EX-99.1 2 exhibit1.htm TRANSGLOBE ENERGY CORPORATION ANNUAL INFORMATION FORM Filed by Automated Filing Services Inc. (604) 609-0244 - TransGlobe Energy Corp. - Exhibit 1

TransGlobe Energy Corporation

Renewal Annual Information Form
Year Ended December 31, 2004

 

 

March 24, 2005

TABLE OF CONTENTS

  Page
   
ABBREVIATIONS 2
CONVERSIONS 2
FORWARD LOOKING STATEMENTS 2
CURRENCY AND EXCHANGE RATES 3
CERTAIN DEFINITIONS 4
TRANSGLOBE ENERGY CORPORATION 6
GENERAL DEVELOPMENT OF THE BUSINESS 7
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES 8
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION 16
DIVIDEND POLICY 38
DESCRIPTION OF SHARE CAPITAL 38
MARKET FOR SECURITIES 39
ESCROWED SECURITIES 39
DIRECTORS AND OFFICERS 40
HUMAN RESOURCES 41
INTEREST OF EXPERTS 41
LEGAL PROCEEDINGS 42
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS 42
AUDITORS, TRANSFER AGENT AND REGISTRAR 42
MATERIAL CONTRACTS 42
AUDIT COMMITTEE INFORMATION 42
RISK FACTORS 43
INDUSTRY CONDITIONS 47
ADDITIONAL INFORMATION 49

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

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ABBREVIATIONS

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

Other

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

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

CONVERSIONS

To Convert From  To  Multiply By 
     
Mcf  cubic meters  28.174 
cubic meters  cubic feet  35.494 
bbls  cubic meters  0.159 
cubic meters  bbls oil  6.293 
feet  meters  0.305 
meters  feet  3.281 
miles  kilometers  1.609 
kilometers  miles  0.621 
acres  hectares  0.405 
hectares  acres  2.471 
gigajoules  Mmbtu  0.950 

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

FORWARD LOOKING STATEMENTS

Certain statements contained in this annual information form (the "Annual Information Form") and in certain documents incorporated by reference into this Annual Information Form, constitute forward-looking statements. These statements relate to future events or the Company's future performance. All statements other than statements

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of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Actual operational and financial results may differ materially from TransGlobe's expectations contained in the forward-looking statements as a result of various factors, many of which are beyond the control of the Company. These factors include, but are not limited to, unforeseen changes in the rate of production from TransGlobe's oil and gas fields, changes in the price of crude oil and natural gas, adverse technical factors associated with exploration, development, production or transportation of TransGlobe's crude oil and natural gas reserves, changes or disruptions in the political or fiscal regimes in TransGlobe's areas of activity, changes in Canadian, Egyptian, Yemen or American tax, energy or other laws or regulations, changes in significant capital expenditures, delays in production starting up due to an industry shortage of skilled manpower, equipment or materials, and the cost of inflation.

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

• the quantity of reserves; 
• oil and natural gas production levels; 
• capital expenditure programs; 
• projections of market prices and costs; 
• supply and demand for oil and natural gas; 
• expectations regarding the Company's ability to raise capital and to continually add to reserves through 
• 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 intend, 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, 2004, 2003 and 2002.

  Year Ended December 31, 2004    Year Ended December 31, 2003    Year Ended December 31, 2002 
End of Period  Cdn$1.2020    Cdn$1.2965                     Cdn$1.5776 
Period Average  Cdn$1.3015    Cdn$1.4009                     Cdn$1.5704 

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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;

"DeGolyer" means DeGolyer and MacNaughton Canada Limited, independent petroleum consultants, which firm acquired OSAL effective April 15, 2004;

"DeGolyer Report" means the report of DeGolyer dated March 16, 2005 evaluating the Canadian crude oil, natural gas liquids and natural gas reserves of the Company as at December 31, 2004;

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

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

"Egypt" means the Arab Republic of Egypt;

"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.

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(b)     
in relation to wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and
   
(c)     
in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company;

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

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

"OSAL" means Outtrim Szabo Associates Ltd., independent petroleum consultants, which firm was subsequently acquired by DeGolyer and MacNaughton Canada Limited effective April 15, 2004;

"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 Alberta, 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.

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TRANSGLOBE ENERGY CORPORATION

General

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

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

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

Intercorporate Relationships

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

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

Note:

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

TG Holdings Yemen Inc. owns TransGlobe's interests in the Republic of Yemen in Block 32, in Block S-1 and in Block 72 (awarded in a bid round, pending ratification of Yemen Parliament). TransGlobe Petroleum Egypt Inc. owns TransGlobe's interest in the Nuqra Area Block 1, Arab Republic of Egypt.

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

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GENERAL DEVELOPMENT OF THE BUSINESS

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

During the past three years, TransGlobe has developed its business interests through a combination of exploration and development and to a lesser extent, acquisitions and dispositions, primarily focusing on two production sharing agreements in Yemen (a 13.81% working interest in Block 32 and a 25% working interest in Block S-1) and in central Alberta, Canada.

In 2002, the Company's primary focus continued to be 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 and participated in drilling three wells (one drilling over year end), leading to the An Nagyah light oil discovery. A small three well drilling program was also conducted in Canada.

In 2003, the Company's primary focus was on Block S-1 in the Republic of Yemen and an expanded exploration drilling program in Canada. On Block S-1, the An Nagyah light oil discovery was appraised with two wells 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, also in Yemen, the Company participated in five wells, resulting in four oil wells for an 80% success ratio. In Canada, the Company drilled nine wells, resulting in six gas wells, two oil wells and one cased potential gas well for an 88% success ratio.

In November 2003, the Company listed on the American Stock Exchange ("AMEX") under the symbol TGA, which replaced the Company's previous listing on the NASDAQ bulletin board under the symbol TGLEF. The Company has been listed on the TSX under the symbol TGL since November 7, 1997. In December 2003, the Company completed a private placement financing consisting of 1,363,637 common shares issued on a "flow-through" basis within the meaning of the Income Tax Act (Canada) ("Flow-Through Shares") at a price of Cdn $2.20 per Flow-Through Share, for gross proceeds of approximately Cdn $3,000,000.

In 2004, the primary exploration and production focus was on Blocks S-1 and 32 in Yemen and central Alberta in Canada. On Block S-1, the An Nagyah light oil development is underway with an active development and appraisal drilling program resulting in eight new producing oil wells. The Company has also participated in one appraisal oil well (Harmel #2) and one exploration dry hole at Al Hareth on Block S-1. Commensurate with the early production facilities, the Company is participating in the construction of a central production facility and pipeline for the An Nagyah pool development on Block S-1 which is on schedule with a planned start up in June 2005. The An Nagyah field production is anticipated to increase to over 10,000 bopd (2,500 bopd to TransGlobe) when the facilities and pipeline are operational. On Block 32, the Company participated in the acquisition of 3-D seismic and the drilling of three producing oil wells in the Tasour field. In western Canada, the Company has drilled 15 wells, resulting in 10 gas wells, two oil wells and three dry wells.

In addition to the 2004 exploration and production activities, the Company participated in the Yemen International Bid Round for Exploration and Production of Hydrocarbons with the successful award of Block 72. The Block 72 production sharing contract has been approved by the Cabinet and is currently before the Yemen Parliament for final approval. Following parliamentary approval the Block 72 partnership plans to acquire 3-D seismic to identify drilling locations. Drilling is anticipated to commence in late 2005 or early 2006.

In July 2004, the Company announced the addition of an exploration concession in the Arab Republic of Egypt, representing a new country of operation for the Company. The Company has entered into a farm-out agreement to incur US $6.0 million of expenditures in the stage 1 and stage 2 work programs over the next five years to acquire a 50% working interest in the Nuqra Block 1, located in the Upper Nile region of Egypt. The Company is the operator of the Nuqra Block.

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In November 2004, the Company obtained, from Standard Bank London Limited as agent and bank, certain syndicated credit facilities of up to an aggregate amount of U.S. $7.0 million (the "New Credit Facility") to TransGlobe Petroleum International Inc., as borrower. The New Credit Facility was guaranteed by each of TransGlobe, TG Holdings Yemen Inc. and TransGlobe Petroleum Egypt Inc.

On November 24, 2004, the Company completed a public offering by way of short form prospectus of 2,530,000 common shares ("Common Shares") at a price of Cdn$4.35 per Common Share for gross proceeds of approximately Cdn$11,000,000. On December 7, 2004, in connection with the financing, the Company announced that the underwriters exercised their over-allotment option to acquire an additional 379,500 Common Shares at Cdn$4.35 per share, resulting in additional gross proceeds of approximately Cdn$1,650,825.

Anticipated Changes in the Business

As at the date hereof, the Company does not anticipate any material change in its business during the balance of the 2005 financial year.

Significant Acquisitions and Significant Dispositions

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

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES

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

TransGlobe's major operations and principal activities are in the oil and gas exploration and production business. The Company has operated in the Republic of Yemen and Canada during the past three years. In the Republic of Yemen, the Company has interests in three production sharing agreements: in Block 32, in Block S-1 and in Block 72 (awarded in a bid round, pending ratification of Yemen Parliament). In 2004 the Company expanded into the Arab Republic of Egypt with the acquisition of an interest in the Nuqra Block 1 property. In Canada, all of the Company's interests are located in the Province of Alberta, primarily in central Alberta.

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Republic of Yemen properties:

Block 32, Republic of Yemen

Background

TransGlobe entered into its first international project in January 1997 through a farmout agreement and joint venture on Block 32. The Company has since participated in acquisition of seismic data, drilling of twenty wells and construction of production facilities. The Tasour field commenced production on November 3, 2000. The joint venture currently consists of TG Holdings Yemen Inc. (a wholly-owned subsidiary of TransGlobe Energy Corporation) with a 13.81087% working interest and partners Ansan Wikfs Hadramaut Ltd. and DNO ASA holding the balance ("the Block 32 Joint Venture Group"). DNO ASA (an independent Norwegian oil company) is the operator of 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.

2004 Exploration/Development

During 2004, the Block 32 Joint Venture work program consisted of the acquisition of a 100 square kilometer 3-D seismic program over the greater Tasour area, and the drilling of three development wells in the western extension of the Tasour field. The well results are summarized in the table below.

2004 Drilling Results

    Initial Production Test   
Well  Date Completed  (bopd – gross)  Formation 
Tasour #12  June 2004  6,100  Qishn sandstone 
Tasour #13  September 2004  2,240  Qishn sandstone 
Tasour #14  October 2004  2,820  Qishn sandstone 

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Production

The Tasour field continues to be a stellar performer, averaging 17,760 bopd (2,453 bopd to TransGlobe) during 2004. During 2004, the primary focus on Block 32 was the development of the western extension of the Tasour field, with additional work to increase water disposal capacity. As is typical of all the Qishn fields in the prolific Masila basin, the economic success of the project is dependent upon handling increased water production in a cost effective manner. The strong natural water drive provides an exceptional primary recovery (over 50% of the original oil in place). All the Qishn wells in Tasour and in the Masila basin are pumped utilizing very large electric (up to 1,000 hp) submersible pumps. The power in the Tasour field is generated by diesel powered generators, making diesel costs one of the largest components of operating costs. In late 2004, the Joint Venture group approved the purchase of a diesel topping plant which is expected to be operational during the third quarter of 2005. The diesel topping plant will produce diesel fuel from a portion of the Tasour crude oil. This is expected to stabilize diesel costs and maintain low operating costs which should extend the life of the field.

2005 Outlook

The main Tasour field is now largely developed. Therefore the primary focus for 2005 will be exploration for new reserves. The Block 32 Joint Venture group initially approved a 6 well drilling program for 2005 and recently discussed expanding the 2005 program to 8 wells by utilizing a second drilling rig. A new 70 km 2-D seismic program is planned for early 2005 to define several interesting exploration leads located north and west of the Tasour area.

In the first quarter of 2005 the group drilled Tasour #15, #16 and #17 on Block 32. Tasour #15 was drilled as a water injector near the central production facility ("CPF") and found a 2.5 meter oil column. The well was completed as a water injection well. Tasour #16 was suspended after encountering 6.0 meters of oil pay overlying 3.0 meters of water bearing sandstone. The dip meter indicates a structurally higher location can be reached by sidetracking the well to the south of the current bottom hole location. The Tasour #17 well was drilled approximately 2.0 kilometers east of Tasour #15 to test a new structure east of the Tasour field. The well has been plugged and suspended after encountering Qishn S-1A sand in a structurally low position. Although hydrocarbon shows were encountered, no tests were conducted as it was determined that the Qishn S-1A sand was water bearing.

Two development wells are planned for the main Tasour field and a deep exploration well is planned to test formations below the producing Tasour Qishn formation on a prospect defined on the 3-D seismic survey. In addition several new Qishn prospects have been identified and one or two are expected to be drilled in 2005.

Block 72, Republic Of Yemen

Background

In June 2004, the Ministry of Oil and Minerals ("MOM") selected the joint venture group comprised of DNO ASA (34%), TG Holdings Yemen Inc. (33%) and Ansan Wikfs (Hadramaut) Limited (33%) ("Block 72 Partnership") as the successful bidder for Block 72 in the International Bid Round for Exploration and Production of Hydrocarbons. TG Holdings Yemen Inc. is a wholly owned subsidiary of TransGlobe. Block 72 encompasses 1,822 square kilometers (approximately 450,234 acres) and is located in the western Masila Basin adjacent to the Canadian Nexen Masila Block. The bid consists of an exploration work program and a signature bonus of $1.05 million ($350,000 to TransGlobe). The work program is split into two, thirty month exploration periods and entails seismic acquisition and two wells in each period.

2005 Outlook

The Block 72 Production Sharing Contract has been approved by the Cabinet and as of early March 2005 it is before the Yemen Parliament for final approval. Following approval, the Block 72 Partnership plans to re-process existing seismic and to acquire new 3-D seismic to identify drilling locations. Drilling is anticipated to commence late in 2005 or early 2006. Any discoveries made on Block 72 would follow a similar development program to Block 32's whereby a separate oil processing facility and a pipeline would be constructed to connect to the Nexen export pipeline.

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Block S-1, Republic of Yemen

Background

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 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.

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

To year end 2004, the Company has participated in two 3-D seismic surveys, drilling of 19 wells and the construction of early production facilities, resulting in the commencement of production in late March 2004.

2004 Exploration/Development

During 2004 the primary focus of the Joint Venture Group was the delineation and development of the An Nagyah Lam A oil pool. Eight oil wells were drilled in the An Nagyah Lam A pool (now producing), one appraisal well was drilled at Harmel #2 and one exploration well was drilled at Al Hareth #1 (dry).

2004 Drilling Results

    Initial Production Test   
Well  Date Completed  (bopd – gross)  Formation 
An Nagyah #5  March 2004  1,150  Lam A 
An Nagyah #6  April 2004  1,142  Lam A 
An Nagyah #7  May 2004  360  Lam A 
An Nagyah #8  July 2004  607  Lam A 
An Nagyah #9  August 2004  530  Lam A 
An Nagyah #10  September 2004  1,547  Lam A 
An Nagyah #11 Hz  October 2004  3,100  Lam A 
An Nagyah #12 Hz  November 2004  4,801  Lam A 
Harmel #2  June 2004  Cased oil, testing 2005  Azal, Sarr, Qishn 
Al Hareth #1  August 2004  Dry  Alif Prospect 

The 2004 drilling program focused on the appraisal and development of the An Nagyah Lam A light oil pool resulting in eight successful producing oil wells during the year. The initial wells were drilled vertically to delineate the pool as mapped on 3-D seismic, with An Nagyah #7 and An Nagyah #8 defining the western and eastern edges of the field respectively. One of the more significant wells drilled during the year was An Nagyah #11, drilled horizontally to improve well productivity and pool drainage. An Nagyah #11 was a relatively short horizontal of approximately 150 meters. The 3,100 bopd tested from An Nagyah #11 supported a second horizontal well at An Nagyah #12 with a larger horizontal section of approximately 860 meters. The An Nagyah #12 well flow tested 4,801 bopd while significantly constrained by the 2 7/8 inch tubing in the well. The An Nagyah #12 well confirmed that horizontal drilling is the preferred method to develop the Lam formation.

A workover rig was mobilized in the fourth quarter. The An Nagyah #2 well was successfully re-completed as a producing Lam A oil well. The workover rig also re-completed the An Nagyah #3 well as a Lam A gas injector. Natural gas from the An Nagyah pool is injected into An Nagyah #3 to conserve the gas and to maintain reservoir pressure thereby enhancing oil recovery.

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Harmel #2 was drilled in June 2004 to appraise the shallow oil reservoirs found in the discovery well, Harmel #1. The Harmel #2 well is located 1.2 kilometers from the Harmel #1 discovery well. Full diameter cores were cut over three separate oil zones. The analysis of the cores suggested that the well productivity could be improved by acidizing the oil zones. The Harmel #2 well was completed and acidized in November of 2004.

The only exploration well drilled in 2004, Al Hareth #1, was drilled to a total depth of 1,400 meters (4,239 feet) and was abandoned. The primary target, the Alif reservoir sandstone was encountered, however the open hole well logs did not indicate commercial hydrocarbons were present.

Production

Early production (trucking) facilities were installed at An Nagyah during the first quarter of 2004 with an initial capacity of 2,500 bopd (625 bopd to TransGlobe). The oil production is currently being trucked 18 miles to the Jannah Hunt facility where it enters the pipeline to the Ras Isa loading terminal on the Red Sea. Trucking operations will be phased out following the construction of a CPF at An Nagyah and a 28 kilometer (18 mile) pipeline to the Jannah Hunt export pipeline.

After commencing production the trucking facilities were steadily expanded to the current capacity of approximately 7,600 bopd (1,900 bopd to TransGlobe). After drilling An Nagyah #12 the field productive well capacity is in excess of 12,000 bopd.

The pipeline and facility construction for the An Nagyah field is on schedule with a planned start up in June 2005. The An Nagyah field production is anticipated to increase to over 10,000 bopd (2,500 bopd to TransGlobe) when the facilities and pipeline are operational. The CPF is designed for an initial capacity of 10,000 to 12,000 bopd (2,500 to 3,000 bopd to TransGlobe), with expansion capabilities. The 10 inch pipeline has an ultimate design capacity of 80,000 bopd to provide expansion capabilities for future developments.

2005 Outlook

The focus in 2005 includes the evaluation/assessment of undeveloped discoveries (Harmel and An Naeem), new exploration on the Block, and development drilling at An Nagyah.

Two wells were drilled in the first quarter of 2005 (An Nagyah #14 and Malaki #1). The An Nagyah #14 well was drilled to a total depth of 1,365 meters and suspended as a Lam B oil well in early January 2005. The An Nagyah #14 well encountered a 19 meter oil column in the Lam B (lower Lam) sandstone. The well was swab tested at a rate of approximately 80 barrels of light (40 degree API) oil per day. No water was produced during the test period. This discovery is located south of the An Nagyah field in a separate fault block. The An Nagyah #14 oil test has identified a new exploration fairway south of the main An Nagyah field. Additional work will be required to incorporate the well results and remap the seismic in this area to identify future drilling locations.

Malaki #1 is located approximately nine kilometers south east of the An Nagyah pool. The Malaki #1 exploration well was drilled to a total depth of 2,315 meters. The well was plugged and abandoned after encountering minor hydrocarbon shows. The Lam A sandstone reservoirs were encountered structurally lower than the oil/water contact in the An Nagyah field and were water saturated.

In March 2005 An Nagyah #15 commenced drilling. The An Nagyah #15 well is planned as an 800 meter horizontal well in the northwest area of the An Nagyah field, adjacent to An Nagyah #12. Following An Nagyah #15, it is expected that the drilling rig will move to the Markhah exploration prospect (approximately 40 kilometers south east of An Nagyah).

The An Naeem gas condensate pool is being evaluated for potential make up gas to maintain reservoir pressure and improve recoveries from the An Nagyah pool. Produced condensate could be sold with the An Nagyah crude oil production. A gas cycling scheme to recover condensate from An Naeem is also being studied.

In addition to An Nagyah Lam A development wells (horizontal), it is expected that a Lam B horizontal well will be drilled to develop the Lam B oil pool tested in the An Nagyah #3 and An Nagyah #14 wells, along with several

13

additional exploration wells. The 3-D seismic survey shot in 1999 in the An Naeem area is being reprocessed to further refine additional exploration targets for the 2005/2006 drilling program.

The Harmel #1 and #2 wells are currently being equipped with pumps and production testing equipment which are expected to be operational by the end of the March 2005. It is expected that both Harmel wells will be production tested for three to six months. Production and test data obtained from the Harmel #1 and #2 wells will help to determine the commerciality of the medium gravity oil (22 degree API). The Harmel structure identified on 3-D seismic could require 80 to 90 shallow wells (700 to 800 meters in depth) to be fully developed.

Nuqra Block 1, Arab Republic of Egypt

Background

In July 2004, TransGlobe Petroleum Egypt Inc. ("TransGlobe Egypt"), a wholly owned subsidiary of TransGlobe, entered into a Farmout Agreement with Quadra Egypt Limited ("QEL"), a subsidiary of Quadra Resources Corp. headquartered in Calgary, and Rampex Petroleum International ("Rampex") headquartered in Cairo, Egypt. This agreement provides TransGlobe Egypt the opportunity to participate and earn a 50% working interest in the Nuqra Concession.

Under the terms of this agreement TransGlobe Egypt will earn 50% of the Nuqra Concession by paying 100% of the initial $6.0 million of qualifying expenditures in the Stage 1 and the Stage 2 work programs. QEL will hold a 30% working interest in the Concession and Rampex will hold a 20% working interest. After the initial earning, costs will be shared 60% TransGlobe Egypt, 40% QEL and Rampex will be carried until first production. The cost of the Rampex carry will be recovered by TransGlobe Egypt and QEL from 100% of the Rampex cost oil and 50% of the Rampex production sharing oil. TransGlobe Egypt is the Operator of the Nuqra Block.

The Nuqra Concession Agreement Stage 1 work program requires expenditure of $2.0 million to reprocess existing seismic and to shoot new seismic within the first two years. Upon expiry of the Stage 1 term, there is an option to proceed to the Stage 2 work program. Stage 2 requires completion of a two well drilling program, with a minimum expenditure of $4.0 million over a period of three years. Upon expiry of the Stage 2 term there is an option to proceed to the Stage 3 work program. Stage 3 requires completion of a two well drilling program, with a minimum

14

expenditure of $5.0 million over a final three year term. Exploitation of discovered commercial fields will continue under a Development Lease for a further 20 years. The Concession fiscal terms allow for the recovery of costs from 40% of production. The remaining balance of 60% of production is then shared on a 70:30 basis between the government and the contractor respectively. Production sharing above 25,000 bopd is shared on an 80:20 basis.

The Nuqra Concession is located in Upper Egypt near of the city of Luxor on the east bank of the Nile River. The concession encompasses over two-thirds of the Kom Ombo Basin, a rift basin analogous to the Gulf of Suez Basin in Egypt, the Marib Basin in the Republic of Yemen, and the Muglad Basin in Sudan, all of which contain major reserves. The Nuqra Concession contains more than 30,000 square kilometers or 7,500,000 acres of exploration lands with 13 seismically defined leads identified from over 4,000 km of existing 2-D seismic. Seismic and well data have confirmed the existence of Jurassic and Cretaceous sediments and the presence of a petroleum system which could potentially hold significant oil reserves.

2004 Activities

In October 2004 Mr. Mitchell Wren joined the Company as General Manager of TransGlobe Petroleum Egypt Inc. in Cairo. TransGlobe Petroleum Egypt Inc. was assigned a 50% interest in the project and approved as operator by the Egyptian Government in October 2004. An office has been established in Cairo and work has commenced on geological field studies, re-processing of existing 2-D seismic and field acquisition bid parameters for the acquisition of additional 2-D seismic data.

2005 Outlook

TransGlobe has obtained the existing seismic data on the Nuqra Block and is currently re-processing the data to improve the resolution. A new seismic acquisition program is anticipated to commence in the fourth quarter 2005. A field geological survey is also underway to investigate surface outcrops and oil seeps in the Nuqra area. The exploration of the Nuqra Block is being fast tracked and will probably exceed the PSA requirements. It is anticipated that TransGlobe will complete the seismic acquisition by the first quarter of 2006 and will be preparing for a two well drilling program in late 2006. This would complete all the first period and second period PSA commitments ahead of schedule.

Canada


15

Background

TransGlobe acquired its Canadian operations in April 1999. TransGlobe operates most of the wells which are almost entirely in the southern/central part of the Province of Alberta. Until 2003, investment in Canadian operations was limited to development and exploitation of producing areas with minimal investment in land or exploration opportunities. In 2003 and 2004 Canadian operations were successfully expanded providing increased cash flow and asset value. Canadian operations will continue to be expanded to capitalize on the North American gas market.

2004 Exploration/Development

For the year 2004, the Company drilled 15 wells (11.2 net) resulting in 10 gas wells, 2 oil wells and 3 dry holes for an 80% success rate. The wells were all drilled in central Alberta focusing in the core areas of Nevis (5 gas, 1 oil) and Twining (2 gas). The balance of the wells were drilled at Morningside (oil), Gadsby (gas), Three Hills Creek (gas), Thorsby (gas), with dry holes at Lone Pine Creek and Cynthia. Seven of the 2004 wells were placed on production by year end contributing approximately 350 boepd in December. Subsequent to year end, two (0.9 net) additional wells (50 boepd) were tied in and placed on production. Negotiations are currently underway to tie in two (1.5 net) additional wells in 2005 which should contribute an additional 70 boepd. One Nevis well will undergo additional testing and evaluation prior to initiating tie in negotiations.

Production

Production in the fourth quarter averaged 900 boepd but was constrained due to natural gas compression capacity limitations at third party operated facilities in the Nevis and Twining areas. It is anticipated that additional compression will be installed by mid 2005.

2005 Outlook

The Canadian 2005 drilling program is expected to commence in April or May after spring break-up to take advantage of lower equipment and service prices during the summer months. The Company plans to drill 10 to 15 wells in Canada during 2005. The majority of the wells will be drilled in the Nevis area, targeting natural gas.

16

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

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

The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated March 16th, 2005. The effective date of the Statement is December 31, 2004 and the preparation date of the Statement is March 16th, 2005.

Disclosure of Reserves Data

All of the Company's reserves herein reported were evaluated by independent evaluators in accordance with NI 51-101 for the years ended December 31, 2004 and December 31, 2003. In 2004, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, independent petroleum engineering consultants based in Calgary and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company's Reserve Committee, to independently evaluate 100% of TransGlobe's reserves as at December 31, 2004.

Prior thereto, Outtrim Szabo Associates Ltd. ("OSAL") of Calgary, Alberta (now DeGolyer and MacNaughton Canada Limited), independent petroleum engineering consultants, had historically evaluated the Company's Canadian reserves including December 31, 2003 and Fekete Associates Inc. ("Fekete") of Calgary, Alberta, independent petroleum engineering consultants, had historically evaluated the Company's reserves in Yemen including December 31, 2003. On selected tables, reserves for the year ended December 31, 2003 have been presented for comparative purposes to assist the reader.

The reserves data set forth below (the "Reserves Data") was prepared by DeGolyer with an effective date of December 31, 2004. The Reserves Data summarizes the oil, liquids and natural gas reserves of the Company and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Company reports in US currency and therefore the reports have been converted to US $'s at the prevailing conversion rate at December 31 of the respective years.

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

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

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

17

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
TOTAL COMPANY
AS AT DECEMBER 31, 2004
(CONSTANT PRICES AND COSTS)

  Light & Medium Crude              
  Oil   Natural Gas   Natural Gas Liquids   Total boe's  
    Gross (1)   Net (2)   Gross (1)   Net (2)   Gross (1)   Net (2)   Gross (1)   Net (2)  
By Category  (Mbbls) (Mbbls)   (MMcf)   (MMcf)   (Mbbls)   (Mbbls)   (MBoe)   (MBoe)  
Proved               
     Producing  2,822 1,879   6,679   5,378   139   98   4,074   2,873  
     Non-Producing  134 77   1,231   887   105   73   444   298  
     Undeveloped  1,555 911   2,949   2,275   100   72   2,146   1,363  
Total Proved  4,511 2,867   10,859   8,540   344   243   6,664   4,534  
                                   
Probable  2,823 1,514   4,890   3,718   124   86   3,763   2,220  
                                   
Proved Plus Probable  7,334 4,381   15,749   12,258   468   329   10,427   6,754  

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS AT DECEMBER 31, 2004
(CONSTANT PRICES AND COSTS)

    Light & Medium Crude                    
  Oil   Natural Gas    Natural Gas Liquids    Total boe's  
    Gross (1)   Net (2)   Gross(1)    Net(2)    Gross(1)    Net(2)    Gross (1)   Net (2)  
By Category    (Mbbls)   (Mbbls)   (MMcf)    (MMcf)    (Mbbls)    (Mbbls)    (MBoe)   (MBoe)  
Proved                       
     Producing    2,749   1,813   -         -    -         -    2,749   1,813  
     Non-Producing    118   64   -         -    -         -    118   64  
     Undeveloped    1,554   911   -         -    -         -    1,554   911  
Total Proved    4,421   2,788   -         -    -         -    4,421   2,788  
                                   
Probable    2,796   1,489   -         -    -         -    2,796   1,489  
                                   
Proved Plus Probable    7,217   4,277   -         -    -         -    7,217   4,277  

18

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS AT DECEMBER 31, 2004
(CONSTANT PRICES AND COSTS)

  Light & Medium Crude              
  Oil   Natural Gas   Natural Gas Liquids   Total boe's  
    Gross (1)   Net (2)   Gross (1)   Net (2)   Gross (1)   Net (2)   Gross (1)   Net (2)  
By Category  (Mbbls)   (Mbbls)   (MMcf)   (MMcf)   (Mbbls)   (Mbbls)   (MBoe)   (MBoe)  
Proved                 
     Producing  73   66   6,679   5,378   139   98   1,326   1,060  
     Non-Producing  16   13   1,231   887   105   73   325   234  
     Undeveloped  -   -   2,949   2,275   100   72   592   451  
Total Proved  89   79   10,859   8,540   344   243   2,243   1,745  
                                   
Probable  28   25   4,890   3,718   124   86   967   731  
                                   
Proved Plus Probable  117   104   15,749   12,258   468   329   3,210   2,476  

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.

19

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, 2004
(CONSTANT PRICES AND COSTS)

  Before Income Tax(1)(2)   After Income Tax(1)(2)  
US$'s  Discounted at %/yr   Discounted at %/yr  
$MM  0%   5%   10%   15%   20%   0%   5%   10%   15%   20%  
                                         
Proved                     
                                         
Developed producing  73.4   63.4   56.5   51.3   47.1   71.2   62.1   55.6   50.7   46.7  
Developed non-producing  7.4   8.7   8.7   8.4   7.9   5.1   6.3   6.4   6.3   6.0  
Undeveloped  21.3   16.9   13.6   11.0   8.8   17.0   13.5   10.8   8.6   6.9  
Total Proved  102.1   89.0   78.8   70.7   64.0   93.4   81.8   72.9   65.6   59.6  
Probable  51.5   40.5   33.2   28.0   23.9   44.3   35.3   29.2   24.6   21.2  
                                         
Total Proved Plus Probable  153.5   129.5   112.1   98.6   87.9   137.7   117.1   102.0   90.3   80.8  

NET PRESENT VALUES OF FUTURE NET REVENUES

YEMEN
AS AT DECEMBER 31, 2004
(CONSTANT PRICES AND COSTS)

  Before Income Tax(1)   After Income Tax(1)  
US$'s  Discounted at %/yr   Discounted at %/yr  
$MM  0%   5%   10%   15%   20%   0%   5%   10%   15%   20%  
                                         
Proved                     
                                         
Developed producing  40.3   37.6   35.2   33.1   31.1   40.3   37.6   35.2   33.1   31.1  
Developed non-producing  1.4   1.4   1.3   1.3   1.2   1.4   1.4   1.3   1.3   1.2  
Undeveloped  7.6   6.3   5.1   4.1   3.2   7.6   6.3   5.1   4.1   3.2  
Total Proved  49.2   45.3   41.6   38.4   35.6   49.2   45.3   41.6   38.4   35.6  
Probable  29.1   24.5   20.8   17.9   15.5   29.1   24.5   20.8   17.9   15.5  
                                         
Total Proved Plus Probable  78.5   69.8   62.5   56.3   51.1   78.5   69.8   62.5   56.3   51.1  

20

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS AT DECEMBER 31, 2004
(CONSTANT PRICES AND COSTS)

  Before Income Tax(2)   After Income Tax(2)  
US$'s  Discounted at %/yr   Discounted at %/yr  
$MM  0%   5%   10%   15%   20%   0%   5%   10%   15%   20%  
                                         
Proved                     
                                         
Developed producing  33.1   25.8   21.3   18.2   16.0   30.9   24.4   20.4   17.6   15.6  
Developed non-producing  6.0   7.3   7.4   7.1   6.7   3.7   4.9   5.1   5.0   4.8  
Undeveloped  13.7   10.7   8.5   6.9   5.7   9.4   7.2   5.7   4.6   3.7  
Total Proved  52.8   43.7   37.2   32.3   28.4   44.0   36.5   31.2   27.2   24.1  
Probable  22.3   16.0   12.4   10.1   8.4   15.2   10.8   8.3   6.7   5.6  
                                         
Total Proved Plus Probable  75.0   59.7   49.6   42.3   36.8   59.2   47.3   39.5   33.9   29.7  

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, 2004 exchange rates of 1.2020 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

US$'s  NET PRESENT VALUE OF ALBERTA ROYALTY TAX CREDITS
CANADA
AS AT DECEMBER 31, 2004
(CONSTANT PRICES AND COSTS)
Future Cash Flow as of December 31, 2004
$M  Discounted at %/yr
Reserve Category  0%   5%   10%   15%   20%
                   
Proved Developed         
     Producing  1,273   1,086   943   830   740
     Non-Producing  476   451   422   392   364
Proved Undeveloped  428   343   276   226   186
Total Proved  2,177   1,880   1,641   1,448   1,290
                   
Probable  647   482   364   276   211
                   
Total Proved + Probable  2,824   2,362   2,005   1,724   1,501

21

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2004
(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)    175.0    64.6    24.9    11.4    -    74.1    24.8    49.4 
        Canada(2)    82.8    14.9    12.7    1.9    0.6    52.8    8.8    44.0 
Total Company    257.8    79.5    37.5    13.4    0.6    126.9    33.5    93.4 
                                 
Proved Plus Probable Reserves                                 
        Yemen(1)    284.9    116.0    37.0    12.5    -    119.3    40.9    78.5 
        Canada(2)    118.1    22.0    18.1    2.3    0.6    75.1    15.8    59.2 
Total Company    403.0    138.1    55.1    14.8    0.6    194.4    56.7    137.7 

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, 2004 exchange rates of 1.202 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, 2004
(CONSTANT PRICES AND COSTS)

      Yemen   Canada    
      Future net Revenue   Future net Revenue   Total Company 
      Before Income   Before Income   Future net Revenue 
        Taxes (1)   Taxes (2)   Before Income Taxes 
      (discounted at   (discounted at   (discounted at 
      10%/year)   10%/year)   10%/year) 
Reserves Category    Product Group  (US$MM)   (US$MM)   (US$MM) 
                 
Proved Reserves    Light and Medium Crude Oil (including solution gas and other by-products) 41.6

  9.0   50.7 
    Natural Gas (including by-products but excluding solution gas) -   26.5   26.5 
                 
Proved Plus Probable 
Reserves  		  Light and Medium Crude Oil (including solution gas and other by-products) 62.5

   11.6   74.1 
    Natural Gas (including by-products but excluding solution gas) -   35.9   35.9 

Notes:

(1)     
In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
   
(2)     
Canadian values converted to US dollars at the December 31, 2004 exchange rates of 1.2020 US $'s/Cdn $'s and do not include the Alberta Royalty Tax Credit (ARTC) in the Before Income Tax values.

22

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
TOTAL COMPANY
AS OF DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

  Light & Medium Crude              
  Oil   Natural Gas   Natural Gas Liquids   Total boe's  
    Gross (1)   Net(2)   Gross (1)   Net(2)   Gross (1)   Net(2)   Gross (1)   Net(2)  
By Category  (Mbbls)   (Mbbls)   (MMcf)   (MMcf)   (Mbbls)   (Mbbls)   (MBoe)   (MBoe)  
Proved                 
     Producing  2,822   1,882   6,679   5,372   139   99   4,074   2,876  
     Non-Producing  134   76   1,232   883   105   73   444   297  
     Undeveloped  1,555   1,004   2,949   2,270   100   73   2,147   1,455  
Total Proved  4,511   2,962   10,860   8,525   344   245   6,665   4,628  
                                   
Probable  2,823   1,582   4,892   3,713   124   86   3,762   2,288  
                                   
Proved Plus Probable  7,334   4,545   15,752   12,238   468   331   10,427   6,916  

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS OF DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

  Light & Medium Crude              
  Oil   Natural Gas   Natural Gas Liquids   Total boe's  
    Gross (1)   Net(2)   Gross (1)   Net(2)   Gross (1)   Net(2)   Gross (1)   Net(2)  
By Category  (Mbbls)   (Mbbls)   (MMcf)    (MMcf)    (Mbbls)    (Mbbls)  (MBoe)   (MBoe)  
Proved                       
     Producing  2,748   1,816   -         -    -         -  2,748   1,816  
     Non-Producing  119   63   -         -    -         -  119   63  
     Undeveloped  1,554   1,004   -         -    -         -  1,554   1,004  
Total Proved  4,421   2,884   -         -    -         -  4,421   2,884  
                                   
Probable  2,796   1,557   -         -    -         -  2,796   1,557  
                                   
Proved Plus Probable  7,217   4,441   -         -    -         -  7,217   4,441  

23

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS OF DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

  Light & Medium Crude              
  Oil   Natural Gas   Natural Gas Liquids   Total boe's  
    Gross (1)   Net(2)   Gross (1)   Net(2)   Gross (1)   Net(2)   Gross (1)   Net(2)  
By Category  (Mbbls)   (Mbbls)   (MMcf)   (MMcf)   (Mbbls)   (Mbbls)   (MBoe)   (MBoe)  
Proved                 
     Producing  74   66   6,679   5,372   139   99   1,326   1,060  
     Non-Producing  15   13   1,232   883   105   73   325   234  
     Undeveloped  -   -   2,949   2,270   100   73   592   451  
Total Proved  89   79   10,860   8,525   344   245   2,243   1,745  
                                   
Probable  28   25   4,892   3,713   124   86   967   730  
                                   
Proved Plus Probable  117   104   15,752   12,238   468   331   3,210   2,475  

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.

NET PRESENT VALUES OF FUTURE NET REVENUES
TOTAL COMPANY
AS OF DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

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

  Before Income Tax(1)(2)   After Income Tax(1)(2)  
US$'s  Discounted at %/yr   Discounted at %/yr  
$MM  0%   5%   10%   15%   20%   0%   5%   10%   15%   20%  
                                         
Proved                     
                                         
Developed producing  63.5   55.7   50.4   46.3   43.1   63.0   55.5   50.3   46.3   43.1  
Developed non-producing  6.1   7.5   7.7   7.5   7.1   3.9   5.3   5.7   5.7   5.6  
Undeveloped  17.3   13.8   11.1   8.9   7.2   14.1   11.2   8.9   7.1   5.6  
Total Proved  86.9   76.9   69.1   62.7   57.4   81.1   72.0   64.9   59.1   54.3  
Probable  40.5   32.2   26.8   22.9   19.9   34.9   28.0   23.5   20.2   17.6  
                                         
Total Proved Plus Probable  127.4   109.1   95.9   85.7   77.3   115.9   100.0   88.4   79.3   71.9  

24

NET PRESENT VALUES OF FUTURE NET REVENUES
YEMEN
AS OF DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

  Before Income Tax(1)   After Income Tax(1)  
US$'s  Discounted at %/yr   Discounted at %/yr  
$MM  0%   5%   10%   15%   20%   0%   5%   10%   15%   20%  
                                         
Proved                     
                                         
Developed producing  35.5   33.6   31.9   30.3   28.8   35.5   33.6   31.9   30.3   28.8  
Developed non-producing  1.3   1.2   1.2   1.2   1.2   1.3   1.2   1.2   1.2   1.2  
Undeveloped  6.7   5.5   4.4   3.5   2.6   6.7   5.5   4.4   3.5   2.6  
Total Proved  43.5   40.3   37.5   34.9   32.6   43.5   40.3   37.5   34.9   32.6  
Probable  22.2   19.1   16.6   14.5   12.8   22.2   19.1   16.6   14.5   12.8  
                                         
Total Proved Plus Probable  65.7   59.4   54.1   49.4   45.4   65.7   59.4   54.1   49.4   45.4  

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS OF DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

  Before Income Tax(2)   After Income Tax(2)  
US$'s  Discounted at %/yr   Discounted at %/yr  
$MM  0%   5%   10%   15%   20%   0%   5%   10%   15%   20%  
                                         
Proved                     
                                         
Developed producing  28.0   22.0   18.5   16.1   14.3   27.5   21.8   18.4   16.0   14.3  
Developed non-producing  4.9   6.2   6.4   6.3   6.0   2.7   4.1   4.5   4.5   4.4  
Undeveloped  10.6   8.3   6.7   5.5   4.5   7.4   5.7   4.5   3.6   3.0  
Total Proved  43.4   36.6   31.6   27.8   24.8   37.6   31.7   27.4   24.2   21.6  
Probable  18.3   13.1   10.2   8.4   7.1   12.7   8.9   6.9   5.7   4.8  
                                         
Total Proved Plus Probable  61.7   49.7   41.8   36.2   31.9   50.2   40.6   34.3   29.8   26.4  

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, 2004 exchange rates of 1.2020 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

25

US$'s  NET PRESENT VALUE OF ALBERTA ROYALTY TAX CREDITS
CANADA
AS AT DECEMBER 31, 2004
(FORECAST PRICE CASE)
Future Cash Flow as of December 31, 2004 		 
$M  Discounted at %/yr  
Reserve Category  0%   5%   10%   15%   20%  
                     
Proved Developed           
     Producing  1,091   943   828   737   663  
     Non-Producing  411   395   373   351   329  
Proved Undeveloped  358   292   243   203   171  
Total Proved  1,860   1,630   1,444   1,291   1,163  
                     
Probable  553   424   328   256   202  
                     
Total Proved + Probable  2,413   2,054   1,772   1,547   1,365  

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

                        Future        Future 
                        Net        Net 
                        Revenue        Revenue 
                    Well    Before        After 
            Operating    Development    Abandonment    Income    Income    Income 
    Revenue    Royalties    Costs    Costs    Costs    Taxes    Taxes    Taxes 
Reserves Category    (US$MM)   (US$MM)   (US$MM)   (US$MM)   (US$MM)    (US$MM)   (US$MM)   (US$MM)
                                 
Proved Reserves                                 
        Yemen(1)    158.1    55.1    25.9    11.5    -    65.5     22.0    43.5 
        Canada(2)    72.2    12.4    13.8    1.9    0.7    43.4    5.8    37.6 
Total Company    230.3    67.5    39.7    13.4    0.7    108.9    27.9    81.1 
                                 
Proved Plus Probable                                 
Reserves                                 
        Yemen(1)    246.0    94.1    39.4    12.6    -    99.9     34.2    65.7 
        Canada(2)    103.4    18.4    20.2    2.3    0.7    61.7    11.5    50.2 
Total Company    349.4    112.5    59.6    14.9    0.7    161.6    45.7    115.9 

Notes:

(1)     
In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)     
Canadian values converted to US dollars at the December 31, 2004 exchange rates of 1.2020 US $'s/Cdn $'s and include the Alberta Royalty Tax Credit (ARTC) in the Before and After Income Tax values.

26

TOTAL FUTURE NET REVENUES
BY PRODUCTION GROUP
AS AT DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

      Yemen   Canada   Total Company  
      Future net Revenue   Future net Revenue   Future net Revenue  
      Before Income   Before Income   Before Income  
        Taxes(1)   Taxes(2)   Taxes(1)  
      (discounted at   (discounted at   (discounted at  
      15%/year)   15%/year)   15%/year)  
Reserves Category    Product Group  (US$MM)   (US$MM)   (US$MM)  
                   
Proved Reserves    Light and Medium Crude Oil (including solution gas and other by-products)  34.9   6.0   40.9  
    Natural Gas (including by-products but excluding solution gas)    20.5   20.5  
           
Proved Plus Probable Reserves    Light and Medium Crude Oil (including solution gas and other by-products)  49.4   7.5   57.0  
    Natural Gas (including by-products but excluding solution gas)    27.2   27.2  

Notes:

(1)     
In Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Yemen Future Net Revenues are after Yemen income tax.
(2)     
Canadian values converted to US dollars at the December 31, 2004 exchange rates of 1.2020 US $'s/Cdn $'s and do not include the Alberta Royalty Tax Credit (ARTC) in the Before Income Tax values.

Notes to Reserves Data Tables:

1.     
Columns may not add due to rounding.
 
2.     
The crude oil, natural gas liquids and natural gas reserve estimates presented in the DeGolyer and Fekete Reports are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.
 
 
"Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
 
 
(a)     
gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, pumping equipment and wellhead assembly;
 
 
(b)     
drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;
 
 
(c)     
acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and
 
 
(d)     
provide improved recovery systems.
 
 
"Exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Exploration

27

 
costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
 
 
(a)     
costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies;
 
 
(b)     
costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
 
 
(c)     
dry hole contributions and bottom hole contributions;
 
 
(d)     
costs of drilling and equipping exploratory wells; and
 
 
(e)     
costs of drilling exploratory type stratigraphic test wells.
 
   
Reserve Categories
 
   
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on
 
   
•
 analysis of drilling, geological, geophysical and engineering data;
   
•
 the use of established technology; and
   
•
 specified economic conditions which are generally accepted as being reasonable.
 
    Reserves are classified according to the degree of certainty associated with the estimates.
   
(a)     
Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
 
(b)     
Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
 
 
Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.
 
 
Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:
 
(c)     
Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
 
 
(i)     
Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable 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

28

 
them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.
     
 
In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
     
 
Levels of Certainty for Reported Reserves
     
 
The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:
     
  (a)
at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
  (b)
at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.
     
 
A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
     
 
Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.
     
3.     
Forecast Prices and Costs
     
 
The forecast cost and price assumptions assume changes in wellhead selling prices and take into account inflation with respect to future operating and capital costs.
     
 
For the Reserves, crude oil and natural gas benchmark reference pricing, as at December 31, 2004, inflation and exchange rates utilized by DeGolyer in the DeGolyer Report, which were DeGolyer's then current forecasts at the date of the DeGolyer Report, were as follows:

    Crude Oil                 
    WTI Cushing    Edmonton Par  Natural Gas AECO    Natural Gas Liquids  Inflation   Exchange
    Oklahoma    Price 40° API  Spot Gas Price    FOB Edmonton    Rates(1)   Rate(2)
Year    (US$/bbl)    (Cdn$/bbl)  (Cdn$/Mcf)    (Cdn$/bbl)  % Year   (Cdn$/US$)
              Condensate    Butane    Propane   
Forecast                         
2005    45.00    54.00  6.87    55.08    39.42    34.56  0   0.81
2006    40.80    48.78  6.67    49.76    35.61    31.22  2.0   0.81
2007    36.41    43.34  6.45    44.20    30.33    27.73  2.0   0.81
2008    34.49    40.93  5.87    41.75    28.65    26.19  2.0   0.81
2009    32.47    38.40  5.51    39.17    26.88    24.58  2.0   0.81
2010    33.12    39.17  5.42    39.96    27.42    25.07  2.0   0.81
Thereafter    +2%/year    +2%/year    +1.1%/yr to 12    +2%/year    +2%/year    +2%/year  +2%/year   +0%/year
            +1.5%/yr to 16               
          +2.0%/yr thereafter               

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

29

 
The weighted average historical price in US $'s realized by the Company in Yemen, for the year ended December 31, 2004 for crude oil was $36.33/bbl.
 
 
The weighted average historical prices in Cdn $'s realized by the Company in Canada, for the year ended December 31, 2004, were $6.75/mcf for natural gas, $49.89/bbl for crude oil and $40.83/bbl for natural gas liquids.
 
4.     
Constant Prices and Costs
 
 
In Yemen, a constant price of $39.58/bbl (December 2004 actual prices) was utilized in the constant price case.
 
 
In Canada, constant prices of $37.05/bbl of oil and $5.93/Mcf of natural gas (December 2004 actual prices converted to US $'s at the December 31, 2004 currency rate of 1.2020 US$/Cdn$), were utilized in the constant price case.
 
5.     
Future Development Costs

FUTURE DEVELOPMENT COSTS
TOTAL COMPANY(1)
AS AT DECEMBER 31, 2004

  (US$ millions)  Constant Prices and Costs    Forecast Prices and Costs 
        Proved Plus        Proved Plus 
    Proved    Probable    Proved    Probable 
  Year  Reserves    Reserves    Reserves    Reserves 
  2005  11.9    13.0    11.8    13.0 
  2006  0.8    0.8    0.9    0.9 
  2007  0.2    0.1    0.2    0.1 
  2008  0.1    0.1    0.1    0.1 
                 
  Total Undiscounted  13.4    14.8    13.4    14.9 
                 
  Total Discounted at 10%  12.4    13.7    12.5    13.7 

  Note:
     
  (1)      Cdn$'s converted at the December 31, 2004 year end rate of 1.2020 US$/Cdn$.

FUTURE DEVELOPMENT
COSTS YEMEN
AS AT DECEMBER 31, 2004

  (US$ millions)  Constant Prices and Costs    Forecast Prices and Costs 
        Proved Plus        Proved Plus 
    Proved    Probable    Proved    Probable 
  Year  Reserves    Reserves    Reserves    Reserves 
  2005  10.0    11.0    10.0    11.0 
  2006  0.8    0.8    0.8    0.8 
  2007  0.1    0.1    0.1    0.1 
  2008  0.1    0.1    0.1    0.1 
                 
  Total Undiscounted  11.4    12.5    11.5    12.6 
                 
  Total Discounted at 10%  10.6    11.6    10.7    11.6 

30

FUTURE DEVELOPMENT COSTS
CANADA(1)
AS AT DECEMBER 31, 2004

  (US$ millions)   Constant Prices and Costs     Forecast Prices and Costs 
        Proved Plus        Proved Plus 
    Proved    Probable    Proved    Probable 
  Year  Reserves    Reserves    Reserves    Reserves 
  2005  1.8    2.1             1.8               2.1 
  2006  0.1    0.1             0.1               0.1 
  2007  0    0             0               0 
  2008  0    0             0               0 
                 
  Total Undiscounted  1.9    2.3             1.9               2.5 
                 
  Total Discounted at 10%  1.8    2.1             1.8               2.1 

  Note:
     
  (1)      Cdn$'s converted at the December 31, 2004 year-end rate of 1.2020 US$/Cdn$.

 
The Company expects to fund the future development costs noted above through the use of working capital, cash flow, debt and equity financing as required.
 
6.     
The Alberta royalty tax credit ("ARTC") is included in the cumulative cash flow amounts. ARTC is based on the program announced November 1989 by the Alberta government with modifications effective January 1, 1995. The estimated Net Present Value of the Alberta Royalty Tax Credit for both the Constant Price and Forecast Price cases, is presented as a separate table for the respective price cases.
 
7.     
In Yemen, estimated future abandonment and reclamations costs related to properties evaluated have not been taken into account by DeGolyer in determining the aggregate future net revenue therefrom. Under the terms of the production sharing agreements, ownership in the facilities and wells is transferred to the Government of Yemen through cost recovery. Therefore the future abandonment and reclamation costs have been assessed a zero value.
 
 
In Canada, estimated future abandonment and reclamation costs related to a property have been taken into account by DeGolyer in determining reserves that should be attributed to a property and in determining the aggregate future net revenue therefrom, there was deducted the reasonable estimated future well abandonment costs. No allowance was made, however, for reclamation of wellsites or the abandonment and reclamation of any facilities.
 
8.     
Both the constant and forecast price and cost assumptions assume the continuance of current laws and regulations.
 
9.     
The extent and character of all factual data supplied to DeGolyer was accepted by DeGolyer as represented. No field inspections were conducted by DeGolyer.

31

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, 2004
(FORECAST PRICES AND COSTS)

        ASSOCIATED & NON-        
  LIGHT & MEDIUM OIL   ASSOCIATED GAS   NATURAL GAS LIQUIDS  
      Net       Net       Net  
      Proved       Proved       Proved  
  Net   Net   Plus   Net      Net      Plus   Net   Net   Plus  
  Proved   Probable   Probable   Proved   Probable   Probable   Proved   Probable   Probable  
FACTORS  (MBbl)   (MBbl)   (MBbl)   (MMcf)   (MMcf)   (MMcf)   (MBbl)   (MBbl)   (MBbl)  
December 31, 2003  1,549   1,588   3,137   5,498   3,893   9,391   158   85   242  
Extensions                   
Improved recovery                   
Technical Revisions  100   624   724   (106 )  (2,160 )  (2,266 )  34   (48 )  (14 ) 
Discoveries  2,027   (630 )  1,397   3,980   1,976   5,956   80   50   130  
Acquisitions                   
Dispositions                   
Economic Factors  (1 )  -   (1 )  12   5   17   (1 )  -   (1 ) 
Production  (713 )  -   (713 )  (859 )  -   (859 )  (26 )  -   (26 ) 
December 31, 2004  2,962   1,582   4,545   8,525   3,713   12,239   245   87   331  

RECONCILIATION OF NET RESERVES
(AFTER ROYALTIES/BEFORE TAXES)
BY PRINCIPAL PRODUCT TYPE
YEMEN
AS AT DECEMBER 31, 2004
(FORECAST PRICES AND COSTS)

        ASSOCIATED & NON-             
  LIGHT & MEDIUM OIL   ASSOCIATED GAS    NATURAL GAS LIQUIDS 
      Net           Net           Net 
      Proved           Proved           Proved 
  Net   Net   Plus   Net    Net    Plus   Net    Net    Plus 
  Proved   Probable   Probable   Proved    Probable    Probable   Proved    Probable    Probable 
FACTORS  (MBbl)   (MBbl)   (MBbl)   (MMcf)    (MMcf)    (MMcf)   (MBbl)    (MBbl)    (MBbl) 
December 31, 2003  1,476   1,576   3,052   -    -    -    -    -    - 
Extensions                             
Improved recovery                             
Technical Revisions  82   617   699                        
Discoveries  2,011   (636 )  1,375                        
Acquisitions                             
Dispositions                             
Economic Factors                             
Production  (685 )  -   (685 )                       
December 31, 2004  2,884   1,557   4,441   -    -    -    -    -    - 

32

RECONCILIATION OF NET RESERVES
(AFTER ROYALTIES/BEFORE TAXES)
BY PRINCIPAL PRODUCT TYPE
CANADA
AS AT DECEMBER 31, 2004
(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)  
January 1, 2004  74   12    85   5,498   3,893   9,391   158   85   242  
Extensions                   
Improved recovery                   
Technical Revisions  18   7    25   (106 )  (2,160 )  (2,266 )  34   (48 )  (14 ) 
Discoveries  16   7    23   3,980   1,976   5,956   80   50   130  
Acquisitions                   
Dispositions                   
Economic Factors        12   5   17   (1 )  -   (1 ) 
Production  (28 )  -    (28 )  (859 )  -   (859 )  (26 )  -   (26 ) 
December 31, 2004  79   25    104   8,525   3,713   12,239   245   87   331  

     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)  
  2004   2004   2004  
US$'s  ($M)   ($M)   ($M)  
Estimated Future Net Revenue at beginning of year  18,701   15,683   34,384  
Sales and transfers of oil and gas produced, net of production costs and royalties  (5,049 )  (14,248 )  (19,297 ) 
Net change in prices, production costs and royalties related to future production  4,837   15,538   20,375  
Changes in previously estimated development costs incurred during the period  672   12,511   13,183  
Changes in estimated future development costs  (771 )  (13,373 )  (14,144 ) 
Extensions and improved recovery  -   -   -  
Discoveries  14,812   30,025   44,837  
Acquisitions of reserves  -   -   -  
Dispositions of reserves  -   -   -  
Net change resulting from revisions in quantity estimates  811   2,124   2,935  
Accretion of discount  2,362   1,192   3,554  
Net change in income taxes  (3,647 )  (2,510 )  (6,157 ) 
Other (value of production in disposed and acquired properties, changes in timing of       
       future production)  (1,520 )  (5,299 )  (6,819 ) 
             
Estimated Future Net Revenue at end of year  31,207   41,644   72,851  

Note:

(1)     
In Canada values were converted to US currency using the following currency exchange rates: December 31, 2003 at 1.2965 $US/$Cdn, December 31, 2004 at 1.2020 $US/$Cdn. Sale and transfers of oil and gas produced, net of production costs and royalties at Booked values for the year end at the 2004 year average exchange rate of 1.3013 $US/$Cdn for all other changes. The estimated Future Net Revenues include ARTC.

Additional Information Relating to Reserves Data

Undeveloped Reserves

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

33

Proved Undeveloped Reserves

  Light and Medium Oil    Natural Gas    Natural Gas Liquids 
  Year   (MBbl)    (MMcf)    (MBbl) 
  First    Cumulative at    First    Cumulative    First    Cumulative 
  Attributed    Year End    Attributed    at Year End    Attributed    at Year End 
                           
  2003(1)   —    —    1,422    1,422         58    58 
  2004(2)   1,554    1,554    1,758    2,949         51    100 

  Notes:
     
  (1)     
Prior to 2003, the Company did not have any proved undeveloped reserves. All the Proved Undeveloped reserves assigned in 2003 were in Canada, and relate to the Wabamum formation in the Nevis area. Proved reserves were assigned to 320 acres of the 640 acres gas spacing unit/ well. The remaining 320 acres/well were assigned Proved Undeveloped reserves. It was anticipated that a down space application to 320 acres/well would be approved in 2004, with drilling to occur in 2004 & 2005. The wells are scheduled to be drilled in 2005 and 2006.
     
  (2)     
In 2004, all the Proved Undeveloped light oil was assigned to Yemen, with four horizontal development wells in the An Nagyah field in Block S-1 and one development vertical well in the Tasour field in Block 32, all five wells are scheduled for 2005. All the Proved Undeveloped gas and liquid reserves were assigned to Canada. In the Nevis area, proved undeveloped reserves were assigned to one additional Wabamum down space (320 acres/well) and one well to accelerate production from a well which encountered four gas zones. Both wells are scheduled for 2005.
     
    Probable Undeveloped Reserves

  Light and Medium Oil    Natural Gas    Natural Gas Liquids 
  Year   (MBbl)    (MMcf)    (MBbl) 
  First    Cumulative    First    Cumulative    First    Cumulative at 
  Attributed   at Year End    Attributed    at Year End    Attributed   Year End 
                           
                           
  2000   —    —    271    271         —             — 
  2001   —    —    —    271         —             — 
  2002   —    —    —    224         —             — 
  2003(1)   2,342    2,342    1,328    1,629         55             55 
  2004(2)   1,111    1,111    256    577         —             13 

  Notes:
     
  (1)     
In 2003, Probable Undeveloped Reserves were assigned in Yemen and Canada. The light oil reserves were assigned to a portion of the mapped An Nagyah light oil discovery on Block S-1 in Yemen. During 2004, 8 successful oil wells were drilled in the An Nagyah field and placed on production. The An Nagyah reserves have been upgraded to proved producing and proved developed. The Natural Gas reserves and associated liquids were assigned in Canada, and generally related to the Wabamum formation in the Nevis area. Proved reserves were assigned to 320 acres of the 640 acres gas spacing unit/ well. The remaining 320 acres/well were assigned Proved Undeveloped reserves. Probable Undeveloped reserves were assigned to one well which was scheduled to be drilled in 2004 & 2005. The well location has been upgraded to Proved Undeveloped in 2004.
   
     
  (2)     
In 2004, Probable Undeveloped reserves were assigned in Yemen and Canada. All the light oil reserves were assigned in Yemen, relating to; 2 planned wells in the Tasour field on Block 32 and performance associated with Proved Undeveloped wells planned in the Tasour field (1 well) and the An Nagyah field (4 horizontal wells). All the Yemen wells are scheduled for 2005 and 2006. All the Probable Undeveloped natural gas and natural gas liquids were assigned in Canada and relate to additional performance from planned Proved Undeveloped wells in the Nevis area (4 Wabamum gas wells and 1 Manville gas well). All the Canadian wells are scheduled for 2005 and 2006.

34

Other Oil and Gas Information

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Company has a working interest as at December 31, 2004. All of the Company's wells are located onshore.

  Oil Wells    Natural Gas Wells 
  Producing    Non-Producing    Producing    Non-Producing 
  Gross    Net    Gross    Net    Gross    Net    Gross    Net 
                               
Yemen  20    3.9                       3    0.6    0    0    3    0.8 
Canada, Alberta  9    4.7                       5    2.6    17    12.4    10    7.4 
Total  29    8.6                       8    3.2    17    12.4    13    8.2 

Properties with no Attributable Reserves

The following table sets out the Company's developed and undeveloped land holdings as at December 31, 2004.

  Developed Acres    Undeveloped Acres    Total Acres 
  Gross    Net    Gross         Net    Gross    Net 
                       
Yemen  16,740    3,404    414,030    87,945    430,770    91,349 
Canada, Alberta  18,661    12,404    33,321    23,662    51,982    36,066 
Egypt  0    0    7,500,000    3,750,000    7,500,000    3,750,000 
Total  35,401    15,808    7,947,351    3,861,607    7,982,752    3,877,415 

Of the Company's undeveloped land, the rights to explore, develop and exploit 640 net acres may expire in Canada by December 31, 2005. The Company does not have any work commitments associated with its undeveloped lands in Yemen or Canada. In Egypt, the Company has work commitments of $2MM in Phase 1 (2 years expiring July 16, 2006) and $4MM in Phase 2 (3 years expiring July 16, 2009).

In Yemen, the Block 72 undeveloped land of 450,234 gross acres (150,028 net acres) is not included in the Company's land holdings as at December 31, 2004. The Block 72 PSA was awarded in the 2004 International Bid Round, signed by Cabinet and is before the Yemen Parliament for final approval.

35

Forward Contracts

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

•
In March 2005, the Company entered into a fixed price contract to sell 2,000 gigajoules (GJ) per day (approximately 2,000 Mcfpd) of natural gas in Canada for the month of April and from June 1 to October 31, 2005 at Cdn$6.95/GJ.
   
•
In June 2004, the Company entered into a one year fixed price contract to sell 10,000 barrels of oil per month in Block 32 commencing July 1, 2004 at $33.90 per barrel for dated Brent plus or minus the Yemen Government's official selling price differential.

Additional Information Concerning Abandonment and Reclamation Costs

In Canada, future well abandonment costs net of salvage were included in the DeGolyer reserves evaluation presented herein. Cost in US $'s to abandon approximately 46 (32.0 net) wells totalled $619 thousand undiscounted, or $330 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 $231 thousand undiscounted, or $191 thousand discounted at 10%, are scheduled during the next 3 years (2005-2007).

Tax Horizon

In 2004, the Company did not pay any income taxes in Canada, except for a large corporation tax of $11,000.

Transglobe does not expect to pay income taxes in the near future assuming the Company incurs further Canadian exploration expense and Canadian development expense and utilizes such tax pools and carry forward tax pools of $26,299,000 available to protect future revenue.

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, 2004:

  Yemen    Canada    Egypt    Total 
($ thousands)               
Property acquisition costs               
       Proved properties  -     -       -    - 
       Undeveloped properties  -    1,469       -    1,469 
Exploration costs  2,115    4,790       540    7,445 
Development costs  12,473    3,711       -    16,184 
Corporate and other  687    130       452    1,269 
Total  15,275    10,100       992    26,367 

36

Production Estimates

The following table sets out the volume of the Company's daily production (working interest before royalties) estimated for the year ended December 31, 2005 which is reflected in the estimate of future net revenue disclosed in the Forecast Prices and Costs and Constant Prices and Costs tables contained under " - Disclosure of Reserves Data".

  Yemen    Yemen                 
  Block 32    Block S-1    Canada        Canada    Total 
  Light and    Light and    Light and    Canada    Natural Gas    Company 
  Medium Oil    Medium Oil    Medium Oil    Natural Gas    Liquids    BOE 
  Gross (bbls/d)    Gross (bbls/d)    Gross (bbls/d)    Gross (Mcf/d)    Gross (bbls/d)    Gross (BOE/d) 
Proved Producing  1,726    1,658    82    3,249    79    4,086 
Proved Developed                       
Non-Producing  255    0    0    2,088    71    674 
Proved Undeveloped  30    107    0    263    0    181 
Total Proved  2,011    1,764    82    5,600    151    4,941 
Total Probable  137    208    3    1,307    32    598 
Total Proved Plus Probable  2,148    1,973    85    6,907    183    5,539 

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, 2004:

Yemen:  Gross    Net 
  Exploration    Development    Total    Exploration    Development    Total 
Natural Gas  -    -    -    -    -    - 
Crude Oil  -    12    12    -    2.7    2.7 
Dry and Abandoned(1)  1    -    1    0.3    -    0.3 
Total  1    12    13    0.3    2.7    3.0 
                       
                       
Canada:  Gross    Net 
  Exploration    Development    Total    Exploration    Development    Total 
Natural Gas  4    6    10    3.7    3.6    7.3 
Crude Oil  2    -    2    1.7    -    1.7 
Dry and Abandoned(1)  3    -    3    2.5    -    2.5 
Total  9    6    15    7.9    3.6    11.5 

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.

37

Production History

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

  2004 
  Quarter Ended 
  Mar. 31    Jun. 30    Sep. 30    Dec. 31 
Average Daily Sales Volumes               
Yemen               
      Light and Medium Crude Oil (bbls/d)  2,290    2,618    3,072    4,483 
Canada               
      Light and Medium Crude Oil (bbls/d)  66    60    100    115 
      Gas (Mcf/d)  2,008    2,114    3,865    3,942 
      NGL (bbls/d)  69    73    102    128 
Combined (BOE/d)  2,760    3,103    3,918    5,384 
               
Average Price Received               
Yemen               
      Light and Medium Crude Oil ($/bbl)  31.56    34.81    38.72    37.97 
Canada               
      Light and Medium Crude Oil ($/bbl)  31.16    37.49    39.50    41.86 
      Gas ($/Mcf)  5.27    5.09    4.92    5.47 
      NGL ($/bbl)  25.75    26.49    32.90    35.90 
Combined ($/BOE)  31.44    34.25    37.12    37.45 
               
Royalties               
Yemen               
      Light and Medium Crude Oil ($/bbl)  8.69    15.32    16.79    15.28 
Canada               
      Light and Medium Crude Oil ($/bbl)  2.97    4.89    3.48    2.88 
      Gas ($/Mcf)  0.96    0.94    0.86    1.03 
      NGL ($/bbl)  3.86    5.26    7.67    7.03 
Combined ($/BOE)  8.08    13.78    14.30    13.71 
               
Operating Expenses               
Yemen               
      Light and Medium Crude Oil ($/bbls)  4.14    4.42    4.79    5.29 
Canada               
      Light and Medium Crude Oil ($/bbls)  8.97    6.82    9.66    10.88 
      Gas ($/Mcf)  1.15    1.37    0.93    1.43 
      NGL ($/bbls)  -    -    -    - 
Combined ($/BOE)  4.49    4.79    4.91    5.68 
               
Netback Received               
Yemen               
      Light and Medium Crude Oil ($/bbl)  18.73    15.07    17.14    17.40 
Canada               
      Light and Medium Crude Oil ($/bbl)  19.22    25.78    26.36    28.10 
      Gas ($/Mcf)  3.16    2.78    3.13    3.01 
      NGL ($/bbl)  21.89    21.23    25.23    28.87 
Combined ($/boe)  18.87    15.68    17.91    18.06 

The following table indicates the Company's average daily sales volumes from its important fields for the year ended December 31, 2004.

  Light and Medium Crude    Gas    NGL's    boe 
  (bbls/d)    (Mcf/d)    (bbls/d)    (boe/d) 
               
Yemen               
      Block 32  2,453    -         -    2,453 
      Block S-1  666    -         -    666 
Canada  86    2,987         93    677 
               
Total  3,205    2,987         93    3,796 

38

DIVIDEND POLICY

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

DESCRIPTION OF SHARE CAPITAL

We are authorized to issue an unlimited number of Common Shares and an unlimited number of preferred shares

("Preferred Shares"). As at March 16, 2005, there were 57,200,939 Common Shares only. In addition, as at such date, there were an aggregate of 5,720,094 Common Shares reserved for issuance upon the exercise of the Company's options.

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

Common Shares

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

Preferred Shares

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

Rights Plan

On April 16, 2003, the Company entered into a shareholder protection rights plan agreement (the "Rights Plan") with Computershare Trust Company of Canada, as rights agent, which was approved by TransGlobe's shareholders on May 29, 2003 at the 2003 annual general and special meeting of shareholders. The Rights Plan generally provides that following any person or entity acquiring 20% or more of the issued and outstanding Common Shares (except pursuant to certain permitted or excepted transactions) and upon the occurrence of certain other events, each holder of Common Shares, other than such person or entity, shall be entitled to acquire Common Shares at a discounted price. The Rights Plan is similar to other shareholder or unitholder rights plans adopted in the energy sector.

39

MARKET FOR SECURITIES

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

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

(Cdn dollars, except volumes)  High    Low    Volume 
2004           
January  4.05    2.85    3,168,600 
February  3.43    2.40    2,262,800 
March  3.93    2.95    1,283,600 
April  3.93    3.12    1,148,400 
May  3.50    2.79    622,500 
June  3.79    2.70    1,169,800 
July  3.77    3.04    1,026,200 
August  3.35    3.00    564,900 
September  4.34    2.62    1,927,300 
October  5.53    4.07    2,867,800 
November  7.39    4.20    3,921,800 
December  6.52    4.90    1,535,200 

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

(U.S. dollars, except volumes)  High    Low    Volume 
2004           
January  3.14    2.15    10,046,000 
February  2.60    1.83    7,563,000 
March  2.92    2.19    6,424,300 
April  2.99    2.31    6,870,000 
May  2.59    1.98    3,166,600 
June  2.84    2.10    3,246,400 
July  2.86    2.26    4,127,300 
August  2.54    2.28    1,819,000 
September  3.40    2.11    6,500,000 
October  4.47    3.20    9,724,400 
November  5.94    3.56    8,252,700 
December  5.52    4.08    7,331,500 

ESCROWED SECURITIES

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

40

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 (on each case, as at March 15, 2005) is as follows:

             Number of    
      Common  
      Shares  
    Year Became  Beneficially  
Name and Municipality    Director or   Owned or Principal Occupation and Positions 
of Residence  Position Held  Officer   Controlled for the Past Five Years 
         
Robert A. Halpin(1)(2)(4)
 Calgary, AB 		Chairman of the 
Board and Director  		1997  527,585(5)
 (0.9%)
Retired Petroleum Engineer, President and owner, Halpin Energy Resources Ltd., which provides consulting services on international energy projects.
         
Ross G. Clarkson
Calgary, AB 		President, Chief 
Executive Officer 
and Director  		1995  1,974,272(6)
 (3.5%)
President and Chief Executive Officer of the Company since December 4, 1996, with over 29 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  536,000(7)
 (0.9%)
Vice-President and Chief Operating officer of the Company since April 28, 1999, with over 29 years' experience in both domestic and international oil and gas exploration and development.
         
Erwin L. Noyes(2)(3)(4)
 Saanichton, BC 		Director  1995  188,247(8)
 (0.3%)
Retired since July 31, 2000; formerly Vice- President, International Operations of the Company, with over 30 years' experience in the oil and gas industry.
         
Geoffrey C. Chase(1)(3)(4)
 Calgary, AB 		Director  2000  45,000(9)
 (0.1%)
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 C. Ferguson
Calgary, AB 		Vice-President, 
Finance, Chief 
Financial Officer 
and Secretary  		2001  110,000(11)
 (0.2%)
Chartered accountant with over 22 years' experience in the oil and gas industry. Previously Chief Financial Officer with Northstar Drilling Systems Inc. (1999-2000), Chief Financial Officer and a director of Myriad Energy Corporation (1998-1999).
         
Edward Bell
Calgary, AB 		Vice-President, Exploration  2004  136,000(12)
 (0.2%)
Professional Geoscientist with 36 years of experience in the petroleum industry. Prior positions with Nexen as General Manager Business Development and Occidental Petroleum as Technical Advisor.

41

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.
(12)     
Mr. Bell also holds incentive stock options to purchase 150,000 Common Shares at Cdn$3.40 per share expiring January 12, 2009.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

No director or officer of the Company, or a shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company is, or within the last ten years has been, a director, officer or promoter of any reporting issuer that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied us access to any statutory exemption for a period of more than 30 consecutive days or, within a year of such person ceasing to act in that capacity or within the 10 years prior to the date hereof, 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 that person.

No director or officer of the Company, or a shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company, has been subject to any penalties or sanctions under securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or 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.

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 13 full-time employees and 4 part-time consultants. The Company intends to add additional professional and administrative staff as the needs arise.

INTEREST OF EXPERTS

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

42

interests, direct or indirect, in any securities or other property of the Corporation or of our associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them.

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

LEGAL PROCEEDINGS

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

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There were no material interests, direct or indirect, of directors and senior officers of the Company, any shareholder who beneficially owns more than 10% of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transactions since the beginning of the Company's last completed financial year or in any proposed transaction which has materially affected or will materially affect the Company.

AUDITORS, TRANSFER AGENT AND REGISTRAR

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

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

MATERIAL CONTRACTS

Except for contracts entered into by the Corporation in the ordinary course of business or otherwise disclosed herein, the Corporation has no contracts which can reasonably be regarded as material.

AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

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

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

43

Geoffrey C. Chase 
Calgary, AB  		  Yes    Yes   
Mr. Chase received a B.Sc. in Applied Science from Queen's University, Ontario and is a P.Eng. in the Province of Alberta. He has over 35 years of business, executive and international management experience with a major and later a mid-size public petroleum corporation. His activities have involved various aspects of financial planning, budgeting and operations.
             
Fred J. Dyment 
Calgary, AB  		  Yes    Yes   
Mr. Dyment received a Chartered Accountant designation from the Province of Ontario in 1972 and is a member of the Alberta Institute of Chartered Accountants. He has over 30 years of financial, business, executive, international management experience at several mid-size public corporations where he served as President, CEO, CFO and director. Currently, Mr. Dyment sits as a director on several other public companies.

Pre-Approval of Policies and Procedures

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

Audit Committee Charter

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

Audit Service Fees

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

    Fiscal Year         
    Ended    Aggregate     
Type of Fees    December 31    Fees Billed    Nature of Services Performed 
             
             
Audit Fees    2004    Cdn$73,435    2004 corporate year-end audit 
    2003    Cdn$42,665    2003 corporate year-end audit 
             
Audit – Related Fees    2004    Cdn$19,080    2004 Quarterly reviews, S-8 consent letters and review of 
            Alberta Security Commission letter 
    2003    Cdn$15,370    2003 Quarterly reviews 
             
Tax Fees    2004    Cdn$10,282    2004 corporate tax returns and tax compliance 
    2003    Cdn$ 9,500    2003 corporate tax returns and tax compliance 
             
All other fees    2004    Cdn$30,210    Prospectus 
    2003    Cdn$ nil     

RISK FACTORS

General Conditions Relating to Oil and Gas Exploration and Production Operations

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

Industry Risks

The Company is subject to normal industry risks due to the relatively small size of the Company, its level of cash flow, and the nature of the Company's involvement in the exploration for, and the acquisition, development and production of, oil and natural gas. Exploration for oil and natural gas involves many risks, which even a combination

44

of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that further commercial quantities of oil and natural gas will be discovered by the Company.

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

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

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

Exploration and Development

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

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

Competition

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

45

Title to Properties

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

Interests in Properties

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

Government Regulation

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

Political Risks Relating to Yemen and Egypt

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

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

Reliance Upon Officers

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

Multi-jurisdictional Legal Risks

The Company is incorporated under the laws of the Province of Alberta, Canada, and all of the Company's directors and all of its officers are residents of Canada. Consequently, it may be difficult for United States investors to effect service of process within the United States upon the Company or upon those directors or officers, who are not residents of the United States, or to realize in the United States upon judgements of United States courts predicated upon civil liabilities under the Securities Exchange Act of 1934, as amended (United States). Furthermore, it may

46

be difficult for investors to enforce judgements of the U.S. courts based on civil liability provisions of the U.S. federal securities laws in a Canadian court against the Company or any of the Company's non-U.S. resident executive officers or directors. There is substantial doubt whether an original lawsuit could be brought successfully in Canada against any of such persons or the Company predicated solely upon such civil liabilities.

Reserve Information

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

Additional Financing Requirements

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

Canadian Tax Considerations

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

Exchange Rate Risks

The Canadian to US dollar exchange rate has strengthened during 2004 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 general and administrative expenses which are paid for in Canadian dollars.

Dividends

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

Conflicts of Interest

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

47

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 the various levels of government in Canada, Egypt 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 Canada, Egypt and Yemen 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 the province for consumption elsewhere based on such factors as reserve availability, transportation arrangement and market considerations.

48

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 Canadian 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.

49

In Yemen and Egypt, 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 Canada, Egypt and Yemen 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 and options to purchase securities, if applicable, is contained in the Company's Information Circular for the most recent annual meeting of shareholders that involved the election of directors. Additional financial information is provided for in our financial statements and the management's discussion and analysis for the year ended December 31, 2004. Documents affecting the rights of securityholders, along with other information relating to the Company, may be found on SEDAR at www.sedar.com.

SCHEDULE "A"

REPORT ON RESERVES DATA

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

1.     
We have evaluated the Company's reserves data as at December 31, 2004. The reserves data consist of the following:
 
 
(a)     
(i)      proved, proved plus probable and proved plus probable plus possible oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and
 
   
(ii)      the related estimated future net revenue; and
 
 
(b)     
(i)       proved, proved plus probable and proved plus probable plus possible oil and gas reserves estimated as at December 31, 2004 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, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors.

    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 
            U.S. M$    U.S. M$    U.S. M$  U.S. M$ 
                         
DeGolyer and MacNaughton Canada    Appraisal    Canada    -    41,848    -    $41,848 
Limited    Report as of                   
    December 31,    Yemen    -    54,078    -  54,078 
    2004 on    Total    -    95,926    -  95,926 
    Certain                   
    Properties                   
    owned by                   
    Transglobe                   
    Energy                   
    Corporation in                   
    Canada and                   
    Yemen dated                   
    March 16,                   
    2005                   

5.     
In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
   
6.     
We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.

A-2

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:

DeGolyer and MacNaughton Canada Limited, Calgary, Alberta, dated March 16, 2005

  DEGOLYER and MACNAUGHTON CANADA LIMITED
   
   
 

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

 

SCHEDULE "B"

     REPORT OF MANAGEMENT AND DIRECTORS
ON RESERVES DATA AND OTHER INFORMATION

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

(a)  (i) 
proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 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, 2004 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

(a)     
reviewed the Company's procedures for providing information to the independent qualified reserves evaluators;
 
(b)     
met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of each such independent qualified reserves evaluator to report without reservation; and
 
(c)     
reviewed the reserves data with management and 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

(a)     
the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;
 
(b)     
the filing of the report of the independent qualified reserves evaluator on the reserves data; and
 
(c)     
the content and filing of this report.

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

(signed) "Ross Clarkson"  (signed) "Geoffrey Chase" 
Ross Clarkson  Geoffrey Chase 
President, Chief Executive Officer and Director  Director and Chair of the Reserves Committee 
   
(signed) "Lloyd Herrick"   
Lloyd Herrick   
Vice-President, Chief Operating Officer and Director   
   
   
March 16, 2005   

SCHEDULE "C"

AUDIT COMMITTEE CHARTER

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

GENERAL FUNCTIONS, AUTHORITY, AND ROLE

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

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

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

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

MEMBERSHIP

The membership of the Audit Committee will be as follows:

•
The Committee will consist of a minimum of three members of the Board of Directors, appointed annually, each of whom is affirmatively confirmed as independent by the Board of Directors, with such affirmation disclosed in the Company's annual circular.
   
•
The Board will elect, by a majority vote, one member as chairperson
   
•
A member of the Audit Committee may not, other than in his or her capacity as a member of the Audit Committee, the Board of Directors, or any other Board committee, accept any consulting, advisory, or other compensatory fee from the Company, and may not be an affiliated person of the Company or any subsidiary thereof.

RESPONSIBILITIES

The responsibilities of the Audit Committee shall be as follows:

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Frequency of Meetings

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

Reporting Responsibilities

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

Charter Evaluation

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

Whistleblower Mechanisms

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

Independent Auditor

•
Nominate annually the independent auditor to be proposed for shareholder approval. 
     
•
Approve the compensation of the independent auditor, and evaluate the performance of the independent auditor. 
     
•
Establish policies and procedures for the engagement of the independent auditor to provide non-audit services. 
     
•
Insure that the independent auditor is not engaged for any activities not allowed by any of the Canadian provincial securities commissions, the SEC or any securities exchange on which the Company's shares are traded.
     
•
Insure that the auditors are not engaged for any of the following nine types of non-audit services contemporaneous with the audit:
     
  o  Bookkeeping or other services related to accounting records or financial statements of the Company; 
  o  Financial information systems design and implementation; 
  o  Appraisal or valuation services, fairness opinions, or contributions-in-kind reports; 
  o  Actuarial services; 
  o  Internal audit outsourcing services; 
  o  Any management or human resources function; 
  o  Broker, dealer, investment advisor, or investment banking services; 
  o  Legal services; and 
  o  Expert services related to the auditing service. 

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Hiring Practices

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

Independence Test

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

Audit Committee Meetings

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

Restrictions

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

AUDIT AND REVIEW PROCESS AND RESULTS

Scope

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

Review Process and Results

• Consider and review with the independent auditor the matters required to be discussed by Statement on Auditing Standards No. 61, as the same may be modified or supplemented from time to time. 
     
• Review and discuss with management and the independent auditor at the completion of the annual examination: 
     
  o the Company's audited financial statements and related notes; 
  o the Company's MD&A and news releases related to financial results; 

C-4

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

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

SECURITIES REGULATORY FILINGS

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

RISK ASSESSMENT

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

C-5

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

AMENDMENTS TO AUDIT COMMITTEE CHARTER

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