).
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.

11.

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

2006$219,9972007219,9972008171,371200973,839201073,839Thereafter12,306








---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





12.

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:



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.
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, 2005 and 2004.



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



b)

Income TaxesCanadian GAAP previously required the Company to record potential future taxes using the deferral method.  However, the Canadian Institute of Chartered Accountants accounting standard is now similar to U.S. GAAP.   
Upon implementation of the new Canadian standard, retained earnings was decreased for temporary differences that had not previously been recognized.  Under U.S. GAAP, these temporary differences would have already been reflected in property and equipment, therefore further differences in depletion and depreciation expense results in subsequent years.
Under U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas under Canadian GAAP, substantively enacted tax rates are used.



c)

Flow-through 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) until the renunciation of expenditures has occurred.  Under Canadian GAAP, the gross proceeds received on flow-through share issuances are initially





---

|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





recorded as share capital.  The Premium recorded as a current liability under U.S. GAAP for 2005 is $Nil (2004 - $38,400).
When the expenditures are incurred and the tax deductions are renounced to subscribers, Canadian GAAP requires that the stated capital be reduced by and a future tax liability be recorded for the estimated future income taxes payable as a result of the renouncement. Under U.S. GAAP, the future tax liability is recorded through a charge to income tax expense less the reversal of the Premium previously reported.



d)

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



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



e)

Stock-based CompensationEffective January 1, 2003, the Company prospectively adopted the Canadian Institute of Chartered Accountants new standard with respect to accounting for stock-based compensation arrangements relating to stock options granted to employees, officers and directors.  Hence, under Canadian GAAP, compensation costs have been recognized in the financial statements for stock options granted to employees, officers and directors in 2004 and 2005.  For the effect of stock-based compensation on the financial results under Canadian GAAP in 2004 and 2005, which would be the same adjustment under U.S. GAAP, see Note 8(f).
U.S. Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation establishes financial accounting and reporting standards for stock-based employee compensation plans under U.S. GAAP.  The Statement requires disclosure of the pro-forma net income and net income per share as if the fair value based accounting method had been used to account for stock-based compensation costs in advance of the equivalent Canadian standard.  There are no differences for 2005.  The effects of the fair value disclosures under U.S. GAAP are as follows:

20052004As ReportedProFormaAs ReportedProFormaNet Income$9,885,959$9,885,959$3,540,553$3,530,702Net income per share  Basic$0.26$0.26$0.11$0.11 Diluted$0.24$0.24$0.11$0.11


The fair value of the options issued by the Company during 2005 and 2004 was estimated under U.S. GAAP using the same assumptions as under Canadian GAAP, as disclosed in Note 8(f).





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|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





f)

Variable Interest Entities



The Canadian Institute of Chartered Accountants 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 Financial Accounting Standards Boards (FASB) Interpretation No. 46 Consolidation of Variable Interest Entities.
At December 31, 2005, the Company did not have any variable interests in variable interest entities.



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.



i)

Recent Accounting Pronouncements



i)

Share-Based Payment
In 2004, FASB issued revised FAS 123 Share-Based Payment. This amended statement eliminates the alternative to use Accounting Principles Board (APB) Opinion No. 25s intrinsic value method of accounting, as was provided in the originally issued Statement 123.
As a result, public entities are required to use the grant-date fair value of the award in measuring the cost of employee services received in exchange for an equity award of equity instruments. Compensation cost is required to be recognized over the requisite service period.
For liability awards, entities are required to re-measure the fair value of the award at each reporting date up until the settlement date. Changes in fair value of liability awards during the requisite service period are required to be recognized as compensation cost over the vesting period. Compensation cost is not recognized for equity instruments for which employees do not render the requisite service.
This amended statement is effective the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Company is currently assessing the impact of this amendment.

ii)

Exchange of Non-monetary Assets
In 2004, FASB issued FAS 153 Exchange of Non-monetary Assets. This statement is an amendment of APB Opinion No. 29 Accounting for Non-monetary Transactions. Based on the guidance in APB Opinion No. 29, exchanges of non-monetary assets are to be measured based on the fair value of the assets exchanged. Furthermore, APB Opinion No. 29 previously allowed for certain exceptions to this fair value principle. FAS 153 eliminates APB Opinion





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|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                





No. 29s exception to fair value for non-monetary exchanges of similar productive assets and replaces this with a general exception for exchanges of non-monetary assets which do not have commercial substance. For purposes of this statement, a non-monetary exchange is defined as having commercial substance when the future cash flows of an entity are expected to change significantly as a result of the exchange.
The provisions of this statement are effective for non-monetary asset exchanges which occur in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. Earlier application is permitted for non-monetary asset exchanges which occur in fiscal periods beginning after the issue date of this statement.

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



iii)

Asset Retirement Obligations



In March 2005, FASB issued Financial Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies the timing of recognition for asset retirement obligations. An entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated.  FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. The adoption of the statement did not have a material impact on the consolidated financial statements.



iv)

Accounting Changes and Error Corrections



As of January 1, 2006 the Company will be required to adopt, for U.S. GAAP purposes, SFAS 154 Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and SFAS 3. SFAS 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. The Company does not expect this standard to have a material impact on the consolidated financial statements.



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

20052004Net income under Canadian GAAP$10,202,438$3,401,610U.S. GAAP adjustmentsDepletion, depreciation & accretion286,161252,743Future tax expense on flow-through share renouncements(73,024)(370,500)Future income taxes(529,616)256,700Net income under U.S. GAAP$9,885,959$3,540,553Net income per share- Basic$0.26$0.11- Diluted$0.24$0.11






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|                                          
|------------------------------------------
|GENTRY RESOURCES LTD.                     
|NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|DECEMBER 31, 2005 AND 2004                



ii)

Statements of Comprehensive Income



20052004Net income under U.S. GAAP$9,885,959$3,540,553Unrealized gain (loss) on investments, net of tax effect of $(36,333) (2004 - $823,300)(172,359)3,892,445Comprehensive income$9,713,600$7,432,998




iii)

Condensed Consolidated Balance Sheets



20052004Canadian GAAPU.S.
GAAPCanadian GAAPU.S.
GAAPAssetsCurrent assets$15,458,139$15,458,139$14,171,557$14,171,557Investments1,707,4588,503,4671,707,4588,712,159Property and equipment114,901,195113,462,45679,635,25377,910,353$132,066,792$137,424,062$95,514,268$100,794,069Liabilities and Shareholders EquityCurrent liabilities$54,632,568$54,632,568$33,900,063$33,938,463Asset retirement obligations3,473,1443,473,1442,671,6572,671,657Future income taxes11,897,01612,631,2637,100,7767,230,31670,002,72870,736,97543,672,49643,840,436Share capital42,906,25344,785,71842,474,62344,354,088Contributed surplus823,918823,918318,765318,765Retained earnings18,333,89315,464,6279,048,3846,495,597Accumulated other comprehensive income-5,612,824-5,785,18362,064,60466,687,08751,841,77256,953,663$132,066,792$137,424,062$95,514,268$100,794,069




iv)

Non-cash working capital under U.S. GAAP



|                                         |                 |               
|---------------------------------------- | --------------- | --------------
|                                         | 2005            | 2004          
|Cash provided by (used for)              |                 |               
|Accounts receivable                      | $ (2,010,806)   | $ (5,346,486) 
|Prepaid expenses                         | 669,027         | (1,084,601)   
|Accounts payable and accrued liabilities | 3,549,166       | 7,763,709     
|Income taxes payable                     | 253,339         | (429,174)     
|Changes in non-cash working capital      | $     2,460,726 | $      903,448













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Exhibit 3





MANAGEMENT'S
DISCUSSION AND ANALYSIS

The following Managements Discussion and Analysis (MD&A) should be read in conjunction with the 2005 Consolidated Financial Statements of the Company.

Reported production represents Gentrys ownership share before the deduction of royalties. Where amounts are expressed on a barrel of oil equivalent
(boe) basis, natural gas has been converted at a ratio of six thousand cubic feet to one
boe. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Included in the MD&A are references to financial measures commonly used in the oil and gas industry such as cash flow and cash flow per share. These measures have no standardized meaning, are not defined by Canadian generally accepted accounting principles (GAAP), and accordingly are referred to as non-GAAP measures. Cash flow and cash flow per share are used by the Company to assess operating results between years and between peer companies. Gentrys reported amounts may not be comparable to similarly titled measures reported by other companies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined by Canadian GAAP as an indicator of the Companys performance or liquidity.

Certain disclosure in this MD&A contains forward-looking statements that involve risks and uncertainties. Such information, although considered reasonable by Gentry at the time of preparation, may prove to be incorrect and actual results may differ materially from those anticipated in the statements made. For this purpose, any statements contained herein that are not statements of historical fact may be deemed to be forward-looking statements. Such risks and uncertainties include, but are not limited to, risks associated with operations, loss of market, regulatory matters, commodity price risk, environmental risks, industry competition, reserve measurements 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.

The date of this MD&A is March 27, 2006.

SELECTED ANNUAL INFORMATION

($thousands, except per share amounts)200520042003Production revenue64,665.231,717.024,679.8Cash flow from operations35,192.713,384.510,386.2per share  basic0.910.420.42per share  diluted0.870.410.40Net income10,202.43,401.63,040.5per share  basic0.260.110.12per share  diluted0.250.100.12Total assets132,066.895,514.353,472.6Long-term financial liabilities15,370.29,772.47,704.5




PRODUCTION AND PRICING

The majority of Gentrys operations in 2005 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 and
Whitecourt, two other core areas in southeastern and central Alberta respectively, provided additional growth in gas production.

As a result of the growth in Alberta, the Companys production in Saskatchewan, which contributed 22% of volumes in 2004, accounted for only 12% in 2005. Generally speaking, the Companys non-operated,







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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 2006, gains in gas production are slated to come from Princess, Whitecourt and Sedalia, while the driving force behind increased oil production will be Princess.

Revenue Volume Price

Oil & LiquidsRevenue
($ thousands)Volume
(bbls/d)Price
($/bbl)200525,589.11,33052.71200413,525.086242.88200311,860.489736.22Natural GasRevenue
($ thousands)Volume
(mcf/d)Price
($/mcf)200539,076.111,6999.15200418,192.07,5556.58200312,819.45,3306.59BoeRevenue
($ thousands)Volume
(boe/d)Price
($/boe)200564,665.23,28054.01200431,717.02,12140.86200324,679.81,78537.87


Gross production revenue more than doubled in 2005 to $64.67 million from $31.72 million a year ago. Approximately $17.20 million of this increase was a result of higher sales volumes and $15.75 million was attributable to higher commodity prices.

Gentrys natural gas sales rose 55% to 11,699
mcf/d from 7,555 mcf/d in 2004. This increase contributed $9.91 million to the change in revenue, which exceeded the $7.29 million gained on the 54% increase of oil and liquids sales to 1,330
bbls/d from 862 bbls/d a year ago.

Changes in gas pricing to $9.15/mcf from $6.58/mcf increased revenue by $10.98 million. The rise in oil and liquids pricing to $52.71/bbl from $42.88/bbl contributed another $4.77 million when compared to the prior year.

Gentry has not had any forward contracts for the sale of commodities since 2001 and none are in place for 2006.

ROYALTIES

With the increase in revenue, Gentrys royalties, net of Alberta Royalty Tax Credit
(ARTC), increased to $11.87 million from $6.27 million in 2004. Expressed as a percentage of production, oil royalties were 19.9% in 2005 versus 21.2% in 2004 and gas royalties were 17.3% versus 18.6% a year ago. On a barrel of oil equivalent basis, the percentages were 18.4% in 2005 and 19.8% in 2004. The shift in production weighting from Saskatchewan to Alberta, which generally has a more favorable royalty regime for the Companys assets, is the primary reason for the overall decrease in royalties as a percentage of revenues.

($thousands)200520042003Crown royalties6,294.63,689.53,054.7Freehold royalties4,015.22,128.71,821.7Overriding royalties2,061.1886.3502.2Gross royalties12,370.96,704.55,378.6ARTC(500.0)(439.5)(311.5)Net royalties11,870.9$6,265.0$5,067.1As a % of revenue18.4%19.8%20.5%








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PRODUCTION EXPENSES

Production expenses increased to $11.89 million from $7.27 million in 2004. On a barrel of equivalent basis, costs increased 6% to $9.93/boe from $9.37/boe in 2004. 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 trucking costs at Princess, as the Company now transports its oil a greater distance to another facility where it receives a higher price for the oil, thus increasing the overall product netbacks. Going forward, Gentry expects to reap the benefits from the recent electrification of certain facilities at Princess and realize a full year of benefits from the ownership of fluid handling batteries, also in the Princess area.

GENERAL AND ADMINISTRATIVE EXPENSES

Gentrys general and administrative expenses increased 18% to $3.76 million in 2005 from $3.17 million in 2004. Seven percent of this increase was due to additional
staff and compensation requirements while higher professional fees, due in part to increased activity and compliance costs, accounted for a 12% rise in expenses. On a barrel of oil equivalent basis, general and administrative expenses decreased 77% to
$3.14/boe from $4.09/boe in 2004. Looking forward to 2006, moderate increases to gross administrative costs are expected, however, as production increases, it is anticipated that per unit costs will decline.

($thousands)200520042003Gross expenses5,615.94,715.23,458.7Recoveries(371.5)(375.8)(333.1)Capitalized(1,489.1)(1,165.3)(848.0)Net expenses3,775.33,174.12,277.6Net expenses ($/boe)3.144.093.50




STOCK-BASED COMPENSATION

In 2005, Gentrys stock based compensation expense was $644 thousand versus $376 thousand a year ago. In the most recent year, $557 thousand related to the value of vested incentive stock options while the remaining $87 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
$297 thousand from stock options and $79 thousand from the ESOP. A greater number of higher priced options vesting in 2005 resulted in the higher charge.

INTEREST EXPENSE

Gentrys interest expense increased to $1.43 million in 2005 from $698 thousand in 2004. While interest rates did increase to an average of 4.4% in 2005 from 4.0% in 2004, the primary reason for the greater interest cost was the higher utilization of the Companys credit facilities to fund its increased capital exploration programs. Whereas Gentry began and ended 2004 with $11.96 million and $17.22 million in bank debt respectively, it ended 2005 with $34.15 million in bank debt.

DEPLETION, DEPRECIATION AND ACCRETION

These charges for
2005 were $19.55 million compared with $9.05 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 $16.33/boe versus $11.65/boe in 2004.

Included in the above amounts is accretion expense, which is the amortization of the Companys asset retirement obligations. For 2005, this expense amounted to $147 thousand, or
$0.12/boe, compared to $102 thousand, or $0.13/boe, a year ago.







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The Companys depletion rate increased to 16.59% in 2005 from 12.78% in 2004 and is based on the ratio of annual production to proved reserves estimates. While production increased 55%, reserves used for the depletion calculation increased 14%, which accounted for the higher rate.

INCOME TAXES

Gentry was liable for $535 thousand in current taxes in 2005, which was a 42% decrease from the $924 thousand recorded in 2004. The reason for the decrease is that the amalgamation of Gentry with its wholly-owned subsidiary, Gentry Resources (Saskatchewan) Ltd., at the start of the second quarter allowed certain tax pools to be more efficiently applied against the Companys consolidated income stream. On a unit of production basis, current taxes were
$0.45/boe versus $1.19/boe a year ago.

Future taxes increased substantially to $4.80 million in 2005 from $560 thousand in 2004. On a unit of production basis, future taxes for 2005 equated to $4.00/boe versus $0.72/boe in 2004. The increase was largely due to the use of more tax pools to keep current taxes at lower levels.

As a result of flow-through financings in 2004, Gentry agreed to renounce $2.82 million of Canadian exploration expenditures in 2004. Of the total, $2.50 million was incurred in 2004 and the remaining $320 thousand was spent in the first quarter of 2005.

At the end of 2005, Gentry had approximately $76.90 million of accumulated tax pools available for deduction against income in future years.

($thousands)Available balanceMaximum Annual deduction (%)Canadian oil and gas property expense$31,974.410Canadian development expense14,877.430Canadian exploration expense5,078.4100Foreign exploration and development expense214.610Undepreciated capital cost23,479.620-100Cumulative eligible capital59.67Financing costs1,212.220Total$76,896.2


CASH FLOW AND NET INCOME

In 2005, cash flow from operations reached a record high of $35.19 million, an increase of 163% from $13.38 million in 2004. This increase was largely achieved from higher net revenues as a result of increases in production and commodity prices.

Net income tripled to $10.20 million from $3.40 million in 2004. In assessing the change in net income, the positive impact of the extra $21.81 million in cash flow was greatly reduced by the additional $10.50 million in depletion, depreciation and accretion charges and $4.24 million in future taxes.

On a per share basis, cash flow was $0.91 per share ($0.87 diluted) in 2005 compared to $0.42 ($0.41 diluted) in 2004. Net income was $0.26 per share ($0.25 diluted) versus $0.11 per share ($0.10 diluted) a year ago.







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CORPORATE NETBACKS

($/boe)200520042003Selling price54.0140.8637.87Royalties (net of ARTC)(9.91)(8.07)(7.78)Production expenses(9.93)(9.37)(8.54)Operating netbacks34.1723.4221.55Administration(3.14)(4.09)(3.50)Interest(1.19)(0.90)(0.74)Current taxes(0.45)(1.19)(1.44)Other income--0.07Cash flow29.3917.2415.94Depletion and depreciation(16.33)(11.65)(10.86)Future taxes(4.00)(0.72)(0.13)Non-cash compensation(0.54)(0.49)(0.27)Other expenses--(0.01)Net income8.524.384.67


CAPITAL EXPENDITURES

Net capital expenditures increased 24% in 2005 to $53.85 million from $43.40 million in 2004. The increase was due to a record level of activity for the Company as it increased drilling in all of its core exploration areas; pursued an aggressive land acquisition program to facilitate further exploration activities; and acquired and built additional infrastructure to bring new volumes onstream.

($thousands)200520042003Drilling and completions$26,050.4$11,773.5$  9,723.8Facilities and equipping13,170.96,403.34,208.4Land and seismic5,508.97,359.84,160.4Acquisitions, net7,606.816,571.02,503.6Capitalized Expenses1,489.11,165.3848.0Other28.1128.5209.353,854.2$43,401.4$21,653.5


The 2004 acquisition costs included the $16.25 million purchase of interests in the Princess/Bantry area, which was followed up by an $8 million purchase (before adjustments) of additional interests at Princess in the first quarter of 2005. The 2004 acquisition included approximately 275 boe/d of production and 120 sections of undeveloped land net to Gentry, while the 2005 acquisition included approximately 195 boe/d of production net to Gentry.

The Company drilled or participated in 88 gross wells (57.9 net) in 2005 with a success rate of 94% (92% net). This compares to 52 gross wells (33.5 net) and a success rate of 85% (86% net) in 2004.

NET ASSET VALUE

At December 31, 2005, the Companys net asset value, based on a 10% discount on future cash flow, equated to $6.20 per share compared with $4.04 per share in 2004. The following is a summary of the net asset value calculation, discounted at 10%:







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($thousands, except per share amounts)200520042003Reserves$235,376$129,322$59,048Undeveloped land and seismic135,94537,1019,960Investments28,4888,6983,827Net debt(39,174)(19,729)(13,443)Net Asset Value240,635$155,392$59,392Common shares outstanding38,83138,47127,353Net asset value per common share$6.20$4.04$2.17


(1) internal estimate 
  (2) market value as at December 31

LIQUIDITY AND CAPITAL RESOURCES

After completing two financings with underwriters and one minor financing with the management group in 2004, Gentry did not access the equity markets in 2005.

Gentry began the year with 38,471,234 common shares issued and outstanding. During 2005, the Company issued 546,167 shares on the exercise of incentive stock options ($0.84 per share); 36,298 shares were issued pursuant to the Companys employee share purchase plan ($4.79 per share); and 222,900 shares were repurchased and cancelled pursuant to the Companys Normal Course Issuer Bid ($5.22 per share). As a result of these changes, Gentry ended the year with 38,830,799 common shares issued and outstanding. As of the date of this MD&A, 38,595,880 common shares were outstanding and a further 2,581,067 shares were reserved for issuance pursuant to the exercise of outstanding incentive stock options (at an average price of $1.77 per share).

Gentrys year-end net debt was $39.17 million compared with $19.73 million at the end of 2004. 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, 2005 Reserves Report.

CONTRACTUAL OBLIGATIONS

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

($thousands)20062007200820092010ThereafterTotalOffice lease173.5173.5159.1---506.1Firm transportation46.546.512.373.873.812.3265.2220.0220.0171.473.873.812.3771.3










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FOURTH QUARTER RESULTS

Gentrys financial and operating highlights from the fourth quarter of 2005, as compared with the fourth quarter of 2004, are summarized below:

Three months ended December 3120052004% changeFinancial($thousands)Gross revenue22,164.69,193.1141Royalties, net of ARTC3,947.81,917.2106Production expenses3,473.62,682.130Administrative1,536.51,113.638Current taxes101.8213.8(52)Cash flow12,725.63,028.8320Depletion, depreciation and accretion8,715.92,934.9197Future taxes (recovery)1,169.7(556.0)n/aStock-based compensation102.8148.7(31)Net income2,737.1501.2446Capital expenditures, net19,742.611,095.078ProductionOil & Liquids (bbls/d)1,48696055Gas (mcf/d)14,1898,86960Barrels of oil equivalent3,8512,43958PricingOil & Liquids ($/bbl)52.2743.3421Natural gas ($/mcf)11.50$6.5775Boe ($/boe)62.56$40.9853




The 141% growth in production revenue in the fourth quarter of 2005, when compared to the fourth quarter of 2004, came from increased sales volumes as well as increased pricing for both gas and oil and liquids. As expected, royalty expense also increased, but by less than the same percentage for the same reasons as described on the annual basis. Production expenses increased with the higher production volumes and administrative expenditures also increased with the greater level of activity. Based largely on the above reasons, cash flow was up 320% over the comparative fourth quarter.

Depletion, depreciation and accretion increased substantially in the fourth quarter of 2005. The larger asset base combined with a higher depletion rate is the reason for the increased provision. Future taxes also increased significantly as the Company continued to utilize its tax pools to reduce its taxable income and current taxes.

Deducting the depletion and future tax provisions from cash flow, as well as stock-based compensation, gives net income of $2.73 million in the fourth quarter of 2005, a substantial increase from the $501 thousand recorded in the fourth quarter of 2004.

Capital expenditures increased significantly to $19.74 million from $11.09 million a year ago. Drilling and completions were up 86% to $11.92 million while expenditures on facilities and equipping were up 69% to $5.44 million as the Company participated in 29 wells (19.6 net) and completed the electrification and tie-in of certain facilities at Princess.







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SELECTED QUARTERLY INFORMATION



20052004(Three months ended)Dec 31Sep 30Jun 30Mar 31Dec 31Sep 30Jun 30Mar 31Productionbbls/d1,4861,2911,2951,246960808808870mcf/d14,18911,17710,51210,8898,8697,7536,6636,919boe/d3,8513,1543,0473,0612,4392,1001,9192,023Financial($thousands except per share amounts)Production revenue$22,164.6$17,685.1$12,832.0$11,983.5$9,193.1$8,019.9$7,438.0$7,066.0Cash flow from operations12,725.610,091.26,596.85,779.13,028.83,870.53,330.53,154.7per share - basic0.330.260.170.150.090.110.110.12per share - diluted0.310.250.160.140.080.110.100.11Net income2,737.14,335.61,843.21,286.4501.21,114.71,128.0657.6per share - basic0.070.110.050.030.010.030.040.02per share - diluted0.070.110.050.030.010.030.040.02


2006 OUTLOOK

Gentrys Board of Directors has approved the 2006 budget of $43 million. Approximately $26 million is slated for drilling and completions, $9 million for facilities and the remainder for land and seismic expenditures. This budget will be funded entirely from corporate cash flow and is based on average production of 4,900-5,100
boe/d; oil prices of U.S.$52.00/bbl; and gas prices of $7.50/mcf.

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, development and exploration of oil and natural gas reserves are capitalized and then depleted using the unit-of-production method based on estimated proved reserves. A ceiling test ensures the carrying value of a long-life asset can be recovered from its undiscounted future cash flows.

Reserve estimates can have a significant impact on net income and the carrying value of property and equipment as they are the key component in the calculation of both depletion and depreciation and the ceiling test. Revisions to reserve estimates could result in a higher or lower depletion, 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.

One hundred percent of Gentrys reserves were evaluated by the independent engineering
..rm of Martin Brusset & Associates. This evaluation requires significant estimates to be made on various engineering data as well as future production rates, capital expenditures and commodity prices, all of which are subject to a number of uncertainties and various interpretations. The Company expects that over time its estimates of reserves will be revised, either upwards or downwards, based on future drilling, testing, production rates and commodity forecasts.

Asset Retirement Obligations

Gentry estimates the fair value of each asset retirement obligation. The obligation is based on current regulations, costs, technologies and industry standards and is calculated using estimates for the timing of







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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.

Earnings per Share

The CICA introduced handbook section 3500  Earnings per Share which became effective for interim and fiscal periods beginning on or after January 1, 2005. The main feature of this section, as it currently pertains to Gentry, is that the number of incremental shares included in year-to-date diluted earnings per share (EPS) is to be computed using the average market price of common shares for the year-to-date period, rather than on a quarterly basis, as Gentry computed it in 2004. This change did not have a material effect on the Companys diluted EPS.

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







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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 annual 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. Currently, Gentry follows the cost method of accounting for its investment whereby no gains or losses on investments are recognized unless there has been a permanent decline in value. 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 annual 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 2005 and none are in place for 2006, 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 sta. 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 sta. and







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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 established certain disclosure controls and procedures to provide a reasonable level of assurance that the financial and other information required to be disclosed under applicable Securities laws is accurately prepared and disclosed within the time periods required.  The Company's Chief Executive Officer and Chief Financial Officer have evaluated these controls and procedures and concluded that at the end of the period covered by
Gentry's annual filings, they are effective.







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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, 2005, of our audit report dated March 24, 2006, on the consolidated balance sheets of Gentry Resources Ltd. as at December 31, 2005 and 2004, 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



March 31, 2006







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Exhibit 5





[LETTERHEAD OF MARTIN & BRUSSET ASSOCIATES]







CONSENT OF MARTIN & BRUSSET ASSOCICATES



Reference is made to the Annual Report on Form 40-F for the year ended December 31, 2005 (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 23, 2006 entitled Evaluation of the Oil and Gas Reserves Owned by Gentry Resources Ltd. Effective January 1, 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.







Martin & Brusset Associates





/s/ S. Neil Sedgwick



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





March 31, 2006









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Exhibit 6.1

CERTIFICATION



I, Hugh G. Ross, certify that:



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



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



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



4.  The companys other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) 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) 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



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



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



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



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



Date:  March 31, 2006



/s/ Hugh G. Ross

Hugh G. Ross, President and Chief Executive Officer









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Exhibit 6.2

CERTIFICATION



I, Ketan Panchmatia, certify that:



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



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



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



4.  The companys other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) 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) 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



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



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



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



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



Date:  March 31, 2006



/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, 2005, as filed with the Securities and Exchange Commission, I hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:



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



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





Date:  March 31, 2006





/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, 2005, as filed with the Securities and Exchange Commission, I hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:



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



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





Date:  March 31, 2006





/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.