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

Financially

Name and Place of Residence

Independent

Relevant Education and Experience

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.

Robert A. Halpin
Alberta, Canada

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 50 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.

EX-99.1 8 exhibit99-1.htm TRANSGLOBE ENERGY CORPORATION ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2007 Filed by Automated Filing Services Inc. (604) 609-0244 - TransGlobe Energy Corporation - Exhibit

TRANSGLOBE ENERGY CORPORATION

ANNUAL INFORMATION FORM

Year Ended December 31, 2007

March 24, 2008

TABLE OF CONTENTS

	Page

CURRENCY AND EXCHANGE RATES	2
ABBREVIATIONS	3
CONVERSIONS	3
FORWARD-LOOKING STATEMENTS	4
CERTAIN DEFINITIONS	5
TRANSGLOBE ENERGY CORPORATION	8
GENERAL DEVELOPMENT OF THE BUSINESS	8
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES	11
OPERATIONS REVIEW - INTERNATIONAL	11
OPERATIONS REVIEW - CANADA	17
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	18
DIVIDEND POLICY	43
DESCRIPTION OF SHARE CAPITAL	43
MARKET FOR SECURITIES	44
ESCROWED SECURITIES	45
DIRECTORS AND OFFICERS	45
HUMAN RESOURCES	47
INTEREST OF EXPERTS	47
INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS	48
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	48
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	48
TRANSFER AGENT AND REGISTRAR	48
MATERIAL CONTRACTS	48
AUDIT COMMITTEE INFORMATION	48
RISK FACTORS	50
INDUSTRY CONDITIONS	53
ADDITIONAL INFORMATION	58

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

CURRENCY AND EXCHANGE RATES

All dollar amounts in this Annual Information Form, unless otherwise indicated, are stated in United States currency. The Company has adopted the U.S. dollar as the functional currency for its consolidated financial statements. The exchange rates for the period average and end of period for the U.S. dollar in terms of Canadian dollars as reported by the Bank of Canada were as follows for each of the years ended December 31, 2007, 2006 and 2005.

	Year Ended December 31, 2007	Year Ended December 31, 2006	Year Ended December 31, 2005

End of Period	Cdn$0.9913	Cdn$1.1654	Cdn$1.1630

Period Average	Cdn$1.0740	Cdn$1.1343	Cdn$1.2114

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	The 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)
boepd	barrels of oil equivalent per day
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	0.28174
cubic meters	cubic feet	35.494
Bbls	cubic meters	0.159
cubic meters	Bbls oil	6.293
feet	meters	0.305
meters	feet	3.281
miles	kilometers	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoules	MMBtu	0.950

In this document, a boe conversion ratio of 6 Mcf : 1 Bbl has been used. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

FORWARD-LOOKING STATEMENTS

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

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

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

The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this Annual Information Form:

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

The Company believes that the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in, or incorporated by reference into, this Annual Information Form should not be unduly relied upon. These statements speak only as of the date of this Annual Information Form, as the case may be. The Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by securities law.

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;

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

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

"Block 84 Partnership" means the joint venture group comprised of DNO ASA (34%), TG Holdings Yemen Inc. (33%) and Ansan Wikfs (Hadramaut) Ltd. (33%);

"Block 75 Joint Venture Group" means a joint venture arrangement for Block 75 in Yemen with a subsidiary of OXY;

"Block S-1 Joint Venture Group" means a joint venture arrangement for Block S-1 in Yemen with a subsidiary of OXY;

"Brent" means the reference price paid in U.S. 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;

"Common Shares" means the common shares of the Company;

"CPF" means central production facility;

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

"DeGolyer Report" means the report of DeGolyer dated February 6, 2008 evaluating the Egypt, Yemen crude oil and Canadian crude oil, natural gas liquids and natural gas reserves of the Company as at December 31, 2007;

"Dublin" means Dublin International Petroleum (Egypt) Limited, a wholly-owned subsidiary of TransGlobe;

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

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

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

"Egypt" means the Arab Republic of Egypt;

"GAAP" means Canadian generally accepted accounting principles;

"GHP" means GHP Exploration (West Gharib) Ltd., a wholly-owned subsidiary of TransGlobe;

"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;

"MENA" means Middle East North African region;

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

"NASDAQ" means National Association of Securities Dealers Automated Quotations;

"NEB" means National Energy Board of Canada;

"Net" or "net" means:

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

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

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

"NI 51-101" means National Instrument 51-101 of the Canadian Securities Administrators, entitled "Standards of Disclosure for Oil and Gas Activities";

"NI 51-102" means National Instrument 51-102 of the Canadian Securities Administrators, entitled "Continuous Disclosure Obligations";

"OXY" means Occidental Petroleum Corporation and its subsidiaries;

"PSC" means production sharing agreement;

"PSC" means production sharing concession;

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

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

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

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

"TSX" means the Toronto Stock Exchange;

"U.S." means the United States of America;

"West Gharib" means the West Gharib area in Egypt;

"West Gharib PSC" means the West Gharib production sharing concession in Egypt;

"Yemen" means the Republic of Yemen; and

"YOC" means Yemen Oil Company.

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

TRANSGLOBE ENERGY CORPORATION

General

TransGlobe Energy Corporation ("TransGlobe" or the "Company") was incorporated on August 6, 1968 and was organized under variations of the name "Dusty Mac" as a mineral exploration and extraction venture under The Company Act (British Columbia). In 1992, the Company entered into the oil and gas exploration and development field in the United States and later in Yemen and Canada, ceasing operations as a mining company. The Company's 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 Egypt, Yemen and Alberta, Canada.

The Company has been listed on the TSX under the symbol "TGL" since November 7, 1997 and on the AMEX under the symbol TGA since November 2003. The Company recently transferred its U.S. listing to the NASDAQ under the symbol TGA on January 18, 2008.

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

Intercorporate Relationships

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

Name of Subsidiary	Jurisdiction of Incorporation	Ownership
1377116 Alberta Ltd.	Alberta, Canada	100%
Dublin International Petroleum (Egypt) Limited⁽¹⁾	Bermuda	100%
Drucker Petroleum Inc.⁽¹⁾	British Virgin Islands	100%
GHP Exploration (West Gharib) Ltd.⁽¹⁾	Barbados	100%
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 Dublin International, Drucker, GHP, TG Holdings and TransGlobe Egypt, which companies are 100% owned directly by TGPI. TGPI is a wholly owned subsidiary of the Company.

TransGlobe Egypt holds TransGlobe's interest in Nuqra Block 1, Egypt. Dublin International, Drucker and GHP hold TransGlobe's interest in the West Gharib PSC in the Arab Republic of Egypt. TG Holdings holds TransGlobe's interests in Yemen in Block 32, Block 72, Block 75, Block 84 and Block S-1.

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

GENERAL DEVELOPMENT OF THE BUSINESS

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

During the past three years, TransGlobe has developed its business interests through a combination of acquisitions and exploration and development. During this period, TransGlobe's primary focus has been on two concessions in Egypt (a

50% working interest in Nuqra Block 1 and 100% working interest in the West Gharib Concession), five PSCs in Yemen (a 13.81087% working interest in Block 32, a 25% working interest in Block S-1, a 33% working interest in Block 72, a 33% working interest in Block 84 and a 25% working interest in Block 75) and in central Alberta, Canada.

2005

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

2006

In 2006, the Company's primary exploration and production focus was on Blocks S-1, 32, 72, 84 and 75 in Yemen; Nuqra Block 1 in Egypt and central Alberta in Canada. On Block S-1, the Company participated in the drilling of seven wells resulting in two new discoveries (oil at Osaylan #2 and gas/condensate at Wadi Bayhan #2), one exploration dry hole (Al Qurain), two Lam A oil producers at An Nagyah (#20 and #21), and two Lam B wells at An Nagyah (#22 is a suspended well and #23 is a water injector). In addition, work continued on the Block S-1 CPF expansion. On Block 32, the Company participated in the acquisition of 275 km² of 3-D seismic over the Godah discovery and the eastern portion of the Block, the drilling of eight wells resulting in two new discoveries (Godah #1 and Tasour #23 deep), three appraisal wells at Godah (two oil wells and one water injector), three wells at Tasour (two oil wells and one injector), upgrades to the Tasour CPF and construction/start-up of the Godah production facility. On Block 72, the Company participated in the processing and mapping of the 255 km of 2-D seismic (2005) and selected a drilling location for the first exploration well (Nasim #1) to be drilled in 2007. The Company also successfully bid on Block 84 at the third international bid round in Yemen and acquired a 33% working interest in the Block, subject to final approval and ratification of the PSC, which is expected in 2008. In Egypt, on Nuqra Block 1, the Company acquired 834 km of 2-D seismic data. In western Canada, the Company drilled 26 wells, resulting in 19 gas wells, five oil wells and two dry wells.

2007

In 2007, the primary exploration and production focus was on the West Gharib Concession and Nuqra Block 1 in Egypt, Blocks S-1, 32, 72, 84 and 75 in Yemen; and central Alberta in Canada.

In Egypt, the Company drilled four wells, consisting of one oil well and one dry hole on West Gharib, and two exploration dry holes on Nuqra.

On September 25, 2007 the Company completed the acquisition of two companies with interests in West Gharib, Egypt and thereby acquired working interests in eight development leases (plus one development lease pending) and 24 producing wells in the West Gharib PSC area in Egypt. The Company completed the acquisition of Dublin International and Drucker from Tanganyika Oil (Bermuda) I Ltd. for U.S.$59.0 million plus working capital adjustments effective as at July 1, 2007. Dublin International and Drucker together hold a 70% working interest in the West Gharib PSC. The Company assumed operatorship of the West Gharib PSC following the closing of the transaction. The West Gharib PSC is comprised of nine development leases (including the East Hoshia development lease which was approved on January 31, 2008). Eight of the nine development leases (excluding the Hana development lease) are encumbered with a 25% financial interest through an investment agreement between Dublin and a private company. The 25% financial interest is non-voting but otherwise the private company is a 25% participating interest partner.

Subsequent to the year end, on February 5, 2008 the Company completed the acquisition of GHP, which holds a 30% interest in the West Gharib PSC. TransGlobe acquired GHP for aggregate consideration of approximately U.S.$40.2 million plus working capital adjustments.

With the acquisition of GHP, the Company now holds a 100% working interest in the West Gharib PSC, with a working interest of 100% in the Hana development lease and an effective working interest of 75% in the eight non-Hana development leases.

The West Gharib PSC is located onshore in the western Gulf of Suez rift basin of Egypt. Major oil and gas discoveries have been made in this basin with approximately 8 billion barrels of oil and 5 trillion cubic feet of gas having been discovered to date. The 8 approved West Gharib development leases encompass 178 km² and are valid for 20 years (expiring between 2019 and 2026). Modern 3D seismic coverage exists over a majority of the leases. Gross oil production from the West Gharib PSC was approximately 3,000 bopd (2,550 bopd net) with the acquisition of GHP's 30% interest on February 5, 2008. There are seven fields on the lands, which are producing from 26 wells. The oil produced ranges from 16 degrees API to 26 degrees API and is currently trucked to a terminal.

In Yemen, the Company drilled 13 wells, consisting of four oil wells and two dry holes on Block 32; six oil wells on Block S-1 and one dry hole on Block 72. On February 1, 2007 the Company entered into an agreement with OXY to participate with OXY as to a 25% working interest in Block 75, Yemen. The Block 75 PSC received final approval and ratification on March 8, 2008. In addition, the Company participated in a 3-D seismic acquisition program on Block 72, and facility expansions on Block S-1 and Block 32.

In Alberta, Canada, the Company drilled 18 wells, resulting in 15 gas wells and three dry wells.

On October 25, 2007, the Alberta government released the New Royalty Framework ("NRF") pertaining to royalties on oil and gas resources including oil sands, conventional oil and gas and coalbed methane. The NRF is scheduled to take effect on January 1, 2009. The NRF was the Alberta government's response to the recommendations put forth by the Alberta Royalty Review Panel. Given the methodology used in the proposed royalty regime, the effect on TransGlobe's cash flow will be affected by depths and productivity of wells. The actual effect of the Alberta royalty rate changes on TransGlobe will be determined based on, among other things, the actual legislation enacted, the production rates, commodity prices, foreign exchange rates, production mix, service costs and the percentage of production from Alberta after January 1, 2009.

Anticipated Changes in the Business

As of December 18, 2007, the Company announced that it would seek a buyer for its Canadian assets and anticipates a sale of the Canadian assets by April of 2008 subject to satisfactory terms being achieved. Apart from the sale of its Canadian assets, the Company does not anticipate any material changes in its business during the balance of the 2008 financial year.

Significant Acquisitions and Significant Dispositions

The West Gharib PSC is comprised of nine development leases (including the East Hoshia development lease which was approved on January 31, 2008). Eight of the nine development leases (excluding the Hana development lease) are encumbered with a 25% financial interest through an investment agreement between Dublin International and a private company. The 25% financial interest is non-voting but otherwise the private company is a 25% participating interest partner. A business acquisition report in respect of this acquisition was filed on SEDAR on December 10, 2007.

Recent Developments

Subsequent to the year end, on February 5, 2008 the Company completed the acquisition of GHP, which holds a 30% interest in the West Gharib PSC. Upon closing the acquisition, TransGlobe now holds a 100% interest in West Gharib Concession. TransGlobe acquired GHP for aggregate consideration of approximately U.S.$40.2 million plus working capital adjustments. TransGlobe intends to file a business acquisition report on SEDAR in respect of this acquisition.

With the acquisition of GHP, the Company now holds a 100% working interest in the West Gharib PSC, with a working interest of 100% in the Hana development lease and a working interest of 75% in the eight non-Hana development leases.

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 Egypt, Yemen 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 Egypt, Yemen and Canada during the past four, 11 and nine years, respectively. In Egypt, the Company has an interest in the Nuqra Block 1 and the West Gharib PSC. In Yemen, the Company has interests in five PSCs: Block 32, Block 72, Block 75, Block 84 and Block S-1. In Canada, all of the Company's interests are located in the Province of Alberta, primarily in central Alberta.

OPERATIONS REVIEW - INTERNATIONAL

TransGlobe's first international property was acquired in Yemen in January 1997, through a farm-out and joint venture agreement on Block 32 in Yemen. During the past 11 years, TransGlobe has grown its land holdings in the MENA region to 6.8 million acres (3.1 million net) in Egypt and Yemen.

Through TGPI (a wholly owned subsidiary) the Company owns interests in seven PSCs in the MENA region, being two in Egypt and five in Yemen.

The following table summarizes the Company's current international land holdings:

Summary of International Land Holdings (Egypt and Yemen)

	Egypt		Yemen
Block	West Gharib	Nuqra #1	32	72	84	S-1	75

Basin	Gulf of Suez	Nuqra	Masila	Masila	Masila	Marib	Marib

Year acquired	2007	2004	1997	2004/2005	2006/2007⁽³⁾	1998	2007

Status	Development	Exploration	Development	Exploration	Exploration	Development	Exploration

Operator	TransGlobe	TransGlobe	DNO ASA	DNO ASA	DNO ASA	OXY	OXY

TransGlobe WI (%)	100%⁽¹⁾	50%⁽²⁾	13.81087%	33%	33%	25%	25%

Block Area (km²)	214	22,500	591	1,822	731	1,152	1,050

Block Area (acres)	52,900	5,500,000	146,070	450,234	183,000	284,700	262,500

Expiry date(s)	2019-26	July 2009	2020	Jan. 2009	N/A	2023	N/A

Extensions:
Exploration	N/A	2^ndExtension 36 months	N/A	2^ndPhase 36 months	1^stPhase 42 months	N/A	2^ndPhase 36 months

Notes:

(1)	Effective February 5, 2008, the Company owns 100% of the West Gharib concession, consisting of nine development leases. The Company owns 100% of the Hana development lease and has a working interest of 75% in the balance of the development leases.
(2)	TransGlobe pays 60% of costs to first oil production and recovers carried costs from partners' share of production.
(3)	PSC awaiting final government approval and ratification. First exploration term commences on the ratification date.

Egypt

The Company is operator of two PSCs in Egypt. The Company's first project in Egypt, Nuqra Block 1, is a large exploration concession located in Upper Egypt. The recently acquired West Gharib property is a development concession located in the prolific Gulf of Suez basin.

2007 Highlights - Egypt

West Gharib acquisition (Dublin International & Drucker) in September 2007
Operator with 70% interest in West Gharib Concession
1,600 bopd production net to TransGlobe
Drilled four wells (two at Nuqra and two at West Gharib)
Additional 30% interest acquired in West Gharib (February 2008)
Additional 900 bopd production acquired (February 2008)

2007 Activities and Results

During 2007, the Company significantly expanded operations in Egypt with the acquisition of the West Gharib PSC on September 25, 2007 and drilled the first two exploration wells on Nuqra Block 1 in Upper Egypt.

The following summary of the Company's activities in Egypt in 2007:

On September 25, 2007, TGPI acquired all of the shares of Dublin International and Drucker for U.S.$59.0 million, plus working capital adjustments, as at July 1, 2007. Dublin and Drucker together hold a 70% working interest in the West Gharib PSC. TransGlobe has assumed operatorship of the West Gharib properties. The West Gharib PSC is located onshore in the western Gulf of Suez rift basin of Egypt. To date, eight billion barrels of oil and five trillion cubic feet of gas have been discovered in this prolific basin. The eight approved West Gharib development leases encompass 178 km²(approximately 44,059 acres) and are valid for 20 years (expiring between 2019 and 2026). One additional development lease at East Hoshia was subsequently approved by the Minister of Oil in early 2008. Eight of the nine development leases (excluding the Hana development lease) are encumbered with a 25% financial interest through an investment agreement between Dublin International and a private company. The 25% financial interest is non-voting but otherwise the private company is treated as a 25% participating interest partner.
On February 5, 2008, TGPI acquired all of the shares of GHP for U.S. $40.2 million, plus working capital adjustments with an effective date of September 30, 2007. GHP holds a 30% working interest in the West Gharib PSC. Following the acquisition of GHP, TransGlobe holds a 100% working interest in the West Gharib PSC, with a working interest of 100% in the Hana development lease and an effective working interest of 75% in the eight non-Hana development leases.
The Company consolidated the TransGlobe Egypt and Dublin International Cairo offices and hired a new Country Manager for Egypt.
The Company expanded the Calgary head office technical team to focus on the West Gharib PSC.
Two wells were drilled on West Gharib during the fourth quarter of 2007, resulting in a potential multi- zone oil well in the Hana field and an exploration dry hole on the Hoshia lease. A new development oil well was drilled in the Hana field subsequent to year end. The two new wells at Hana were placed on production in late February, increasing production by approximately 500 bopd to TransGlobe.
Two exploration wells were drilled on the Nuqra Block 1 in Upper Egypt, resulting in two dry holes. The successful identification of a 460-meter (1,500-foot) interval of mature source rocks in the shallower Cretaceous section of the Narmer #1 exploration well and the discovery of oil on a non-owned block by a third party in the Cretaceous section of Al Baraka #1 on the west side of the Nile river has encouraged the Company to continue with additional exploration drilling on the Nuqra Block.

2007 Drilling Activities

	Working Interest	Gross wells	Oil	Dry
West Gharib	70%⁽¹⁾	2	1	1
Nuqra Block 1	50%	2	-	2
Total		4	1	3

Note:

(1)	Effective February 5, 2008, the Company owns 100% of the West Gharib PSC, consisting of nine development leases. The Company owns 100% of the Hana development lease and has an effective working interest of 75% in the balance of the development leases.

2007 Production

Production from the West Gharib PSC averaged 2,932 bopd (1,594 bopd net to TransGlobe) during the fourth quarter of 2007, consistent with the expected 1,600 bopd at the time of the initial purchase of Dublin International and Drucker. Production from the West Gharib PSC averaged 2,895 bopd (1,636 bopd net to TransGlobe) in January 2008 and approximately 3,000 bopd (2,550 bopd net to TransGlobe) in February 2008 (with the GHP 30% interest being acquired on February 5, 2008).

With the addition of the new wells at Hana, it is expected that production from West Gharib will average approximately 3,400 bopd (2,900 bopd net to TransGlobe) during March. This represents a 16% production increase in total field production from West Gharib since the acquisition of the West Gharib assets in September 2007.

Quarterly West Gharib Production (bopd)

	2007
	Q-3⁽¹⁾	Q-4
Gross field production rate	218	2,932
TransGlobe working interest	118	1,594
TransGlobe net (after royalties and other)	73	971
TransGlobe net (after royalties and tax) ⁽²⁾	51	714

Notes:

(1)	Production presented represents six days' production averaged over the quarter.
(2)	Under the terms of the West Gharib PSC, royalties, other and taxes are paid out of the government's share of production sharing oil.

2008 Outlook

The Company has budgeted $33.5 million for Egypt in 2008, with $24.3 million (73%) allocated to development and $9.2 million (27%) allocated to exploration. With the addition of the West Gharib PSC in 2007, the primary focus in Egypt will shift to the appraisal and development of West Gharib in 2008 and 2009.

On West Gharib, the Company has budgeted for 15 to 18 wells, a new 300+ km² 3-D seismic acquisition program, facility upgrades and potential pressure maintanence/waterflood projects. TransGlobe has two drilling rigs under long-term contracts for the West Gharib properties. The larger 1,500 hp rig has the depth capacity to drill all of the exploration and development prospects. TransGlobe plans to utilize this rig to drill continuously at a pace of eight to 12 wells per year, depending upon the depths drilled. The second, smaller drilling rig is capable of drilling shallow wells (up to 4,000 feet) and can be utilized when appropriate. The smaller rig is currently working for another party on a farm-out basis and will be available as required in 2008. The Company has added a third drilling rig to accelerate the exploration and development program for the West Gharib area. Assuming the third rig commences operations in July 2008, a total of 15 to 18 wells could be drilled in 2008 on the West Gharib leases. The Hana and Hoshia fields have been identified as potential candidates for pressure maintenance or water floods to enhance recoveries. The Company expects to finalize reservoir simulations studies and initiate secondary recovery pilot projects at Hana and Hoshia in 2008. Depending upon the results, the respective pilot projects could be expanded into full field developments in 2009.

On the Nuqra Block 1, existing seismic data was re-mapped and several Cretaceous targets were identified for a future drilling program. One exploration well has been budgeted for 2008, on a contingency basis. Currently, the Company is discussing rig sharing possibilities with adjacent operators to facilitate a potential 2008 drilling program.

2008 Capital Program

	2008 Capital Budget $ Millions	Wells Exploration	Wells Development	Seismic
West Gharib PSC	$ 29.3	2	16	300+ km²new 3-D
Nuqra Block 1	$ 4.2	1	-
Total	$ 33.5	3	16	300+ km²new 3-D

Yemen

The Company holds interests in five non-operated PSCs in Yemen. Blocks 32 and S-1 are development agreements, and Blocks 72, 75 and 84 are exploration agreements.

Highlights - Yemen

Drilled 13 wells (10 oil, 3 dry)
Development of the Godah Oil pool – Block 32
Expanded Central Production Facility at An Nagyah – Block S-1
Commenced large 3-D seismic program – Block 72
Progressed potential gas development – Block S-1
Signed PSCs for Blocks 75 and 84

2007 Activities and Results

During 2007, the Company participated in 13 wells, a new 3-D seismic acquisition program and facility expansions at An Nagyah, Tasour PF and Godah. The following is a summary of the Company's activities in Yemen in 2007:

On Block 32, the operator drilled four oil wells, two exploratory dry holes and completed the expansion of facilities at the Tasour and Godah CPF.
On Block S-1, the operator drilled six oil wells, re-entered one gas well and completed the An Nagyah CPF expansion. In addition, the operator proposed to MOM that natural gas from An Naeem be injected into the western portion of the An Nagyah pool. The planned gas injection will provide additional pressure support in the western portion of the field to improve production performance and increase recoverable reserves. Subject to MOM approval, gas injection could commence in 2008 when a 25-km pipeline from An Naeem to the An Nagyah CPF is completed.
On Block 72, the operator drilled one (0.33 net) exploration well (dry) and commenced a 410 km²3-D seismic acquisition program, which will be completed in early 2008.
On the new exploration Blocks 75 and 84, the respective PSCs were signed and submitted to MOM and the Government of Yemen for approval and ratification. The Block 75 PSC was approved on March 8, 2008. It is expected that the Block 84 PSCs will also be approved during 2008.

2007 Drilling Activities

	Working Interest	Gross wells	Oil	Dry
Block 32	13.8	6	4	2
Block S-1	25.0	6	6	-
Block 72	33.0	1	-	1
Total		13	10	3

2007 Production

Production from Block 32 averaged 8,700 bopd (1,202 bopd net to TransGlobe) during the year. The Godah field contributed 2,034 bopd (gross), with the balance coming from the Tasour field (6,666 bopd gross). Block 32 production averaged approximately 7,475 bopd (1,032 bopd net to TransGlobe) in January and February of 2008. A six-inch gas pipeline connecting the Godah production facility to the Tasour CPF was constructed to supply associated gas production from the Godah pool to the Tasour CPF for fuel gas. It is expected that up to 60% of diesel being consumed for power generation can be replaced with natural gas, resulting in lower operating costs. The fuel-gas project is expected to be operational in the second quarter of 2008.

	2007
Block 32 Production by Quarter (bopd)	Q-1	Q-2	Q-3	Q-4
Gross field production rate	9,842	8,488	8,913	7,582
TransGlobe working interest	1,359	1,172	1,231	1,047
TransGlobe net (after royalties and other)	983	900	845	620
TransGlobe net (after royalties, other and tax)⁽¹⁾	867	819	722	478

Note:

(1)	Under the terms of the Block 32 PSC, royalties, other and taxes are paid out of the government's share of production sharing oil.

Production from Block S-1 averaged 10,497 bopd (2,624 bopd net to TransGlobe) during 2007. The new expanded CPF at An Nagyah became fully operational in the fourth quarter and is now capable of processing 20,000 bopd of oil production and associated gas production. The average production during January and February was 11,117 bopd (2,779 bopd net to TransGlobe).

	2007
Block S-1 Production by Quarter (bopd)	Q-1	Q-2	Q-3	Q-4
Gross field production rate	10,132	11,167	9,924	10,768
TransGlobe working interest	2,533	2,792	2,481	2,692
TransGlobe net (after royalties and other)	1,471	1,577	1,418	1,469
TransGlobe net (after royalties, other and tax)	1,198	1,264	1,162	1,153

Note:

(1)	Under the terms of the Block S-1 PSC, royalties, other and taxes are paid out of the government's share of production sharing oil.

2008 Outlook

The Company has budgeted $23.8 million for Yemen in 2008, with $8.4 million (35%) allocated to development and $15.4 million (65%) allocated to exploration. With the completion of the An Nagyah and Godah facility expansions in 2007, the primary focus will shift to exploration in 2008 and 2009. On Block 72, the 410 km²3-D seismic acquisition will be processed and mapped by mid-2008, with exploration drilling to commence in the second half of 2008. With the recent (March 8, 2008) approval of the Block 75 PSC, it is expected that 400 km² of 3-D seismic will be shot by the Company on Block 75/S-1. Subject to government approval of the Block 84 PSC, an additional 400+ km² of 3-D seismic will be acquired during 2008, with an expected increase in exploration drilling in 2009.

In addition to the planned capital program, the Block S-1 Joint Venture Group is also considering possibilities for a gas sales agreement utilizing known deposits of gas on Block S-1. An approved gas development plan is required prior to TransGlobe being able to recognize any reserves associated with the An Naeem discovery or proceed with development of this discovery.

2008 Capital Program

Firm & Contingent	2008 Budget $ Millions	Wells Exploration	Wells Development	Seismic
Block 32	$ 3.8	3	3
Block S-1	$ 8.7	-	3	200+ Km²new 3-D
Block 72	$ 5.7	2	-	410 Km²new 3-D commenced Q4,07
Block 75	$ 1.8	-	-	200+ Km²new 3-D
Block 84	$ 3.8	-	-	400+ Km²new 3-D
Total	$23.8	5	6	1,200+ Km²new 3-D

Summary of International PSC Terms

All of the Company's international blocks are PSCs between the host government and the contractor (joint venture partners). The government and the contractors take their share of production based on the terms and conditions of the respective contracts. The contractors' share of all taxes and royalties are paid out of the governments' share of production.

The PSCs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Each PSC is treated individually in respect of cost recovery and

production sharing purposes. The remaining production sharing oil (total production, less gross royalty, less cost oil) is shared between the government and the contractor as defined in the specific PSCs.

The following table summarizes the Company's international PSC terms for the first tranche of production for each block. All the PSCs have different terms for production levels above the first tranche, which are unique to each PSC. The government's share of production increases and the contractor's share of production decreases as the production volumes go to the next production tranche.

PSC Terms – Egypt and Yemen (Oil Production: First Production Tranche)

	Egypt		Yemen
Block	West Gharib	Nuqra #1	32⁽¹⁾(original)	72	84	S-1	75

First Tranche (Mbopd)	0 – 5	0-25	0-25	0-25	0-25	0-12.5	0-25

Gross Royalty %	0%	0%	3%/(10%)	3%	6.5%	3%	3%

Max. Cost Oil %	30%	40%	60%/(25%)	50%	35%	50%	50%

Excess Cost Oil	Prod. Sharing	Prod. Sharing	Prod. Sharing	Prod. Sharing	Prod. Sharing	Prod. Sharing	Prod. Sharing

Depreciation per Quarter
Operating	100%	100%	100%	100%	100%	100%	100%
Capital	6.25%	6.25%	12.5%	12.5%	8.33%	12.5%	12.5%

Production
Sharing Oil:
Contractor	30%	30%	33.25%/ (23%)	32.4%	23.98%	28.88%	34.2%
Government	70%	70%	66.75%/ (77%)	67.6%	76.02%	71.13%	65.8%

Note:

(1)	Block 32 terms will revert to original PSC terms if production exceeds 25 Mbopd or proved reserves exceed 30 million barrels. Reserves are audited every two years by an independent evaluator. At November 2006, proved reserves were less than 30 MMbbl. The next reserve audit is November 2008.

OPERATIONS REVIEW - CANADA

Divestitures

In December 2007, the Company announced the strategic decision to sell the Canadian division to fund and focus on growth opportunities in the MENA region. Early in 2008, the Company retained Tristone Capital Inc. as financial advisor to assist in the divestment of the Canadian properties. In the current divestiture schedule, bids were due by March 13, 2008, with an anticipated closing date of late April/early May, subject to an acceptable price being achieved.

Highlights

Drilled 18 wells (15 gas, 3 dry)
Increased production to 1,500 boepd

2007 Activities and Results

The Company drilled 15 gas wells in the Nevis, Thorsby and Morningside areas in central Alberta. The Company's production averaged 1,394 boepd during 2007. The Company's average production during January and February was approximately 1,492 boepd.

2007 Canadian Production by Quarter (boepd)

	Q-1	Q-2	Q-3	Q-4
TransGlobe working interest	1,283	1,389	1,397	1,504
TransGlobe net (after royalties)	1,148	1,144	1,175	1,250

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The report of management and the directors on oil and gas disclosure in Form 51-101F2 and the report on reserves data in Form 51-101F3 are attached as Schedules "A" and "B", 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 February 6, 2008, with the effective date of the Statement being December 31, 2007.

Disclosure of Reserves Data

All of the Company's reserves herein reported were evaluated by independent evaluators in accordance with NI 51-101 for the year ended December 31, 2007. In 2007, DeGolyer and MacNaughton Canada Limited ("DeGolyer"), independent petroleum engineering consultants based in Calgary, Alberta and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company's Reserves Committee to independently evaluate 100% of TransGlobe's reserves as at December 31, 2007.

The reserves data set forth below (the "Reserves Data") was prepared by DeGolyer with an effective date of December 31, 2007. The Reserves Data summarizes the oil, liquids and natural gas reserves of the Company and the net present values of future net revenue for these reserves using constant prices and costs and forecast prices and costs. The Company reports in U.S. currency and therefore the reports have been converted to U.S. dollars at the prevailing conversion rate at December 31 of the respective years.

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

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

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

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
TOTAL COMPANY
AS OF DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total Boes
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	4,467	2,373	2,145	1,199	7,454	6,153	166	120	8,020	4,718
Non-Producing	302	188	141	77	1,996	1,726	41	28	817	581
Undeveloped	2,294	1,244	509	291	1,257	1,039	17	11	3,029	1,719
Total Proved	7,063	3,805	2,795	1,566	10,707	8,918	224	160	11,866	7,018

Probable	1,066	602	2,311	1,249	5,759	4,784	186	128	4,523	2,777

Proved Plus Probable	8,129	4,407	5,106	2,816	16,467	13,703	410	288	16,389	9,795

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 Egypt and 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.

SUMMARY OF OIL AND GAS RESERVES
EGYPT
AS OF DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total Boes
	Gross⁽¹	Net⁽²	Gross⁽¹	Net⁽²	Gross⁽¹	Net⁽²	Gross⁽¹	Net⁽²	Gross⁽¹	Net⁽²
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	-	-	2,145	1,199	-	-	-	-	2,145	1,199
Non-Producing	-	-	141	77	-	-	-	-	141	77
Undeveloped	-	-	509	291	-	-	-	-	509	291
Total Proved	-	-	2,795	1,566	-	-	-	-	2,795	1,566

Probable	-	-	2,311	1,249	-	-	-	-	2,311	1,249

Proved Plus Probable	-	-	5,106	2,816	-	-	-	-	5,106	2,816

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 Egypt 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.

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS OF DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total Boes
	Gross^(1}	Net^(2}	Gross^(1}	Net^(2}	Gross^(1}	Net^(2}	Gross^(1}	Net^(2}	Gross^(1}	Net^(2}
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing			-	-	-	-	-	-
	4,236	2,171							4,236	2,171
Non-Producing			-	-	-	-	-	-
	219	114							219	114
Undeveloped	2,112	1,078	-	-	-	-	-	-	2,112	1,078
Total Proved			-	-	-	-	-	-
	6,567	3,362							6,567	3,362

Probable	903	457	-	-	-	-	-	-	903	457

Proved Plus Probable	7,470	3,819	-	-	-	-	-	-	7,470	3,819

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.

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS OF DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total Boes
	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing
	231	203	-	-	7,454	6,153	166	120	1,639	1,349
Non-Producing
	83	74	-	-	1,996	1,726	41	28	457	390
Undeveloped	182	166	-		1,257	1,039	17	11	409	350
Total Proved
	495	443	-	-	10,707	8,918	224	160	2,504	2,089

Probable	163	145	-	-	5,759	4,784	186	128	1,309	1,070

Proved Plus Probable	659	588	-	-	16,467	13,703	410	288	3,813	3,160

Notes:

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

NET PRESENT VALUES OF FUTURE NET REVENUES
TOTAL COMPANY
AS OF DECEMBER 31, 2007
(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$	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%

Proved

Developed producing	177.6	158.3	142.6	129.7	118.9	177.6	158.3	142.6	129.7	118.9
Developed non-producing	19.3	15.4	12.8	10.8	9.3	16.7	13.4	11.1	9.4	8.2
Undeveloped	50.1	38.0	29.2	22.6	17.6	48.5	36.6	28.0	21.6	16.8
Total Proved	246.9	211.7	184.6	163.1	145.8	242.8	208.3	181.7	160.8	143.9

Probable	96.0	72.8	57.2	46.3	38.2	85.7	65.1	51.2	41.5	34.3

Total Proved Plus Probable	343.0	284.5	241.8	209.4	184.1	328.4	273.3	233.0	202.2	178.2

Notes:

(1)	In Egypt and Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Egypt and Yemen Future Net Revenues are after Egypt and Yemen income tax.
(2)	Canadian values converted to U.S. dollars at the December 31, 2007 exchange rates of 1.00 US$/Cdn$.

NET PRESENT VALUES OF FUTURE NET REVENUES
EGYPT
AS OF DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

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

Proved

Developed producing	43.8	38.5	34.3	30.9	28.0	43.8	38.5	34.3	30.9	28.0
Developed non-producing	2.2	1.8	1.5	1.3	1.1	2.2	1.8	1.5	1.3	1.1
Undeveloped	7.5	6.3	5.3	4.5	3.8	7.5	6.3	5.3	4.5	3.8
Total Proved	53.5	46.6	41.1	36.6	32.9	53.5	46.6	41.1	36.6	32.9

Probable	37.9	29.7	24.0	19.8	16.6	37.9	29.7	24.0	19.8	16.6

Total Proved Plus Probable	91.4	76.3	65.0	56.4	49.6	91.4	76.3	65.0	56.4	49.6

Note:

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

NET PRESENT VALUES OF FUTURE NET REVENUES
YEMEN
AS OF DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

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

Proved

Developed producing	84.8	76.2	69.0	63.1	58.0	84.8	76.2	69.0	63.1	58.0
Developed non-producing	4.1	3.7	3.2	2.9	2.6	4.1	3.7	3.2	2.9	2.6
Undeveloped	36.5	27.6	21.3	16.8	13.4	36.5	27.6	21.3	16.8	13.4
Total Proved	125.4	107.4	93.6	82.7	74.0	125.4	107.4	93.6	82.7	74.0

Probable	17.4	13.4	10.6	8.6	7.2	17.4	13.4	10.6	8.6	7.2

Total Proved Plus Probable	142.8	120.8	104.2	91.4	81.2	142.8	120.8	104.2	91.4	81.2

Note:

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

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS OF DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

	Before Income Tax⁽¹⁾					After Income Tax⁽¹⁾
US$	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Proved
Developed producing	49.0	43.6	39.3	35.8	32.8	49.0	43.6	39.3	35.8	32.8
Developed non-producing	13.0	10.0	8.0	6.6	5.6	10.4	7.9	6.3	5.2	4.5
Undeveloped	6.0	4.0	2.5	1.4	0.5	4.4	2.7	1.4	0.4	(0.4	)
Total Proved	68.0	57.7	49.9	43.8	38.9	63.8	54.3	47.1	41.5	36.9

Probable	40.8	29.7	22.7	17.8	14.4	30.4	22.0	16.6	13.0	10.5

Total Proved Plus Probable	108.7	87.4	72.5	61.6	53.3	94.2	76.2	63.7	54.5	47.4

Note:

(1)	Canadian values converted to U.S. dollars at the December 31, 2007 exchange rates of 1.00 US$/Cdn$.

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

					Well	Future Net		Future Net
					Abandonment	Revenue		Revenue
					and	Before		After
			Operating	Development	Reclamation	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
Egypt⁽¹⁾	172	76	39	4	1	54	-	54
Yemen⁽¹⁾	551	269	150	7	-	125	-	125
Canada⁽²⁾	144	22	40	11	3	68	4	64
Total Company	868	367	228	22	4	247	4	243

Proved Plus Probable
Reserves
Egypt⁽¹⁾	315	141	72	10	1	91	-	91
Yemen⁽¹⁾	626	306	169	8	-	143	-	143
Canada⁽²⁾	221	35	60	13	4	109	15	94
Total Company	1162	482	301	31	5	343	15	328

Notes:

(1)	In Egypt and Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Egypt and Yemen Future Net Revenues are after Egypt and Yemen income tax. Income taxes payable in Egypt and Yemen have been recorded as a Royalty for reporting purposes.
(2)	Canadian values converted to U.S. dollars at the December 31, 2007 exchange rates of 1.00 US$/Cdn$.

TOTAL FUTURE NET REVENUES
BY PRODUCTION GROUP
AS AT DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

		Egypt
		Future net	Egypt	Yemen	Yemen	Canada		Canada		Total	Total
		Revenue	Unit Value	Future net	Unit Value	Future net		Unit Value		Future net	Unit Value
		Before	Before Tax	Revenue	Before Tax	Revenue		Before Tax		Revenue	Before Tax
		Taxes⁽¹⁾	(discounted at	Before Taxes⁽¹⁾	(discounted at	Before Taxes^(2}		(discounted at		Before Taxes⁽¹⁾	(discounted at
		(discounted at	10%/year)	(discounted at	10%/year)	(discounted at		10%/year)		(discounted at	10%/year)
Reserves	Product	10%/year	($/Mcf)	10%/year)	($/Mcf)	10%/year)		($/Mcf)		10%/year)	($/Mcf)
Category	Group	(US$MM)	($/Bbl)	(US$MM)	($/Bbl)	(US$MM)		($/Bbl)		(US$MM)	($/Bbl)
Proved	Light and	-		69.0	31.78	6.6		32.51		75.6	31.84
Producing	Medium Oil
	Heavy Oil	34.3	28.61	-	-	-		-		34.3	28.61

	Natural Gas	-	-	-	-	24.4		3.97		24.4	3.97

	Natural Gas	-	-	-	-	8.3		69.17		8.3	69.17
	Liquids
Proved Non-	Light and	-	-	3.2	28.07	1.0		13.51		4.2	22.34
Producing	Medium Oil
	Heavy Oil	1.5	19.48	-	-	-		-		1.5	19.48

	Natural Gas	-	-	-	-	5.2		3.01		5.2	3.01

	Natural Gas	-	-	-	-	1.9		67.86		1.9	67.86
	Liquids
Proved	Light and	-	-	21.3	19.76	(2.2	)	(13.25	)	19.1	15.35
Undeveloped	Medium Oil
	Heavy Oil	5.3	18.21	-	-	-		-		5.3	18.21

	Natural Gas	-	-	-	-	4.0		3.85		4.0	3.85

	Natural Gas	-	-	-	-	0.6		54.55		0.6	54.55
	Liquids
Total Proved	Light and	-	-	93.5	27.81	5.4		12.19		98.9	25.99
	Medium Oil
	Heavy Oil	41.1	26.25	-	-	-		-		41.1	26.25

	Natural Gas	-	-	-	-	33.6		3.77		33.6	3.77

	Natural Gas	-	-	-	-	10.8		67.50		10.8	67.50
	Liquids
Probable	Light and	-	-	10.6	23.19	3.1		21.38		13.7	22.76
	Medium Oil
	Heavy Oil	24.0	19.22	-	-	-		-		24.0	19.22

	Natural Gas	-	-	-	-	14.1		2.95		14.1	2.95

	Natural Gas	-	-	-	-	5.8		45.31		5.8	45.31
	Liquids
Proved Plus	Light and	-	-	104.1	27.26	8.5		14.46		112.6	25.55
Probable	Medium Oil
	Heavy Oil	65.1	23.12	-	-	-		-		65.1	23.12

	Natural Gas	-	-	-	-	47.7		3.48		47.7	3.48

	Natural Gas	-	-	-	-	16.6		57.64		16.6	57.64
	Liquids

Notes:

(1)	In Egypt and Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Egypt and Yemen Future Net Revenues are after Egypt and Yemen income tax.
(2)	Canadian values converted to U.S. dollars at the December 31, 2007 exchange rates of 1.00 US$/Cdn$.

Reserves Data (Constant Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES
TOTAL COMPANY
AS OF DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy 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⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	4,472	2,312	2,145	1,173	7,549	6,239	167	121	8,042	4,646
Non-Producing	305	187	141	75	2,027	1,752	41	29	825	583
Undeveloped	2,301	1,207	509	284	1,279	1,057	17	12	3,040	1,679
Total Proved	7,078	3,705	2,795	1,532	10,855	9,048	225	161	11,907	6,908

Probable	1,076	598	2,311	1,222	5,825	4,846	187	129	4,545	2,757

Proved Plus Probable	8,153	4,304	5,106	2,754	16,681	13,894	412	290	16,452	9,665

Notes:

(1)

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

(2)

SUMMARY OF OIL AND GAS RESERVES
EGYPT
AS OF DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy 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⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing	-	-	2,145	1,173	-	-	-	-	2,145	1,173
Non-Producing	-	-	141	75	-	-	-	-	141	75
Undeveloped	-	-	509	284	-	-	-	-	509	284
Total Proved	-	-	2,795	1,532	-	-	-	-	2,795	1,532

Probable	-	-	2,311	1,222	-	-	-	-	2,311	1,222

Proved Plus Probable	-	-	5,106	2,754	-	-	-	-	5,106	2,754

Notes:

(1)

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

(2)

SUMMARY OF OIL AND GAS RESERVES
YEMEN
AS OF DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy 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⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing
	4,236	2,104	-	-	-	-	-	-	4,236	2,104
Non-Producing
	219	110	-	-	-	-	-	-	219	110
Undeveloped	2,112	1,034	-	-	-	-	-	-	2,112	1,034
Total Proved
	6,567	3,248	-	-	-	-	-	-	6,567	3,248

Probable	903	444	-	-	-	-	-	-	903	444

Proved Plus Probable	7,470	3,693	-	-	-	-	-	-	7,470	3,693

Notes:

(1)

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

(2)

SUMMARY OF OIL AND GAS RESERVES
CANADA
AS OF DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

	Light & Medium Crude
	Oil		Heavy 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⁾	Gross⁽¹⁾	Net⁽²⁾
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(MMcf)	(MMcf)	(Mbbls)	(Mbbls)	(MBoe)	(MBoe)
Proved
Producing
	236	207	-	-	7,549	6,239	167	121	1,661	1,368
Non-Producing
	86	77	-	-	2,027	1,752	41	29	465	398
Undeveloped	189	173	-	-	1,279	1,057	17	12	419	361
Total Proved
	510	457	-	-	10,855	9,048	225	161	2,545	2,127

Probable	173	154	-	-	5,825	4,846	187	129	1,331	1,091

Proved Plus Probable	683	611		-	16,681	13,894	412	290	3,876	3,218

Notes:

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

NET PRESENT VALUES OF FUTURE NET REVENUES
TOTAL COMPANY
AS OF DECEMBER 31, 2007
(CONSTANT 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 average price received on December 31, 2007. 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).

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

Proved

Developed producing	197.5	174.8	156.6	141.7	129.4	197.2	174.6	156.4	141.6	129.3
Developed non-producing	21.8	17.3	14.2	12.0	10.3	18.5	14.7	12.1	10.3	8.9
Undeveloped	60.3	45.4	34.8	27.0	21.1	58.3	43.8	33.4	25.8	20.1
Total Proved	279.6	237.5	205.6	180.7	160.7	274.0	233.1	201.9	177.7	158.3

Probable	112.1	84.3	65.8	53.0	43.7	100.4	75.7	59.3	47.9	39.5

Total Proved Plus Probable	391.7	321.7	271.4	233.7	204.5	374.4	308.8	261.3	225.6	197.8

Notes:

(1)	In Egypt and Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Egypt and Yemen Future Net Revenues are after Egypt and Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2007 exchange rates of 1.0 US$/Cdn$.

NET PRESENT VALUES OF FUTURE NET REVENUES
EGYPT
AS OF DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

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

Proved

Developed producing	49.1	42.9	38.1	34.1	30.9	49.1	42.9	38.1	34.1	30.9
Developed non-producing	2.6	2.1	1.8	1.5	1.3	2.6	2.1	1.8	1.5	1.3
Undeveloped	8.9	7.4	6.2	5.3	4.5	8.9	7.4	6.2	5.3	4.5
Total Proved	60.6	52.5	46.0	40.9	36.7	60.6	52.5	46.0	40.9	36.7

Probable	43.9	34.4	27.8	23.0	19.3	43.9	34.4	27.8	23.0	19.3

Total Proved Plus Probable	104.4	86.9	73.8	63.8	56.0	104.4	86.9	73.8	63.8	56.0

Note:

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

NET PRESENT VALUES OF FUTURE NET REVENUES
YEMEN
AS OF DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

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

Proved

Developed producing	96.0	85.6	77.0	70.0	64.1	96.0	85.6	77.0	70.0	64.1
Developed non-producing	4.6	4.1	3.7	3.3	3.0	4.6	4.1	3.7	3.3	3.0
Undeveloped	44.0	32.8	25.1	19.6	15.5	44.0	32.8	25.1	19.6	15.5
Total Proved	144.6	122.5	105.8	92.8	82.6	144.6	122.5	105.8	92.8	82.6

Probable	22.2	17.1	13.5	11.0	9.1	22.2	17.1	13.5	11.0	9.1

Total Proved Plus Probable	166.8	139.6	119.3	103.8	91.7	166.8	139.6	119.3	103.8	91.7

Note:

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

NET PRESENT VALUES OF FUTURE NET REVENUES
CANADA
AS OF DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

	Before Income Tax⁽¹⁾					After Income Tax⁽¹⁾
US$	Discounted at %/yr					Discounted at %/yr
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%
Proved
Developed producing	52.3	46.3	41.5	37.6	34.4	52.1	46.1	41.4	37.5	34.3
Developed non-producing	14.6	11.1	8.8	7.2	6.0	11.3	8.5	6.7	5.5	4.7
Undeveloped	7.5	5.2	3.4	2.1	1.1	5.5	3.5	2.1	1.0	0.1
Total Proved	74.4	62.6	53.7	46.9	41.5	68.9	58.1	50.1	44.0	39.0

Probable	46.0	32.7	24.5	19.1	15.3	34.3	24.2	18.0	14.0	11.1

Total Proved Plus Probable	120.5	95.3	78.3	66.0	56.8	103.2	82.3	68.1	57.9	50.2

Note:

(1)	Canadian values converted to US dollars at the December 31, 2007 exchange rates of 1.0 US$/Cdn$.

TOTAL FUTURE NET REVENUES
(UNDISCOUNTED)
AS AT DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

					Well	Future Net		Future Net
					Abandonment	Revenue		Revenue
					and	Before		After
			Operating	Development	Reclamation	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
Egypt⁽¹⁾	195	88	42	4	1	61	-	61
Yemen⁽¹⁾	609	308	149	7	-	145	-	145
Canada⁽²⁾	149	23	38	11	3	74	6	69
Total Company	952	418	229	21	4	280	6	274

Proved Plus Probable
Reserves
Egypt⁽¹⁾	355	164	77	10	1	104	-	104
Yemen⁽¹⁾	692	350	167	8	-	167	-	167
Canada⁽²⁾	229	36	56	13	3	120	17	103
Total Company	1,276	550	300	30	4	392	17	374

Notes:

(1)	In Egypt and Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Egypt and Yemen Future Net Revenues are after Egypt and Yemen income tax. Income taxes payable in Egypt and Yemen have been recorded as a Royalty for reporting purposes.
(2)	Canadian values converted to US dollars at the December 31, 2007 exchange rates of 1.0 US$/Cdn$.

TOTAL FUTURE NET REVENUES
BY PRODUCTION GROUP
AS AT DECEMBER 31, 2007
(CONSTANT PRICES AND COSTS)

		Egypt		Yemen	Yemen	Canada		Total
		Future net	Egypt	Future net	Unit Value	Future net	Canada	Future net	Total
		Revenue	Unit Value	Revenue	Before Tax	Revenue	Unit Value	Revenue	Unit Value
		Before	Before Tax	Before	(discounted	Before	Before Tax	Before	Before Tax
		Taxes⁽¹⁾	(discounted	Taxes⁽¹⁾	at	Taxes⁽²⁾	(discounted	Taxes⁽¹⁾	(discounted
		(discounted	at 10%/year)	(discounted	10%/year)	(discounted	at 10%/year)	(discounted	at 10%/year)
Reserves	Product	at 10%/year)	($/Mcf)	at 10%/year)	($/Mcf)	at 10%/year)	($/Mcf)	at 10%/year)	($/Mcf)
Category	Group	(US$MM)	($/Bbl)	(US$MM)	($/Bbl)	(US$MM)	($/Bbl)	(US$MM)	($/Bbl)
Proved	Light and	-		77.0	36.60	7.2	34.78	84.2	36.43
Producing	Medium Oil
	Heavy Oil	38.1	32.48	-	-	-	-	38.1	32.48

	Natural Gas	-	-	-	-	25.9	4.15	25.9	4.15

	Natural Gas	-	-	-	-	8.4	69.42	8.4	69.42
	Liquids
Proved Non-	Light and	-	-	3.7	33.64	1.2	15.58	4.9	26.20
Producing	Medium Oil
	Heavy Oil	1.8	24.00	-	-	-	-	1.8	24.00

	Natural Gas	-	-	-	-	5.6	3.20	5.6	3.20

	Natural Gas	-	-	-	-	2.0	68.97	2.0	68.97
	Liquids
Proved	Light and	-	-	25.1	24.27	(1.6)	(9.25)	23.5	19.47
Undeveloped	Medium Oil
	Heavy Oil	6.2	21.83	-	-	-	-	6.2	21.83

	Natural Gas	-	-	-	-	4.4	4.16	4.4	4.16

	Natural Gas	-	-	-	-	0.6	50.00	0.6	50.00
	Liquids
Total Proved	Light and	-	-	105.8	32.57	6.8	14.88	112.6	30.39
	Medium Oil
	Heavy Oil	46.1	30.09	-	-	-	-	46.1	30.09

	Natural Gas	-	-	-	-	35.9	3.97	35.9	3.97

	Natural Gas	-	-	-	-	11.0	67.90	11.0	67.90
	Liquids
Probable	Light and	-	-	13.5	30.41	3.5	22.73	17.0	28.43
	Medium Oil
	Heavy Oil	27.8	22.75	-	-	-	-	27.8	22.75

	Natural Gas	-	-	-	-	15.4	3.18	15.4	3.18

	Natural Gas	-	-	-	-	5.8	44.96	5.8	44.96
	Liquids
Proved Plus	Light and	-	-	119.3	32.30	10.3	16.86	129.6	30.11
Probable	Medium Oil
	Heavy Oil	73.9	26.83	-	-	-	-	73.9	26.83

	Natural Gas	-	-	-	-	51.3	3.69	51.3	3.69

	Natural Gas	-	-	-	-	16.8	57.73	16.8	57.73
	Liquids

Notes:

(1)	In Egypt and Yemen, under the terms of the Production Sharing Agreements, income tax is current and assessed on all production sharing oil, therefore all Egypt and Yemen Future Net Revenues are after Egypt and Yemen income tax.
(2)	Canadian values converted to US dollars at the December 31, 2007 exchange rates of 1.0 US $'s/Cdn $'s.

Notes to Reserves Data Tables:

1.	Columns may not add due to rounding.

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

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

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

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

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

	(d)	provide improved recovery systems.

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

	(e)	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;

	(f)	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;

	(g)	dry hole contributions and bottom hole contributions;

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

	(i)	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.

(j)	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.

(k)	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:

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

	(i)	Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

	(ii)	Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

(m)	Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

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

	*Levels of Certainty for Reported Reserves*

	The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

	(i)	at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

(ii)

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, 2007, 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
2008	90.00	89.50	6.69	91.29	71.60	55.49	3.0	1.00
2009	86.52	86.01	7.29	87.73	64.50	53.32	3.0	1.00
2010	84.87	84.34	7.18	86.03	63.26	52.29	3.0	1.00
2011	83.32	82.78	7.13	84.44	62.09	51.32	2.0	1.00
2012	82.78	82.23	7.19	83.87	61.67	50.98	2.0	1.00
2013	82.19	81.62	7.21	83.26	61.22	50.61	2.0	1.00
Thereafter	+2%/year	+2%/year	+2.0%/yr	+2%/year	+2%/year	+2%/year	+2%/year	+0%/year

Notes:

(1)	Inflation rates for forecasting expenditure prices and costs.

(2)	Exchange rates used to generate the benchmark reference prices in this table.

	The weighted average historical price in US$ realized by the Company in Egypt, for the year ended December 31, 2007 for crude oil was $68.13/Bbl (for the period September 25, 2007 to December 31, 2007).

	The weighted average historical price in US$ realized by the Company in Yemen, for the year ended December 31, 2007 for crude oil was $72.64/Bbl.

	The weighted average historical prices in Cdn$ realized by the Company in Canada, for the year ended December 31, 2007, were $6.64/Mcf for natural gas, $66.82/Bbl for crude oil and $56.49/Bbl for natural gas liquids.

4.	Constant Prices and Costs

	In Egypt, a constant price of $69.60/Bbl (December 31, 2007 actual prices) was utilized in the constant price case.

	In Yemen, a constant price of $92.62/Bbl (December 31, 2007 actual prices) was utilized in the constant price case.

	In Canada, constant prices of $79.41/Bbl of oil and $7.97/Mcf of natural gas (December 31, 2007 actual prices converted to US$ at the December 31, 2007 currency rate of 1.0 US$/Cdn$, adjusted for quality and energy content), were utilized in the constant price case.

5.	Future Development Costs

FUTURE DEVELOPMENT COSTS
TOTAL COMPANY⁽¹⁾AS AT DECEMBER 31, 2007

(US$ MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2008	20.1	26.1
2009	1.3	4.3
2010	-	-
2011	0.0	0.0
2012	0.2	0.2

Total Undiscounted	21.8	31.1

Note:

(1)	Cdn$'s converted at the December 31, 2007 year end rate of 1.00 US$/Cdn$.

FUTURE DEVELOPMENT COSTS
EGYPT
AS AT DECEMBER 31, 2007

(US$ MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2008	3.7	8.4
2009	-	1.2
2010	-	-
2011	-	-
2012	-	0.0

Total Undiscounted	3.7	9.6

FUTURE DEVELOPMENT COSTS
YEMEN
AS AT DECEMBER 31, 2007

(US$ MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2008	7.1	8.3
2009	-	-
2010	-	-
2011	-	-
2012	-	-

Total Undiscounted	7.1	8.3

FUTURE DEVELOPMENT COSTS
CANADA⁽¹⁾AS AT DECEMBER 31, 2007

(US$ MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2008	9.3	9.4
2009	1.3	3.1
2010	-	-
2011	0.0	0.0
2012	0.2	0.2

Total Undiscounted	10.9	13.2

Note:

(1)	Cdn$ converted at the December 31, 2007 year-end rate of 1.00 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.	In Egypt, 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.

	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.

7.	The forecast price and cost assumptions assume the continuance of current laws and regulations.

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

Reconciliations of Changes in Reserves

RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
COMPANY
AS AT DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

												ASSOCIATED & NON-
	LIGHT & MEDIUM OIL						HEAVY OIL					ASSOCIATED GAS						NATURAL GAS LIQUIDS
					Gross					Gross						Gross						Gross
					Proved					Proved						Proved						Proved
	Gross		Gross		Plus		Gross		Gross	Plus		Gross		Gross		Plus		Gross		Gross		Plus
	Proved		Probable		Probable		Proved		Probable	Probable		Proved		Probable		Probable		Proved		Probable		Probable
FACTORS	(MBbl)		(MBbl)		(MBbl)		(MBbl)		(MBbl)	(MBbl)		(MMcf)		(MMcf)		(MMcf)		(MBbl)		(MBbl)		(MBbl)
December 31, 2006	7,445		1,107		8,552		-		-	-		10,005		6,090		16,095		227		190		417
Extensions	134		36		170		-		-	-		2,946		555		3,501		30		8		38
Improved recovery	-		-		-		-		-	-		-		-		-		-		-		-
Technical Revisions	957		(77	)	880		-		-	-		(58	)	(886	)	(944	)	37		(12	)	25
Discoveries	-		-		-		-		-	-		-		-		-		-		-		-
Acquisitions	-		-		-		2,952		2,311	5,263		-		-		-		-		-		-
Dispositions	-		-		-		-		-	-		-		-		-		-		-		-
Economic Factors	-		-		-		-		-	-		-		-		-		-		-		-
Production	(1,473	)	-		(1,473	)	(158	)	-	(158	)	(2,185	)	-		(2,185	)	(71	)	-		(71	)
December 31, 2007	7,063		1,066		8,129		2,795		2,311	5,106		10,708		5,759		16,467		224		186		410

RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
EGYPT
AS AT DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

									ASSOCIATED & NON-
	LIGHT & MEDIUM OIL			HEAVY OIL					ASSOCIATED GAS			NATURAL GAS LIQUIDS
			Gross				Gross				Gross			Gross
			Proved				Proved				Proved			Proved
	Gross	Gross	Plus	Gross		Gross	Plus		Gross	Gross	Plus	Gross	Gross	Plus
	Proved	Probable	Probable	Proved		Probable	Probable		Proved	Probable	Probable	Proved	Probable	Probable
FACTORS	(MBbl)	(MBbl)	(MBbl)	(MBbl)		(MBbl)	(MBbl)		(MMcf)	(MMcf)	(MMcf)	(MBbl)	(MBbl)	(MBbl)
December 31, 2006	-	-	-	-		-	-		-	-	-	-	-	-
Extensions	-	-	-	-		-	-		-	-	-	-	-	-
Improved recovery	-	-	-	-		-	-		-	-	-	-	-	-
Technical Revisions	-	-	-	-		-	-		-	-	-	-	-	-
Discoveries	-	-	-	-		-	-		-	-	-	-	-	-
Acquisitions	-	-	-	2,952		2,311	5,263		-	-	-	-	-	-
Dispositions	-	-	-	-		-	-		-	-	-	-	-	-
Economic Factors	-	-	-	-		-	-		-	-	-	-	-	-
Production	-	-	-	(158	)	-	(158	)	-	-	-	-	-	-
December 31, 2007	-	-	-	2,795		2,311	5,106		-	-	-	-	-	-

RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
YEMEN
AS AT DECEMBER 31, 2007
(FORECAST PRICES AND COSTS)

										ASSOCIATED & NON-
	LIGHT & MEDIUM OIL						HEAVY OIL			ASSOCIATED GAS			NATURAL GAS LIQUIDS
					Gross				Gross			Gross			Gross
					Proved				Proved			Proved			Proved
	Gross		Gross		Plus		Gross	Gross	Plus	Gross	Gross	Plus	Gross	Gross	Plus
	Proved		Probable		Probable		Proved	Probable	Probable	Proved	Probable	Probable	Proved	Probable	Probable
FACTORS	(MBbl)		(MBbl)		(MBbl)		(MBbl)	(MBbl)	(MBbl)	(MMcf)	(MMcf)	(MMcf)	(MBbl)	(MBbl)	(MBbl)
December 31, 2006	7,048		951		7,999		-	-	-	-	-	-	-	-	-
Extensions	-		-		-		-	-	-	-	-	-	-	-	-
Improved recovery	-		-		-		-	-	-	-	-	-	-	-	-
Technical Revisions	915		(48	)	867		-	-	-	-	-	-	-	-	-
Discoveries	-		-		-		-	-	-	-	-	-	-	-	-
Acquisitions	-		-		-		-	-	-	-	-	-	-	-	-
Dispositions	-		-		-		-	-	-	-	-	-	-	-	-
Economic Factors	-		-		-		-	-	-	-	-	-	-	-	-
Production	(1,396	)	-		(1,396	)	-	-	-	-	-	-	-	-	-
December 31, 2007	6,567		903		7,470		-	-	-	-	-	-	-	-	-

RECONCILIATION OF GROSS RESERVES
BY PRINCIPAL PRODUCT TYPE
CANADA
AS AT DECEMBER 31, 2007
(FORECAST PRICES AND COST)

										ASSOCIATED & NON-
	LIGHT & MEDIUM OIL						HEAVY OIL			ASSOCIATED GAS						NATURAL GAS LIQUIDS
					Gross				Gross					Gross						Gross
					Proved				Proved					Proved						Proved
	Gross		Gross		Plus		Gross	Gross	Plus	Gross		Gross		Plus		Gross		Gross		Plus
	Proved		Probable		Probable		Proved	Probable	Probable	Proved		Probable		Probable		Proved		Probable		Probable
FACTORS	(MBbl)		(MBbl)		(MBbl)		(MBbl)	(MBbl)	(MBbl)	(MMcf)		(MMcf)		(MMcf)		(MBbl)		(MBbl)		(MBbl)
December 31, 2006	397		156		553		-	-	-	10,005		6,090		16,095		227		190		417
Extensions	134		36		170		-	-	-	2,946		555		3,501		30		8		38
Improved recovery	-		-		-		-	-	-	-		-		-		-		-		-
Technical Revisions	41		(28	)	13		-	-	-	(58	)	(886	)	(944	)	37		(12	)	25
Discoveries	-		-		-		-	-	-	-		-		-		-		-		-
Acquisitions	-		-		-		-	-	-	-		-		-		-		-		-
Dispositions	-		-		-		-	-	-	-		-		-		-		-		-
Economic Factors	-		-		-		-	-	-	-		-		-		-		-		-
Production	(77	)	-		(77	)	-	-	-	(2,185	)	-		(2,185	)	(71	)	-		(71	)
December 31, 2007	495		164		659		-	-	-	10,708		5,759		16,467		224		186		410

Additional Information Relating to Reserves Data

Undeveloped Reserves

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

Proved Undeveloped Reserves

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

2005⁽¹⁾	1,655	1,655	-	-	2,570	2,869	7	20
2006⁽²⁾	917	2,293	-	-	42	224	2	2
2007⁽³⁾	1,400	2,294	509	509	1,161	1,257	15	17

Notes:

(1)	In 2005, 91% of the Proved Undeveloped light oil was assigned to Yemen with five horizontal development wells planned in the An Nagyah field (three wells in Lam A and two wells in Lam B), the balance was assigned to un-drilled Wabamum oil spacing units at Nevis in Canada. All the Proved Undeveloped gas and liquids reserves were assigned to Canada. The majority of the gas was assigned to Horseshoe Canyon coal bed methane wells in the Nevis and Morningside areas, assuming 160 acres/well.

(2)	In 2006, 99% of the Proved Undeveloped light oil was assigned to Yemen with two horizontal development wells planned in the An Nagyah field along with gas cycling for liquids recovery at An Nagyah, liquids recovery from the An Naeem gas pool and a re-entry well at Osaylan. The remainder was for a Wabamun oil development well at Nevis. All the Proved Undeveloped gas and liquid reserves were assigned to Canada at Morningside for Horseshoe Canyon coal bed methane development and at Nevis for Wabamun solution gas.

(3)	In 2007, 88% of the Proved Undeveloped light oil was assigned to Yemen with three horizontal development wells at An Nagyah. The remaining light oil reserves are in Canada at Nevis with five horizontal Wabamun oil wells. The heavy oil reserves were assigned to Egypt with one development well at Fadl, two at Hana and two at South Rahmi. Natural gas was assigned in Canada for four Horseshoe Canyon CBM wells at Nevis, seven Horseshoe Canyon CBM wells at Thorsby and associated gas from the five Nevis Wabamun horizontal oil wells. Natural gas liquids were also assigned to the five horizontals. All development activities are anticipated to take place during 2008.

Probable Undeveloped Reserves

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

2005⁽¹⁾	365	365	-	-	593	698	1	5
2006⁽²⁾	591	991	-	-	93	527	16	22
2007⁽³⁾	188	456	1,471	1,471	227	564	4	5

Notes:

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

(2)	In 2006, 96% of Probable Undeveloped light oil reserves were assigned to Yemen consisting of one vertical well at Tasour, one vertical well at Godah and probable components assigned to the proved undeveloped projects including two horizontal An Nagyah wells, gas cycling for liquids recovery at An Nagyah, liquids recovery from the An Naeem gas pool and the re- entry well at Osaylan. The remainder is assigned to two Wabamun oil wells at Nevis. All the Probable Undeveloped gas and liquids reserves were assigned to Canada, specifically, two Wabamun gas wells at Nevis.

(3)	In 2007, 76% of the Probable Undeveloped light oil was assigned to Yemen for a development well at Godah. The remainder was assigned in Canada for the five Nevis horizontal Wabamun oil wells. The heavy oil reserves were assigned to Egypt with one development well at Arta, two at Fadl, four at Hana and seven at South Rahmi. Natural gas was assigned in Canada for one Horseshoe Canyon CBM wells at Morningside, two Horseshoe Canyon CBM wells at Thorsby and associated gas from the five Nevis Wabamun horizontal oil wells. Natural gas liquids were also assigned to the five horizontals. All development activities are anticipated to take place during 2008.

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, 2007. 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

Egypt	26	14.0	13	6.4	0	0	0	0
Yemen	39	7.7	9	1.9	0	0	5	1.3
Canada, Alberta	11	7.7	5	4.5	52	37.3	29	14.6
Total	76	29.4	27	12.8	52	37.3	34	15.9

Properties with No Attributed Reserves

The following table sets out the Company's developed and undeveloped land holdings as at December 31, 2007.

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

Egypt	3,680	1,856	5,540,379	2,768,596	5,544,059	2,770,452
Yemen⁽¹⁾	35,200	6,918	1,291,304	359,023	1,326,504	365,941
Canada, Alberta	29,096	18,708	65,798	50,122	94,894	68,830
Total	67,976	27,482	6,897,481	3,177,741	6,965,457	3,205,223

Note:

(1)	Yemen undeveloped land includes 183,000 gross (60,390 net) acres on Blocks 84 that still requires final government approval and ratification, which approval is expected in 2008.

Of the Company's undeveloped land, the rights to explore, develop and exploit 8,079 gross (6867 net) acres may expire in Canada by December 31, 2008.

The Company does not have any work commitments associated with its undeveloped lands in Yemen Blocks 32 and S-1 or in Canada.

In Yemen Block 72, the Company has a work commitment of $4 million gross ($1.32 million net) in Phase 1 (expiry extended to January 2009). Seismic acquisition is ongoing with drilling expected in mid-2008. In Yemen Block 75, the contractor (Block 75 Joint Venture Group) has a commitment of $7 million gross ($1.75 million net) for the signature bonus and first exploration period work period (36 months) commencing March 8, 2008. Pursuant to the bid awarded for Yemen Block 84, the contractor has a minimum commitment of $20.1 million gross ($6.63 million net) for the signature bonus and first exploration work period (42 months). The commitment will commence when the PSC has been approved and ratified by the government of Yemen, anticipated to occur in 2008.

In Nuqra Block 1 in Egypt, the Company has fulfilled the work commitments of the first three-year exploration extension period expiring July 18, 2009. There is an option to proceed with a second three-year extension which requires a mandatory relinquishment of 25% of the original Block and the drilling of two wells.

In the West Gharib PSC in Egypt, the Company has a commitment to drill three exploration wells by May 31, 2009 on the East Hoshia development lease, which is secured by a $4 million production guarantee.

Forward Contracts

The Company's contracts to sell crude oil or natural gas are at prevailing market pricing, except for the following financial derivative contracts respecting crude oil:

			*Dated Brent Pricing*
*Period*	*Volume*	*Type*	*Put – Call*
Sep 1, 2007 – Aug 31, 2008	15,000 Bbls/month	Financial Collar	$60.00 - $78.55/Bbl
Jan 1, 2008 – Dec 31, 2008	12,000 Bbls/month	Financial Collar	$60.00 - $81.20/Bbl
Jan 1, 2009 – Dec 31, 2009	12,000 Bbls/month	Financial Collar	$60.00 - $82.10/Bbl

			*Dated Brent Pricing*
*Period*	*Volume*	*Type*	*Put – Call*
Nov 1, 2007 – Mar 31, 2008	5,000 Bbls/month	Financial Collar	$65.00 - $89.35/Bbl
Sep 1, 2008 – Jan 31, 2009	11,000 Bbls/month	Financial Collar	$60.00 - $88.80/Bbl
Feb 1, 2009 – Dec 31, 2009	6,000 Bbls/month	Financial Collar	$60.00 - $86.10/Bbl
Jan 1, 2010 – Aug 31, 2010	12,000 Bbls/month	Financial Collar	$60.00 - $84.25/Bbl

The total volumes hedged per year are listed below:

*Volume*	*2008*	*2009*	*2010*
Annual (Bbls)	323,000	221,000	96,000
Daily Average (bopd)	885	605	263

Additional Information Concerning Abandonment and Reclamation Costs

In Egypt, future well abandonment costs net of salvage were included in the DeGolyer reserves evaluation presented herein. Cost in U.S. dollars to abandon approximately 46 gross (24.0 net) wells totalled $906,000 undiscounted, or $252,000 discounted at 10%, are included in the estimate of future net revenue from total proved plus probable reserves. Approximately $29,000 thousand undiscounted, or $21,000 thousand discounted at 10%, are scheduled during the next three years (2008-2010).

In Yemen, estimated future abandonment costs have not been taken into account by DeGolyer. 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, future well abandonment costs net of salvage were included in the DeGolyer reserves evaluation presented herein. Cost in US$ to abandon approximately 143 gross (92.5 net) wells totalled $3,959,000 undiscounted, or $1,698,000 discounted at 10%, are included in the estimate of future net revenue from total proved plus probable reserves. Approximately $787,000 undiscounted, or $591,000 discounted at 10%, are scheduled during the next three years (2008-2010).

Tax Horizon

In 2007, the Company did not pay any income taxes in Canada.

TransGlobe does not expect to pay income taxes in Canada in the near future, assuming the Company incurs further Canadian exploration expense and Canadian development expense and utilizes such tax pools and tax losses available to be carried forward of Cdn$54 million available to shelter future taxable income.

Capital Expenditures

The following table summarizes the 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, 2007:

	Canada	Yemen	Egypt	Total
($ thousands)
Property acquisition costs
Proved properties	600	0	-	600
Undeveloped properties	1,577	(240)	-	1,337
Exploration costs	1,217	2,787	4,200	8,204
Development costs	7,371	12,639	2,704	22,714
Corporate and other	909	3,251	-	4,160
Corporate acquisition	-	-	59,136	59,136
Total	11,674	18,437	66,040	96,151

Production Estimates

The following table sets out the volume of the Company's daily production (working interest before royalties) estimated for the year ending December 31, 2008 which is reflected in the estimate of future net revenue disclosed in the prior reserves summary tables.

	Yemen	Yemen
	Block 32	Block S-1	Egypt	Canada		Canada⁽¹⁾	Total
	Light and	Light and	West Gharib	Light and	Canada⁽¹⁾	Natural Gas	Company⁽¹⁾
	Medium Oil	Medium Oil	Heavy Oil	Medium Oil	Natural Gas	Liquids	BOE
	Gross	Gross	Gross	Gross	Gross	Gross	Gross
	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(BOE/d)
Proved Producing	872	2,426	1,493	172	6,391	125	6,153
Proved Developed
Non-Producing	48	84	61	8	798	15	349
Proved
Undeveloped	0	154	252	27	249	2	477
Total Proved	920	2,665	1,806	206	7,437	143	6,979
Total Probable	131	38	733	15	462	10	1,004
Total Proved Plus
Probable	1,051	2,702	2,539	221	7,899	153	7,983

Note:

(1)	Production numbers for 2008 include Canadian production for the full year 2008. The Company’s outlook for 2008 assumes the Canadian production is divested April 1, 2008.

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, 2007:

*Egypt:*		Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	-	-	-	-	-	-
Crude Oil	-	1	1	-	0.7	0.7
Service	-	-	-	-	-	-
Dry and Abandoned⁽¹⁾	3	-	3	1.5	-	1.5
Total	3	1	4	1.5	0.7	2.2


*Yemen:*		Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	-	-	-	-	-	-
Crude Oil	-	10	10	-	2.1	2.1
Service	-	-	-	-	-	-
Dry and Abandoned⁽¹⁾	3	-	3	0.6	-	0.6
Total	3	10	13	0.6	2.1	2.7


*Canada:*		Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	1	14	15	0.5	4.9	5.4
Crude Oil	-	-	-	-	-	-
Service	-	-	-	-	-	-
Dry and Abandoned⁽¹⁾	1	2	3	0.7	1.5	2.2
Total	2	16	18	1.2	6.4	7.6

Note:

(1)

"Dry well" means a well which is not a productive well or a service well. A productive well is a well that 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.

(2)

For the Company's 2008 planned exploration and development activities, see "Principal Properties".

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:

	2007
	Quarter Ended
	Mar. 31	Jun. 30	Sep. 30	Dec. 31
*Average Daily Sales Volumes*
Egypt
Heavy Crude Oil (Bbls/d)	-	-	118	1,594
Yemen
Light and Medium Crude Oil (Bbls/d)	3,892	3,964	3,712	3,739
Canada
Light and Medium Crude Oil (Bbls/d)	229	208	214	194
Gas (Mcf/d)	6,177	5,767	6,067	6,756
NGL (Bbls/d)	191	220	172	184
Combined (BOE/d)	5,341	5,353	5,227	6,837

*Average Price Received*
Egypt
Heavy Crude Oil ($/Bbl)	-	-	56.73	68.97
Yemen
Light and Medium Crude Oil ($/Bbl)	57.14	69.42	75.29	89.18
Canada
Light and Medium Crude Oil ($/Bbl)	52.36	60.56	74.05	82.23
Gas ($/Mcf)	6.73	6.96	6.19	6.71
NGL ($/Bbl)	47.26	51.12	58.43	70.30
Combined ($/BOE)	53.58	63.68	67.04	75.83

*Royalties*
Egypt
Heavy Crude Oil ($/Bbl)	-	-	32.25	38.09
Yemen
Light and Medium Crude Oil ($/Bbl)	26.88	33.00	38.10	49.16
Canada
Light and Medium Crude Oil ($/Bbl)	7.96	7.90	8.43	9.35
Gas ($/Mcf)	1.35	1.19	1.03	1.19
NGL ($/Bbl)	10.21	13.99	12.62	15.87
Combined ($/BOE)	21.85	26.60	29.75	37.63

*Operating Expenses*
Egypt
Heavy Crude Oil ($/Bbls)	-	-	2.33	4.75
Yemen
Light and Medium Crude Oil ($/Bbls)	3.89	8.34	7.22	10.17
Canada
Light and Medium Crude Oil ($/Bbl)	14.72	21.36	17.44	18.33
Gas ($/Mcf)	1.33	1.48	0.91	1.31
NGL ($/Bbls)	-	-	-	-
Combined ($/BOE)	5.01	8.60	6.95	8.48

*Netback Received*
Egypt
Heavy Crude Oil ($/Bbl)	-	-	22.15	26.13
Yemen
Light and Medium Crude Oil ($/Bbl)	26.37	28.08	29.97	29.85

	2007
	Quarter Ended
	Mar. 31	Jun. 30	Sep. 30	Dec. 31
Canada
Light and Medium Crude Oil ($/Bbl)	29.68	31.30	48.18	54.55
Gas ($/Mcf)	4.05	4.29	4.24	4.20
NGL ($/Bbl)	37.05	37.14	45.81	54.43
Combined ($/Boe)	26.72	28.48	30.34	29.75

The following table indicates the Company's average daily sales volumes from its important fields for the year ended December 31, 2007:

		Light and
		Medium Crude	Gas	NGLs	boe
	Heavy Crude Oil	(Bbls/d)	(Mcf/d)	(Bbls/d)	(boe/d)

Egypt⁽¹⁾	432		-	-	432
Yemen
Block 32		1,202	-	-	1,202
Block S-1		2,624	-	-	2,624
Canada		211	6,193	191	1,434

Total		4,469	6,193	191	5,692

Note:

(1)	Operating results for Egypt are for the period September 25, 2007 to December 31, 2007. In that period, production averaged 1,607 bopd for a yearly average of 432 bopd.

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

TransGlobe is authorized to issue an unlimited number of Common Shares and an unlimited number of preferred shares. As at March 19, 2008, there were 59,766,539 Common Shares issued and outstanding. In addition, as at such date, there were an aggregate of 5,976,654 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 Business Corporations Act (Alberta), the Board of Directors is authorized to fix, before the issue thereof, the designation, rights, privileges, restrictions and condition attaching thereto.

Rights Plan

On April 16, 2003, the Company entered into a shareholder protection rights plan agreement (the "Rights Plan") with Computershare Trust Company of Canada, as rights agent, which was approved by TransGlobe's shareholders on May 29, 2003 at the 2003 annual general and special meeting of shareholders. The Rights Plan generally provides that upon any person or entity acquiring 20% or more of the issued and outstanding Common Shares (except pursuant to certain permitted or excepted transactions) and upon the occurrence of certain other events, each holder of Common Shares, other than such person or entity, shall be entitled to acquire Common Shares at a discounted price. The Rights Plan is similar to other shareholder or unitholder rights plans adopted in the energy sector. The Rights Plan expires in April, 2008 and the Company expects to propose ratification of a new rights plan on the same basic terms as the Rights Plan at its 2008 annual shareholders meeting.

MARKET FOR SECURITIES

TransGlobe's Common Shares are listed and posted on the TSX and the NASDAQ under the trading symbols "TGL" and "TGA", respectively (prior to January 16, 2008 the Common Shares traded in the United States on the AMEX).

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:

(Canadian dollars, except volumes)	High	Low	Volume
2007
January	$6.09	$5.24	643,500
February	$6.06	$5.07	755,400
March	$5.38	$3.50	666,300
April	$5.09	$4.30	683,900
May	$4.88	$4.10	627,500
June	$4.91	$4.12	1,419,100
July	$5.68	$4.50	1,322,100
August	$5.14	$3.69	905,200
September	$5.34	$4.20	593,800
October	$5.74	$4.73	1,482,000
November	$5.51	$4.63	1,429,500
December	$5.60	$4.78	1,502,700

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
2007
January	5.17	4.57	3,506,100
February	5.15	4.30	4,559,000
March	4.61	3.65	4,403,500
April	4.60	3.80	3,376,500
May	4.46	3.79	3,679,500
June	4.60	3.89	4,386,400
July	5.45	4.40	8,164,900
August	4.83	3.45	7,441,900
September	5.29	3.97	4,349,800
October	5.90	4.77	6,643,500
November	6.10	5.08	4,813,900
December	5.75	4.78	3,444,300

ESCROWED SECURITIES

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

DIRECTORS AND OFFICERS

The name and place of residence of each director and officer, the offices held by each in the Company, the principal occupation of each director and officer, the period served as director or officer and the number of securities of the Company owned by such individuals as at March 19, 2008 is as follows:

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

Robert A. Halpin^(1)(2)(4) Alberta, Canada	Chairman of the Board and Director	1997	634,000 ⁽⁵⁾ (1.06%)	Retired Petroleum Engineer, formerly Vice President, International Exploration of Petro- Canada with 50 years' experience in the petroleum industry.

Ross G. Clarkson Alberta, Canada	President, Chief Executive Officer and Director	1995	2,320,972 ⁽⁶⁾ (3.88%)	President and Chief Executive Officer of the Company since December 4, 1996, with over 30 years' oil and gas industry experience as a senior geological advisor.

Lloyd W. Herrick Alberta, Canada	Vice-President, Chief Operating Officer and Director	1999	745,900 ⁽⁷⁾ (1.25%)	Vice-President and Chief Operating Officer of the Company since April 28, 1999, with over 30 years' experience in both domestic and international oil and gas exploration and development.

Erwin L. Noyes^(2)(3)(4) British Columbia, Canada	Director	1995	268,347⁽⁸⁾ (0.45%)	Retired since July 31, 2000; formerly Vice- President, International Operations of the Company, with over 40 years' experience in the oil and gas industry.

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

Geoffrey C. Chase^(1)(3)(4) Alberta, Canada	Director	2000	86,500⁽⁹⁾ (0.15%)	Retired Senior Vice-President, Business Development, with Ranger Oil, with over 35 years' experience in the oil and gas industry.

Fred J. Dyment^(1)(2)(3) Alberta, Canada	Director	2004	50,000⁽¹⁰⁾ (0.08%)	Chartered accountant with over 30 years' experience in the oil and gas industry. Previously President and Chief Executive Officer, Maxx Petroleum Company (2000- 2001). Prior thereto Controller, Vice- President, Finance and then President and Chief Executive Officer of Ranger Oil Limited from 1978-2000.

David C. Ferguson Alberta, Canada	Vice-President, Finance, Chief Financial Officer and Secretary	2001	350,000⁽¹¹⁾ (0.59%)	Chartered accountant with over 25 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⁽¹²⁾(13) Alberta, Canada	Vice-President, Exploration	2004	36,000⁽¹²⁾ (0.06%)	Professional geoscientist with 36 years of experience in the petroleum industry. Prior positions with Nexen as General Manager, Business Development and Occidental Petroleum as Technical Advisor.

Notes:

(1)	Members of the Company's Audit Committee.
(2)	Members of the Company's Compensation Committee.
(3)	Members of the Company's Governance and Nominating Committee.
(4)	Members of the Company's Reserves Committee.
(5)	Mr. Halpin also holds incentive stock options to purchase 152,900 Common Shares consisting of: options to purchase 80,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009, to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 18,900 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(6)	Mr. Clarkson also holds incentive stock options to purchase 322,000 Common Shares consisting of: options to purchase 120,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009, to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 136,000 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(7)	Mr. Herrick also holds incentive stock options to purchase 270,000 Common Shares consisting of: options to purchase 100,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009, to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 104,000 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(8)	Mr. Noyes also holds incentive stock options to purchase 130,500 Common Shares consisting of: options to purchase 60,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009, to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 16,500 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(9)	Mr. Chase also holds incentive stock options to purchase 130,500 Common Shares consisting of: options to purchase 60,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009, to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 16,500 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(10)	Mr. Dyment holds incentive stock options to purchase 111,000 Common Shares consisting of: options to purchase 40,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009, to purchase 54,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 18,000 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(11)	Mr. Ferguson also holds incentive stock options to purchase 219,000 Common Shares consisting of: options to purchase 90,000 Common Shares at Cdn$3.26 per share expiring March 15, 2009, to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 63,000 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(12)	Mr. Bell also holds incentive stock options to purchase 246,000 Common Shares consisting of: options to purchase 150,000 Common Shares at Cdn$3.40 per share expiring January 12, 2009, to purchase 30,000 Common Shares at

	Cdn$7.74 per share expiring March 17, 2010, to purchase 66,000 Common Shares at Cdn$6.03 per share expiring December 5, 2010 and to purchase 60,000 Common Shares at Cdn, $4.27 expiring June 8, 2012.
(13)	Mr. Bell's employment with the Company terminated in March, 2008.

Cease-Trade Orders, Bankruptcies, Penalties or Sanctions

No director is as at the date hereof, or has been, within 10 years of the date hereof, a director or executive officer of any company, including TransGlobe, that while that person was acting in that capacity:

	(a)	was the subject of a cease-trade or similar order or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days;

	(b)	was subject to an event that resulted, after the director or executive officer ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order, or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days,

	(c)	or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or comprise with creditors, or had a receiver, receiver manager or trustee appointed to hold its assets; or

	(d)	has, within the 10 years before the date of this Annual Information Form, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceeding, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or shareholder.

In addition, no director has had any penalties or sanctions imposed against him or entered into any settlement agreement in respect of any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority, including a settlement agreement with a securities regulatory authority, or any other penalties or sanctions imposed by a court or regulatory body.

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 33 full-time employees and 10 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. As at the date hereof, to the knowledge of management of the Company, none of the aforementioned persons or companies, or principals thereof, had any registered or beneficial interests, direct or indirect, in any securities or other property of the Company or of its 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.

INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS

Deloitte & Touche LLP is independent in accordance with the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

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. In addition, there were no penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority during the 2007 financial year, no other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decision, and no settlement agreements entered into by the Company with a court relating to securities legislation or with a securities regulatory authority during the 2007 financial year.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

TRANSFER AGENT AND REGISTRAR

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

MATERIAL CONTRACTS

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

AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

The audit committee of the Company (the "Audit Committee") is comprised of Messrs. Fred Dyment, Geoffrey Chase and Robert Halpin. 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.

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

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

Geoffrey C. Chase Alberta, Canada	Yes	Yes	Mr. Chase received a B.Sc. in Applied Science from Queen's University, Ontario and is a P.Eng. in the Province of Alberta. He has over 35 years of business, executive and

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 TransGlobe 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	2007	Cdn$327,062	2007 corporate year-end and SOX testing
	2006	Cdn$177,844	2006 corporate year-end audit and SOX audit planning

Audit – Related Fees	2007	Cdn$Nil	2007 quarterly reviews
	2006	Cdn$30,330	2006 Quarterly reviews and review of SEC letter

Tax Fees	2007	Cdn$12,869	2007 corporate tax returns and tax compliance
	2006	Cdn$5,937	2006 corporate tax returns and tax compliance

All Other Fees	2007	Cdn$204,197	Due diligence assistance in respect of acquisition
	2006	Cdn$38,877	Annual subscription to Petroview, a software program for oil and gas reconnaissance

RISK FACTORS

General Conditions Relating to Oil and Gas Exploration and Production Operations

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

Industry Risks

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

The Company's operations are subject to the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including encountering unexpected formations or pressures, premature decline of reservoirs, invasion of water into producing formations, blow-outs, cratering, fires and oil spills, all of which could result in personal injuries, loss of life and damage to the property of the Company and others. Although the Company maintains insurance, in amounts and coverages which it considers adequate and 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, royalty 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 (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, as well as the Nuqra Block 1 and West Gharib PSC in Egypt represent major undertakings. The exploration programs in Yemen and Egypt are high-risk ventures with uncertain prospects for ongoing success.

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

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

Competition

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

Title to Properties

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

Interests in Properties

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

There can be no assurance that the agreements entered into with the Government of Egypt and the Government of Yemen 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 Egypt and Yemen are subject to risks due to the harsh climate, difficult topography and the potential for social, political, economic, legal and financial instability.

Reliance Upon Officers

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

Kyoto Protocol

In December 2002, the Government of Canada ratified and signed the Kyoto Protocol (see "Industry Conditions – Environmental Regulation"). As a result of the ratification of the Kyoto Protocol and the adoption of legislation or other regulatory initiatives designed to implement its objectives by the federal or provincial governments, reductions in greenhouse gases from crude oil and natural gas producers may be required which could result in, among other things, increased operating and capital expenditures for producers (including the Company) which may make certain

production of crude oil and natural gas by those producers uneconomic, resulting in reductions in such production. Until such legislation or other regulatory initiatives are finalized, the impact of the Kyoto Protocol and any such legislation adopted as a result of its ratification remains uncertain. The direct or indirect costs of such legislation or regulatory initiatives may adversely affect the business of the Company.

Exchange Rate Risks

The Canadian to US dollar exchange rate has strengthened 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.

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 dependent on the performance of its key employees. Failure to retain or to attract and retain additional key employees with necessary skills could have a materially adverse impact upon the Company's growth and profitability.

Dilutive Effect of Financings and Acquisitions

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

INDUSTRY CONDITIONS

Government Regulation Generally

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

Pricing and Marketing – Oil and Natural Gas

In Canada, the producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council.

In Yemen, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance. Yemen is not currently a member of the Organization of Petroleum Exporting Countries ("OPEC").

In Egypt, 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. Egypt is not currently a member of OPEC.

Pricing and Marketing - Natural Gas

In Canada, the price of natural gas is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m³/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export license from the NEB and the issuance of such license requires the approval of the Governor in Council.

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

Pipeline Capacity

In Egypt, export oil pipelines are owned by the government of Egypt 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.

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.

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

The North American Free Trade Agreement

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, United States of America and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export

restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period), (ii) impose an export price higher than the domestic price subject to an exception with respect to certain measures which only restrict the volume of exports, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export-price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

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

Royalties and Incentives

Egypt

In Egypt, the respective Production Sharing Concessions 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.

Yemen

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

Canada

In addition to federal regulation in Canada, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are from time to time carved out of the working interest owner's interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

From time to time the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the trend in recent years has been for provincial governments to allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

The Canadian federal corporate income tax rate levied on taxable income is 22.1% effective January 1, 2007 for active business income including resource income. With the elimination of the corporate surtax effective January 1, 2008 and other rate reductions introduced in the 2006 Federal Budget, the federal corporate income tax rate will decrease to 19% in three steps: 20.5% on January 1, 2008, 20% on January 1, 2009 and 19% on January 1, 2010.

Alberta

In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. Currently, the amount of royalties that are payable is influenced by the oil production, density of the oil, and the vintage of the oil. Originally, the vintage classified oil in "new oil" and "old oil" depending on when the oil pools were discovered. If discovered prior to March 31, 1974, it is considered "old oil", if discovered after March 31, 1974 and before September 1, 1992, it is considered "new oil". The Alberta government introduced in 1992 a Third-Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.

The royalty reserved to the Crown in respect of natural gas production, subject to various incentives, is between 15% and 30%, in the case of new natural gas, and between 15% and 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends on the depth of the well.

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

Regulations made pursuant to the Mines and Minerals Act (Alberta) provided various incentives for exploring and developing oil reserves in Alberta. However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program ("ARTC") was to be eliminated, effective January 1, 2007. The programs affected by this announcement are: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction. The program being introduced is the Innovative Energy Technologies Program (the "IETP"), which is intended to promote the producers' investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value. The IETP provides royalty reductions which are presumed to reduce financial risk. Alberta Energy will be the one to decide which projects qualify and the level of support that will be provided. The deadline for the IETP's third round of applications is May 31, 2007.

Land Tenure

Crude oil and natural gas located in the western Canadian provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms from two years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with

such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.

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

In December, 2002, the Government of Canada ratified the Kyoto Protocol. The Kyoto Protocol calls for Canada to reduce its greenhouse gas emissions to 6% below 1990 "business-as-usual" levels between 2008 and 2012. Given revised estimates of Canada's normal emissions levels, this target translates into an approximately 40% gross reduction in Canada's current emissions. It remains uncertain whether the Kyoto Protocol target of 6% below 1990 emission levels will be enforced in Canada. The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using a "intensity based" approach, the specifics of which have yet to be determined. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007. As details of the implementation of this legislation have not yet been announced, the effect of our operations cannot be determined at this time.

The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production. Future federal legislation may require reductions of emissions or emissions intensity produced by our operations and facilities.

Provincial legislation currently requires energy industries to follow a mandatory emissions reporting scheme, in advance of further regulations targeting emissions output and improving energy efficiency standards of our operations. The direct or indirect costs of these enactments and proposals may adversely affect our business.

Trends

Certain trends that have been developing in the oil and gas industry during the past several years appear to be shaping the near future of the business.

One of the trends is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. A tight supply-demand balance for natural gas causes significant elasticity in pricing, whereas higher than average storage levels tend to depress natural gas pricing. Drilling activity, weather, fuel switching and demand for electrical generation are all factors that affect the supply-demand balance. Changes to any of these or other factors create price volatility.

Crude oil is influenced by the world economy and OPEC's ability to adjust supply to world demand. Crude oil prices are at historical highs due to political events causing disruptions in the supply and concerns over potential supply due to high world demand.

The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. Purchasing land and properties similarly increase in price during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline.

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 the Company's financial statements and the management's discussion and analysis for the year ended December 31, 2007. These documents, along with other documents affecting the rights of securityholders and other information relating to the Company, may be found on SEDAR at www.sedar.com.

SCHEDULE "A"

FORM 51-101F2
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, 2007. The reserves data are estimates of proved reserves and probable reserves and related future net revenues at December 31, 2007, estimated using forecast prices and costs.

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, 2007, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's board of directors.

Location of

Net Present Value of Future Net Revenue

Reserves

(before income taxes, 10% discount rate)

(County or

Independent Qualified

Description and

Foreign

Reserves Evaluator or

Preparation Date of

Geographic

Auditor

Evaluation Report

Area)

Audited

Evaluated

Reviewed

Total

U.S. M$

DeGolyer and

Appraisal Report as of

Canada

72,542

MacNaughton Canada

December 31, 2006 on

Egypt

65,044

Limited

Certain Properties owned

by TransGlobe Energy

Yemen

104,202

Corporation dated

Total

241,788

February 16, 2007

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

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

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

Executed as to our report referred to above:

DeGolyer and MacNaughton Canada Limited, Calgary, Alberta, dated February 6, 2008.

	DEGOLYER and MACNAUGHTON CANADA LIMITED



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

SCHEDULE "B"

FORM 51-101F3
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 are estimates of, proved reserves and probable reserves and related future net revenues as at December 31, 2007, estimated using forecast prices and costs.

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

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

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

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

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

The Reserves Committee of the board of directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved

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

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

	(f)	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.

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


Per:	(signed) "Lloyd Herrick"	Per:	(signed) "Robert Halpin"
	Lloyd Herrick		Robert Halpin
	Vice-President, Chief Operating Officer and		Director and Chairman of the Board
	Director

March 24, 2008

SCHEDULE "C"

CHARTER OF AUDIT COMMITTEE

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

GENERAL FUNCTIONS, AUTHORITY, AND ROLE

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

The Audit Committee 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. In its capacity as a committee of the Board of Directors, the Audit Committee has the power to determine the amount of Company funds that are appropriate for payment of (1) compensation to the Company's independent auditor engaged for the purpose of preparing audit reports and performing other audit and non-audit services, (2) independent counsel and other advisers as it determines necessary to carry out its duties and (3) ordinary administrative expenses as it determines necessary to carry out its duties. 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 retain and evaluate the independent auditor, 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 by the Board of Directors as having satisfied the independence standards specified in all applicable rules of the Canadian provincial securities commissions, the U.S. Securities and Exchange Commission (the "SEC") and any securities exchange on which the Company's shares are traded, with such affirmation disclosed in the Company's Annual Information Circular.
The Committee will also consist of all members that meet the definition of "Financially Literate" as defined in Multilateral Instrument 52-110 Part 1(1.5) and are able to read and understand fundamental

C-2

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:

Frequency of Meetings

Meet on at least a quarterly basis, either in person or telephonically.

Meet with the independent auditor on at least a quarterly basis, 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.

Charter Review

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

Advise of Counsel

The Committee shall receive and review any reports from counsel to the Company concerning evidence of any material violation of law by the Company.

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, internal accounting controls and auditing matters. The mechanism must include procedures for receiving, 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.

C-3

Insure that the independent auditor is not engaged for any of the following nine types of non-audit services contemporaneous with the audit:

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

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

Hiring Practices

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

Independence Test

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

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;
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
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.

C-4

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:

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

Review, discuss with management and the independent auditor and approve annual and interim quarterly financial statements (including related notes and MD&A) at the completion of any review engagement or other examination and prior to public disclosure. The designated financial expert of the Audit Committee may represent the entire Audit Committee for purposes of this review.

Review and discuss with management and the independent auditor the adequacy of the Company's internal control over financial reporting that management and the Board of Directors have established and the effectiveness of those systems, including, but not limited to, review and discussion of (1) management's report on its assessment of the effectiveness of internal control over financial reporting as of the end of each fiscal year and the independent auditor's report on management's assessment and the effectiveness of internal control over financial reporting, (2) inquiry of management and the independent auditor about significant financial risks, exposures, deficiencies or material weaknesses identified and the steps management has taken to minimize such risks, exposures, deficiencies and material weaknesses to the Company and (3) any changes in internal control over financial reporting that have materially affected or are reasonably likely to materially affect the Company's internal control over financial reporting and are required to be disclosed, as well as any other changes in internal control over financial reporting that were considered for disclosure in the Company's periodic filings with the SEC.

Meet separately with the independent auditor, management and the CFO as necessary or appropriate to discuss any matters that the Audit Committee or any of these groups believe should be discussed privately with the Audit Committee.

Review and discuss with management and the independent auditor the accounting policies which may be viewed as critical, including all alternative treatments for financial information within generally accepted accounting principles that have been discussed with management, and review and discuss any significant changes in the accounting policies of the Company and industry accounting and regulatory financial reporting proposals that may have a significant impact on the Company's financial reports.

Review with management and the independent auditor the effect of regulatory and accounting initiatives as well as off-balance sheet structures, if any, on the Company's financial statements.

Review with management and the independent auditor any correspondence with regulators or governmental agencies and any employee complaints or published reports which raise material issues regarding the Company's financial statements or accounting policies.

C-5

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, prior to filing with regulatory bodies, annual and periodic filings with the Canadian provincial securities commissions and the SEC and other published documents containing the Company's financial statements.

RISK ASSESSMENT

Review the Company's policies with respect to risk assessment and risk management including, without limitation, environmental risk, insurance coverage and the risk of fraud. The Committee also shall discuss the Company's major risk exposures and the steps management has taken to monitor and control them.

AMENDMENTS TO AUDIT COMMITTEE CHARTER

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