Filed by Automated Filing Services Inc. (604) 609-0244 - Transglobe Energy Corporation

EX-99.1 2 exhibit99-1.htm ANNUAL INFORMATION FORM Filed by Automated Filing Services Inc. (604) 609-0244 - Transglobe Energy Corporation - Exhibit 1

TRANSGLOBE ENERGY CORPORATION

ANNUAL INFORMATION FORM

Year Ended December 31, 2005

March 28, 2006

TABLE OF CONTENTS

	Page

CURRENCY AND EXCHANGE RATES	1
ABBREVIATIONS	2
CONVERSIONS	2
FORWARD LOOKING STATEMENTS	3
CERTAIN DEFINITIONS	4
TRANSGLOBE ENERGY CORPORATION	6
GENERAL DEVELOPMENT OF THE BUSINESS	6
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES	8
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	19
DIVIDEND POLICY	40
DESCRIPTION OF SHARE CAPITAL	40
MARKET FOR SECURITIES	41
ESCROWED SECURITIES	41
DIRECTORS AND OFFICERS	42
HUMAN RESOURCES	43
INTEREST OF EXPERTS	44
LEGAL PROCEEDINGS	44
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	44
AUDITORS, TRANSFER AGENT AND REGISTRAR	44
MATERIAL CONTRACTS	44
AUDIT COMMITTEE INFORMATION	44
RISK FACTORS	46
INDUSTRY CONDITIONS	49
ADDITIONAL INFORMATION	53

SCHEDULE "A"	Report on Reserves Data
SCHEDULE "B"	Report of Management and Directors on Reserves Data and Other Information
SCHEDULE "C"	Charter of Audit Committee

CURRENCY AND EXCHANGE RATES

All dollar amounts in this Annual Information Form, unless otherwise indicated, are stated in United States currency. The Company has adopted the U.S. dollar as the functional currency for its consolidated financial statements. The exchange rates for the period average and end of period for the U.S. dollar in terms of Canadian dollars as reported by the Bank of Canada were as follows for each of the years ended December 31, 2005, 2004 and 2003.

	Year Ended December 31, 2005	Year Ended December 31, 2004	Year Ended December 31, 2003

End of Period	Cdn$1.1630	Cdn$1.2020	Cdn$1.2965

Period Average	Cdn$1.2114	Cdn$1.3015	Cdn$1.4009

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas

Bbl	Barrel	Mcf	thousand cubic feet
Bbls	Barrels	MMcf	million cubic feet
Mbbls	thousand barrels	Mcf/d	thousand cubic feet per day
MMbbls	million barrels	MMcf/d	million cubic feet per day
Mstb	1,000 stock tank barrels	MMbtu	million British Thermal Units
bbls/d	barrels per day	Bcf	billion cubic feet
bopd	barrels of oil per day	Tcf	trillion cubic feet
NGLs	natural gas liquids	GJ	gigajoule
STB	standard tank barrels

Other

AECO	EnCana Corp.'s natural gas storage facility located at Suffield, Alberta.
API	American Petroleum Institute
°API	an indication of the specific gravity of crude oil measured on the API gravity scale. Liquid petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil.
°API
ARTC	Alberta royalty tax credit
BOE or boe	barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 Mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices)
BOE or boe
m³	cubic meters
MBOE	1,000 barrels of oil equivalent
Mstboe	1,000 stock tank barrels of oil equivalent
$M	thousands of dollars
$MM	millions of dollars
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
WTI
psi	pounds per square inch

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

CONVERSIONS

To Convert From	To	Multiply By

Mcf	cubic meters	0.28174
cubic meters	cubic feet	35.494
bbls	cubic meters	0.159
cubic meters	bbls oil	6.293
feet	meters	0.305
meters	feet	3.281
miles	kilometers	1.609
kilometers	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoules	Mmbtu	0.950

A boe conversion ratio of 6 Mcf = 1 bbl has been used. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

FORWARD LOOKING STATEMENTS

Certain statements contained in this annual information form (the "Annual Information Form") and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements. These statements relate to future events or the Company's future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. 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. Actual operational and financial results may differ materially from TransGlobe's expectations contained in the forward-looking statements as a result of various factors, many of which are beyond the control of the Company. These factors include, but are not limited to, unforeseen changes in the rate of production from TransGlobe's oil and gas fields, changes in the price of crude oil and natural gas, adverse technical factors associated with exploration, development, production or transportation of TransGlobe's crude oil and natural gas reserves, changes or disruptions in the political or fiscal regimes in TransGlobe's areas of activity, changes in Canadian, Egyptian, Yemen or American tax, energy or other laws or regulations, changes in significant capital expenditures, delays in production starting up due to an industry shortage of skilled manpower, equipment or materials, and the cost of inflation.

In particular, this Annual Information Form and the documents incorporated by reference herein contain forward-looking statements pertaining to the following:

the quantity of reserves;
oil and natural gas production levels;
capital expenditure programs;
projections of market prices and costs;
supply and demand for oil and natural gas;
expectations regarding the Company's ability to raise capital and to continually add to reserves through exploration, acquisitions and development; and
treatment under government regulatory and taxation regimes.

The Company's actual results 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 oil and natural gas;
liabilities and risks inherent in oil and natural gas operations;
uncertainties associated with estimating reserves;
competition for, among other things, capital, acquisitions of reserves, undeveloped lands, equipment and skilled personnel;
incorrect assessments of the value of acquisition; and
geological, technical, drilling and processing problems.

The Company believes that 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, or incorporated by reference into, this Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual Information Form, as the case may be. The Company does not intend, and does not assume any obligation, to update these forward-looking statements.

CERTAIN DEFINITIONS

In this Annual Information Form, the following words and phrases have the following meanings, unless the context otherwise requires:

"AMEX" means the American Stock Exchange;

“Arsenal” means Arsenal Energy Inc. and its subsidiaries;

"Block 32 Joint Venture Group" means TG Holdings Yemen Inc. (a wholly-owned subsidiary of TransGlobe Energy Corporation) with a 13.81087% working interest and partners Ansan Wikfs (Hadramaut) Ltd. and DNO ASA holding the balance;

"Block 72 Partnership" means the joint venture group comprised of DNO ASA (34%), TG Holdings Yemen Inc. (33%) and Ansan Wikfs (Hadramaut) Ltd. (33%);

"Block S-1 Joint Venture Group" means a joint venture arrangement for Block S-1 with a subsidiary of Vintage Petroleum Inc.;

"Brent" means the reference price paid in US dollars, for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea;

"Cdn" means Canadian;

"COGE Handbook" means the Canadian Oil and Gas Evaluation Handbook prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum;

"CPF" means central production facility;

"DeGolyer" means DeGolyer and MacNaughton Canada Limited, independent petroleum consultants;

"DeGolyer Report" means the report of DeGolyer dated March 16, 2006 evaluating the Yemen crude oil and Canadian crude oil, natural gas liquids and natural gas reserves of the Company as at December 31, 2005;

"Dry Hole" or "Dry Well" or "Non-Productive Well" means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well;

"Exploratory Well" means a well drilled either in search of a new, as-yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir;

"Egypt" means the Arab Republic of Egypt;

"GAAP" means Generally Accepted Accounting Principles;

"Gross" or "gross" means:

(a)	in relation to the Company's interest in production and reserves, its "Company gross reserves", which are the Company's interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company;

(b)	in relation to wells, the total number of wells in which the Company has an interest; and

(c)	in relation to properties, the total area of properties in which the Company has an interest;

"MOM" means Ministry of Oil and Minerals, Republic of Yemen, formerly MOMR, the Ministry of Oil and Mineral Resources;

"NEB" means National Energy Board of Canada;

"Net" or "net" means:

(a)	in relation to the Company's interest in production and reserves, the Company's interest (operating and non- operating) share after deduction of royalties obligations, plus the Company's royalty interest in production or reserves.

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

(c)	in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company;

"NI 51-101" means National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities;

"NI 51-102" means National Instrument 51-102 Continuous Disclosure Obligations;

“OXY” means Occidental Petroleum Corporation and its subsidiaries; "PSA" means Production Sharing Agreement;

"QEL" means Quadra Egypt Limited, a subsidiary of Arsenal Resources Inc., a corporation headquartered in Calgary, Alberta;

"Rampex" means Rampex Petroleum International, a corporation headquartered in Cairo, Egypt;

"TransGlobe" or the "Company" means TransGlobe Energy Corporation, a corporation organized and registered under the laws of Alberta, Canada and its subsidiary companies;

"TransGlobe Egypt" means TransGlobe Petroleum Egypt Inc., a wholly-owned subsidiary of TransGlobe;

"TG Holdings" means TG Holdings Yemen Inc., a wholly-owned subsidiary of TransGlobe;

"TSX" means the Toronto Stock Exchange;

"U.S." means United States;

"Vintage" means Vintage Petroleum, Inc. and its subsidiaries; now a subsidiary of Occidental Petroleum Corporation and

"YOC" means Yemen Oil Company.

Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

TRANSGLOBE ENERGY CORPORATION

General

TransGlobe Energy Corporation ("TransGlobe" or the "Company") was incorporated on August 6, 1968 and was organized under variations of the name "Dusty Mac" as a mineral exploration and extraction venture under The Company Act (British Columbia). In 1992, the Company entered into the oil and gas exploration and development field in the United States and later in the Republic of Yemen and Canada, ceasing operations as a mining company. The U.S. oil and gas properties were sold in 2000 to fund opportunities in Yemen. The Company changed its name to TransGlobe Energy Corporation on April 2, 1996 and on June 9, 2004, the Company continued from the Province of British Columbia to the Province of Alberta.

TransGlobe, through its wholly-owned subsidiaries, is primarily engaged in the exploration for, and the development and production of, oil and gas in Canada, in the Arab Republic of Egypt and in the Republic of Yemen.

The Company has been listed on the TSX under the symbol TGL since November 7, 1997 and on the AMEX under the symbol TGA since November 2003.

The Company's principal office is located at 2500, 605 – 5th Avenue S.W., Calgary, Alberta, T2P 3H5. The Company's registered office is located at 1400, 350 – 7^th Avenue S.W., Calgary, Alberta, T2P 3N9.

Intercorporate Relationships

The following table sets out the name and jurisdiction of incorporation of the Company's subsidiaries and the Company's ownership interest therein:

Name of Subsidiary	Jurisdiction of Incorporation	Ownership
TransGlobe Oil & Gas Corporation	Washington State, United States	100%
TransGlobe Petroleum International Inc.	Turks & Caicos Islands, B.W.I.	100%
TG Holdings Yemen Inc.⁽¹⁾	Turks & Caicos Islands, B.W.I.	100%
TransGlobe Petroleum Egypt Inc.⁽¹⁾	Turks & Caicos Islands, B.W.I.	100%

Note:

(1)	TransGlobe is the indirect holder of TG Holdings Yemen Inc. and TransGlobe Petroleum Egypt Inc., which are 100% owned directly by TransGlobe Petroleum International Inc.

TG Holdings Yemen Inc. owns TransGlobe's interests in the Republic of Yemen in Block 32, in Block S-1 and in Block 72. TransGlobe Petroleum Egypt Inc. owns TransGlobe's interest in the Nuqra Area Block 1, Arab Republic of Egypt.

Unless the context otherwise requires, reference in this Annual Information Form to the "Company" includes the Company and its direct and indirect wholly-owned subsidiaries.

GENERAL DEVELOPMENT OF THE BUSINESS

TransGlobe is an independent, Canadian-based, international upstream oil and gas company whose main business activities include exploration, development and production of crude oil, natural gas liquids and natural gas. The Company has exploration and production operations in Canada and in the Republic of Yemen and an exploration project in the Arab Republic of Egypt.

During the past three years, TransGlobe has developed its business interests through a combination of exploration and development and to a lesser extent, acquisitions and dispositions, primarily focusing on three Production Sharing Agreements ("PSAs") in Yemen (a 13.81087% working interest in Block 32, a 25% working interest in Block S-1 and a 33% working interest in Block 72), in central Alberta, Canada and a Concession Agreement in the Arab Republic of Egypt (a 50% working interest in Nuqra Block 1).

In 2003, the Company's primary focus was on Block S-1 in the Republic of Yemen and an expanded exploration drilling program in Canada. On Block S-1, the An Nagyah light oil discovery was appraised with two wells that led to the Declaration of Commerciality and the filing of a Development Plan on October 14, 2003. On October 15, 2003, the Ministry of Oil and Minerals ("MOM") approved the Development Plan and a 20 year Development Area of approximately 285,000 acres for Block S-1. On Block 32, also in Yemen, the Company participated in five wells, resulting in four oil wells for an 80% success ratio. In Canada, the Company drilled nine wells, resulting in six gas wells, two oil wells and one cased potential gas well for an 88% success ratio.

In November 2003, the Company listed on the American Stock Exchange ("AMEX") under the symbol TGA, which replaced the Company's previous listing on the NASDAQ bulletin board under the symbol TGLEF.

In 2004, the primary exploration and production focus was on Blocks S-1 and 32 in Yemen and central Alberta in Canada. On Block S-1, the An Nagyah light oil development resulted in eight new producing oil wells due to an active development and appraisal drilling program. The Company also participated in one appraisal oil well (Harmel #2) and one exploration dry hole at Al Hareth on Block S-1. On Block 32, the Company participated in the acquisition of 3-D seismic and the drilling of three producing oil wells in the Tasour field. In western Canada, the Company drilled 15 wells, resulting in 10 gas wells, two oil wells and three dry wells.

In addition to the 2004 exploration and production activities, the Company participated in the Yemen International Bid Round for Exploration and Production of Hydrocarbons with the successful award of Block 72. The Block 72 PSA was ratified by the Yemen Parliament on June 18, 2005 and became law following the Presidential decree on July 12, 2005.

In July 2004, the Company announced the addition of an exploration concession in the Arab Republic of Egypt, representing a new country of operation for TransGlobe. The Company entered into a farm-out agreement to incur $6.0 million of expenditures in the Period One and Period Two work programs over the next five years to earn a 50% working interest in the Nuqra Block 1, located in the Upper Nile region of Egypt. TransGlobe is the operator of the Nuqra Block.

In November 2004, TransGlobe Petroleum International Inc. obtained a credit facility of up to an aggregate amount of $7.0 million that are guaranteed by each of TransGlobe, TG Holdings Yemen Inc. and TransGlobe Petroleum Egypt Inc. The Company also completed a public offering on November 24, 2004 for 2,530,000 common shares at a price of Cdn$4.35 per share for gross proceeds of approximately Cdn$11,000,000. The underwriters exercised their over-allotment option in connection with the financing on December 7, 2004 resulting in additional gross proceeds of approximately Cdn$1,650,825.

In 2005, the primary exploration and production focus was on Blocks S-1, 32 and 72 in Yemen; Nuqra Block #1 in Egypt and central Alberta in Canada. On Block S-1, the Company participated in reprocessing the An Naeem 3-D seismic, the development of the An Nagyah light oil pool and the drilling eight wells (5 An Nagyah oil wells and 3 exploration dry holes). The pipeline connecting the An Nagyah field with the Jannah Hunt operated Halewah production facility and export pipeline was completed in July 2005. The pipeline has an ultimate capacity of 80,000 barrels of oil per day so that future discoveries can be placed on stream quickly. The central production facility was expanded to 10,000 Bopd, with an additional expansion to 15,000 Bopd scheduled for mid 2006. On Block 32, the Company participated in the acquisition of 2-D seismic, the drilling of seven wells (2 oil producers, 2 water injection wells, 1 cased potential oil well and 2 dry holes) and upgrades to the Tasour CPF. On Block 72, the Company participated in the acquisition of 255 km of 2-D seismic. In Egypt, on Nuqra Block 1, the Company conducted geological field studies, reprocessed 3,190 km of existing 2-D seismic data and prepared a new 800 km 2-D seismic acquisition program for 2006. In western Canada, the Company drilled 31 wells, resulting in 21 gas wells, 7 oil wells and 3 dry wells.

Anticipated Changes in the Business

As at the date hereof, the Company does not anticipate any material change in its business during the balance of the 2006 financial year.

Significant Acquisitions and Significant Dispositions

The Company did not complete any significant dispositions or significant acquisitions for which disclosure is required under Part 8 of NI 51-102 within or since the completion of the most recently completed financial year.

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES

TransGlobe is engaged in the exploration for, and the development and production of, crude oil and natural gas primarily in the Republic of Yemen, the Arab Republic of Egypt and in central Alberta, Canada. The Company also reviews potential acquisitions and new international exploration blocks to supplement its exploration and development activities.

TransGlobe's major operations and principal activities are in the oil and gas exploration and production business. The Company has operated in the Republic of Yemen, Canada and Egypt during the past eight, six and two years, respectively. In the Republic of Yemen, the Company has interests in three PSA’s: Block 32, Block S-1 and Block 72. In the Arab Republic of Egypt, the Company has an interest in one Concession Agreement, Nuqra Block 1. In Canada, all of the Company's interests are located in the Province of Alberta, primarily in central Alberta.

Republic of Yemen:

Block 32, Republic of Yemen

Background

TransGlobe entered into its first international project in January 1997 through a farmout agreement and joint venture on Block 32. The Company has since participated in acquisition of seismic data, drilling of twenty-six wells and construction of production facilities. The Tasour field commenced production in November, 2000. The joint venture currently consists of TG Holdings Yemen Inc. (a wholly-owned subsidiary of TransGlobe Energy Corporation) with a 13.81087% working interest and partners Ansan Wikfs Hadramaut Ltd. and DNO ASA holding the balance (“the Block 32 Joint Venture Group”). DNO ASA (an independent Norwegian oil company) is the operator of Block 32. The Yemen Oil Company (“YOC” - a Yemen government oil company) has a 5% interest in the Block 32 Joint Venture Group’s production sharing oil.

The Block 32 development area covers 591 square kilometers (146,070 acres). The development area encompasses all of the Tasour structure and several additional prospects. The approved development/production period extends until the year 2020, with an optional five-year extension to 2025.

PSA Summary (13.81087% working interest)

TransGlobe commenced production on Block 32 in November, 2000. Production from the block is shared between the Block 32 Joint Venture Group and the Ministry of Oil and Minerals, Republic of Yemen (“MOM”) pursuant to a Production Sharing Agreement (“PSA”). The PSA provides for MOM to receive a 3% royalty of gross production. The balance of production is split between cost recovery oil and production sharing oil. Cost recovery oil is up to a maximum of 60% of the production after deducting the 3% royalty. Cost recovery oil allows the Block 32 Joint Venture Group to recover operating costs and exploration and development expenditures as outlined in the PSA. The remaining oil is allocated to production sharing oil shared 65% by MOM, 33.25% by the Block 32 Joint Venture Group and 1.75% to YOC. The Block 32 Joint Venture Group’s Yemen royalties and income taxes are paid out of MOM’s share of production sharing oil. These terms remain in place until gross proved recoverable reserves exceed 30 million barrels of oil (assessed every two years) or until gross production exceeds 25,000 Bopd at which time the terms would revert to the original PSA terms in place prior to the 1999 PSA amendment. The original PSA terms provided for a 10% royalty on gross production with the remaining 90% of production split between cost recovery oil and production sharing oil. Cost recovery oil would be to a maximum of 25%, with the remaining oil allocated to production sharing oil shared 77% by MOM and 23% by the Block 32 Joint Venture Group. The proved recoverable reserve determination is conducted every two years from the anniversary of first oil production. At November 4, 2004, the proved recoverable reserves recognized by an independent third party audit were less than 10 million barrels. This audit was approved by MOM. The next Block 32 MOM audit will be conducted effective November 4, 2006.

2005 Activities and Results

During 2005, the Block 32 Joint Venture Group work program consisted of a 70 km 2-D seismic program north and west of the Tasour field and the drilling of seven wells. In the Tasour area three development wells (2 oil wells and 1 suspended), two dedicated water injectors and one dry hole (appraisal of an eastern extension to Tasour) were drilled. The Balan #1 exploration well was drilled and abandoned after failing to test hydrocarbons from the Saar or Basement zones. The well was located approximately 11 km northwest of the Tasour field.

2005 Drilling Results

			Initial Production
Well	Well Type	Status	Test (Bopd – gross)	Formation
Tasour #15	Injector	Water Injector	N/A	Qishn
Tasour #16	Development	Suspended	N/A	Qishn
Tasour #17	Appraisal	D&A	N/A	Qishn
Tasour #18	Development	Oil Producer	3,000	Qishn 1-C
Tasour #19	Development	Oil Producer	1,300	Qishn 1-A
Tasour #20	Injector	Water Injector	N/A	Qishn
Balan #1	Exploration	D&A	N/A	Sarr/Basement

Production
The Tasour field averaged 13,946 Bopd (1,926 Bopd to TransGlobe) during 2005. With the boundaries of the Tasour field defined and production maturing, two facility optimization projects were constructed at the central production facility (“CPF”) during 2005. The first project, a diesel topping plant, was installed to reduce operation costs by manufacturing diesel from produced crude oil. The diesel topping plant was commissioned in December 2005 and is currently producing 380 Bpd of diesel which is used to generate electricity to run all the pumps and facilities on the Block. The second project, to expand CPF fluid handling and water injection capacity, will be completed in April 2006. Several dedicated water injectors were drilled to handle increased volumes associated with the expansion. It is expected that production from the Tasour field will average approximately 8,000 Bopd during 2006 assuming the CPF expansion is operational in April.

2005 Tasour Production by Quarter (Bopd)

	Q-1	Q-2	Q-3	Q-4
Gross field production rate	16,167	13,838	14,302	11,527
TransGlobe working interest	2,233	1,911	1,975	1,592
TransGlobe net (after royalties)	1,567	1,060	1,100	834
TransGlobe net (after royalties and tax)	1,357	775	809	573

Under the terms of the Block 32 PSA royalties and taxes are paid out of the government’s share of production sharing oil.

TASOUR FIELD

2006 Outlook

The Block 32 Joint Venture Group approved a six well drilling program (firm and contingent) for 2006 focused primarily on exploration (five exploration wells and one development well).

The first exploration well of 2006 at Godah #1 (side track) tested 1,839 Bopd from the Qishn formation. A second well, Godah #2 will be drilled approximately 1,100 meters northeast of Godah #1 to appraise the new oil pool. It is expected that Godah #2 will commence drilling in April. Additional drilling on the Godah structure will be dependent upon the results of Godah #2. The operator is currently evaluating production options, however it is expected that the Godah discovery could be connected to the Tasour CPF with a 23 km pipeline in the latter half of 2006.

In addition to the appraisal/potential development of Godah, a second drilling rig will commence drilling Tasour #21 in late March. Tasour #21 will be drillied on the south eastern flank of the Tasour field to evaluate a deeper Sarr prospect. An exploration well, Tasour #22, will be drilled south of the Tasour field to evaluate a fractured basement prospect.

Block 72, Republic Of Yemen

Background
Block 72 was acquired in a bid round in 2004 by a joint venture group comprised of DNO ASA (34%), TG Holdings Yemen Inc. (33%) and Ansan Wikfs (Hadramaut) Limited (33%) (“Block 72 Joint Venture Group”). TG Holdings Yemen Inc. is a wholly owned subsidiary of TransGlobe Energy Corporation. The YOC has a 10% interest in the Block 72 Joint Venture Group’s production sharing oil. The Block 72 PSA was ratified by the Yemen parliament on June 18, 2005 and became law following the Presidential decree on July 12, 2005. Block 72 encompasses 1,822 square kilometers (approximately 450,234 acres) located in the western Masila Basin adjacent to the billion barrel Nexen Masila Block. The Block 72 Joint Venture Group committed to a seismic acquisition program and the drilling of two exploration wells during the first exploration period of thirty months.

PSA Summary (33% working interest)

Production from the Block will be shared between the Block 72 Joint Venture Group and MOM pursuant to a PSA. The PSA provides for MOM to receive a 3% royalty of gross production up to 25,000 Bopd in a month (escalating thereafter), with the remaining 97% of production split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum of 50% of the production after deducting the 3% royalty. The remaining oil allocated to production sharing oil is shared 64% MOM, 32.4% Block 72 Joint Venture Group and 3.6% to YOC (increasing share to the government on incremental production more than 25,000 Bopd).

2005 Activities and Results
A 255 km 2-D seismic acquisition program commenced in the fourth quarter of 2005 and was completed in January 2006.

2006 Outlook
The new seismic data is currently being processed along with 500 km of existing 2-D seismic data. Interpretation and mapping is expected to be completed during the second quarter of 2006. A two well exploration program is scheduled to commence drilling in the fourth quarter of 2006.

Block S-1, Republic of Yemen

Background
TransGlobe entered into its second international exploration venture in 1997 by signing a PSA for the Damis S-1 Block (“Block S-1”) with MOM. TG Holdings Yemen Inc. (a wholly owned subsidiary of TransGlobe Energy Corporation) entered into a joint venture arrangement for Block S-1 with a subsidiary of Vintage Petroleum Inc. (“Vintage”), a U.S. independent exploration and production company (“Block S-1 Joint Venture Group”). During 2000 Vintage earned a 75% working interest in Block S-1 by funding 100% of the work commitments for the first exploration period of the Block S-1 PSA and by spending a minimum of $20 million. TransGlobe has retained a 25% working interest in Block S-1. In September 2005 Occidental Petroleum Corporation (“OXY”) announced the acquisition of Vintage. The acquisition closed on January 30, 2006. OXY through its wholly owned subsidiary (Vintage) is now the operator of Block S-1. The YOC has a 17.5% interest in the Block S-1 Joint Venture Group’s share of production sharing oil.

Block S-1 originally encompassed an area of 4,484 square kilometers (approximately 1.1 million acres). Upon declaring commerciality in October 2003, a final relinquishment reduced the block to a Development Area of 1,152 square kilometers (284,700 acres). The Development Area is now valid until October 2023 with an additional five year extension available.

To date, the Company has participated in two 3-D seismic surveys, drilling of 27 wells, the construction of production facilities and commencement of production in March 2004.

PSA Summary (25% working interest)

TransGlobe commenced production on Block S-1 on March 31, 2004. Production from the block is shared between the Block S-1 Joint Venture Group and MOM pursuant to a PSA. The PSA provides for MOM to receive a 3% royalty of gross production up to 12,500 Bopd (4% royalty from 12,500 to 25,000 Bopd) with the remaining 97% of production split between cost recovery oil and production sharing oil. Cost recovery oil is up to a maximum of 50% of the production after deducting the 3% royalty. Cost recovery oil allows the Block S-1 Joint Venture Group to recover operating costs and exploration and development expenditures as outlined in the PSA. The remaining oil allocated to production sharing oil is shared 65% by MOM, 28.875% by the Block S-1 Joint Venture Group and 6.125% to YOC up to 12,500 Bopd (70% by MOM, 24.75% by the Block S-1 Joint Venture Group and 5.25% to YOC from 12,500 Bopd to 25,000 Bopd). The Block S-1 Joint Venture Group’s Yemen royalties and income taxes are paid out of MOM’s share of production sharing oil.

2005 Activities and Results
During 2005, the Block S-1 Joint Venture Group reprocessed the 1999 An Naeem 3-D seismic program and drilled eight wells resulting in five oil wells and three dry holes. The main focus in 2005 was the use of horizontal drilling to develop the An Nagyah Lam A pool (3 wells in 2005) and to evaluate the potential of the Lam B pool (1 well in 2005). In addition to the Lam A and B drilling, oil was tested from the Lam B formation south of the main bounding fault, which may be appraised in the future.

2005 Drilling Results

			Initial Production
Well	Well Type	Status	Test (Bopd – gross)	Formation
An Nagyah #14	Appraisal	Oil	80	Lam B
An Nagyah #15Hz	Development	Oil	2,625	Lam A
An Nagyah #16Hz	Development	Oil	2,520	Lam A
An Nagyah #17Hz	Development	Oil	3,250	Lam A
An Nagyah #18Hz	Appraisal	Oil	1,300	Lam B
Malaki #1	Exploration	D&A	N/A	Alif/Lam
Markhah #1	Exploration	D&A	Non-commercial oil	Shuqra and Basement
Hatat #1	Exploration	D&A	N/A	Basement

AN NAGYAH FIELD

Lam A Reservoir (only Lam A wells shown)

Lam B Reservoir (150 meters below Lam A Reservoir)

(Only Lam B wells shown)

Production

Production from Block S-1 averaged 8,792 Bopd (2,198 Bopd to TransGlobe) during 2005. Production increased throughout the year with the addition of wells and facilities. Production during 2005 was partially constrained, initially by the early production trucking operations and later by insufficient capacity at the processing facility. A 30 km (18 mile) 10 inch pipeline connecting the An Nagyah field with the Jannah Hunt operated Halewah production facility and export pipeline was constructed during the first half of 2005. The pipeline has an ultimate capacity of 80,000 Bopd to provide expansion capabilities for future developments. The pipeline became operational in early July and the trucking operations ceased, thereby reducing operating costs. The CPF was expanded throughout 2005 to handle 10,000 Bopd and re-injection of associated gas production. Production increased during 2005 to a level of 12,300 Bopd (3,075 Bopd to TransGlobe) in early December. Facility constraints associated with cooler temperatures in late December and in January restricted production to approximately 9,300 Bopd (2,325 Bopd to TransGlobe). Field production increased to 12,000 Bopd, following the installation of additional treating capacity at the CPF in late February 2006. Additional equipment was ordered to increase the CPF capacity to 15,000 Bopd in the third quarter 2006.

2005 Production by Quarter (Bopd)

	Q-1	Q-2	Q-3	Q-4
Gross field production rate	7,332	8,164	8,939	10,704
TransGlobe working interest	1,833	2,041	2,235	2,676
TransGlobe net (after royalties)	1,284	1,421	1,558	1,472
TransGlobe net (after royalties and tax)	1,146	1,247	1,389	1,258

Production equipment was installed at Harmel #1 and Harmel #2 in March 2005. The initial Harmel #1 production rate of approximately 100 Bopd has declined to a rate of less than 15 Bopd. The Harmel #2 well encountered a poorer quality reservoir and has less productive capacity than the Harmel #1 well. Although the production rates are disappointing, it is expected that new wells may be drilled targeting deeper prospects (Alif and Basement) on the Harmel structure. Future wells could provide additional reservoir information on the shallow medium gravity oil (22 degree API) pool. The Harmel pool (500 to 800 meters in depth) encompasses 15 square miles as defined by 3-D

seismic and represents a potentially significant accumulation of oil in place. The shallow zones require several more wells (vertical and/or horizontal) to fully evaluate the economic viability of the oil accumulation. For 2006 the partnership plans to focus on developing the light oil discovery at An Nagyah as well as other potential leads. Therefore no additional work on Harmel is currently planned for 2006.

2006 Outlook

The Block S-1 Joint Venture Group approved a capital budget of $48 million ($12 million to TransGlobe) for 2006 projects (firm and contingent). The program includes additional 3-D seismic acquisition over the southern portion of Block S-1, a continuous drilling program (a mixture of development horizontal wells and exploration wells) and expansion of the production facilities. Vintage (the operator of Block S-1) was acquired by and merged into OXY effective January 30, 2006. OXY is currently reviewing the Block S-1 prospects and approved 2006 work program. It is expected that the Joint Venture Group will meet in the next few months to discuss the 2006 work program. TransGlobe is very pleased to have OXY as a new partner in Block S-1. In addition to being a very successful international oil and gas exploration company, OXY also brings a vast regional knowledge of Yemen from their ownership in two producing blocks in the prolific Masila Basin (Block 14 and Block 10) and more recently, their drilling in Block 20 immediately north west of Block S-1. OXY was also awarded Block 75 in 2005, which bounds Block S-1 to the south.

During the first quarter of 2006, two horizontal development wells (An Nagyah #19 and #20) targeting the Lam A pool have been drilled and tested at rates of 3,226 Bopd and 2,992 Bopd, respectively. The drilling rig is currently drilling the An Nagyah #21 Lam B development well. Following An Nagyah #21 the rig will drill another development well at Wadi Bayhan. The Wadi Bayhan prospect is an Alif/Lam prospect. It is expected that up to ten wells will be drilled on Block S-1 during 2006.

The approved 2006 work program included funds to evaluate the feasibility of producing additional stabilized condensate from the An Nagyah solution gas and possible make-up gas from the An Naeem gas condensate pool. An Naeem gas (make-up gas) could be used to maintain reservoir pressure and improve oil recoveries from the An Nagyah pool. A gas cycling scheme to recover additional condensate from the An Naeem gas condensate pool may also be studied.

Block S-1 Prospects

Nuqra Block 1, Arab Republic of Egypt

Background
In July 2004, TransGlobe Petroleum Egypt Inc. ("TransGlobe Egypt"), a wholly owned subsidiary of TransGlobe Energy Corporation, entered into a Farmout Agreement with Quadra Egypt Limited ("QEL"), a subsidiary of Quadra Resources Corp. headquartered in Calgary, and Rampex Petroleum International ("Rampex") headquartered in Cairo, Egypt (“Nuqra Block 1 Joint Venture Group”). Quadra Resources was subsequently acquired by Arsenal Energy Inc. (“Arsenal”) of Calgary in 2005 and the Rampex interest was assigned to Petrosina Limited and Wantapex Limited in 2004. QEL is a wholly owned subsidiary of Arsenal.

Under the terms of this agreement TransGlobe Egypt earns a 50% interest in the Nuqra Concession by paying 100% of the initial $6.0 million of expenditures in the Period One and the Period Two work programs. After the initial $6.0 million has been spent, costs will be shared 60% TransGlobe Egypt and 40% Arsenal. Petrosina and Wantapex will be carried until first production. The cost of the Petrosina and Wantapex carry will be recovered by TransGlobe Egypt and Arsenal from 100% of the Petrosina and Wantapex cost oil and 50% of the Rampex production sharing oil. TransGlobe Egypt is the Operator of the Nuqra Block.

The Nuqra Concession Agreement Period One work program requires expenditure of $2.0 million to reprocess existing seismic and to acquire new seismic within the first two years. Upon expiry of the Period One term, there is an option to proceed to the Period Two work program. Period Two requires completion of a two well drilling program, with a minimum expenditure of $4.0 million over a period of three years. Upon expiry of the Period Two term there is an option to proceed to the Period Three work program. Period Three requires completion of a two well drilling program, with a minimum expenditure of $5.0 million over a final three year term. Exploitation of discovered commercial fields will continue under a Development Lease for a further 20 years.

The Nuqra Concession is located in Upper Egypt near of the city of Luxor on the east bank of the Nile River. The concession encompasses over two-thirds of the Kom Ombo/Nuqra Basin. The Nuqra Concession contains more than 30,000 square kilometers or 7,500,000 acres of exploration lands with eight seismically defined leads identified

from over 4,000 km of existing 2-D seismic. Seismic and well data have confirmed the existence of Jurassic and Cretaceous sediments and the presence of a petroleum system which could potentially hold significant oil reserves.

Nuqra Sub Basin
2006 2-D Seismic Program, 800 km

Concession Agreement Summary (50% working interest)

Production from the Block will be shared between the Nuqra Block 1 Joint Venture Group and the government pursuant to a Concession Agreement. The Concession Agreement terms allow for the recovery of costs up to a maximum of 40% of gross production. The remaining balance of production is then shared on a 70:30 basis between the government and the Nuqra Block 1 Joint Venture Group, respectively, for the first 25,000 Bopd. Production sharing above 25,000 Bopd is shared on an 80:20 basis.

2005 Activities

TransGlobe completed the reprocessing of 3,190 km of existing 2-D seismic data on the Nuqra Block 1 in the summer of 2005. The reprocessed seismic data has been mapped and interpreted, resulting in eight identified leads in the central area of the basin.

2006 Outlook

An 800 km 2-D seismic acquisition program commenced in early January 2006 and is expected to be completed by the end of March. To save on mobilization and demobilization costs the seismic acquisition program was bid jointly with Centurion Energy who holds the exploration concession adjacent to the Nuqra Block. TransGlobe is preparing for a two well exploration drilling program to commence in late 2006. Tenders for long lead items and a drilling rig are out for bid. It is expected that the availability of a suitable drilling rig will determine when drilling commences.

The Company has already exceeded the Period One work commitments of $2.0 million and plans to commit to Period Two at the end of Period One on July 18, 2006. There is a mandatory relinquishment of 25% of the Block at the end of Period One.

Canada

Background
TransGlobe acquired its Canadian operations in April 1999. TransGlobe operates most of the wells which are located almost entirely in the southern/central part of the Province of Alberta. Until 2003, investment in Canadian operations was limited to development and exploitation of producing areas with minimal investment in land or exploration opportunities. Since 2003 Canadian operations have been successfully expanded providing increased cash flow and asset value. The Company plans to continue expanding the Canadian operations to capitalize on the North American gas market.

2005 Activities and Results

In early 2005 the Canadian budget and work program was increased from 10-15 wells to 30-35 wells due to increased corporate cash flow associated with record commodity prices. The Company participated in a total of 31 wells resulting in 21 gas, 7 oil and 3 dry for an overall success rate of 90%. The majority of the wells were drilled in the Nevis, Gadsby and Morningside areas of central Alberta. Of the 31 wells drilled, TransGlobe had an average working interest of 79% in 26 wells and a carried interest after payout in five wells which were farmed out to a third party. Included in the 31 wells were eight successful coal bed methane (“CBM”) wells targeting the Horseshoe Canyon coals in the Nevis (1 well) and Morningside (7 wells) areas.

The Company acquired 15,100 net acres of exploration land in 2005, bringing the Company’s total net undeveloped land to 33,300 acres at year end.

2005 Drilling Results

	Oil		Gas		Dry		Total
Area	Gross	(Net)	Gross	(Net)	Gross	(Net)	Gross	(Net)

Nevis	5	(4.7)	8	(6.6)	1	(1.0)	14	(12.3)
Gadsby*	1	(1.0)	4*	(2.0)	1	(1.0)	6*	(4.0)
Morningside**	1	(0.8)	7**	(1.4)	-	-	8**	(2.2)
Other	-	-	2	(1.6)	1	(0.5)	3	(2.1)
Total	7	(6.5)	21	(11.6)	3	(2.5)	31	(20.6)

*	Includes 2 farm out wells.
**	Includes 3 farm out wells.

The Canadian drilling budget was increased from 10-15 wells to 30-35 wells in the second quarter of 2005, resulting in the majority of the wells being drilled in the fourth quarter.

2005 Wells (excluding farm outs)	Q-1	Q-2	Q-3	Q-4	Total
Total drilled	0	7	4	20	26
Successful drilled	0	6	3	18	23
Pipeline connected	0	2	1	4	7

Production

In Canada, production increased 28% from an average of 677 Boepd in 2004 to 867 Boepd (75% natural gas) in 2005. In December, production averaged 889 Boepd. Several wells were connected during late December and January which increased Canadian production to approximately 1,100 Boepd in February. There are an additional 14 (11 net) wells, representing 400 Boepd to the Company, still requiring pipeline connections. This work is anticipated to be carried out during the first half of 2006.

2005 Canadian Production by Quarter (Boepd)

	Q-1	Q-2	Q-3	Q-4
TransGlobe working interest	821	706	1,075	864
TransGlobe net (after royalties)	673	600	887	691

2006 Outlook

The approved 2006 Canadian budget of $20.4 million is primarily focused on development drilling, completions and facilities. It is expected that 25-30 wells will be drilled during 2006 including 12-16 wells targeting the Horseshoe Canyon coals in the Nevis and Morningside areas. Approximately 20% of the budget is dedicated to exploration drilling and land acquisitions.

Up to mid-March of 2006 the Company participated in drilling 4 (2.0 net) potential gas wells. To ensure the 2006 program can be carried out the Company has secured access to drilling rigs in central Alberta with several other companies. The Company commenced drilling in the Nevis area in March, and expects to drill 8-10 wells in central Alberta during the next two to three months depending on surface access conditions associated with spring breakup. In addition, the Company has filed applications to drill four CBM wells per section in the Nevis area. It is expected that the CBM Nevis drilling program (10-12 wells) will commence in the second or third quarter.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The report of management and the directors on oil and gas disclosure in Form 51-101F3 and the report on reserves data in Form 51-101F2 are attached as Schedules "B" and "A", respectively to this Annual Information Form, which forms are incorporated herein by reference.

The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated March 16, 2006 with the effective date of the Statement being December 31, 2005.

Disclosure of Reserves Data

All of the Company's reserves herein reported were evaluated by independent evaluators in accordance with NI 51-101 for the year ended December 31, 2005. In 2005, DeGolyer and MacNaughton Canada Limited ("DeGolyer"), independent petroleum engineering consultants based in Calgary, Alberta and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company's Reserve Committee, to independently evaluate 100% of TransGlobe's reserves as at December 31, 2005.

The reserves data set forth below (the "Reserves Data") was prepared by DeGolyer with an effective date of December 31, 2005. The Reserves Data summarizes the oil, liquids and natural gas reserves of the Company and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Company reports in U.S. currency and therefore the reports have been converted to U.S. $'s at the prevailing conversion rate at December 31 of the respective years.

The Reserves Data conforms with the requirements of NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which the Company believes is important to the readers of this information.

Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Company's properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGLs and natural gas reserves may be greater than or less than the estimates provided herein.

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
TOTAL COMPANY
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

	Light & Medium Crude
	Oil		Natural Gas		Natural Gas Liquids		Total boe's
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	3,117	1,809	5,832	4,542	193	140	4,282	2,706
Non-Producing	953	557	2,480	1,873	42	28	1,408	898
Undeveloped	1,638	846	2,879	2,358	20	14	2,138	1,253
Total Proved	5,708	3,211	11,191	8,773	255	183	7,828	4,856

Probable	1,561	831	5,783	4,464	129	90	2,654	1,664

Proved Plus Probable	7,269	4,042	16,974	13,237	384	272	10,482	6,520

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

	Light & Medium Crude
	Oil		Natural Gas		Natural Gas Liquids		Total boe's
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	3,014	1,716					3,014	1,716
Non-Producing	837	452					837	452
Undeveloped	1,491	719					1,491	719
Total Proved	5,342	2,887					5,342	2,887

Probable	1,472	749					1,472	749

Proved Plus Probable	6,814	3,636					6,814	3,636

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

	Light & Medium Crude
	Oil		Natural Gas		Natural Gas Liquids		Total boe's
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	104	93	5,832	4,542	193	140	1,269	990
Non-Producing	115	104	2,480	1,873	42	28	570	444
Undeveloped	147	127	2,879	2,358	20	14	647	534
Total Proved	366	325	11,191	8,773	255	182	2,486	1,969

Probable	89	82	5,783	4,464	129	90	1,181	916

Proved Plus Probable	455	406	16,974	13,237	384	272	3,668	2,885

Notes:

(1)

Gross reserves are the Company's working interest share before the deduction of royalties.

(2)

Net reserves are the Company's working interest share after the deduction of royalties. Net reserves in Yemen include our share of future cost recovery and production sharing oil after the Government's royalty interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.

Estimated Future Net Revenues

The estimated future net revenues presented do not represent fair market value. The estimated future net revenues presented below are calculated using the average price received on December 31^st of the respective reporting periods. The prices were held constant and costs were not inflated for the life of the reserves, as summarized in the Notes to Reserves Data Tables (Note 4).

NET PRESENT VALUES OF FUTURE NET REVENUES
TOTAL COMPANY
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

	Before Income Tax⁽¹⁾⁽²⁾					After Income Tax⁽¹⁾⁽²⁾
US$'s	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%

Proved

Developed producing	88.2	78.2	70.7	64.6	59.5	85.6	76.2	69.1	63.3	58.5
Developed non-producing	25.5	24.1	22.3	20.5	18.9	19.9	19.1	17.8	16.5	15.2
Undeveloped	34.7	28.3	23.2	19.0	15.7	30.4	24.7	20.1	16.4	13.4
Total Proved	148.4	130.6	116.1	104.2	94.0	135.9	120.0	107.0	96.2	87.2

Probable	65.7	52.9	43.5	36.4	31.0	54.0	43.8	36.2	30.5	26.0

Total Proved Plus Probable	214.1	183.5	159.7	140.6	125.0	189.9	163.8	143.2	126.7	113.1

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of $1.1630 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

NET PRESENT VALUES OF FUTURE NET REVENUES
YEMEN
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

	Before Income Tax⁽¹⁾					After Income Tax⁽¹⁾
US$'s	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%

Proved

Developed producing	47.1	44.0	41.2	38.7	36.4	47.1	44.0	41.2	38.7	36.4
Developed non-producing	10.3	9.3	8.4	7.6	6.9	10.3	9.3	8.4	7.6	6.9
Undeveloped	21.1	17.7	15.0	12.7	10.8	21.1	17.7	15.0	12.7	10.8
Total Proved	78.5	71.0	64.6	59.0	54.1	78.5	71.0	64.6	59.0	54.1

Probable	29.5	25.0	21.4	18.5	16.1	29.5	25.0	21.4	18.5	16.1

Total Proved Plus Probable	108.0	96.0	86.0	77.5	70.2	108.0	96.0	86.0	77.5	70.2

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of $1.1630 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

	Before Income Tax⁽²⁾					After Income Tax⁽²⁾
US$'s	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%

Proved

Developed producing	41.1	34.2	29.5	25.9	23.2	38.5	32.2	27.9	24.7	22.2
Developed non-producing	15.2	14.8	13.9	12.9	12.0	9.6	9.8	9.4	8.9	8.3
Undeveloped	13.6	10.5	8.2	6.3	4.8	9.3	6.9	5.1	3.7	2.6
Total Proved	69.9	59.6	51.6	45.2	40.0	57.4	48.9	42.4	37.3	33.1

Probable	36.3	27.9	22.1	17.9	14.8	24.6	18.8	14.8	12.0	9.9

Total Proved Plus Probable	106.2	87.5	73.7	63.1	54.8	81.9	67.7	57.2	49.2	43.0

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of $1.1630 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

NET PRESENT VALUE OF ALBERTA ROYALTY TAX CREDITS
CANADA
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

US$'s	Future Cash Flow as of December 31, 2005
$M	Discounted at %/yr
Reserve Category	0%	5%	10%	15%	20%

Proved Developed
Producing	1.8	1.6	1.4	1.2	1.1
Non-Producing	0.3	0.3	0.3	0.2	0.2
Proved Undeveloped	0.3	0.2	0.2	0.1	0.1
Total Proved	2.4	2.0	1.8	1.5	1.4

Probable	1.0	0.7	0.5	0.4	0.3

Total Proved + Probable	3.4	2.7	2.3	1.9	1.7

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

						Future Net		Future Net
						Revenue		Revenue
					Well	Before		After
			Operating	Development	Abandonment	Income	Income	Income
	Revenue	Royalties	Costs	Costs	Costs	Taxes	Taxes	Taxes
Reserves Category	($MM)	($MM)	($MM)	($MM)	($MM)	($MM)	($MM)	($MM)

Proved Reserves
Yemen⁽¹⁾	302	143	34	10	-	115	36	79
Canada⁽²⁾	119	21	17	9	1	70	13	57
Total Company	421	164	51	20	1	185	49	136

Proved Plus
Probable Reserves
Yemen⁽¹⁾	385	184	38	11	-	152	44	108
Canada⁽²⁾	175	32	24	11	1	106	24	82
Total Company	560	216	63	22	1	258	68	190

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of 1.1630 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

FUTURE NET REVENUE
BY PRODUCTION GROUP
AS AT DECEMBER 31, 2005
(CONSTANT PRICES AND COSTS)

		Yemen	Canada
		Future net Revenue	Future net Revenue	Total Company
		Before Income	Before Income	Future net Revenue
		Taxes⁽¹⁾	Taxes⁽²⁾	Before Income Taxes
		(discounted at	(discounted at	(discounted at
		10%/year)	10%/year)	10%/year)
Reserves Category	Product Group	(US$MM)	(US$MM)	(US$MM)

Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	64.6	8.4	73.0

	Natural Gas (including by-products but excluding solution gas)	-	41.3	41.3


Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	86.0	12.3	98.3

	Natural Gas (including by-products but excluding solution gas)	-	59.1	59.1

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of 1.1630 US $'s/Cdn $'s and do not include the Alberta Royalty Tax Credit (ARTC) in the Before Income Tax values.

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
TOTAL COMPANY
AS OF DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

	Light & Medium Crude
	Oil		Natural Gas		Natural Gas Liquids		Total boe's
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	3,117	1,834	5,835	4,700	193	141	4,283	2,758
Non-Producing	870	520	2,485	1,978	42	29	1,326	879
Undeveloped	1,721	898	2,869	2,427	20	14	2,219	1,316
Total Proved	5,708	3,252	11,189	9,105	255	183	7,828	4,953

Probable	1,561	790	5,786	4,649	129	90	2,654	1,655

Proved Plus Probable	7,269	4,042	16,975	13,754	384	273	10,482	6,608

Notes:

(1)

Gross reserves are the Company's working interest share before the deduction of royalties.

(2)

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS OF DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

	Light & Medium Crude
	Oil		Natural Gas		Natural Gas Liquids		Total boe's
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	3,014	1,741					3,014	1,741
Non-Producing	755	416					755	416
Undeveloped	1,574	770					1,574	770
Total Proved	5,342	2,927					5,342	2,927

Probable	1,472	708					1,472	708

Proved Plus Probable	6,814	3,636					6,814	3,636

Notes:

(1)

Gross reserves are the Company's working interest share before the deduction of royalties.

(2)

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS OF DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

	Light & Medium Crude
	Oil		Natural Gas		Natural Gas Liquids		Total boe's
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	104	93	5,835	4,700	193	141	1,269	1,017
Non-Producing	115	104	2,485	1,978	42	29	572	463
Undeveloped	147	127	2,869	2,427	20	14	645	546
Total Proved	366	325	11,189	9,105	255	183	2,486	2,025

Probable	89	82	5,786	4,649	129	90	1,182	946

Proved Plus Probable	455	407	16,975	13,754	384	273	3,668	2,972

Notes:

(1)	Gross reserves are the Company's working interest share before the deduction of royalties.
(2)	Net reserves are the Company's working interest share after the deduction of royalties.

NET PRESENT VALUES OF FUTURE NET REVENUES
TOTAL COMPANY
AS OF DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

The estimated future net revenues presented do not represent fair market value. The estimated future net revenues presented below are calculated using the respective Consultant price forecasts and inflation rates as summarized in the Notes to Reserves Data Tables (Note 3).

	Before Income Tax⁽¹⁾⁽²⁾					After Income Tax⁽¹⁾⁽²⁾
US$'s	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%

Proved

Developed producing	87.5	78.4	71.4	65.7	61.0	85.1	76.4	69.8	64.4	59.8
Developed non-producing	27.2	25.9	23.7	22.4	20.7	21.0	20.2	18.5	17.6	16.3
Undeveloped	31.3	25.7	21.7	17.6	14.7	27.1	22.2	18.6	15.0	12.3
Total Proved	146.0	130.0	116.8	105.8	96.4	133.2	118.8	106.9	96.9	88.4

Probable	54.6	44.2	36.7	30.9	26.5	43.9	35.7	29.6	25.1	21.5

Total Proved Plus Probable	200.6	174.3	153.5	136.7	122.9	177.1	154.5	136.6	122.0	109.9

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of 1.1630 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

NET PRESENT VALUES OF FUTURE NET REVENUES
YEMEN
AS OF DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

	Before Income Tax⁽¹⁾					After Income Tax⁽¹⁾
US$'s	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%

Proved

Developed producing	46.8	43.8	41.1	38.7	36.5	46.8	43.8	41.1	38.7	36.5
Developed non-producing	10.8	9.7	8.2	7.9	7.1	10.8	9.7	8.2	7.9	7.1
Undeveloped	18.0	15.2	13.4	11.0	9.4	18.0	15.2	13.4	11.0	9.4
Total Proved	75.6	68.7	62.8	57.6	53.0	75.6	68.7	62.8	57.6	53.0

Probable	21.0	17.9	15.3	13.3	11.6	21.0	17.9	15.3	13.3	11.6

Total Proved Plus Probable	96.6	86.6	78.1	70.8	64.6	96.6	86.6	78.1	70.8	64.6

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS OF DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

	Before Income Tax⁽¹⁾					After Income Tax⁽¹⁾
US$'s	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%

Proved

Developed producing	40.7	34.6	30.3	27.0	24.5	38.3	32.6	28.6	25.7	23.3
Developed non-producing	16.4	16.3	15.5	14.5	13.6	10.2	10.6	10.3	9.7	9.2
Undeveloped	13.2	10.5	8.3	6.6	5.3	9.1	6.9	5.3	4.0	2.9
Total Proved	70.4	61.3	54.1	48.2	43.4	57.6	50.1	44.2	39.4	35.4

Probable	33.6	26.4	21.3	17.7	14.9	22.9	17.8	14.3	11.8	9.9

Total Proved Plus Probable	104.0	87.7	75.4	65.9	58.3	80.5	67.9	58.5	51.2	45.4

Notes:

(1)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of 1.1630 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

NET PRESENT VALUE OF ALBERTA ROYALTY TAX CREDITS
CANADA
AS AT DECEMBER 31, 2005
(FORECAST PRICE CASE)

US$'s	Future Cash Flow as of December 31, 2005
$M	Discounted at %/yr
Reserve Category	0%	5%	10%	15%	20%

Proved Developed
Producing	1.5	1.3	1.2	1.0	0.9
Non-Producing	0.3	0.3	0.3	0.2	0.2
Proved Undeveloped	0.2	0.2	0.2	0.1	0.1
Total Proved	2.0	1.8	1.6	1.4	1.3

Probable	0.8	0.6	0.4	0.3	0.2

Total Proved plus	2.8	2.4	2.0	1.7	1.5
Probable

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

						Future		Future
						Net		Net
						Revenue		Revenue
					Well	Before		After
			Operating	Development	Abandonment	Income	Income	Income
	Revenue	Royalties	Costs	Costs	Costs	Taxes	Taxes	Taxes
Reserves Category	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)

Proved Reserves
Yemen⁽¹⁾	290	135	36	10	-	109	33	76
Canada⁽²⁾	118	19	18	9	1	70	13	58
Total Company	408	154	54	20	1	179	46	133

Proved Plus Probable
Reserves
Yemen⁽¹⁾	368	175	41	11	-	141	44	97
Canada⁽²⁾	170	28	27	11	1	104	24	81
Total Company	538	203	67	22	1	244	67	177

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of 1.1630 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

TOTAL FUTURE NET REVENUES
BY PRODUCTION GROUP
AS AT DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

		Yemen	Canada	Total Company
		Future net	Future net	Future net
		Revenue Before	Revenue Before	Revenue Before
		Income Taxes⁽¹⁾	Income Taxes⁽²⁾	Income Taxes⁽¹⁾
		(discounted at	(discounted at	(discounted at
Reserves		15%/year)	15%/year)	15%/year)
Category	Product Group	(US$MM)	(US$MM)	(US$MM)

Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	57.6	6.8	64.4

	Natural Gas (including by-products but excluding solution gas)	-	40.0	40.0


Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-products)	70.8	9.2	80.0


	Natural Gas (including by-products but excluding solution gas)	-	55.0	55.0

Notes:

(1)	In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2005 exchange rates of 1.1630 US $'s/Cdn $'s and do not include the Alberta Royalty Tax Credit (ARTC) in the Before Income Tax values.

Notes to Reserves Data Tables:

1.	Columns may not add due to rounding.

2.	The crude oil, natural gas liquids and natural gas reserve estimates presented in the DeGolyer Reports are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

	"Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

	(a)	gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;

	(b)	drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;

	(c)	acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

	(d)	provide improved recovery systems.

	"Exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

	(a)	costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;

	(b)	costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;

	(c)	dry hole contributions and bottom hole contributions;

	(d)	costs of drilling and equipping exploratory wells; and

	(e)	costs of drilling exploratory type stratigraphic test wells.

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on

analysis of drilling, geological, geophysical and engineering data;
the use of established technology; and
specified economic conditions which are generally accepted as being reasonable.

Reserves are classified according to the degree of certainty associated with the estimates.

(a)	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.

(b)	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.

	Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

	Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

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

	(i)	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.

	(ii)	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.

(d)	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.

	In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

	*Levels of Certainty for Reported Reserves*

	The qualitative certainty levels referred to in the definitions above are applicable to individual reserve 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 are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

	(a)	at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
	(b)	at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

3.	Forecast Prices and Costs

	The forecast cost and price assumptions assume changes in wellhead selling prices and take into account inflation with respect to future operating and capital costs.

	For the Reserves, crude oil and natural gas benchmark reference pricing, as at December 31, 2005, inflation and exchange rates utilized by DeGolyer in the DeGolyer Report, which were DeGolyer's then current forecasts at the date of the DeGolyer Report, were as follows:

	Crude Oil
	WTI Cushing	Edmonton Par		Natural Gas AECO	Natural Gas Liquids			Inflation	Exchange
	Oklahoma	Price 40° API		Spot Gas Price		FOB Edmonton		Rates⁽¹⁾	Rate⁽²⁾
Year	(US$/bbl)	(Cdn$/bbl)		(Cdn$/Mcf)		(Cdn$/bbl)		% Year	(Cdn$/US$)
					Condensate	Butane	Propane
Forecast
2006	58.00	67.16		10.37	68.50	49.02	41.64	0.0	1.1628
2007	56.38	65.26		9.65	66.57	47.64	40.46	2.5	1.1628
2008	52.53	60.78		8.53	62.00	44.37	37.69	2.5	1.1628
2009	51.69	59.80		7.86	60.99	43.65	37.08	2.5	1.1628
2010	52.72	60.99		7.12	62.21	44.53	37.82	2.0	1.1628
2011	53.78	62.21		6.89	63.46	45.42	38.57	2.0	1.1628
Thereafter	+2%/year	+2%/year		+ 1.8%/yr to 17	+2%/year	+2%/year	+2%/year	+2%/year	+0%/year
			+2.0%/yr thereafter

Notes:

	(1)	Inflation rates for forecasting expenditure prices and costs.
	(2)	Exchange rates used to generate the benchmark reference prices in this table.

The weighted average historical price in U.S. $'s realized by the Company in Yemen, for the year ended December 31, 2005 for crude oil was $51.09/bbl.

The weighted average historical prices in Cdn $'s realized by the Company in Canada, for the year ended December 31, 2005, were $8.80/mcf for natural gas, $63.04/bbl for crude oil and $49.01/bbl for natural gas liquids.

4.	Constant Prices and Costs

	In Yemen, a constant price of $56.42/bbl (December 31, 2005 actual prices) was utilized in the constant price case.

	In Canada, constant prices of $52.49/bbl of oil and $8.08/Mcf of natural gas (December 31, 2005 actual prices converted to U.S. $'s at the December 31, 2005 currency rate of 1.1630 US$/Cdn$, adjusted for quality and energy content), were utilized in the constant price case.

5.	Future Development Costs

FUTURE DEVELOPMENT COSTS
TOTAL COMPANY⁽¹⁾AS AT DECEMBER 31, 2005

(US$ millions)	Constant Prices and Costs		Forecast Prices and Costs
		Proved Plus		Proved Plus
	Proved	Probable	Proved	Probable
Year	Reserves	Reserves	Reserves	Reserves
2006	18.9	20.5	18.9	20.5
2007	0.2	0.3	0.2	0.3
2008	0.2	0.2	0.2	0.2
2009	0.1	0.2	0.1	0.2

Total Undiscounted	20.2	21.9	19.8	22.0

Total Discounted at 10%	18.4	20.2	18.4	20.3

Note:

(1) Cdn$'s converted at the December 31, 2005 year end rate of 1.1630 US$/Cdn$.

FUTURE DEVELOPMENT COSTS
YEMEN
AS AT DECEMBER 31, 2005

(US$ millions)	Constant Prices and Costs		Forecast Prices and Costs
		Proved Plus		Proved Plus
	Proved	Probable	Proved	Probable
Year	Reserves	Reserves	Reserves	Reserves
2006	9.6	10.1	9.6	10.1
2007	0.2	0.2	0.2	0.2
2008	0.2	0.2	0.2	0.2
2009	0.1	0.2	0.1	0.2

Total Undiscounted	10.4	11.1	10.4	11.2

Total Discounted at 10%	9.5	10.1	9.5	10.1

FUTURE DEVELOPMENT COSTS
CANADA⁽¹⁾AS AT DECEMBER 31, 2005

(US$ millions)	Constant Prices and Costs		Forecast Prices and Costs
		Proved Plus		Proved Plus
	Proved	Probable	Proved	Probable
Year	Reserves	Reserves	Reserves	Reserves
2006	9.4	10.4	9.4	10.4
2007	-	0.1	-	0.1
2008	-	-	-	-
2009	-	-	-	-

Total Undiscounted	9.8	10.8	9.4	10.8

Total Discounted at 10%	8.9	10.1	8.9	10.2

Note:

(1)

Cdn$'s converted at the December 31, 2005 year-end rate of 1.1630 US$/Cdn$.

The Company expects to fund the future development costs noted above through the use of working capital, cash flow, debt and equity financing as required.

6.	The Alberta royalty tax credit ("ARTC") is included in the cumulative cash flow amounts. ARTC is based on the program announced November 1989 by the Alberta government with modifications effective January 1, 1995. The estimated Net Present Value of the Alberta Royalty Tax Credit for both the Constant Price and Forecast Price cases, is presented as a separate table for the respective price cases.

7.	In Yemen, estimated future abandonment and reclamations costs related to properties evaluated have not been taken into account by DeGolyer in determining the aggregate future net revenue therefrom. Under the terms of the production sharing agreements, ownership in the facilities and wells is transferred to the Government of Yemen through cost recovery. Therefore the future abandonment and reclamation costs have been assessed a zero value.

	In Canada, estimated future abandonment and reclamation costs related to a property have been taken into account by DeGolyer in determining reserves that should be attributed to a property and in determining the aggregate future net revenue therefrom, there was deducted the reasonable estimated future well abandonment costs. No allowance was made, however, for reclamation of wellsites or the abandonment and reclamation of any facilities.

8.	Both the constant and forecast price and cost assumptions assume the continuance of current laws and regulations.

9.	The extent and character of all factual data supplied to DeGolyer was accepted by DeGolyer as represented. No field inspections were conducted by DeGolyer.

Reconciliations of Changes in Reserves and Future Net Revenue

RECONCILIATION OF NET RESERVES
(AFTER ROYALTIES/BEFORE TAXES)
BY PRINCIPAL PRODUCT TYPE
COMPANY
AS AT DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

							ASSOCIATED & NON-
	LIGHT & MEDIUM OIL						ASSOCIATED GAS						NATURAL GAS LIQUIDS
					Net						Net						Net
					Proved						Proved						Proved
	Net		Net		Plus		Net		Net		Plus		Net		Net		Plus
	Proved		Probable		Probable		Proved		Probable		Probable		Proved		Probable		Probable
FACTORS	(MBbl)		(MBbl)		(MBbl)		(MMcf)		(MMcf)		(MMcf)		(MBbl)		(MBbl)		(MBbl)
December 31, 2004	2,962		1,582		4,545		8,525		3,713		12,239		245		87		331
Extensions
Improved recovery
Technical Revisions	287		(900	)	(613	)	(3,728	)	(323	)	(4,051	)	(115	)	(24	)	(139	)
Discoveries	1066		175		1,241		5,437		1,273		6,710		87		28		115
Acquisitions
Dispositions
Economic Factors	(95	)	(68	)	(163	)	(23	)	(14	)	(37	)	(1	)	(1	)	(2
Production	(968	)	-		(968	)	(1,106	)	-		(1,106	)	(33	)	-		(33	)
December 31, 2005	3,252		789		4,042		9,105		4,649		13,754		183		90		273

RECONCILIATION OF NET RESERVES
(AFTER ROYALTIES/BEFORE TAXES)
BY PRINCIPAL PRODUCT TYPE
YEMEN
AS AT DECEMBER 31, 2005
(FORECAST PRICES AND COSTS)

							ASSOCIATED & NON-
	LIGHT & MEDIUM OIL						ASSOCIATED GAS			NATURAL GAS LIQUIDS
					Net				Net			Net
					Proved				Proved			Proved
	Net		Net		Plus		Net	Net	Plus	Net	Net	Plus
	Proved		Probable		Probable		Proved	Probable	Probable	Proved	Probable	Probable
FACTORS	(MBbl)		(MBbl)		(MBbl)		(MMcf)	(MMcf)	(MMcf)	(MBbl)	(MBbl)	(MBbl)
December 31, 2004	2,884		1,557		4,441		-	-	-	-	-	-
Extensions
Improved recovery
Technical Revisions	238		(918	)	(680	)
Discoveries	836		137		973
Acquisitions
Dispositions
Economic Factors	(95	)	(68	)	(163	)
Production	(935	)	-		(935	)
December 31, 2005	2,927		709		3,636		-	-	-	-	-	-

RECONCILIATION OF NET RESERVES
(AFTER ROYALTIES/BEFORE TAXES)
BY PRINCIPAL PRODUCT TYPE
CANADA
AS AT DECEMBER 31, 2005
(FORECAST PRICES AND COST)

						ASSOCIATED & NON-
	LIGHT & MEDIUM OIL					ASSOCIATED GAS						NATURAL GAS LIQUIDS
				Net						Net						Net
				Proved						Proved						Proved
	Net		Net	Plus		Net		Net		Plus		Net		Net		Plus
	Proved		Probable	Probable		Proved		Probable		Probable		Proved		Probable		Probable
FACTORS	(MBbl)		(MBbl)	(MBbl)		(MMcf)		(MMcf)		(MMcf)		(MBbl)		(MBbl)		(MBbl)
December 31, 2004	79		25	104		8,525		3,713		12,239		245		87		331

Extensions
Improved recovery
Technical Revisions	49		19	68		(3,728	)	(323	)	(4,051	)	(115	)	(24	)	(139	)
Discoveries	230		38	268		5,437		1,273		6,710		87		28		115
Acquisitions
Dispositions
Economic Factors	-		-	-		(23	)	(14	)	(37	)	(1	)	(1	)	(2	)
Production	(33	)	-	(33	)	(1,106	)	-		(1,106	)	(33	)	-		(33	)
December 31, 2005	325		82	407		9,105		(4,649	)	13,754		183		90		273

RECONCILIATION OF CHANGES IN
NET PRESENT VALUES OF FUTURE NET REVENUE
DISCOUNTED AT 10% PER YEAR PROVED RESERVES
(CONSTANT PRICES AND COSTS)

	Canada⁽¹⁾		Yemen		Total⁽¹⁾
	2005		2005		2005
US$'s	($M)		($M)		($M)
Estimated Future Net Revenue at beginning of year	31,207		41,644		72,851
Sales and transfers of oil and gas produced, net of production costs and	(9,493	)	(31,284	)	(40,777	)
royalties
Net change in prices, production costs and royalties related to future	12,961		24,578		37,539
production
Changes in previously estimated development costs incurred during the	11,144		(13,684	)	(2,540	)
period
Changes in estimated future development costs	(11,423	)	10,016		(1,406	)
Extensions and improved recovery	-				-
Discoveries	26,724		19,582		46,306
Acquisitions of reserves	-		-		-
Dispositions of reserves	-		-		-
Net change resulting from revisions in quantity estimates	(19,820	)	8,897		(10,923	)
Accretion of discount	3,206		3,586		6,792
Net change in income taxes	(3,143	)	-		(3,143	)
Other (value of production in disposed and acquired properties, changes in
timing of future production)	1,071		5,320		6,391

Estimated Future Net Revenue at end of year	42,434		68,655		111,089

Note:

(1)

In Canada values were converted to US currency using the following currency exchange rates: December 31, 2004 at 1.2020 $US/$Cdn, December 31, 2005 at 1.1630 $US/$Cdn. Sale and transfers of oil and gas produced, net of production costs and royalties at Booked values for the year end at the 2005 year average exchange rate of 1.2117 $US/$Cdn for all other changes. The estimated Future Net Revenues include ARTC.

Additional Information Relating to Reserves Data

Undeveloped Reserves

The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by product type, attributed to the Company in the most recent five financial years and, in the aggregate, before that time, as applicable.

Proved Undeveloped Reserves

	Light and Medium Oil		Natural Gas		Natural Gas Liquids
Year	(MBbl)		(MMcf)		(MBbl)
	First	Cumulative at	First	Cumulative	First	Cumulative
	Attributed	Year End	Attributed	at Year End	Attributed	at Year End

2003⁽¹⁾	—	—	1,422	1,422	58	58
2004⁽²⁾	1,554	1,554	1,758	2,949	51	100
2005	1,655	1,655	2,570	2,869	7	20

Notes:

(1)	Prior to 2003, the Company did not have any proved undeveloped reserves. All the Proved Undeveloped reserves assigned in 2003 were in Canada, and relate to the Wabamum formation in the Nevis area. Proved reserves were assigned to 320 acres of the 640 acres gas spacing unit/ well. The remaining 320 acres/well were assigned Proved Undeveloped reserves.
(2)	In 2004, all the Proved Undeveloped light oil was assigned to Yemen, with four horizontal development wells in the An Nagyah field in Block S-1 and one development vertical well in the Tasour field in Block 32. All the Proved Undeveloped gas and liquid reserves were assigned to Canada. In the Nevis area, proved undeveloped reserves were assigned to one additional Wabamum down space (320 acres/well) and one well to accelerate production from a well which encountered four gas zones.
(3)	In 2005, 91% of the Proved Undeveloped light oil was assigned to Yemen with five horizontal development wells planned in the An Nagyah field (3 wells in Lam A and 2 wells in Lam B), the balance was assigned to un-drilled Wabamum oil spacing units at Nevis in Canada. All the Proved Undeveloped gas and liquids reserves were assigned to Canada. The majority of the gas was assigned to Horseshoe Canyon coal bed methane wells in the Nevis and Morningside areas, assuming 160 acres/well.

Probable Undeveloped Reserves

	Light and Medium Oil		Natural Gas		Natural Gas Liquids
Year	(MBbl)		(MMcf)		(MBbl)
	First	Cumulative	First	Cumulative	First	Cumulative at
	Attributed	at Year End	Attributed	at Year End	Attributed	Year End

2001	—	—	—	271	—	—
2002	—	—	—	224	—	—
2003⁽¹⁾	2,342	2,342	1,328	1,629	55	55
2004⁽²⁾	1,111	1,111	256	577	—	13
2005	365	365	593	698	1	5

Notes:

(1)	In 2003, Probable Undeveloped Reserves were assigned in Yemen and Canada. The light oil reserves were assigned to a portion of the mapped An Nagyah light oil discovery on Block S-1 in Yemen. The Natural Gas reserves and associated liquids were assigned in Canada, and generally related to the Wabamum formation in the Nevis area. Proved reserves were assigned to 320 acres of the 640 acres gas spacing unit/ well. The remaining 320 acres/well were assigned Proved Undeveloped reserves.

(2)	In 2004, Probable Undeveloped reserves were assigned in Yemen and Canada. All the light oil reserves were assigned in Yemen, relating to; 2 planned wells in the Tasour field on Block 32 and performance associated with Proved Undeveloped wells planned in the Tasour field (1 well) and the An Nagyah field (4 horizontal wells). All the Probable Undeveloped natural gas and natural gas liquids were assigned in Canada and relate to additional performance from planned Proved Undeveloped wells in the Nevis area (4 Wabamum gas wells and 1 Manville gas well).

(3)	In 2005, 97% of Probable Undeveloped light oil reserves were assigned to Yemen consisting of one vertical well at Tasour and a probable component assigned to the 5 Horizontal (Proved Undeveloped) wells planned for An Nagyah. All the Probable Undeveloped gas and liquids reserves were assigned to Canada and primarily relate to additional performance from planned coal bed methane wells ( Proved Undeveloped) in the Nevis and Morningside areas.

Other Oil and Gas Information

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Company has a working interest as at December 31, 2005. All of the Company's wells are located onshore.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net

Yemen	25	5.0	3	0.6	0	0	3	0.8
Canada, Alberta	10	7.4	9	7.4	19	13.6	27	19.9
Total	35	12.4	12	8.0	19	13.6	30	20.7

Properties with no Attributable Reserves

The following table sets out the Company's developed and undeveloped land holdings as at December 31, 2005.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net

Yemen	20,580	4,419	860,424	237,277	881,004	241,426
Canada, Alberta	24,109	15,620	51,625	33,306	75,734	48,926
Egypt	-	-	7,500,000	3,750,000	7,500,000	3,750,000
Total	44,689	19,770	8,412,049	4,020,583	8,456,738	4,040,353

Of the Company's undeveloped land, the rights to explore, develop and exploit 3,262gross (1,737 net) acres may expire in Canada by December 31, 2006. The Company does not have any work commitments associated with its undeveloped lands in Blocks 32 and S-1in Yemen or Canada. In Yemen, the Company has a work commitment of $4 million in Phase 1 (30 months expiring January 12^th, 2008) In Egypt, the Company has work commitments of $2 million in period 1 (two years expiring July 16, 2006) and $4 million in period 2 (three years expiring July 16, 2009). The Company has exceeded the period 1 work commitment in Egypt and will elect to enter perod 2 during

2006. At the end of period 1, the Company is required to relinquish 25% of the Block to the government, representing approximately 1,875,000 gross (937,500 net) acres of undeveloped land.

Forward Contracts

The Company's contracts to sell crude oil or natural gas are at prevailing market pricing, except as follows:

In September 2005, the Company entered into a crude oil costless collar for 15,000 barrels per month from January 1, 2006 to December 31, 2006. The transaction consisted of the purchase of a $50.00 per barrel dated Brent put (floor) and a $77.93 per barrel dated Brent call (ceiling).

Additional Information Concerning Abandonment and Reclamation Costs

In Canada, future well abandonment costs net of salvage were included in the DeGolyer reserves evaluation presented herein. Cost in US $'s to abandon approximately 58 (42.4 net) wells totalled $1,237 thousand undiscounted, or $631 thousand discounted at 10%, are included in the estimate of future net revenue from total proved plus probable reserves using constant pricing and cost. Approximately $434 thousand undiscounted, or $389 thousand discounted at 10%, are scheduled during the next three years (2006-2008).

Tax Horizon

In 2005, the Company did not pay any income taxes in Canada.

TransGlobe does not expect to pay income taxes in Canada in 2006 assuming the Company incurs further Canadian exploration expense and Canadian development expense and utilizes such tax pools and carry forward tax pools of Cdn $39.8 million available to protect future revenue. TransGlobe expects to be taxable in Canada in 2007.

Capital Expenditures

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

	Yemen	Egypt	Canada	Total
($ thousands)
Property acquisition costs
Proved properties	-	-	149	149
Undeveloped properties	495	-	1,524	2,019
Exploration costs	4,758	474	5,249	10,481
Development costs	11,856	-	5,798	17,654
Corporate and other	830	1,052	469	2,351
Total	17,939	1,526	13,189	32,654

Production Estimates

The following table sets out the volume of the Company's daily production (working interest before royalties) estimated for the year ending December 31, 2006 which is reflected in the estimate of future net revenue disclosed in the Forecast Prices and Costs and Constant Prices and Costs tables contained under " - Disclosure of Reserves Data".

	Yemen	Yemen
	Block 32	Block S-1	Canada		Canada	Total
	Light and	Light and	Light and	Canada	Natural Gas	Company
	Medium Oil	Medium Oil	Medium Oil	Natural Gas	Liquids	BOE
	Gross	Gross	Gross	Gross	Gross	Gross
	(bbls/d)	(bbls/d)	(bbls/d)	(Mcf/d)	(bbls/d)	(BOE/d)
Proved Producing	1,082	2,775	68	3,770	111	4,665
Proved Developed
Non-Producing	312	74	63	2,786	72	986
Proved Undeveloped	0	88	24	721	8	240
Total Proved	1,395	2,937	155	7,277	191	5,890
Total Probable	68	63	11	1,452	28	413
Total Proved Plus Probable	1,463	3,000	166	8,729	219	6,303

Exploration and Development Activities

The following tables set forth the gross and net exploratory and development wells which TransGlobe drilled during the year ended December 31, 2005:

*Yemen:*	Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	-	-	-	-	-	-
Crude Oil	1	6	7	0.3	1.2	1.5
Dry and Abandoned⁽¹⁾	5	1	6	1.0	0.1	1.1
Total	6	7	13	1.3	1.3	2.6


*Canada:*	Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	6	10	16	6.0	5.6	11.6
Crude Oil	3	4	7	3.0	3.5	6.5
Dry and Abandoned⁽¹⁾	3	-	3	2.5	-	2.5
Total	12	14	26	11.5	9.1	20.6

Note:

(1)

"Dry well" means a well which is not a productive well or a service well. A productive well is a well which is capable of producing oil and gas in commercial quantities or in quantities considered by the operator to be sufficient to justify the costs required to complete, equip and produce the well. A service well means a well such as a water or gas-injection, water-source or water-disposal well. Such wells do not have marketable reserves of crude oil or natural gas attributed to them but are essential to the production of the crude oil and natural gas reserves.

Production History

The following table summarizes certain information in respect of sales volumes, product prices received and operating expenses made by the Company (and its subsidiaries) for the periods indicated below:

	2005
		Quarter Ended
	Mar. 31	Jun. 30	Sep. 30	Dec. 31
*Average Daily Sales Volumes*
Yemen
Light and Medium Crude Oil (bbls/d)	4,165	3,669	4,458	4,071
Canada
Light and Medium Crude Oil (bbls/d)	105	91	108	94
Gas (Mcf/d)	3,748	3,243	4,749	3,769
NGL (bbls/d)	91	75	176	141
Combined (BOE/d)	4,985	4,375	5,533	4,985

*Average Price Received*
Yemen
Light and Medium Crude Oil ($/bbl)	43.21	46.17	59.32	54.37
Canada
Light and Medium Crude Oil ($/bbl)	44.83	48.53	59.38	54.82
Gas ($/Mcf)	5.79	6.22	7.35	9.49
NGL ($/bbl)	33.53	37.31	39.78	47.28
Combined ($/BOE)	42.04	44.99	56.57	54.58

*Royalties*
Yemen
Light and Medium Crude Oil ($/bbl)	12.91	17.24	21.62	25.24
Canada
Light and Medium Crude Oil ($/bbl)	3.29	3.55	4.75	3.98
Gas ($/Mcf)	1.17	0.97	1.43	1.95
NGL ($/bbl)	6.57	8.94	6.97	13.37
Combined ($/BOE)	11.85	15.41	18.96	22.77

*Operating Expenses*
Yemen
Light and Medium Crude Oil ($/bbls)	5.47	5.70	5.15	5.75
Canada
Light and Medium Crude Oil ($/bbls)	13.32	13.84	13.97	15.88
Gas ($/Mcf)	0.81	1.20	1.22	1.02
NGL ($/bbls)	-	-	-	-
Combined ($/BOE)	5.46	5.96	5.47	5.83

*Netback Received*
Yemen
Light and Medium Crude Oil ($/bbl)	24.82	23.22	32.55	23.38
Canada
Light and Medium Crude Oil ($/bbl)	28.22	31.14	40.66	34.96
Gas ($/Mcf)	3.81	4.05	4.70	6.52
NGL ($/bbl)	26.96	28.37	32.81	33.91
Combined ($/boe)	24.73	23.62	32.14	25.98

The following table indicates the Company's average daily sales volumes from its important fields for the year ended December 31, 2005.

	Light and Medium Crude	Gas	NGL's	boe
	(bbls/d)	(Mcf/d)	(bbls/d)	(boe/d)

Yemen
Block 32	1,926	-	-	1,926
Block S-1	2,166	-	-	2,166
Block 72	-	-	-	-
Egypt	-	-	-	-
Canada	99	3,880	121	867

Total	4,191	3,880	121	4,959

DIVIDEND POLICY

The Company has not paid any dividends to date on its Common Shares. The board of directors of the Company will determine the timing, payment and amount of dividends, if any, that may be paid by the Company from time to time based upon, among other things, the cash flow, results of operations and financial condition of the Company, the need for funds to finance ongoing operations and other business considerations as the board of directors considers relevant.

DESCRIPTION OF SHARE CAPITAL

We are authorized to issue an unlimited number of common shares ("Common Shares") and an unlimited number of preferred shares ("Preferred Shares"). As at March 8, 2006, there were 58,522,439 Common Shares issued and outstanding. In addition, as at such date, there were an aggregate of 5,852,244 Common Shares reserved for issuance upon the exercise of the Company's options.

The following is a summary of the rights, privileges, restrictions and conditions attaching to each class of shares of the Company. Documents affecting the rights of securityholders, including the Company's articles, have been filed in accordance with NI 51-102 and are available on the Company's SEDAR profile at www.sedar.com.

Common Shares

Each Common Share entitles its holder to receive notice of and to attend all meetings of the shareholders of the Company and to one vote at such meetings. The holders of Common Shares are, at the discretion of the Board of Directors of the Company and subject to applicable legal restrictions, entitled to receive any dividends declared by the Board of Directors on the Common Shares, subject to prior satisfaction of all preferential rights attributed to shares of any class ranking in priority to the Common Shares. The holders of Common Shares are entitled to share equally in any distribution of the assets of the Company upon the liquidation, dissolution, bankruptcy or winding-up of the Company or other distribution of its assets among its shareholders for the purpose of winding-up its affairs.

Preferred Shares

In addition to the Common Shares, the Articles of Arrangement of the Company authorize the issuance of an unlimited number of Preferred Shares, issuable in series. Subject to the provisions of the Alberta Business Corporations Act, the Board is authorized to fix, before the issue thereof, the designation, rights, privileges, restrictions and condition attaching thereto.

Rights Plan

On April 16, 2003, the Company entered into a shareholder protection rights plan agreement (the "Rights Plan") with Computershare Trust Company of Canada, as rights agent, which was approved by TransGlobe's shareholders on May 29, 2003 at the 2003 annual general and special meeting of shareholders. The Rights Plan generally provides that upon 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.

MARKET FOR SECURITIES

TransGlobe's Common Shares are listed and posted on the TSX and the AMEX under the trading symbols "TGL" and "TGA", respectively.

The following table sets out the monthly high and low closing prices and the total monthly trading volumes on the TSX for the indicated periods:

(Cdn dollars, except volumes)	High	Low	Volume
2005
January	8.15	5.60	2,578,684
February	12.04	7.60	4,310,305
March	9.95	6.60	4,277,842
April	8.14	5.91	1,807,037
May	7.03	5.40	1,106,193
June	9.09	6.55	1,954,774
July	8.94	7.12	1,498,474
August	8.25	7.06	1,674,197
September	7.95	6.96	1,219,616
October	7.40	5.20	1,400,034
November	6.83	5.80	1,033,674
December	6.76	5.73	1,824,280

The following table sets out the monthly high and low closing prices and the total monthly trading volumes on the AMEX for the indicated periods:

(U.S. dollars, except volumes)	High	Low	Volume
2005
January	6.48	4.50	9,782,400
February	9.88	6.18	16,004,000
March	7.98	5.30	18,823,100
April	6.72	4.75	11,542,100
May	5.72	4.22	7,171,900
June	7.35	5.15	10,414,300
July	7.15	5.85	8,235,600
August	6.93	5.85	8,688,600
September	6.95	5.88	7,629,500
October	6.33	3.88	8,415,300
November	5.79	4.85	6,185,900
December	5.89	4.98	6,862,100

ESCROWED SECURITIES

As at the date hereof, none of the Company's securities are subject to escrow.

DIRECTORS AND OFFICERS

The name and place of residence of each director and officer, the offices held by each in the Company, the principal occupation of each director and officer, the period served as director or officer and the number of securities of the Company owned by such individuals as at March 8, 2006 is as follows:

			Number of
			Common Shares
		Year Became	Beneficially
Name and Place of		Director or	Owned or	Principal Occupation and Positions
Residence	Position Held	Officer	Controlled	for the Past Five Years

Robert A. Halpin^(1)(2)(4) Alberta, Canada	Chairman of the Board and Director	1997	514,000⁽⁵⁾ (0.88%)	Retired Petroleum Engineer, President and owner, Halpin Energy Resources Ltd., which provides consulting services on international energy projects.




Ross G. Clarkson Alberta, Canada	President, Chief Executive Officer and Director	1995	2,078,772 ⁽⁶⁾ (3.55%)	President and Chief Executive Officer of the Company since December 4, 1996, with over 30 years' oil and gas industry experience as a senior geological advisor.




Lloyd W. Herrick Alberta, Canada	Vice-President, Chief Operating Officer and Director	1999	563,100 ⁽⁷⁾ (0.96%)	Vice-President and Chief Operating officer of the Company since April 28, 1999, with over 30 years' experience in both domestic and international oil and gas exploration and development.





Erwin L. Noyes^(2)(3)(4) British Columbia, Canada	Director	1995	318,347 ⁽⁸⁾ (0.54%)	Retired since July 31, 2000; formerly Vice- President, International Operations of the Company, with over 30 years' experience in the oil and gas industry.




Geoffrey C. Chase^(1)(3)(4) Alberta, Canada	Director	2000	135,000 ⁽⁹⁾ (0.23%)	Retired Senior Vice-President, Business Development, with Ranger Oil, with over 35 years' experience in the oil and gas industry.



Fred J. Dyment^(1)(2)(3) Alberta, Canada	Director	2004	nil ⁽¹⁰⁾	Chartered accountant with over 30 years' experience in the oil and gas industry. Previously President and Chief Executive Officer, Maxx Petroleum Company (2000- 2001). Prior thereto Controller, Vice-President, Finance and then President and Chief Executive Officer of Ranger Oil Limited from 1978-2000.








David C. Ferguson Alberta, Canada	Vice-President, Finance, Chief Financial Officer and Secretary	2001	219,000⁽¹¹⁾ (0.37%)	Chartered accountant with over 22 years' experience in the oil and gas industry. Previously Chief Financial Officer with Northstar Drilling Systems Inc. (1999-2000), Chief Financial Officer and a director of Myriad Energy Corporation (1998-1999).






Edward Bell Alberta, Canada	Vice-President, Exploration	2004	36,000⁽¹²⁾ (0.06%)	Professional Geoscientist with 36 years of experience in the petroleum industry. Prior positions with Nexen as General Manager Business Development and Occidental Petroleum as Technical Advisor.

Notes:

(1)	Members of the Company's Audit Committee.
(2)	Members of the Company's Compensation Committee.
(3)	Members of the Company's Governance and Nominating Committee.
(4)	Members of the Company's Reserves Committee.
(5)	Mr. Halpin also holds incentive stock options to purchase 254,000 Common Shares consisting of: options to purchase 120,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007, to purchase 80,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009 and to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.
(6)	Mr. Clarkson also holds incentive stock options to purchase 436,000 Common Shares consisting of: options to purchase 250,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007, to purchase 120,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009 and to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.
(7)	Mr. Herrick also holds incentive stock options to purchase 416,000 Common Shares consisting of: options to purchase 250,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007, to purchase 100,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009 and to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.
(8)	Mr. Noyes also holds incentive stock options to purchase 114,000 Common Shares consisting of: options to purchase 60,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009 and to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.
(9)	Mr. Chase also holds incentive stock options to purchase 234,000 Common Shares consisting of: options to purchase 120,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007, to purchase 60,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009 and to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.
(10)	Mr. Dyment holds incentive stock options to purchase 144,000 Common Shares consisting of: options to purchase 90,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009 and to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.
(11)	Mr. Ferguson also holds incentive stock options to purchase 356,000 Common Shares consisting of: options to purchase 200,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007 and to purchase 90,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009 and to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.
(12)	Mr. Bell also holds incentive stock options to purchase 246,000 Common Shares consisting of: options to purchase 150,000 Common Shares at Cdn$3.40 per share expiring January 12, 2009, to purchase 30,000 Common Shares at Cdn$7.74 per share expiring March 17, 2010 and to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

No director or executive officer of the Company, or a shareholder holding a sufficient number of securities to materially affect control of the Company has, within the last ten years prior to the date of this document, been a director or executive officer of any company that, while such person was acting in that capacity, (i) was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation for a period of more than 30 consecutive days; or (ii) was subject to an event that resulted, after the director or executive officer ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days; or (iii) within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver-manager or trustee appointed to hold its assets.

No director or executive officer of the Company, or a shareholder holding a sufficient number of securities to materially affect control of the Company has, within the 10 years before the date of this document, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver-manager or trustee appointed to hold its assets.

Conflicts of Interest

Directors and officers of the Company may, from time to time, be involved with the business and operations of other oil and gas issuers, in which case a conflict may arise. See "Risk Factors".

HUMAN RESOURCES

The Company currently employs 26 full-time employees and 9 part-time consultants. The Company intends to add additional professional and administrative staff as the needs arise.

INTEREST OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by the Company during, or related to, the Company's most recently completed financial year other than DeGolyer and MacNaughton Canada Limited, the Company's independent engineering evaluator and Deloitte & Touche LLP, the Company's auditors. As at the date hereof, to the knowledge of management of the Company, none of the aforementioned persons or companies, or principals thereof, had any registered or beneficial interests, direct or indirect, in any securities or other property of the Corporation or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them.

In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of the Company or any associates or affiliates of the Company.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings material to the Company to which the Company is a party or in respect of which any of its respective properties are subject, nor are there any such proceedings known to be contemplated.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of any directors or executive officers of the Company, any shareholder who beneficially owns more than 10% of the outstanding Common Shares or who exercises control or direction over more than 10% of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or will materially affect the Company.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Company are Deloitte & Touche LLP, Chartered Accountants, Suite 3000, 700 – 2nd Street SW, Calgary, Alberta T2P 0S7.

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

MATERIAL CONTRACTS

Other than discussed herein, there are no material contracts, other than the contracts entered into in the ordinary course of business, that are material to the Company that were entered into within the most recently completed financial year, or before the most recently completed financial year but are still in effect.

AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

The audit committee of the Company (the "Audit Committee") is comprised of Messrs. Robert Halpin, Geoffrey Chase and Fred Dyment. The following chart sets out the assessment of each Audit Committee member's independence, financial literacy and relevant educational background and experience supporting such financial literacy.

Name and Place		Financially
of Residence	Independent	Literate	Relevant Education and Experience


Robert A. Halpin Alberta, Canada	Yes	Yes	Mr. Halpin received a B.Sc. from Queen's University, Ontario in 1957 and is a P.Eng. in the Province of Alberta. He has over 45 years of business, executive, international management and director experience at several major and independent international corporations where he has been involved in various aspects of financial planning, budgeting and operations.







Geoffrey C. Chase Alberta, Canada	Yes	Yes	Mr. Chase received a B.Sc. in Applied Science from Queen's University, Ontario and is a P.Eng. in the Province of Alberta. He has over 35 years of business, executive and international management experience with a major and later a mid-size public petroleum corporation. His activities have involved various aspects of financial planning, budgeting and operations.







Fred J. Dyment Alberta, Canada	Yes	Yes	Mr. Dyment received a Chartered Accountant designation from the Province of Ontario in 1972 and is a member of the Alberta Institute of Chartered Accountants. He has over 30 years of financial, business, executive, international management experience at several mid-size public corporations where he served as President, CEO, CFO and director. Currently, Mr. Dyment sits as a director on several other public companies.

Pre-Approval of Policies and Procedures

All non-audit services with our auditors, Deloitte & Touche LLP, require pre-approval by the audit committee.

Audit Committee Charter

The full text of the Company's audit committee charter is included in Appendix C to this Annual Information Form.

Audit Service Fees

The following table sets forth the audit service fees paid by us to Deloitte & Touche LLP for the periods indicated:

	Fiscal Year
	Ended	Aggregate
Type of Fees	December 31	Fees Billed	Nature of Services Performed


Audit Fees	2005	Cdn$74,360	2005 corporate year-end audit and SOX audit planning
	2004	Cdn$73,435	2004 corporate year-end audit

Audit – Related Fees	2005	Cdn$29,537	2005 Quarterly reviews and review of SEC letter
	2004	Cdn$19,080	2004 Quarterly reviews, S-8 consent letters and review of
			Alberta Security Commission letter

Tax Fees	2005	Cdn$5,622	2004 corporate tax returns and tax compliance
	2004	Cdn$10,282	2003 corporate tax returns and tax compliance

All other fees	2005	Cdn$ -	-
	2004	Cdn$30,210	Prospectus

RISK FACTORS

General Conditions Relating to Oil and Gas Exploration and Production Operations

The Company's operations are subject to all the risks normally incident to the exploration for and production of oil and natural gas including geological risks, operating risks, political risks, development risks, marketing risks, and logistical risks of operating in Canada, Yemen and Egypt.

Industry Risks

The Company is subject to normal industry risks due to the relatively small size of the Company, its level of cash flow, and the nature of the Company's involvement in the exploration for, and the acquisition, development and production of, oil and natural gas. Exploration for oil and natural gas involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that further commercial quantities of oil and natural gas will be discovered by the Company.

The Company's operations are subject to the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature decline of reservoirs, invasion of water into producing formations, blow-outs, cratering, fires and oil spills, all of which could result in personal injuries, loss of life and damage to the property of the Company and others. Although the Company maintains insurance, in amounts and coverages which it considers adequate, in accordance with customary industry practice, the Company is not fully insured against all of these risks, nor are all such risks insurable, and, as a result, liability of the Company arising from these risks could have a material adverse effect upon its financial condition.

The operations and earnings of the Company may be affected from time to time in varying degrees by political developments and laws and regulations, such as forced divestiture of assets, restrictions on production, imports and exports; price controls, tax increases and retroactive tax claims, expropriations of property; and cancellation of contract rights. Both the likelihood of such occurrences and their overall effect upon the Company can vary greatly and are not predictable.

The marketability and price of oil and natural gas which may be acquired or discovered by the Company may be affected by numerous factors beyond the control of the Company. The Company may be affected by the differential between the price paid by refiners for light, quality oil and various grades of oil produced by the Company. The Company is subject to market fluctuations in the prices of oil and natural gas, deliverability uncertainties related to the proximity of its reserves to pipeline and processing facilities and extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business. The Company's operations will be further affected by the remoteness of, and restrictions on access to, certain properties as well as climatic conditions. The Company is also subject to compliance with federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. The Company is not aware of present material liability related to environmental matters. However, it may, in the future, be subject to liability for environmental offences of which it is presently unaware. Additionally, the potential impact on the Company's operations and business of the Kyoto Protocol which has now been ratified by Canada, with respect to instituting reductions of greenhouse gases is difficult to quantify at this time as specific measures for meeting Canada's commitments have not been developed.

Exploration and Development

The Company's participation in Block 32, Block 72 and Block S-1 in Yemen and the Nuqra Block 1 in Egypt represent major undertakings. The exploration programs in Yemen and Egypt are high-risk ventures with uncertain prospects for ongoing success.

The operations and earnings of the Company and its subsidiaries are also affected by local, regional and global events or conditions that affect supply and demand for oil and natural gas. These events or conditions are generally not predictable and include, among other things, the development of new supply sources; supply disruptions;

weather; international political events; technological advances; and the competitiveness of alternative energy sources or product substitutes.

Competition

The Company encounters strong competition from other independent operators and from major oil companies in acquiring properties suitable for development, in contracting for drilling equipment, production equipment and in securing trained personnel. Many of these competitors have financial resources and staffs substantially larger than those available to the Company. The availability of a ready market for oil and gas discovered by the Company depends on numerous factors beyond its control, including the extent of production and imports of oil and gas, the demand for its products, the proximity and capacity of natural gas pipelines and the effect of provincial, state or federal regulations.

Title to Properties

The Company's interests in the Canadian producing properties and non-producing properties are in the form of direct or indirect interests in leases. Such properties are subject to customary royalty interests generally contracted for in connection with the acquisition of properties, liens incident to operating agreements, liens for current taxes and other burdens and mineral encumbrances and restrictions. The Company believes that none of these burdens materially interferes with the use of such properties in the operation of the Company's business.

Interests in Properties

The Company participates, in Canada, Egypt and Yemen, with industry partners with access to greater resources from which to meet their joint venture capital commitments. Should the Company be unable to meet its commitments, the joint venture partners may assume some or all of the Company's deficiency and thereby assume a pro-rata portion of the Company's interest in production from the joint venture lands. The Company is not a majority interest owner in all of its properties and does not have sole control over the future course of development in those properties.

Government Regulation

In the areas where the Company conducts activities there are statutory laws and regulations governing the activities of oil and gas companies. These laws and regulations allow administrative agencies to govern the activities of oil companies in the development, production and sale of both oil and gas. Changes in these laws and regulations may substantially increase or decrease the costs of conducting any exploration or development project. The Company believes that its operations comply with all applicable legislation and regulations and that the existence of such regulations have no more restrictive effect on the Company's method of operations than on similar companies in the industry.

Political Risks Relating to Yemen and Egypt

Beyond the risks inherent in the oil and gas industry, the Company is subject to additional risks resulting from doing business in Yemen and Egypt. While the Company has attempted to reduce many of these risks through agreements with the Governments of Yemen, Egypt and others, no assurance can be given that such risks have been mitigated. These risks can involve matters arising out of the evolving laws and policies of Yemen or Egypt, the imposition of special taxes or similar charges, oil export or pipeline restrictions, foreign exchange fluctuations and currency controls, the unenforceability of contractual rights or the taking of property without fair compensation, restrictions on the use of expatriates in the operations and other matters.

There can be no assurance that the agreements entered into with the Government of Yemen and the Government of Egypt and others are enforceable or binding in accordance with TransGlobe's understanding of their terms or that if breached, the Company would be able to find a remedy. The Company bears the risk that a change of government could occur and a new government may void the agreements, laws and regulations that the Company is relying on. Operations in Yemen and Egypt are subject to risks due to the harsh climate, difficult topography and the potential for social, political, economic, legal and financial instability.

Reliance Upon Officers

The Company is largely dependent upon the personal efforts and abilities of its corporate officers. The loss or unavailability to the Company of these individuals may have a material adverse effect upon the Company's business, especially in Yemen and Egypt.

Multi-jurisdictional Legal Risks

The Company is incorporated under the laws of the Province of Alberta, Canada, and all of the Company's directors and all of its officers are residents of Canada. Consequently, it may be difficult for United States investors to effect service of process within the United States upon the Company or upon those directors or officers, who are not residents of the United States, or to realize in the United States upon judgements of United States courts predicated upon civil liabilities under the Securities Exchange Act of 1934, as amended (United States). Furthermore, it may be difficult for investors to enforce judgements of the U.S. courts based on civil liability provisions of the U.S. federal securities laws in a Canadian court against the Company or any of the Company's non-U.S. resident executive officers or directors. There is substantial doubt whether an original lawsuit could be brought successfully in Canada against any of such persons or the Company predicated solely upon such civil liabilities.

Reserve Information

The reserve and recovery information contained in the DeGolyer Report are only estimates and the actual production and ultimate reserves from the Company's properties may be greater or less than the estimates prepared in such report. The DeGolyer Report has been prepared using certain commodity price assumptions which are described in the notes to the reserve tables. If lower prices for crude oil, natural gas liquids and natural gas are realized by the Company and substituted for the price assumptions utilized in the report, the present value of estimated future net cash flows for the Company's reserves would be reduced and the reduction could be significant, particularly based on the constant price case assumptions. Exploration for oil and natural gas involves many risks, which even a combination of experience and careful evaluation may not be able to overcome. There is no assurance that further commercial quantities of oil and natural gas will be discovered by the Company.

Additional Financing Requirements

The future development of the Company's oil and natural gas properties may require additional financing and there are no assurances that such financing will be available or, if available, will be available upon acceptable terms.

Canadian Tax Considerations

As the Company is engaged in the oil and natural gas business its operations are subject to certain unique provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation relating to characterization of costs incurred in their businesses which effects whether such costs are deductible and, if deductible, the rate at which they may be deducted for the purposes of calculating taxable income. The Company has reviewed its historical income tax returns with respect to the characterization of the costs incurred in the oil and natural gas business as well as other matters generally applicable to all corporations including the ability to offset future income against prior year losses. The Company has filed or will file all required income tax returns and believes that it is full compliance with the provisions of the Income Tax Act (Canada) and applicable provincial income tax legislation, but such returns are subject to reassessment. In the event of a successful reassessment of the Company it may be subject to a higher than expected past or future income tax liability as well as potentially interest and penalties and such amount could be material.

Exchange Rate Risks

The Canadian to U.S. dollar exchange rate has strengthened during 2005 and may fluctuate over time. As product prices are generally U.S. dollar based, the Company's exposure to currency exchange rate risks are primarily limited to Canadian capital expenditures, Canadian operating costs and the majority of the Company's general and administrative expenses which are paid for in Canadian dollars.

Dividends

The Company does not anticipate paying any dividends on its outstanding shares in the foreseeable future.

Conflicts of Interest

The directors of the Company may be engaged and may continue to be engaged in the search for oil and gas interests on their own behalf and on behalf of other companies, and situations may arise where the directors may be in direct competition with the Company. Conflicts of interest, if any, which arise will be subject to and governed by procedures prescribed by the corporation's governing corporate law statute which require a director of a corporation who is a party to, or is a director or an officer of, or has some material interest in any person who is a party to, a material contract or proposed material contract with the Company, disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under such legislation.

Reliance on Key Personnel

Holders of Common Shares of the Company must rely upon the experience and expertise of the management of the Company. The continued success of the Company is largely dependant on the performance of its key employees. Failure to retain or to attract and retain additional key employees with necessary skills could have a materially adverse impact upon the Company's growth and profitability.

Dilutive Effect of Financings and Acquisitions

TransGlobe may make future acquisitions or enter into financing or other transactions involving the issuance of securities of TransGlobe which may be dilutive.

INDUSTRY CONDITIONS

Government Regulation Generally

The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by the various levels of government in Canada, Yemen and Egypt and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, Yemen and Egypt, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect the Company's operations in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Company 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.

Pricing and Marketing – Oil and Natural Gas

In Canada, the producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (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 license from the NEB and the issuance of such license requires the approval of the Governor in Council.

In Yemen, 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 quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Yemen is not currently a member of OPEC.

Pricing and Marketing - Natural Gas

In Canada, the price of natural gas is determined by negotiation between buyers and sellers. 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 other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than 2 years or for a term of 2 to 20 years (in quantities of not more than 30,000 m³/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 license from the NEB and the issuance of such license requires the approval of the Governor in Council.

The Company's principal oil and gas operations in Canada are located in the Province of Alberta. The government of Alberta also regulates the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Pipeline Capacity

In Canada, although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market natural gas production. In addition, the prorationing of capacity on the inter-provincial pipeline systems also continues to affect the ability to export oil and natural gas.

In Yemen, export oil pipelines are owned by the government of Yemen through cost recovery. Access to the export pipelines is negotiated with the government. Sufficient export capacity currently exists, however, industry and market conditions may affect export capacity in the future.

The North American Free Trade Agreement

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, United States of America and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources 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 subject to an exception with respect to certain measures which only restrict the volume of exports, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export-price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.

Royalties and Incentives

Canada

In addition to federal regulation in Canada, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. 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, method of recovery 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, net profits interests or net carried interests.

From time to time the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. 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. However, the trend in recent years has been for provincial governments to allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

On March 3, 2003 the Department of Finance (Canada) released a technical paper entitled "Improving the Income Taxation of the Resource Sector in Canada". In November, 2003 the Tax Act was amended to provide the following initiatives applicable to the oil and gas industry (to a maximum of $2,000,000) to be phased in over a five year period: (i) a reduction of the federal statutory corporate income tax rate on income earned from resource activities from 28% to 21%, beginning with a one percentage point reduction effective January 1, 2003, and (ii) a deduction for federal income tax purposes of actual provincial and other Crown royalties and mining taxes paid and the elimination of the 25% resource allowance. In addition, the percentage of Alberta royalty tax credit ("ARTC") that the Company will be required to include in federal taxable income will be 32.5% in 2006; 50% in 2007; 60% in 2008; 70% in 2009; 80% in 2010; 90% in 2011, and 100% in 2012 and beyond.

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 5 years after the well was originally spudded may also qualify for a royalty reduction. A 24-month, 8,000 m³ exemption is available to production from a reactivated well that has not produced for: (i) a 12-month period, if resuming production in October, November or December of 1992 or January, 1993; or (ii) a 24 month period, if resuming production in February 1993 or later. As well, 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.

The Alberta government has also introduced a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.

In Alberta, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, varies between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying intervals in eligible 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.

Oil sands projects are subject to a specific regulation made effective July 1, 1997 and expiring June 30, 2007, which, among other things, determines the Crown's share of crude and processed oil sands products.

In Alberta, a producer of oil or natural gas is entitled to a credit on qualified oil and natural gas production against the royalties payable to the Crown by virtue of the ARTC program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per m³ and 25% at prices at and above $210 per m³. In general, the ARTC program provides a rebate on Alberta Crown royalties paid in respect of eligible producing properties. The ARTC rate is applied to a maximum of $2 million of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from a corporation claiming maximum entitlement 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 was conducting a review of the ARTC program with the objective of setting out better targeted objectives for a smaller program and to deal with administrative difficulties. On August 30, 1999, the Alberta government announced that it would not be reducing the size of the program but that it would introduce new rules to reduce the number of persons who qualify for the program. The new rules will preclude companies that pay less than $10,000 in royalties per year and non-corporate entities from qualifying for the program. Such rules will not presently preclude the Company from being eligible for the ARTC program.

Yemen

In Yemen, the respective Production Sharing Agreements determine the production sharing splits for the oil produced within the respective areas. The Company's share of royalties and taxes are paid out of the government's share of production sharing oil.

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, licenses and permits for varying terms from two years 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 regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the "APEA"), which came into force on September 1, 1993 and the Oil and Gas Conservation Act (Alberta) (the "OGCA"). The APEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations and significantly increase penalties. The Company is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment and will be taking such steps as required to ensure compliance with the APEA and similar legislation in other jurisdictions in which it operates. The Company believes that it is in material compliance with applicable environmental laws and regulations. The Company also believes that it is reasonably likely that the trend towards stricter standards in environmental legislation and regulation will continue.

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Protocol"). The Protocol calls for Canada to reduce its greenhouse gas emissions, during the period between 2008 and 2012. When the Government of Canada implements the Protocol, it is expected to affect the operation of all industries in Canada, including the oil and natural gas industry. As details of implementation of this Protocol have yet to be announced, the affect on our operations cannot be determined at this time. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production. Future federal legislation may require reductions of emissions or emissions intensity produced by our operations and facilities. Provincial legislation currently requires energy industries to follow a mandatory emissions reporting scheme, in advance of further

regulations targeting emissions output and improving energy efficiency standards of our operations. The direct or indirect costs of these enactments and proposals may adversely affect our business.

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Company's securities and options to purchase securities, if applicable, is contained in the Company's Information Circular for the most recent annual meeting of shareholders that involved the election of directors. Additional financial information is provided for in our financial statements and the management's discussion and analysis for the year ended December 31, 2005. These documents, along with other documents affecting the rights of securityholders and other information relating to the Company, may be found on SEDAR at www.sedar.com.

SCHEDULE "A"
REPORT ON RESERVES DATA

To the board of directors of TransGlobe Energy Corporation (the "Company"):

1.	We have evaluated the Company's reserves data as at December 31, 2005. The reserves data consist of the following:

(a)	(i)	proved, proved plus probable and proved plus probable plus possible 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, proved plus probable and proved plus probable plus possible 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 Company'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 Company 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 Company's board of directors.

Location of

Net Present Value of Future Net Revenue

Reserves

(before income taxes, 10% discount rate

(County or

(in millions of U.S. dollars)

Independent Qualified

Description and

Foreign

Reserves Evaluator or

Preparation Date of

Geographic

Auditor

Evaluation Report

Area)

Audited

Evaluated

Reviewed

Total

U.S. M$

DeGolyer and MacNaughton

Appraisal Report as of

Canada

75,405

Canada Limited

December 31, 2005 on

Yemen

78,094

Certain Properties

owned by Transglobe

Total

153,499

Energy Corporation in

Canada and Yemen

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.

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

A-2

Executed as to our report referred to above:

DeGolyer and MacNaughton Canada Limited, Calgary, Alberta, dated March 16, 2006.

	DEGOLYER and MACNAUGHTON CANADA LIMITED



	(signed) "Colin P. Outtrim"
	Colin P. Outtrim, P. Eng.

SCHEDULE "B"

REPORT OF MANAGEMENT AND DIRECTORS
ON RESERVES DATA AND OTHER INFORMATION

Management of TransGlobe Energy Corporation (the "Company") are responsible for the preparation and disclosure of information with respect to the Company'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 and proved plus probable oil and gas reserves estimated as at December 31, 2005 using constant prices and costs; and

	(ii)	the related estimated future net revenue.

Independent qualified reserves evaluators have evaluated the Company's reserves data. The report of the independent qualified reserves evaluator is summarized in this Annual Information Form.

The Reserves Committee of the board of directors of the Company has

(a)	reviewed the Company's procedures for providing information to the independent qualified reserves evaluators;

(b)	met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of each such independent qualified reserves evaluator to report without reservation; and

(c)	reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the board of directors has reviewed the Company'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 Reserves 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.

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

(signed) "Ross Clarkson"	(signed) "Geoffrey Chase"
Ross Clarkson	Geoffrey Chase
President, Chief Executive Officer and Director	Director and Chair of the Reserves Committee

(signed) "Lloyd Herrick"
Lloyd Herrick
Vice-President, Chief Operating Officer and Director


March 16, 2006

SCHEDULE "C"

CHARTER OF AUDIT COMMITTEE

Our Audit Committee Charter outlines the specific roles and duties of the Committee’s members.

GENERAL FUNCTIONS, AUTHORITY, AND ROLE

The Audit Committee is a committee of the Board of Directors appointed to assist the Board in monitoring (1) the integrity of the financial statements of the Company, (2) compliance by the Company with legal and regulatory requirements related to financial reporting, (3) qualifications, independence and performance of the Company's independent auditors, and (4) performance of the Company’s internal controls and financial reporting process. The Audit Committee’s annual report is included in the annual management information circular.

The Audit Committee has the power to conduct or authorize investigations into any matters within its scope of responsibilities, with full access to all books, records, facilities and personnel of the Company, its auditors and its legal advisors. In connection with such investigations or otherwise in the course of fulfilling its responsibilities under this charter, the Audit Committee has the authority to independently retain special legal, accounting, or other consultants to advise it, and may request any officer or employee of the Company, its independent legal counsel or independent auditor to attend a meeting of the Audit Committee or to meet with any members of, or consultants to, the Audit Committee. The Audit Committee also has the power to create specific sub-committees with all of the investigative powers described above.

The Company's independent auditor is ultimately accountable to the Board of Directors and to the Audit Committee; and the Board of Directors and Audit Committee, as representatives of the Company's shareholders, have the ultimate authority and responsibility to evaluate the independent auditor, and to nominate annually the independent auditor to be proposed for shareholder approval, and to determine appropriate compensation for the independent auditor. In the course of fulfilling its specific responsibilities hereunder, the Audit Committee must maintain free and open communication between the Company's independent auditors, Board of Directors and Company management. The responsibilities of a member of the Audit Committee are in addition to such member's duties as a member of the Board of Directors.

While the Audit Committee has the responsibilities and powers set forth in this charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company's financial statements are complete, accurate, and in accordance with generally accepted accounting principles. This is the responsibility of management and the independent auditor. Nor is it the duty of the Audit Committee to conduct investigations, to resolve disagreements, if any, between management and the independent auditor (other than disagreements regarding financial reporting), or to assure compliance with laws and regulations or the Company's own policies.

MEMBERSHIP

The membership of the Audit Committee will be as follows:

The Committee will consist of a minimum of three members of the Board of Directors, appointed annually, each of whom is affirmatively confirmed as independent by the Board of Directors, with such affirmation disclosed in the Company’s annual circular.
The Committee will also consist of all members that meet the definition of “Financially Literate” as defined in Multilateral Instrument 52-110 Part 1(1.5) and is able to read and understand fundamental financial statements, including the Company’s balance sheet, income statement and cash flow statement, as required by Section 121B(2)(a)(ii) of the AMEX Company Guide which also requires one member to be financially sophisticated.
The Board will elect, by a majority vote, one member as chairperson
A member of the Audit Committee may not, other than in his or her capacity as a member of the Audit Committee, the Board of Directors, or any other Board committee, accept any consulting, advisory, or other compensatory fee from the Company, and may not be an affiliated person of the Company or any subsidiary thereof.

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RESPONSIBILITIES

The responsibilities of the Audit Committee shall be as follows:

Frequency of Meetings

Meet quarterly or as often as may be deemed necessary or appropriate in its judgment, either in person or telephonically.
Meet with the independent auditor at least quarterly, either in person or telephonically.

Reporting Responsibilities

Provide to the Board of Directors proper Committee minutes.
Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.
Provide a report for the Company’s Annual Information Circular.

Charter Evaluation

Annually review and reassess the adequacy of this Charter and recommend any proposed changes to the Board of Directors for approval.

Whistleblower Mechanisms

Adopt and review annually a mechanism through which employees and others can directly and anonymously contact the Audit Committee with concerns about accounting and auditing matters. The mechanism must include procedures for responding to, and keeping of records of, any such expressions of concern.

Independent Auditor

Nominate annually the independent auditor to be proposed for shareholder approval.
Approve the compensation of the independent auditor, and evaluate the performance of the independent auditor.
Establish policies and procedures for the engagement of the independent auditor to provide non-audit services.
Insure that the independent auditor is not engaged for any activities not allowed by any of the Canadian provincial securities commissions, the SEC or any securities exchange on which the Company’s shares are traded.
Insure that the independent auditors are not engaged for any of the following nine types of non-audit services contemporaneous with the audit:

	o	Bookkeeping or other services related to accounting records or financial statements of the Company;
	o	Financial information systems design and implementation;
	o	Appraisal or valuation services, fairness opinions, or contributions-in-kind reports;
	o	Actuarial services;
	o	Internal audit outsourcing services;
	o	Any management or human resources function;
	o	Broker, dealer, investment advisor, or investment banking services;

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	o	Legal services; and
	o	Expert services related to the auditing service.

Insure that the independent auditor is compliant with the SEC, any security exchange on which the Company’s shares are traded and the Institute of Chartered Accountants of Alberta (Rules of Professional Conduct) regarding Audit Partner Rotation requirements.

Hiring Practices

Insure that no senior officer or employee who is, or in the past full year has been, affiliated with or employed by a present or former auditor of the Company or an affiliate, is hired by the Company until at least one full year after the end of either the affiliation or the auditing relationship.

Independence Test

	Take reasonable steps to confirm the independence of the independent auditor, which shall include:

	o	insuring receipt from the independent auditor of a formal written statement delineating all relationships between the independent auditor and the Company, consistent with the Independence Standards Board Standard No. 1 and related Canadian regulatory body standards;
	o	considering and discussing with the independent auditor any relationships or services, including non-audit services, that may impact the objectivity and independence of the independent auditor; and
	o	as necessary, taking, or recommending that the Board of Directors take, appropriate action to oversee the independence of the independent auditor.

Audit Committee Meetings

The Audit Committee may request the presence of the independent auditor at any Audit Committee meeting.
At the request of the independent auditor, convene a meeting of the Audit Committee to consider matters the auditor believes should be brought to the attention of the directors or shareholders.
Keep minutes of its meetings and report to the Board for approval of any actions taken or recommendations made.

Restrictions

Insure no restrictions are placed by management on the scope of the auditors’ review and examination of the Company’s accounts.
Insure that no Officer or Director attempts to fraudulently influence, coerce, manipulate or mislead any accountant engaged in auditing of the Company’s financial statements.

AUDIT AND REVIEW PROCESS AND RESULTS

Scope

Consider, in consultation with the independent auditor, the audit scope and plan of the independent auditor.

Review Process and Results

Consider and review with the independent auditor the matters required to be discussed by Statement on Auditing Standards No. 61, as the same may be modified or supplemented from time to time.

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Review and discuss with management and the independent auditor at the completion of the annual examination:

	o	the Company's audited financial statements and related notes;
	o	the Company’s MD&A and news releases related to financial results;
	o	the independent auditor's audit of the financial statements and its report thereon;
	o	any significant changes required in the independent auditor's audit plan;
	o	any non-GAAP related financial information;
	o	any serious difficulties or disputes with management encountered during the course of the audit; and
	o	other matters related to the conduct of the audit, which are to be communicated to the Audit Committee under generally accepted auditing standards.

Review, discuss with management and the independent auditors and approve annual and interim quarterly financial statements prior to public disclosure.
Review and discuss with management and the independent auditor the adequacy of the Company's internal controls that management and the Board of Directors have established and the effectiveness of those systems, and inquire of management and the independent auditor about significant financial risks or exposures and the steps management has taken to minimize such risks to the Company.
Meet separately with the independent auditor, management and the CFO as necessary or appropriate, to discuss any matters that the Audit Committee or any of these groups believe should be discussed privately with the Audit Committee.
Review and discuss with management and the independent auditor the accounting policies which may be viewed as critical, including all alternative treatments for financial information within generally accepted accounting principles that have been discussed with management, and review and discuss any significant changes in the accounting policies of the Company and industry accounting and regulatory financial reporting proposals that may have a significant impact on the Company's financial reports.
Review with management and the independent auditor the effect of regulatory and accounting initiatives as well as off-balance sheet structures, if any, on the Company's financial statements.
Review with management and the independent auditor any correspondence with regulators or governmental agencies and any employee complaints or published reports which raise material issues regarding the Company's financial statements or accounting policies.
Review with the Company's General Counsel legal matters that may have a material impact on the financial statements, the Company's financial compliance policies and any material reports or inquiries received from regulators or governmental agencies related to financial matters.

SECURITIES REGULATORY FILINGS

Review filings with the Canadian provincial securities commissions and the SEC and other published documents containing the Company's financial statements.
Review, with management and the independent auditor, prior to filing with regulatory bodies, the interim quarterly financial reports (including related notes and MD&A) at the completion of any review engagement or other examination. The designated financial expert of the Audit Committee may represent the entire Audit Committee for purposes of this review.

RISK ASSESSMENT

Meet periodically with management to review the Company's major financial risk exposures and the steps management has taken to monitor and control such exposures.

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Assess risk areas and policies to manage risk including, without limitation, environmental risk, insurance coverage and other areas as determined by the Board of Directors from time to time.

AMENDMENTS TO AUDIT COMMITTEE CHARTER

Annually review this Charter and propose amendments to be ratified by a simple majority of the Board of Directors.