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

EX-1 2 exhibit1.htm AMENDED ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2003 Filed by Automated Filing Services Inc. (604) 609-0244 - - TransGlobe Energy Corporation - Exhibit 1

TransGlobe Energy Corporation

Revised Initial Annual Information Form

Year Ended December 31, 2003

September 8, 2004

TABLE OF CONTENTS

					Page

ABBREVIATIONS		2		Quarterly Financial Information	31
CONVERSIONS		2		Capital Expenditures	31
FORWARD LOOKING STATEMENTS		2	MANAGEMENT'S DISCUSSION AND
CURRENCY AND EXCHANGE RATES		3	ANALYSIS OF OPERATING RESULTS		32
CERTAIN DEFINITIONS		4	DIVIDEND POLICY		32
TRANSGLOBE ENERGY CORPORATION		6	MARKET FOR SECURITIES		32
	The Company	6	DIRECTORS AND OFFICERS		32
	Subsidiaries	6		Corporate Cease Trade Orders or Bankruptcies	34
GENERAL DEVELOPMENT OF THE BUSINESS		7		Penalties or Sanctions	34
SIGNIFICANT ACQUISITIONS AND				Personal Bankruptcies	34
SIGNIFICANT DISPOSITIONS		7		Conflicts of Interest	34
TRENDS		7	HUMAN RESOURCES		34
RECENT DEVELOPMENTS		7	AUDITORS, TRANSFER AGENT AND
DESCRIPTION OF THE BUSINESS AND			REGISTRAR		34
PRINCIPAL PROPERTIES		8	RISK FACTORS		34
	Block 32 Republic of Yemen	8		General Conditions Relating to Oil and Gas
	2003 Drilling Results	9		Exploration and Production Operations	34
	Block S-1, Republic of Yemen	9		Industry Risks	35
	2003 Drilling Results	10		Exploration and Development	35
	Development Plan	10		Competition	35
	Canada	11		Title to Properties	36
STATEMENT OF RESERVES DATA AND				Interests in Properties	36
OTHER OIL AND GAS INFORMATION		11		Government Regulation	36
	Disclosure of Reserves Data	11		Political Risks Relating to Yemen	36
RESERVES DATA (CONSTANT PRICES AND				Reliance Upon Officers	36
COSTS)		12		Multi-jurisdictional Legal Risks	36
ESTIMATED FUTURE NET REVENUES		13		Reserve Information	37
RESERVES DATA (FORECAST PRICES AND				Additional Financing Requirements	37
COSTS)		16		Canadian Tax Considerations	37
	Reconciliations of Changes in Reserves and			Exchange Rate Risks	37
	Future Net Revenue	25		Dividends	37
	Additional Information Relating to			Conflicts of Interest	37
	Reserves Data	27		Reliance on Key Personnel	38
	Undeveloped Reserves	27		Dilutive Effect of Financings and Acquisitions .	38
	Probable Undeveloped Reserves	27	INDUSTRY CONDITIONS		38
	Other Oil and Gas Information	28		Government Regulation Generally	38
	Oil And Gas Wells	28		Pricing and Marketing - Oil	38
	Properties with no Attributable Reserves	28		Pricing and Marketing - Natural Gas	38
	Forward Contracts	28		Pipeline Capacity	39
	Additional Information Concerning Abandonment			The North American Free Trade Agreement	39
	and Reclamation Costs	28		Royalties and Incentives	39
	Production Estimates	29		Environmental Regulation	40
	Exploration and Development Activities	29		Kyoto Protocol	40
	Production History	29	ADDITIONAL INFORMATION		40
SELECTED CONSOLIDATED FINANCIAL
INFORMATION		31

SCHEDULE "A"	Report on Reserves Data
SCHEDULE "B"	Report of Management and Directors on Reserves Data and Other Information

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 specified gravity of 28° API or higher is generally referred to as light crude oil
ARTC	Alberta Royalty Tax Credit
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/d	barrel of oil equivalent per day
m³	cubic metres
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

CONVERSIONS

To Convert From	To	Multiply By

Mcf	Cubic metres	28.174
Cubic metres	Cubic feet	35.494
Bbls	Cubic metres	0.159
Cubic metres	Bbls oil	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471

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 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, 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 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 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 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 intent, and does not assume any obligation, to update these forward-looking statements.

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 US dollar as the functional currency for its consolidated financial statements. The exchange rates for the period average and end of period for the US dollar in terms of Canadian dollars as reported by the Bank of Canada were as follows for each of the years ended December 31, 2003, 2002 and 2001 and the six months ended June 30, 2004:

	Six Months Ended	Year Ended	Year Ended	Year Ended
	June 30, 2004	December 31, 2003	December 31, 2002	December 31, 2001

End of Period	Cdn$1.3404	Cdn$1.2965	Cdn$1.5776	Cdn$1.5928

Period Average	Cdn$1.3384	Cdn$1.4009	Cdn$1.5704	Cdn$1.5484

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;

"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;

"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;

"Fekete" means Fekete Associates Inc., independent petroleum engineers;

"Fekete Report" means the report of Fekete dated January 20, 2004 evaluating the Yemen crude oil, natural gas and natural gas reserves of the Company as at December 31, 2003;

"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;

"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;

"OSA" means Outtrim Szabo Associates Ltd., independent petroleum consultants, which firm was subsequently acquired by De Golyer MacNaughton Canada Limited;

"OSA Report" means the report of OSA dated January 29, 2004 evaluating the Canadian crude oil, natural gas liquids and natural gas reserves of the Company as at December 31, 2003;

"OTC BB" means the Over the Counter Bulletin Board operated by the National Association of Securities Dealers Inc.;

"PSA" means Production Sharing Agreement;

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

"TSX" means the Toronto Stock Exchange;

"U.S." means United States;

"Vintage" means Vintage Petroleum, Inc. and its subsidiaries; 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

The Company

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 and ceased operations as a mining company. The United States oil and gas properties were sold in the year 2000 to fund opportunities in Yemen. The Company changed its name to TransGlobe Energy Corporation on April 2, 1996. The Company is presently seeking approval from its shareholders to continue the Company from the Province of British Columbia to the Province of Alberta at the annual and special meeting of shareholders of the Company to be held on May 26, 2004.

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

The Company's principal office is located at 2900, 330 – 5th Avenue S.W., Calgary, Alberta, T2P 0L4, and the Company's registered office is located at Suite 2800, Floor, 666 Burrard Street, Vancouver, British Columbia, V6C 2Z7.

Subsidiaries

The following table sets out the subsidiaries of the Company and the Company's ownership interest in those subsidiaries:

Name of Subsidiary	Country 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%

Note:

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

TG Holdings Yemen Inc. owns TransGlobe's interests in Block 32 and Block S-1 in Yemen.

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.

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 focused on two production sharing agreements in Yemen (a 13.81087% working interest in Block 32 and a 25% working interest in Block S-1) and Central Alberta in Western Canada.

The year 2001 was the first full year of production from the Tasour field on Block 32 in Yemen (production commenced November 4, 2000). The primary focus of 2001 consisted of development/exploration drilling and a 2-D seismic acquisition program on Block 32 and a 3-D seismic acquisition program on Block S-1. A small four-well drilling program was conducted in Canada.

In the year 2002, the primary focus was again on the Republic of Yemen. On Block 32, the Company participated in three wells and additional 2-D seismic acquisition. On March 28, 2002, the Company elected to enter into the second exploration phase (2½ years) on Block S-1. The Company participated in drilling three wells (one drilling over year end) on Block S-1, leading to the An Nagyah light oil discovery. A small three well drilling program was conducted in Canada.

In the year 2003, the primary focus was on Block S-1 in Yemen and an expanded exploration drilling program in Canada. On Block S-1, the An Nagyah light oil discovery was appraised with two wells which led to the Declaration of Commerciality and the filing of a Development Plan on October 14, 2003. On October 15, 2003, MOM approved the Development Plan and a 20 year Development Area of approximately 285,000 acres for Block S-1. On Block 32, 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. The Company continues to be listed on the TSX under the symbol TGL.

SIGNIFICANT ACQUISITIONS AND SIGNIFICANT DISPOSITIONS

There were no significant acquisitions or significant dispositions by the Company or any significant probable acquisition by the Company within or since the completion of the most recently completed financial year of the Company.

TRENDS

There are a number of trends that have been developing in the oil and gas industry during the past few years that appear to be shaping the future of the business.

The most significant trend impacting the Company is the continued volatility of both natural gas and crude oil prices. Natural gas is a commodity influenced by factors exclusively in North America. During 2003 we saw record drilling but natural gas production volumes did not grow. In 2004 to present date, natural gas prices have remained strong. Crude oil is influenced by a world economy and OPEC's ability to adjust supply to world demand. During 2003, crude oil prices remained strong. Historically natural gas and crude oil prices have been very volatile; however, management believes commodity prices will be strong for the balance of 2004.

RECENT DEVELOPMENTS

The Company has recently approved a $20 million capital program for 2004.

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES

The Company is engaged in the exploration for, the development and production of crude oil and natural gas primarily in the Republic of Yemen and also 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 and Canada during the past three years. In the Republic of Yemen the Company has interests in two production sharing agreements; Block 32 and Block S-1. In Canada all the Company's interests are located in the province of Alberta, primarily in central Alberta.

Block 32 Republic of Yemen

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 seventeen wells and construction of production facilities, resulting in commencement of Tasour field production on November 3, 2000. Production from Block 32 is pipeline connected to the Nexen operated export pipe line system and loading terminal on the Indian Ocean. TransGlobe's production is sold to Nexen Marketing International and receives price referenced to dated Brent less a quality differential. 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 the Block. 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.

During 2003, the Block 32 Joint Venture work program consisted of the drilling of three development/appraisal wells and two exploration wells. The five wells resulted in an exploratory dry hole at Haibish and four producing oil wells (Tasour #8, #9, #10 and #11, summarized in the table below).

2003 Drilling Results

Well	Date Completed	Initial Production Rate	Producing Formation
Tasour #8	January 2003	9,000 Bopd	Qishn
Haibish #1	February 2003	-	D&A
Tasour #9	April 2003	1,500 Bopd	Qishn
Tasour #10	July 2003	1,200 Bopd	Qishn
Tasour #11	November 2003	6,000 Bopd	Qishn

The Tasour #8 and Tasour #9 development wells confirmed the southern field extension discovered by Tasour #7 in 2002. The Tasour #10 well was a successful test of the western field extension. This discovery extended the mapped Tasour field length from 3.3 kilometers to approximately 6.8 kilometers. Tasour #11 confirmed the western field extension creating a series of new development locations.

The western field extension combined with continued field performance increased proven plus probable reserves 32% and replaced 169% of 2003 production. Seismic mapping indicates the Tasour field could extend both to the west and to the east of the current wells. In late 2003, the Block 32 Joint Venture Group approved a 100 square kilometer 3-D seismic acquisition survey over the greater Tasour area to refine future drilling locations. It is anticipated that the 3-D seismic will be completed and interpreted by June 2004. Further development/appraisal drilling of three to four wells in the western and potential eastern extension is planned for 2004. One infill well is planned for the central Tasour pool in May 2004 (Tasour #12).

Block S-1, Republic of Yemen

TransGlobe entered into its second international exploration venture in 1997 by signing a Production Sharing Agreement ("PSA") for the Damis S-1 Block ("Block S-1") with the Ministry of Oil and Minerals ("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., 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. Vintage is 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.

The first exploration period ended on March 28, 2002 and the Block S-1 Joint Venture Group elected to proceed with a second exploration period of 2 ½ years. The second exploration period commitments were satisfied by the drilling of An Naeem #2 (2000), Osaylan #1 (2002), An Nagyah #2 (2002) and a 3-D seismic survey (2001).

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 (20 years) with an additional five year extension available.

The 2003 drilling program commenced in September 2002 was completed in May 2003, resulting in three oil wells, one gas/condensate well and one dry hole. The wells drilled during 2003 were An Naeem #3 (gas/condensate), An Nagyah #3 (oil) and An Nagyah #4 (oil).

2003 Drilling Results

	Date Completed	Results	Formation
An Naeem #3	January 2003	Gas/condensate	Alif
An Nagyah #3	March 2003	Gas, not tested	Lam ‘A'
		Oil: 240 Bopd	Lam ‘B'
An Nagyah #4	April 2003	Oil: 1,320 Bopd	Lam ‘A'

The first well, An Naeem #3, was drilled to a total depth of 1,623 meters to evaluate a potential oil rim on the An Naeem structure. The An Naeem #3 well tested gas and condensate from the Alif zone and did not encounter the anticipated oil rim.

The next well, An Nagyah #3, commenced drilling in February 2003 to appraise the light oil discovery made at An Nagyah #2 (1,100 Bopd announced December 10, 2002). The well was drilled to a total depth of 1,292 meters and encountered the Upper Lam sandstones in a structurally higher position than the An Nagyah #2 well. Although the Upper Lam sandstones had a thicker gross reservoir section and better indicated porosity and permeability than found at An Nagyah #2, the Upper Lam was not flow tested as it was gas bearing. The well did test 240 Bopd of light, 42 degree API oil from a new pool in the Lower Lam. The core and test data indicate the Lower Lam reservoir has less porosity and permeability than the Upper Lam reservoir and therefore may require stimulation to enhance production. The discovery of a new productive horizon in the Lower Lam should augment development economics.

The next well in the program, An Nagyah #4, was drilled to a total depth of 1,547 meters and tested 1,320 barrels of light oil (45 degrees API) from the Upper Lam reservoir. The An Nagyah #4 well encountered a much thicker gross sand package and defined a 60 meter (197 feet) total oil column in the Nagyah pool. A longer term test of the An Nagyah #4 well was carried out during June/July confirming the original flow rates and pressures. The successful appraisal well at An Nagyah #4 convinced the Block S-1 partners to declare commerciality and proceed with development of the field.

Development Plan

On October 14, 2003 the Company announced the Declaration of Commerciality and on October 15, 2003 the Ministry of Oil and Minerals approved the Block S-1 Development Plan and Development Area of approximately 1,150 square kilometers (285,000 acres). The large Development Area encompasses the An Naeem, Harmel and An Nagyah discoveries as well as numerous additional prospects for future exploration drilling. The Development/Production period will extend until 2023 with an optional five year extension also possible.

The initial field development is focused on the An Nagyah light oil pool which was discovered and appraised during the 2002/2003 drilling program. The plan provides for early production commencing in the first quarter of 2004 by trucking up to 2,500 Bopd (625 Bopd to TransGlobe) from An Nagyah wells to the Hunt operated Halewah facility.

The construction of a central production facility ("CPF") at An Nagyah and a 28 kilometer (18 mile) pipeline to the Jannah Hunt Halewah export pipeline is planned during 2004, with an anticipated completion by early 2005. The pipeline design was increased from an 8 inch to a 10 inch pipeline to allow future discoveries to be placed on stream quickly (ultimate capacity of 80,000 Bopd). The CPF is designed for an initial capacity of 10,000 Bopd (2,500 Bopd to TransGlobe), with expansion capabilities. The initial front end engineering and design ("FEED") study is complete. Bid requests for detailed engineering and for long lead time major equipment have been issued.

It is expected that the An Nagyah field development will consist of 13 wells to delineate and produce the field. The first development/appraisal well (An Nagyah #5) commenced drilling on the western area of the An Nagyah field on March 8, 2004. An Nagyah #5 was drilled to a total depth of 1,300 meters and completed as an Upper Lam 'A' oil producer. The well flow tested at a rate of 1,150 Bopd of 45 degree API oil. The second development/appraisal well (An Nagyah #6), positioned between An Nagyah #2 and An Nagyah #4, commenced drilling on April 7, 2004. An Nagyah #6 was drilled to a total depth of 1,207 metrs and completed as an Upper Lam 'A' oil producer. The well

flow tested at a rate of 1, 140 Bopd of 42 degree API oil. The well is being equipped for early production via trucking which is expected to commence in early May. The third development/appraisal well (AN Nagyah #7), located west of An Nagyah #5, commenced drilling May 2, 2004. Following An Nagyah #7, it is expected the drilling rig will be moved to Harmel #2 to appraise the shallow depth, medium gravity oil discovered in Harmel #1. Additional development wells in the An Nagyah pool are expected to be drilled in the third and fourth quarters of 2004 and into 2005.

The early production (trucking) facilities at the An Nagyah field were installed during the first quarter of 2004 and field production operations commenced on An Nagyah #4 on March 28, 2004. With the addition of An Nagyah #5 in April, production has been increased to approximately 2,000 Bopd. With the addition of An Nagyah #6 in May, it is anticipated that production will increase to 2,500 Bopd (approximately 625 Bopd to TransGlobe) as the trucking operation is expanded. The oil production is currently being trucked 18 miles to the Jannah Hunt facility where it is blended with the Marib light crude and transported by pipeline to the Ras Isa loading terminal on the Red Sea.

Canada

TransGlobe acquired its Canadian operations in April 1999. The majority of the Canadian operations are operated by TransGlobe and are focused almost entirely in the southern/central part of the province of Alberta. The Nevis area is the major producing area for the Company in Canada. The primary focus at Nevis is the drilling and development of Wabamum gas production and several shallower secondary targets. The Wabamum is characterized as being a tighter, long life gas reserves which may require additional wells per section to fully develop the resource. The Nevis wells are connected to existing pipeline systems and all the gas is processed through third party gas plants. In addition to the Nevis area, the Company has expanded the Canadian operations into several new emerging areas at Twining, Morningside and Lone Pine, where additional drilling is planned for 2004.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated May 14, 2004. The effective date of the Statement is December 31, 2003 and the preparation date of the Statement is May 14, 2004.

Disclosure of Reserves Data

All of the Corporations reserves herein reported were evaluated by independent evaluators in accordance with National Instrument 51 -101 (NI 51-101) for the year ended December 31, 2003 and National Policy 2-B (NP 2-B)

for year ended December 31, 2002. The Corporation retained Outtrim Szabo Associates Ltd. ("OSA") of Calgary, Alberta, independent petroleum engineering consultants, to evaluate the Company's Canadian reserves at December 31, 2003 and 2002. The Corporation retained Fekete Associates Inc. ("Fekete") of Calgary, Alberta, independent petroleum engineering consultants, to evaluate the Company's reserves in the Republic of Yemen at December 31, 2003 and 2002. On selected tables, reserves for the year ended December 31, 2002 have been presented for comparative purposes to assist the reader.

The reserves data set forth below (the "Reserves Data") is a consolidation of evaluations prepared by OSA and Fekete with an effective date of December 31, 2003 and December 31, 2002 contained in the respective Reports. The Reserves Data summarizes the oil, liquids and natural gas reserves of the Corporation and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Corporation reports in US currency and therefore the OSA reports have been converted to US $'s at the prevailing conversion rate at December 31 of the respective years.

Additional information not required by NI 51-101 has been presented to provide continuity and additional information which we believe 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 Corporation'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, 2003
(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)
Proven
Producing	2,083	1,276	3,158	2,527	93	69	2,702	1,766
Non-Producing	263	191	2,475	2,027	73	49	748	578
Undeveloped	-	-	1,422	1,119	58	39	296	225
Total Proven	2,346	1,467	7,055	5,673	224	157	3,746	2,569

Probable	2,356	1,533	4,917	3,993	117	85	3,292	2,283

Proven Plus Probable	4,702	2,999	11,972	9,666	341	242	7,038	4,852

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS AT DECEMBER 31, 2003
(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)
Proven
Producing	2,035	1,233	-	-	-	-	2,035	1,233
Non-Producing	228	160	-	-	-	-	228	160
Undeveloped	-	-	-	-	-	-	-	-
Total Proven	2,263	1,393	-	-	-	-	2,263	1,393

Probable	2,342	1,521	-	-	-	-	2,342	1,521

Proven Plus Probable	4,605	2,914	-	-	-	-	4,605	2,914

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS AT DECEMBER 31, 2003
(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)
Proven
Producing	48	42	3,158	2,527	93	69	667	533
Non-Producing	35	31	2,475	2,027	73	49	520	418
Undeveloped	-	-	1,422	1,119	58	39	295	225
Total Proven	83	74	7,055	5,673	224	157	1,483	1,176

Probable	13	12	4,917	3,993	117	85	950	762

Proven Plus Probable	96	85	11,972	9,666	341	242	2,433	1,938

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 during the final month 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, 2003
(CONSTANT PRICES AND COSTS)

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

Proved

Developed producing	28.5	23.0	21.1	19.6	28.5	23.0	21.1	19.6
Developed non-producing	13.8	10.8	9.7	8.9	11.5	9.2	8.4	7.7
Undeveloped	5.6	3.3	2.7	2.2	3.9	2.2	1.8	1.5
Total Proved	47.9	37.1	33.5	30.7	43.9	34.4	31.3	28.8

Probable	37.4	23.2	19.2	16.3	31.5	19.9	16.6	14.1

Total Proved Plus Probable	85.3	60.2	52.8	47.0	75.4	54.3	47.8	42.8

NET PRESENT VALUES OF FUTURE NET REVENUES
YEMEN
AS AT DECEMBER 31, 2003
(CONSTANT PRICES AND COSTS)

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

Proved

Developed producing	15.6	13.5	12.6	11.9	15.6	13.5	12.6	11.9
Developed non-producing	2.4	2.2	2.1	2.1	2.4	2.2	2.1	2.1
Undeveloped	0.0	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Total Proved	18.0	15.7	14.8	14.0	18.0	15.7	14.8	14.0

Probable	18.4	13.3	11.4	9.7	18.4	13.3	11.4	9.7

Total Proved Plus Probable	36.4	29.0	26.1	23.7	36.4	29.0	26.1	23.7

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS AT DECEMBER 31, 2003
(CONSTANT PRICES AND COSTS)

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

Proved

Developed producing	12.9	9.5	8.5	7.7	12.9	9.5	8.5	7.7
Developed non-producing	11.5	8.6	7.6	6.8	9.2	7.0	6.3	5.7
Undeveloped	5.6	3.3	2.7	2.2	3.9	2.2	1.8	1.5
Total Proved	29.9	21.4	18.8	16.7	25.9	18.7	16.5	14.8

Probable	19.0	9.9	7.9	6.5	13.1	6.6	5.2	4.3

Total Proved Plus Probable	48.9	31.3	26.7	23.3	39.0	25.3	21.7	19.1

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, 2003 exchange rates of 1.2965 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2003
(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⁾	68.0	26.0	12.7	2.8	-	26.5	8.5	18.0
Canada⁽²⁾	46.1	7.6	6.9	1.4	0.4	29.9	4.0	25.9
Total Company	114.1	33.6	19.6	4.2	0.4	56.4	12.5	43.9

Proved Plus Probable Reserves
Yemen⁽¹⁾	138.3	46.5	24.7	11.5	-	55.7	19.3	36.4
Canada⁽²⁾	76.0	12.5	11.9	2.2	0.4	48.9	9.9	39.0
Total Company	214.3	59.0	36.6	13.7	0.4	104.6	29.2	75.4

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, 2003 exchange rates of 1.2965 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, 2003
(CONSTANT 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
		(discounted at	(discounted at	(discounted at
Reserves		10%/year)	10%/year)	10%/year)
Category	Product Group	(US$MM)	(US$MM)	(US$MM)

Proved Reserves	Light and Medium Crude Oil (including	15.7	1.7	17.4
	solution gas and other by-products)
	Natural Gas (including by-products but	-	19.7	19.7
	excluding solution gas)

Proved Plus	Light and Medium Crude Oil (including	29.0	2.0	31.0
Probable	solution gas and other by-products)
Reserves
	Natural Gas (including by-products but	-	29.2	29.2
	excluding solution gas)

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, 2003 exchange rates of 1.2965 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

RESERVES DATA
(FORECAST PRICES AND COSTS)

SUMMARY OF OIL AND GAS RESERVES
TOTAL COMPANY
AS OF DECEMBER 31, 2003
(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)
Proven
Producing	2,083	1,358	3,155	2,494	93	69	2,702	1,843
Non-Producing	263	191	2,475	1,936	73	49	748	563
Undeveloped	-	-	1,422	1,068	58	39	295	217
Total Proven	2,346	1,549	7,052	5,498	224	158	3,746	2,623

Probable	2,356	1,588	4,917	3,893	117	85	3,292	2,321

Proven Plus Probable	4,702	3,137	11,969	9,391	341	242	7,037	4,945

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS OF DECEMBER 31, 2003
(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)
Proven
Producing	2,035	1,316	-	-	-	-	2,035	1,316
Non-Producing	228	160	-	-	-	-	228	160
Undeveloped	-	-	-	-	-	-	-	-
Total Proven	2,263	1,476	-	-	-	-	2,263	1,476

Probable	2,342	1,576	-	-	-	-	2,342	1,576

Proven Plus Probable	4,605	3,052	-	-	-	-	4,605	3,052

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS OF DECEMBER 31, 2003
(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)
Proven
Producing	48	42	3,155	2,494	93	69	667	527
Non-Producing	35	31	2,475	1,936	73	49	520	403
Undeveloped	-	-	1,422	1,068	58	39	295	217
Total Proven	83	74	7,052	5,498	224	158	1,483	1,148

Probable	13	12	4,917	3,893	117	85	950	745

Proven Plus Probable	96	85	11,969	9,391	341	242	2,432	1,893

Notes:

(1)

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

(2)

NET PRESENT VALUES OF FUTURE NET REVENUES
TOTAL COMPANY
AS OF DECEMBER 31, 2003
(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⁾				After Income Tax ⁽¹⁾
US $'s	Discounted at %/yr				Discounted at %/yr
$MM	0%	10%	15%	20%	0%	10%	15%	20%

Proved

Developed producing	19.3	15.8	14.6	13.6	19.3	15.8	14.6	13.6
Developed non-producing	9.2	7.2	6.6	6.0	9.1	7.1	6.4	5.8
Undeveloped	3.4	2.0	1.6	1.3	2.7	1.6	1.3	1.0
Total Proved	31.9	25.0	22.7	20.9	31.1	24.4	22.3	20.5

Probable	22.4	12.7	10.0	8.1	18.8	10.7	8.5	6.8

Total Proved Plus Probable	54.3	37.6	32.8	29.0	49.8	35.1	30.8	27.3

NET PRESENT VALUES OF FUTURE NET REVENUES
YEMEN
AS OF DECEMBER 31, 2003
(FORECAST PRICES AND COSTS)

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

Proved

Developed producing	10.6	9.3	8.7	8.3	10.6	9.3	8.7	8.3
Developed non-producing	1.6	1.5	1.5	1.4	1.6	1.5	1.5	1.4
Undeveloped	-	-	-	-	-	-	-	-
Total Proved	12.2	10.8	10.2	9.7	12.2	10.8	10.2	9.7

Probable	9.8	6.4	5.1	4.0	9.8	6.4	5.1	4.0

Total Proved Plus Probable	22.0	17.2	15.3	13.7	22.0	17.2	15.3	13.7

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS OF DECEMBER 31, 2003
(FORECAST PRICES AND COSTS)

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

Proved

Developed producing	8.7	6.5	5.8	5.3	8.7	6.5	5.8	5.3
Developed non-producing	7.6	5.7	5.1	4.6	7.4	5.6	5.0	4.4
Undeveloped	3.4	2.0	1.6	1.3	2.7	1.6	1.3	1.0
Total Proved	19.7	14.2	12.5	11.2	18.9	13.7	12.1	10.8

Probable	12.7	6.2	4.9	4.1	9.0	4.3	3.4	2.8

Total Proved Plus Probable	32.4	20.5	17.4	15.3	27.8	18.0	15.5	13.6

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.
(2)	Canadian values converted to US dollars at the December 31, 2003 exchange rates of 1.2965 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2003
(FORECAST 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	(US$ MM)	(US$ MM)	(US$ MM)	(US$ MM)	(US$ MM)	(US$ MM)	(US$ MM)	(US$ MM)

Proved Reserves
Yemen⁽¹⁾	51.8	18.1	13.1	2.8	-	17.9	5.7	12.2
Canada⁽²⁾	34.5	5.7	7.3	1.4	0.4	19.7	0.8	18.9
Total Company	86.4	23.8	20.4	4.2	0.4	37.6	6.5	31.1

Proved Plus Probable
Reserves
Yemen⁽¹⁾	104.5	35.6	25.3	11.5	-	32.1	10.1	22.0
Canada⁽²⁾	57.9	9.6	13.3	2.2	0.5	32.4	4.6	27.8
Total Company	162.4	45.1	38.6	13.7	0.5	64.5	14.7	49.8

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, 2003 exchange rates of 1.2965 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, 2003
(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		10%/year)	10%/year)	10%/year)
Category	Product Group	(US$MM)	(US$MM)	(US$MM)

Proved Reserves	Light and Medium Crude Oil (including	10.8	1.2	11.9
	solution gas and other by-products)
	Natural Gas (including by-products but	-	13.0	13.0
	excluding solution gas)

Proved Plus	Light and Medium Crude Oil (including	17.2	1.4	18.6
Probable	solution gas and other by-products)
Reserves
	Natural Gas (including by-products but	-	19.1	19.1
	excluding solution gas)

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, 2003 exchange rates of 1.2965 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After 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 OSA and Fekete Reports are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

	*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 certainly.

	(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 increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs.

	For the Yemen Reserves, Crude oil benchmark reference pricing, as at December 31, 2003, inflation and exchange rates utilized by Fekete in the Fekete Report, which were Fekete's then current forecasts at the date of the Fekete Report, were as follows:

	WTI Cushing	INFLATION
	Oklahoma	RATES ⁽¹⁾
Year	($US/bbl)	%/Year


Forecast
2004	26.50	2.0
2005	23.50	2.0
2006	23.50	2.0
2007	24.00	2.0
2008	24.48	2.0
Thereafter	+2.0%/year	+2.0%/year

Note

(1)	Inflation rates for forecasting prices and costs.

	The weighted average historical price in US $'s realized by the Corporation in Yemen, for the year ended Dec. 31, 2003 for crude oil was $28.13/bbl.

	For the Canadian Reserves, crude oil and natural gas benchmark reference pricing, as at December 31, 2003, inflation and exchange rates utilized by OSA in the OSA Report, which were OSA's then current forecasts at the date of the OSA Report, were as follows:

	Crude Oil
	WTI Cushing	Edmonton Par	Natural Gas AECO				Inflation	Exchange
	Oklahoma	Price 40° API	Spot Gas Price	Natural Gas Liquids			Rates ⁽¹⁾	Rate⁽²⁾
Year	(US$/bbl)	(Cdn$/bbl)	(Cdn$/Mcf)	FOB Edmonton			% Year	(US$/Cdn$)
				Condensate	Butane	Propane
Forecast					(Cdn$/bbl)
2004	26.39	34.16	5.56	34.84	23.91	21.52	1.5	0.750
2005	24.21	31.68	4.79	32.32	22.18	19.96	1.5	0.740
2006	23.53	31.19	4.63	31.82	21.83	19.65	1.5	0.730
2007	23.88	32.12	4.68	32.77	22.49	20.24	1.5	0.720
2008	24.24	32.61	4.66	33.26	22.82	20.54	1.5	0.720
Thereafter	+1.5%/year	+1.5%/year	+1.2%/yr to 14	+1.5%/year	+1.5%/year	+1.5%/year	+1.5%/year	+0%/year
			+1.5%/yr after 14

Notes:

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

The weighted average historical prices in Cdn $'s realized by the Corporation in Canada, for the year ended December 31, 2003, were $7.36/mcf for natural gas, $37.82/bbl for crude oil and $32.81/bbl for natural gas liquids.

4.	Constant Prices and Costs

In Yemen, a constant price of $30.05/bbl (Dec. 2003 actual prices) was utilized in the Fekete constant price case.

In Canada, constant prices of $27.78/bbl of oil and $5.45/Mcf of natural gas (Dec. 2003 actual prices converted to US $'s at the Dec. 31, 2003 currency rate of 1.2965 US$/Cdn$), were utilized in the OSA constant price case.

5.	Future Development Costs

FUTURE DEVELOPMENT COSTS
TOTAL COMPANY⁽¹⁾
AS AT DECEMBER 31, 2003

(US$thousands)	Constant Prices and Costs		Forecast Prices and Costs

		Proved Plus		Proved Plus
	Proved	Probable	Proved	Probable
Year	Reserves	Reserves	Reserves	Reserves
2004	3,465.1	12,431.8	3,465.1	12,431.8
2005	702.8	1,080.3	713.5	1,096.8
2006	-	-	-	-
2007	-	-	-	-
2008	-	38.5	-	40.9

Total Undiscounted	4,178.6	13,718.0	4,190.9	13,749.2

Total Discounted at 10%	4,047.5	13,478.1	4,056.7	13,495.6

Note:

(1)	Cdn$'s converted at the December 31, 2003 year end rate of 1.2965 US$/Cdn$.

FUTURE DEVELOPMENT COSTS
YEMEN
AS AT DECEMBER 31, 2003

(US$thousands)	Constant Prices and Costs		Forecast Prices and Costs
		Proved Plus		Proved Plus
	Proved	Probable	Proved	Probable
Year	Reserves	Reserves	Reserves	Reserves
2004	2,764.0	11,502.0	2,764.0	11,502.0
2005	-	-	-	-
2006	-	-	-	-
2007	-	-	-	-
2008	-	-	-	-

Total Undiscounted	2,764.0	11,502.0	2,764.0	11,502.0

Total Discounted at 10%	2,764.0	11,502.0	2,764.0	11,502.0

FUTURE DEVELOPMENT COSTS
CANADA⁽¹⁾
AS AT DECEMBER 31, 2003

(US$thousands)	Constant Prices and Costs		Forecast Prices and Costs
		Proved Plus		Proved Plus
	Proved	Probable	Proved	Probable
Year	Reserves	Reserves	Reserves	Reserves
2004	701.1	929.8	701.1	929.8
2005	702.8	1,080.3	713.5	1,096.8
2006	-	-	-	-
2007	-	-	-	-
2008	-	38.5	-	40.9

Total Undiscounted	1,414.6	2,216.0	1,426.9	2,247.2

Total Discounted at 10%	1,283.5	1,976.1	1,292.7	1,993.6

	Note:

	(1) Cdn$'s converted at the December 31, 2003 year end rate of 1.2965 US$/Cdn$.

	The Corporation 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.

7.	In Yemen, estimated future abandonment and reclamations costs related to properties evaluated have not been taken into account by Fekete 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 OSA 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 OSA and Fekete were accepted by OSA and Fekete as represented respectively. No field inspections were conducted by OSA or Fekete.

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, 2003
(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)
Dec. 31, 2002	1,063	84	1,147	2,780	1,149	3,929	86	8	94
Extensions	894	170	1,065	3,133	1,812	4,945	98	66	164
Improved
recovery	-	-	-	-	-	-	-	-	-
Technical
Revisions	15	2	17	(989)	909	(80)	(21)	10	(12)
Discoveries	160	1,332	1,492	946	413	1,359	2	1	3
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	(391)	(391)	-	-	-
Economic
Factors	-	-	-	1	1	2	-	-	-
Production	(583)	-	(583)	(373)	-	(373)	(7)	-	(7)
Dec. 31, 2003	1,549	1,588	3,137	5,498	3,893	9,391	158	85	242

RECONCILIATION OF NET RESERVES
(AFTER ROYALTIES/BEFORE TAXES)
BY PRINCIPAL PRODUCT TYPE
YEMEN
AS AT DECEMBER 31, 2003
(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)
Dec. 31, 2002	1,012	80	1,092	-	-	-	-	-	-
Extensions	875	165	1,040	-	-	-	-	-	-
Improved
recovery	-	-	-	-	-	-	-	-	-
Technical
Revisions	-	-	-	-	-	-	-	-	-
Discoveries	160	1,332	1,492	-	-	-	-	-	-
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	-	-	-	-
Economic
Factors	-	-	-	-	-	-	-	-	-
Production	(572)	-	(572)	-	-	-	-	-	-
Dec. 31, 2003	1,476	1,576	3,052	-	-	-	-	-	-

RECONCILIATION OF NET RESERVES
(AFTER ROYALTIES/BEFORE TAXES)
BY PRINCIPAL PRODUCT TYPE
CANADA
AS AT DECEMBER 31, 2003
(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)
Jan. 1, 2003	51	4	55	2,780	1,149	3,929	86	8	94
Extensions	19	6	25	3,133	1,812	4,945	98	66	164
Improved
recovery	-	-	-	-	-	-	-	-	-
Technical
Revisions	15	2	17	(989)	909	(80)	(21)	10	(12)
Discoveries	-	-	-	946	413	1,359	2	1	3
Acquisitions	-	-	-	-	-	-	-	-	-
Dispositions	-	-	-	-	(391)	(391)	-	-	-
Economic
Factors	-	-	-	1	1	2	-	-	-
Production	(11)	-	(11)	(373)	-	(373)	(7)	-	(7)
Dec. 31, 2003	74	12	85	5,498	3,893	9,391	158	85	242

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⁾
	2003		2003		2003
US$'s	(M$)		(M$)		(M$)
Estimated Future Net Revenue at beginning of year	8,761		11,904		20,665
Sales and transfers of oil and gas produced, net of production costs and	(1,842	)	(11,613	)	(13,455	)
royalties
Net change in prices, production costs and royalties related to future	564		(1,574	)	(1,010	)
production
Changes in previously estimated development costs incurred during the	1,472		4,348		5,820
period
Changes in estimated future development costs	(1,214	)	(997	)	(2,211	)
Extensions and improved recovery	10,291		12,605		22,896
Discoveries	3,313		2,575		5,888
Acquisitions of reserves	-		-		-
Dispositions of reserves	-		-		-
Net change resulting from revisions in quantity estimates	(2,834	)	-		(2,834	)
Accretion of discount	834		1,190		2,024
Net change in income taxes	(2,486	)	(2,755	)	(5,241	)
Other (value of production in disposed and acquired properties, changes
in timing of future production)	(659	)	-		(659	)
Other (effects of currency conversion in Canada)	2,501		-		2,501

Estimated Future Net Revenue at end of year	18,701		15,683		34,384

Note:

(1)

In Canada values were converted to US currency using the following currency exchange rates: Dec. 31, 2002 at 1.5776 $US/$Cdn , Dec. 31, 2003 at 1.2965, Sale and transfers of oil and gas produced, net of production costs and royalties at Booked values for the year and at the 2003 year average exchange rate of 1.4010 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 Corporation in 2003.

Proved Undeveloped Reserves

Light and Medium Oil

Natural Gas

Natural Gas Liquids

Year

(Mbbl)

(MMcf)

(Mbbl)

First

Cumulative

First

Cumulative

First

Cumulative

Attributed

at Year End

Attributed

at Year End

Attributed

at Year End

2003 ⁽¹⁾

1,422

58.4

Note:

(1)

Prior to 2003, the Corporation did not have any proved undeveloped reserves. All the Proven Undeveloped reserves assigned in 2003 were in Canada, and relate to the Wabamum formation in the Nevis area. It is expected that down spacing to 320 acres will be approved in the next year, with drilling (2 wells) planned for 2004/2005.

Probable Undeveloped Reserves

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

2000 ⁽¹⁾	-	-	271	271
2001				271
2002				224
2003⁽²⁾	2,342	2,342	1,328	1,629	55.0	55.0

Note:

(1)	In 2000 probable undeveloped reserves we assigned to an un-drilled gas spacing unit it Canada, which is scheduled to be drilled in the second quarter of 2004.

(2)	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 An Nagyah pool is scheduled for development during 2004 and 2005; with the installation of a central production facility, an 18 mile export pipe line, associated gathering facilities and drilling appraisal development wells. Drilling commenced in the 1 st quarter of 2004 and is expected to continue into 2005, and it is expected the facilities will be operational by the 2 nd quarter of 2005. The Natural Gas reserves and associated liquids were assigned in Canada, and generally related to the Wabamum formation in the Nevis area. It is expected that down spacing to 320 acres will be approved in the next year, with drilling (2 wells) planned for 2004/2005.

Other Oil and Gas Information

Oil And Gas Wells

The following table sets forth the number and status of wells in which the Corporation has a working interest as at December 31, 2003. All of the Corporation's wells are located on shore.

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

Yemen	9	1.3	4	1.0	-	-	3	0.8
Canada, Alberta	7	3.5	1	1.0	9	6.2	12	8.1
Total	16	4.8	5	2.0	9	6.2	15	8.9

Properties with no Attributable Reserves

The following table sets out the Corporation's developed and undeveloped land holdings as at December 31, 2003.

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

Yemen	10,760	1,987	420,010	89,361	430,770	91,348
Canada, Alberta	10,780	6,680	28,400	21,290	39,180	27,970
Total	21,540	8,667	448,410	110,651	469,950	119,318

Of the Corporation's undeveloped land, the rights to explore, develop and exploit 2,347 net acres may expire in Canada by December 31, 2004. The Corporation does not have any work commitments associated with its undeveloped lands in Yemen or Canada.

Forward Contracts

At December, 31, 2003 all of the Corporation's contracts to sell crude oil or natural gas were at prevailing market pricing. Subsequent to year-end, the Company entered into a fixed price natural gas contract to sell 1,500 GJ/day at a price of $5.795 Cdn/GJ from April 1, 2004 to October 31, 2004.

Additional Information Concerning Abandonment and Reclamation Costs

In Canada, future well abandonment costs net of salvage were included in the OSA reserves evaluation presented here in. Cost in US $'s to abandon approximately 31 (20.2 net) wells totalled $409 thousand undiscounted, or $219 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 $170 thousand undiscounted, or $131 thousand discounted at 10%, are scheduled during the next 3 years (2004-2006).

Production Estimates

The following table sets out the volume of the Corporation's daily production (working interest before royalties) estimated for the year ended December 31, 2004 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	Canada	Canada	Canada	Total
	Light and	Light and	Natural	Natural Gas	Company
	Medium Oil	Medium Oil	Gas	Liquids	BOE
	Gross (bbls/d)	Gross (bbls/d)	Gross (mcf/d)	Gross (bbls/d)	Gross (BOE/d)
Proved Producing	2,168	54	2,096	54	2,625
Proved Developed
Non-Producing	522	13	1,440	39	814
Proved Undeveloped	-	-	-	-	-
Total Proved	2,690	67	3,536	93	3,439
Total Probable	67	4	418	2	142
Total Proved Plus
Probable	2,757	71	3,954	95	3,581

In Yemen the Proved Producing and the Probable numbers represent the Tasour field in Block 32 and the Proved Developed Non-Producing numbers represent the An Nagyah field in Block S-1.

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, 2003:

*Canada:*	Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	1	5	7	1.00	4.12	5.12
Crude Oil	-	2	2	-	1.65	1.65
Dry and Abandoned ⁽¹⁾	-	1	-	-	1.0	1.0
Total	1	8	9	1.00	6.77	7.77

*Yemen:*	Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	1	-	1	0.25	-	0.25
Crude Oil	3	3	6	0.65	0.41	1.05
Dry and Abandoned⁽¹⁾	1	-	1	0.14	-	0.14
Total	5	3	8	1.03	0.41	1.44

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. Includes 1 Gross (1.0 Net) cased potential gas well in Canada.

Production History

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

	2003				2002
	Quarter Ended				Quarter Ended
	Mar. 31	Jun. 30	Sep. 30	Dec. 31	Mar. 31	Jun. 30	Sep. 30	Dec. 31
*Average Daily Production*
Yemen
Light and Medium Crude Oil (Bbls/d)	2,307	2,280	2,456	2,443	1,296	1,513	1,423	1,945
Canada
Light and Medium Crude Oil (Bbls/d)	31	32	36	40	30	28	25	22
Gas (Mcf/d)	966	1,017	1,105	1,704	895	1,065	816	796
NGL (Bbls/d)	18	18	22	52	13	8	11	12
Combined (BOE/d)	2,518	2,499	2,698	2,819	1,487	1,726	1,596	2,112

*Average Price Received*
Yemen
Light and Medium Crude Oil ($/Bbl)	29.74	25.71	28.05	28.97	21.19	24.56	27.40	26.65
Canada
Light and Medium Crude Oil ($/Bbl)	29.76	25.23	26.10	27.08	17.85	22.87	24.00	24.10
Gas ($/Mcf)	5.56	5.63	5.24	4.82	2.28	2.65	2.27	3.96
NGL ($/Bbl)	26.58	21.68	22.50	23.30	12.03	17.50	17.69	20.45
Combined ($/BOE)	29.95	26.22	28.21	28.84	20.30	23.61	26.10	26.40

*Royalties*
Yemen
Light and Medium Crude Oil ($/Bbl)	11.29	8.46	12.29	12.71	5.99	5.93	6.39	2.14
Canada
Light and Medium Crude Oil ($/Bbl)	3.42	2.80	2.66	2.63	2.56	1.94	2.46	3.10
Gas ($/Mcf)	0.84	0.96	0.66	0.76	0.44	0.27	0.28	0.59
NGL ($/Bbl)	8.80	7.22	5.16	4.61	4.04	3.31	4.37	2.74
Combined ($/BOE)	10.77	8.19	11.53	11.59	5.57	5.41	5.91	1.70

*Operating Expenses*
Yemen
Light and Medium Crude Oil ($/Bbls)	3.07	4.06	2.94	3.87	2.55	2.46	2.98	2.06
Canada
Light and Medium Crude Oil ($/Bbls)	7.99	6.32	10.31	11.76	5.31	7.89	6.88	9.76
Gas ($/Mcf)	1.32	1.31	1.29	1.33	1.25	1.09	1.29	1.02
NGL ($/Bbls)	-	-	-	-	-	-	-	-
Combined ($/BOE)	3.42	4.31	3.34	4.32	3.08	2.95	3.43	2.39

*Netback Received*
Yemen
Light and Medium Crude Oil ($/Bbl)	15.37	13.20	12.82	12.40	12.66	16.18	18.03	26.73
Canada
Light and Medium Crude Oil ($/Bbl)	18.35	16.11	13.13	12.69	9.98	13.05	14.66	11.25
Gas ($/Mcf)	3.40	3.36	3.29	2.73	0.59	1.29	0.70	2.35
NGL ($/Bbl)	17.78	14.47	17.34	18.70	7.99	14.19	13.33	17.71
Combined ($/BOE)	15.75	13.72	13.33	12.92	11.65	15.25	16.76	25.72

The following table indicates the Company's average daily production from its important fields for the year ended December 31, 2003.

	Light and Medium
	Crude	Gas	NGLS	BOE
	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)

Canada	35	1,200	28	263
Yemen	2,372	-	-	2,372
Total	2,407	1,200	28	2,635

SELECTED CONSOLIDATED FINANCIAL INFORMATION

The following is a summary of selected financial information of TransGlobe for the periods indicated.

	Years Ended December 31,
(US$ thousands, except per share	2003	2002	2001
amounts)

Oil and gas sales, net of royalties	17,162	13,254	8,554

Net income	5,905	5,426	3,062
Per share – basic	0.11	0.11	0.06
Per share – diluted	0.11	0.10	0.06

Cash flow from operations	9,347	9,710	5,840
Per share – basic	0.18	0.19	0.12
Per share – diluted	0.17	0.19	0.11

Total Assets	35,215	24,386	18,847

Shareholders' Equity	30,603	23,345	17,912

Quarterly Financial Information

The following is a summary of selected unaudited financial information of TransGlobe for the periods indicated.

	2003				2002
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
	(US$ thousands, except per share amounts)
Oil and gas sales, net of royalties	4,488	4,159	4,139	4,375	5,459	2,964	2,859	1,971

Net income	3,414	291	776	1,425	3,198	1,040	873	315
Per share – basic	0.06	0.01	0.01	0.03	0.07	0.02	0.02	0.01
Per share – diluted	0.06	0.01	0.01	0.03	0.06	0.02	0.02	0.01

Cash flow from operations	1,894	2,193	2,369	2,891	4,381	2,111	1,951	1,267
Per share – basic	0.04	0.04	0.05	0.06	0.09	0.04	0.04	0.02
Per share – diluted	0.04	0.04	0.05	0.06	0.09	0.04	0.04	0.02

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, 2003:

	Canada	Yemen	Total
(US$ thousands)
Property acquisition costs
Proved properties	-	-	-
Undeveloped properties	1,198	-	1,198
Exploration costs	263	4,474	4,737
Development costs	3,123	3,857	6,980
Corporate and other	633	681	1,314
Total	5,217	9,012	14,229

MANAGEMENT'S DISCUSSION AND ANALYSIS OF OPERATING RESULTS

The Company's management discussion and analysis relating to (i) the financial statements for the year ended December 31, 2003, which form part of the Company's 2003 Annual Report, (ii) the financial statements for the three months ended March 31, 2004, and (iii) the financial statements for the six months ended June 30, 2004, are incorporated herein by reference and form an integral part of this Annual Information Form.

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.

MARKET FOR SECURITIES

TransGlobe's common shares are listed and posted on the Toronto Stock Exchange and the American Stock Exchange under the trading symbols "TGL" and "TGA", respectively.

DIRECTORS AND OFFICERS

The names, municipalities of residence, the offices held by each in the Company, and the principal occupation of the directors and officers, the period served as director and the number of securities of the Company owned by such individuals is as follows:

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

Robert A. Halpin ^(1)(2)(4) Calgary, AB	Chairman of the Board and Director	1997	527,585⁽⁵⁾	Retired Petroleum Engineer, President and owner, Halpin Energy Resources Ltd., which provides consulting services on international energy projects

Ross G. Clarkson⁽²⁾ Calgary, AB	President, Chief Executive Officer and Director	1995	1,994,272⁽⁶⁾	President and Chief Executive Officer of the Company since December 4, 1996, with over 28 years' oil and gas industry experience as a senior geological advisor

Lloyd W. Herrick ⁽⁴⁾ Calgary, AB	Vice-President, Chief Operating Officer and Director	1999	550,000⁽⁷⁾	Vice-President and Chief Operating officer of the Company since April 28, 1999, with over 28 years' experience in both domestic and international oil and gas exploration and development

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

Erwin L. Noyes ^(2)(3)(4) Saanichton, BC	Director	1995	188,247⁽⁸⁾	Retired since July 31, 2000, Vice-President, International Operations of the Company, with over 30 years' experience in the oil and gas industry

Geoffrey C. Chase ^(1)(3)(4) Calgary, AB	Director	2000	45,000⁽⁹⁾	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) Calgary, AB	Director	2004	-⁽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 Ferguson Calgary, AB	Vice-President, Finance, Chief Financial Officer and Secretary	2001	119,000⁽¹¹⁾	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).

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 120,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007 and to purchase 80,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009.
(6)	Mr. Clarkson also holds incentive stock options to purchase 154,500 Common Shares at Cdn$0.73 per share expiring August 11, 2005, to purchase 250,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007 and to purchase 120,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009.
(7)	Mr. Herrick also holds incentive stock options to purchase 135,000 Common Shares at Cdn$0.73 per share expiring August 11, 2005, to purchase 250,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007 and to purchase 100,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009.
(8)	Mr. Noyes also holds incentive stock options to purchase 150,000 Common Shares at Cdn$0.73 per share expiring August 11, 2005, to purchase 120,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007 and to purchase 60,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009.
(9)	Mr. Chase also holds incentive stock options to purchase 140,000 Common Shares at Cdn$0.73 per share expiring August 11, 2005, to purchase 120,000 Common Shares at Cdn$0.50 per share expiring April 16, 2007 and to purchase 60,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009.
(10)	Mr. Dyment holds incentive stock options to purchase 180,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009.
(11)	Mr. Ferguson also holds incentive stock options to purchase 200,000 Common Shares at Cdn$0.55 per share expiring June 1, 2006, 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.

Corporate Cease Trade Orders or Bankruptcies

No director or officer or the Company or, to the Company's knowledge, a shareholder holding a sufficient number of securities of the Company to effect materially the control of the Company is, or within the 10 years before the date of this document has been, a director or officer of any other issuer that, while that person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the issuer access to any exemptions under Canadian securities legislation, for a period of more than 30 consecutive days, or 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.

Penalties or Sanctions

No director or officer of the Company, or to the Company's knowledge, a shareholder holding a sufficient number of securities of the Company to effect materially the control of the Company has been subject to any penalties or sanctions imposed by a court relating to Canadian securities legislation or by a Canadian securities regulatory authority or has entered into a settlement agreement with a Canadian securities regulatory authority, or has been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

Personal Bankruptcies

No director or officer of the Company, or to the Company's knowledge, a shareholder holding sufficient securities of the Company to affect materially the control of the Company, or a personal holding company of any such persons, has, within the 10 years preceding the date of this document, become 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 the assets of such director, officer or shareholder.

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 10 full-time employees and 3 part-time consultants. The Company intends to add additional professional and administrative staff as the needs arise.

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 office in Calgary, Alberta is the transfer agent and registrar of the common shares of the Company.

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 gas including geological risks, operating risks, political risks, development risks, marketing risks, and logistical risks of operating in Yemen.

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 and Block S-1 in Yemen represents a major undertaking. The exploration program in Yemen is a high-risk venture 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 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

from Canada, the United States and Republic of Yemen, 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 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

Beyond the risks inherent in the oil and gas industry, the Company is subject to additional risks resulting from doing business in Yemen. While the Company has attempted to reduce many of these risks through agreements with the Government of Yemen 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, 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 MOM 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 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.

Multi-jurisdictional Legal Risks

The Company is incorporated under the laws of the Province of British Columbia, 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 each of the OSA Report and the Fekete 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 reports. Each of the OSA Report and the Fekete Report have 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 reports, 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 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 US dollar exchange rate has strengthened during 2003 and may fluctuate over time. As product prices are generally US 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 G&A 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

The oil and gas industry is subject to extensive controls and regulations imposed by various levels of government in both Canada and Yemen. Outlined below are some of the more significant aspects of the legislation, regulations and agreements governing the oil and gas industry in the jurisdictions in which the Company operates. All current legislation is a matter of public record and the Company is unable to predict what additional legislation or amendments may be enacted.

Government Regulation Generally

The oil and natural gas industry in each of Yemen and Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect the operations of TransGlobe in a manner materially different than they would affect other oil and gas companies of similar size.

Pricing and Marketing - Oil

In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding 1 year in the case of light crude, and not exceeding 2 years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board ("NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

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 sold in interprovincial and international trade 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 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 30,000m3/day), must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issue of such a licence requires the approval of the Governor in Council.

The Company's principal oil and gas operations in Canada are located in the Province of Alberta. The government of Alberta regulates the volume of natural gas, which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangement 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. The pro rating of capacity on the interprovincial pipeline systems also continues to affect the ability to export oil.

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

On January 1, 1994, the North American Free Trade Agreement ("NAFTA") among the governments of Canada, the U.S. and Mexico became effective. 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 to the U.S. or Mexico will be allowed provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period), (ii) impose an export price higher than the domestic price, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements.

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

Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time the governments of Canada and the province of Alberta have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging natural gas exploration or enhanced planning projects.

In Alberta, the royalty reserved to the Crown is subject to various incentives, and varies between 15% and 30% in the case of new gas and between 15% and 35% in the case of old gas, depending upon the posted reference price each month. Royalties on propane, butane and ethane are constant at 30%. While royalties on pentane and pentanes plus are variable. Alberta Crown royalties on oil production are calculated on a sliding scale basis.

In Alberta, natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 8,200 feet is subject to a royalty exemption, with the amount of the exemption varying with depth of the well. Oil produced from qualifying new pools is eligible for a third tier oil royalty rate. In addition, there is a royalty reduction for approved horizontal well re-entries.

In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the Alberta royalty tax credit program. The Alberta royalty tax credit program is based on a price sensitive formula, and the Alberta royalty tax credit rate currently varies between 75% at prices of oil below $15.89 per Bbl and 25% at prices above $33.37 per Bbl. The Alberta royalty tax credit rate is applied to a maximum of $2,000,000

of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to Alberta royalty tax credit will generally not be eligible for Alberta royalty tax credit. The rate is established quarterly based on the average "par price", as determined by Alberta Resource Development for the previous quarterly period.

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.

Environmental Regulation

The oil and natural gas industry in both Yemen and Canada is currently subject to environmental regulation pursuant to existing federal, provincial and state legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation in Canada requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties.

The Company is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased, although not material, expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. The Company believes that it is in material compliance with environmental laws and regulations applicable as at the date hereof.

Kyoto Protocol

In December of 2002, Canada became a signatory to the Kyoto Protocol. The implementation of this plan has not been fully defined by the Federal Government. Until an implementation plan is developed, it is impossible to assess the impact on specific industries and individual businesses within an industry. It is generally believed that the oil and gas industry, as a major producer of carbon dioxide (as a necessary by-product and emission of hydrocarbon production), will bear a disproportionately large share of the anticipated cost of implementation.

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Company's securities, options to purchase securities and interests of insiders in material transactions, if applicable, is contained in the Company's Information Circular-Proxy Statement dated April 16, 2004 which relates to the Annual and Special Meeting of Shareholders to be held on May 26, 2004. Additional financial information is contained in (i) the consolidated financial statements of the Company for the year ended December 31, 2003 and the Management's Discussion and Analysis contained in the Company's 2003 Annual Report and (ii) the unaudited consolidated financial statements of the Company for the three months ended March 31, 2004, and the Management's Discussion and Analysis thereon.

The Company will provide to any person or corporation, upon request to the Company:

(a)	when the securities of the Company are in the course of a distribution pursuant to a preliminary short form prospectus or a short form prospectus:

	(i)	one copy of the Company's annual information form, together with one copy of any document, or the pertinent pages of any document, incorporated therein by reference;

	(ii)	one copy of the comparative financial statements of TransGlobe for its most recently completed financial year in respect of which such financial statements have been issued, together with the report of the auditor thereon, and one copy of any interim financial statements of the Company subsequent to the financial statements for TransGlobe's most recent financial year; and

	(iii)	one copy of the management information circular of the Company in respect of its most recent annual meeting of shareholders that involved the election of directors or one copy of any annual filing prepared in lieu of that circular, as appropriate.

(b)	at any other time, a copy of the documents referred to in clauses (a)(i), (ii) or (iii) above, provided the Company may require a payment of a reasonable charge if the request is made by a person or Company who is not a security holder of the Company.

Additional copies of this Annual Information Form and the materials listed in the preceding paragraph are available on the foregoing basis and upon request by contacting the Company at its offices at Suite 2900, 330 – 5th Avenue S.W., Calgary, Alberta T2P 0L4, or by phone at (403) 264-9888, fax at (403) 264-9898 or email at trglobe@trans-globe.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, 2003. The reserves data consist of the following:

(a)	(i)	proved and proved plus probable oil and gas reserves estimated using forecast prices and costs; and

	(ii)	the related estimated future net revenue; and

(b)	(i)	proved oil and gas reserves estimated 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, 2003, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's Board of Directors. The values contained in the following table are reported in $US using a conversion factor of 1.2965 Cdn/US dollars.

Description

Location of

Net Present Value of Future Net Revenue

and

Reserves

(before income taxes, 10% discount rate)

Preparation

(County or

(in millions of U.S. dollars)

Independent Qualified

Date of

Foreign

Reserves Evaluator or

Evaluation

Geographic

Auditor

Report

Area)

Audited

Evaluated

Reviewed

Total

De Golyer MacNaughton Canada

January 29,

Canada

$20.5

Limited (formerly Outtrim Szabo

2004

Associates Ltd.)

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.

(signed) "De Golyer MacNaughton"

De Golyer MacNaughton Canada Limited (formerly Outtrim Szabo Associates Ltd.)
Calgary, Alberta
May 14, 2004

May 14, 2004

To:	The Board of Directors of TransGlobe Energy Corporation (the "Company")


1.	We have evaluated the Company's reserves data as at December 31, 2003. The reserves data consist of the following:

(a)	(i)	pro ved and proved plus probable oil and gas reserves estimated as at December 31, 2003 using forecast prices and costs; and

	(ii)	the related estimated future net revenue; and

(b)	(i)	proved oil and gas reserves estimated as at December 31, 2003 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 stan dards 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 TransGlobe Energy Corporation evaluated by us for the year ended December 31, 2003, and identifies the respective portions thereof that we have evaluated and reported on to the Company's Board of Directors:

A-2

Independent

Qualified Description and Net Present Value of Future Net Revenue (M$ U.S.)

Reserves Preparation Date o f Location of (before income taxes, 10% discount rate)

Evaluator Evaluation Reserves Audited Evaluated Reviewed Total

Fekete "Evaluation of the Interests Republic of $ - 10726 - 10726

Associates of TransGlobe Energy Corporation Yemen

Inc. Tasour Field, Howarime Block 32

as at December 31, 2003"

dated January 20, 2004

Fekete "Evaluation of the Interests Republic of $ - 6450 - 6450

Associates of TransGlobe Energy Corporation Yemen

Inc. An Nagyah Field, Damis Block S-1

as at December 31, 2003"

dated January 20, 2004

Total $ - 17176 - 17176

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

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.

Executed as to our report referred to above:

Fekete Associates Inc., Calgary, Alberta, Canada	(signed "Gary Metcalfe")
	Gary D. Metcalfe, P. Eng.
	Vice President, Evaluations

	May 14, 2004
	Date

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, 2003 using forecast prices and costs; and

	(i)	the related estimated future net revenue; and

(b)	(i)	proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and

	(i)	the related estimated future net revenue.

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

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

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

(d)	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

(e)	reviewed the reserves data with management and each 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

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

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

(h)	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


May 14, 2004

Independent
Qualified	Description and			Net Present Value of Future Net Revenue (M$ U.S.)
Reserves	Preparation Date o f	Location of		(before income taxes, 10% discount rate)
Evaluator	Evaluation	Reserves		Audited	Evaluated	Reviewed	Total

Fekete	"Evaluation of the Interests	Republic of	$	-	10726	-	10726
Associates	of TransGlobe Energy Corporation	Yemen
Inc.	Tasour Field, Howarime Block 32
	as at December 31, 2003"
	dated January 20, 2004

Fekete	"Evaluation of the Interests	Republic of	$	-	6450	-	6450
Associates	of TransGlobe Energy Corporation	Yemen
Inc.	An Nagyah Field, Damis Block S-1
	as at December 31, 2003"
	dated January 20, 2004

	Total		$	-	17176	-	17176