Edgar Filing: TRANSGLOBE ENERGY CORP

Filed by Automated Filing Services Inc. (604) 609-0244 - TransGlobe Energy Corporation - Form 20-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 20-F

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2002

Commission File No.: 0-11378

TRANSGLOBE ENERGY CORPORATION
(Exact name of Registrant as specified in its charter)

British Columbia, Canada
(Jurisdiction of incorporation or organization)

Suite 2900
330 – Fifth Avenue S.W.
Calgary, Alberta
Canada
T2P 0L4
(Address of principal executive office)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

None

Securities registered or to be registered pursuant to Section 12(g) of the Act:

(Title of class)
Common Shares

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

(Title of class)
None

Indicate the number of outstanding shares of each of the Issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

51,494,801 Common Shares

Indicate by a check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports and (2) has been subject to such filing requirements for the past 90 days.

YES X NO

Indicate by check mark which financial statement item the registrant has elected to follow:

Item 17 X Item 18

Index to Exhibits on Page 42

Page 1 of 62

TABLE OF CONTENTS

PART I		5
ITEM 1.	Identity Of Directors, Senior Management And Advisers	5
ITEM 2.	Offer Statistics And Expected Timetable	5
ITEM 3.	Key Information	5
ITEM 4.	Information On The Company	9
ITEM 5.	Operating and Financial Review and Prospects	23
ITEM 6.	Directors, Senior Management and Employees	30
ITEM 7.	Major Shareholders and Related Party Transactions	34
ITEM 8.	Financial Information	35
ITEM 9.	The Offer and Listing	36
ITEM 10.	Additional Information	36
ITEM 11.	Quantitative and Qualitative Disclosures About Market Risk	40
ITEM 12.	Description Of Securities Other Than Equity Securities	40

PART II		40
ITEM 13.	Defaults, Dividend Arrearages and Delinquencies	40
ITEM 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	40
ITEM 15.	Controls and Procedures	41
ITEM 16.	Reserved	41

PART III		41
ITEM 17.	Financial Statements	41
ITEM 18.	Financial Statements	41
ITEM 19.	Exhibits	42

Page 2 of 62

GLOSSARY OF TERMS

The terms defined are used throughout this Annual Report.

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

Bbl One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Boe One barrel of oil equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas, unless defined otherwise.

Boepd One barrel of oil equivalent per day.

Bopd Barrels of oil per day.

Common Share or Shares The common shares of TransGlobe.

Dry Hole Dry Well Non-Productive Well 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 An exploratory well is 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.

GAAP Generally accepted accounting principles.

Gross Acres or Gross Wells The total acres or wells, as the case may be, in which a working interest is owned. MBbls One thousand barrels of crude oil or other liquid hydrocarbons. Mboe One thousand Boes. Mcf One thousand cubic feet of natural gas. Mcfpd One thousand cubic feet of natural gas per day. MMcf One million cubic feet of natural gas. Moiibus Moiibus Resource Corporation, acquired by the Company in April 1999. MMcfpd One million cubic feet of natural gas per day.

MOM Ministry of Oil and Minerals, Republic of Yemen, formerly MOMR, the Ministry of Oil and Mineral Resources.

Net Acres or Net Wells The sum of the fractional working interests owned in gross acres or gross wells.

NGL’s Natural gas liquids.

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

Productive Well A well that is producing oil or natural gas or that is capable of production.

Proved Developed Reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved Undeveloped Reserves Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

PSA Production Sharing Agreement.

Page 3 of 62

Q Quarter

TSX The Toronto Stock Exchange.

Undeveloped Acreage Lease acreage on which wells have not been participated in or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Vintage means Vintage Petroleum, Inc. and its subsidiaries.

Working Interest The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property as well as to a share of production.

YOC The Yemen Company or Yemen Oil Company.

Yr Year

PRESENTATION OF INFORMATION

TransGlobe Energy Corporation (the “Company”) conducts its operations directly and through subsidiaries. The term “TransGlobe” as used herein refers, unless the context otherwise requires, to the Company and its wholly owned subsidiaries. Unless otherwise specified, all dollar amounts described herein are in United States currency. All references to daily production are before royalty, unless stated otherwise.

FORWARD LOOKING STATEMENTS

This Report contains forward looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 (United States). These forward looking statements are not guarantees of TransGlobe’s future operational or financial performance and are subject to risks and uncertainties. Certain statements in this Report constitute forward looking statements. When used in this Annual Report, the words estimate”, “intend”, “expect”, “anticipate” and similar expressions are intended to identify forward-looking statements. Readers are cautioned not to place undue reliance on these statements, which speak only as of the date of this Annual Report. These statements are subject to risks and uncertainties that could cause results to differ materially from those contemplated in such forward-looking statements. Such risks and uncertainties include, but are not limited to, those identified under the subheading “Risk Factors” in Item 3 hereof.

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, product or transportation of TransGlobe’s crude oil and natural gas reserves, changes or disruptions in the political or fiscal regimes in TransGlobe’s areas of activity, changes in Canadian, Yemen; or American tax, energy or other laws or regulations, changes in significant capital expenditures, delays in production starting up due to an industry shortage of skilled manpower, equipment or materials, and the cost of inflation.

Page 4 of 62

PART I

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. KEY INFORMATION

A. Selected Financial Data

The Company changed its year end in 1999 from September 30 to December 31. The change in year end was made to accommodate the ability to compare the Company’s results with those of its peers in the industry with the same reporting period. All dollar values are expressed in U.S. dollars, unless otherwise stated.

The selected historical financial information presented in the table below for the fiscal years ended December 31, 2002 ( “Fiscal 2002”). December 31, 2001 (“Fiscal 2001”), December 31, 2000 (“Fiscal 2000”), December 31, 1999 (which was a 15 month fiscal year) (“Fiscal 1999”) and September 30, 1998 (“Fiscal 1998”), is derived from the audited consolidated financial statements of TransGlobe. The audited consolidated financial statements of TransGlobe for the years ended December 31, 2002, 2001 and 2000 are included in this Filing. The selected historical financial information for Fiscal 1999( fifteen month period ended December 31, 1999) and 1998 presented in the table below are derived from audited financial statements of TransGlobe that are not included in this Filing. The selected financial information presented below should be read in conjunction with TransGlobe’s audited consolidated financial statements and the notes thereto (Item 17) and the Operating and Financial Review and Prospects (Item 5) elsewhere in this Filing.

The selected consolidated financial data has been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). The consolidated financial statements included in Item 17 in this filing are also prepared under Canadian GAAP. Included within these financial consolidated statements in Note 14 is a reconciliation between Canadian and US GAAP which differ only in respect of profit after tax and shareholders’ equity.

The Company uses the US dollar as the functional currency for its consolidated financial statements. The exchange rates for the high, low, period average and end of period being the inverse of the rates quoted by the Federal Reserve Bank of New York for Canadian dollars per US $1.00 for Fiscal 1998 to 2002 and for the three months ending March 31, 2003 are as follows:

Fiscal Period	Average (1)	High	Low	Period End

Year Ended
December 31, 2002	0.6376	0.6613	0.6202	0.6339
December 31, 2001	0.6339	0.6289	0.6259	0.6278
December 31, 2000	0.6727	0.6969	0.6410	0.6669
December 31, 1999	0.6680	0.6925	0.6535	0.6925
September 30, 1998	0.6895	0.6563	0.6528	0.6530

Months Ended
November 30, 2002	0.6407	0.6613	0.6258	0.6390
December 31, 2002	0.6364	0.6613	0.6258	0.6339
January 31, 2003	0.6406	0.6586	0.6258	0.6572
February 28, 2003	0.6460	0.6739	0.6258	0.6739
March 31, 2003	0.6546	0.6836	0.6258	0.6813
April 30, 2003	0.6638	0.6976	0.6287	0.6976

(1) The average of the exchange rates on the last day of each month during the applicable period.

Page 5 of 62

TRANSGLOBE ENERGY CORPORATION AND SUBSIDIARY COMPANIES
SELECTED FINANCIAL DATA AS OF AND FOR THE PERIODS ENDED AS SHOWN
(IN $000’S EXCEPT PER SHARE DATA)


Selected Income Statement Data

Amounts in accordance with Canadian GAAP

		Year		Year		Year		Fifteen Month
		Ended		Ended		Ended		Period Ended			Year Ended
		Dec. 31		Dec. 31		Dec. 31		Dec. 31			Sept. 30
		2002		2001		2000		1999			1998

Oil and gas revenue net of royalties	$	13,254	$	8,554	$	2,403	$	1,096		$	1,055
Other income		42		16		279		10			78
Operating expenses		1,843		1,540		499		304			162
General and administrative expenses		814		567		1,140		547			831
Interest on long-term debt		16		4		14		94			31
Depletion and depreciation		4,277		2,762		635		395			1,227
Asset write-downs		-		-		-		-			6,575
Income (loss) before income taxes		6,346		3,697		394		(233	)		(7,692	)
Income taxes		920		635		86		-			-
Income (loss) for the period	$	5,426	$	3,062	$	308	$	(233	)	$	(7,692	)
Income (loss) per share - basic	$	0.11	$	0.06	$	0.01	$	(0.01	)	$	(0.42	)
Approximate amounts in accordance with US GAAP
Income (loss) for the period	$	5,359	$	3,062	$	163	$	(233	)	$	(6,274	)
Income (loss) per share	$	0.10	$	0.06		-	$	(0.01	)	$	( 0.34	)

SELECTED BALANCE SHEET INFORMATION

Amounts in accordance with Canadian GAAP

	2002	2001	2000	1999	1998
	($)	($)	($)	($)	($)

Working capital (deficiency)	4,749	1,382	191	285	(1,147	)
Oil and gas properties – Canada	3,651	3,045	2,001	1,172	60
Oil and gas properties – United States	-	-	-	445	1,537
Oil and gas properties – Yemen	15,067	13,591	12,590	7,977	6,156
Total assets	24,386	18,847	16,325	10,628	8,490

Long-term debt	-	-	78	748	83
Shareholders’ equity	23,345	17,912	14,623	9,042	6,523
Amounts in accordance with US GAAP
Oil and gas properties – United States	-	-	-	590	1,622
Shareholders’ equity	23,345	17,912	14,623	9,187	5,208

B. Risk Factors

General Conditions Relating to Oil and Gas Exploration and Production Operations

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

Industry Risks

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

Page 6 of 62

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

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

The marketability and price of oil and natural gas which may be acquired or discovered by the Company may be affected by numerous factors beyond the control of the Company. The Company may be affected by the differential between the price paid by refiners for light, quality oil and various grades of oil produced by the Company. The Company is subject to market fluctuations in the prices of oil and natural gas, deliverability uncertainties related to the proximity of its reserves to pipeline and processing facilities and extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business. The Company’s operations will be further affected by the remoteness of, and restrictions on access to, certain properties as well as climatic conditions. The Company is also subject to compliance with federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. The Company is not aware of present material liability related to environmental matters. However, it may, in the future, be subject to liability for environmental offences of which it is presently unaware.

Exploration and Development

The Company’s participation in Block 32 and Block S-1 in Yemen represents a major undertaking. The exploration program in Yemen is a high-risk venture with uncertain prospects for success. There are no assurances that commercial amounts of oil and natural gas will be discovered in Block S-1. There are sixteen wells on Block S-1 and none has proved a sufficient reserve size to proceed with a commercial development, although some of the wells have tested oil at commercial rates.

Even if commercial amounts of oil are discovered in Block S-1, development of it, including the required pipeline and production facilities, could take several years. The Company’s development plan would likely involve drilling several wells in an attempt to demonstrate to financiers an economic reserve size exists, and contingent on financing, pipeline and production facilities would be constructed to produce the oil. The assumptions in the Company’s development plan are based on the experience of management and the historical operational experience of other companies working in the vicinity. The assumptions may not be accurate in the future and therefore the project economics may be adversely affected. The harsh operating climate, adverse topography, or unanticipated drilling or logistical problems may cause cost overruns or may make a development project uneconomic. Future development of either Block 32 or Block S-1 may require additional financing which may not be available or, if available, may not be on favourable terms.

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

Competition

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

Page 7 of 62

from Canada, the United States and Republic of Yemen, the proximity and capacity of natural gas pipelines and the effect of provincial, state or federal regulations.

Title to Properties

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

As is customary in the oil and gas industry in Canada, title is reviewed at the time of acquisition of undeveloped and developed properties. A thorough examination of title has been performed with respect to substantially all of the Company’s producing properties in Canada and the Company believes that it has generally satisfactory title to such properties.

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

Government Regulation

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

Political Risks Relating to Yemen

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

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

Reliance Upon Officers

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

Multi-jurisdictional Legal Risks

The Company is incorporated under the laws of the Province of British Columbia, Canada, and all of the Company’s directors and all of its officers are residents of Canada. Consequently, it may be difficult for United States investors to effect service of process within the United States upon the Company or upon those directors or officers, who are not residents of the United States, or to realize in the United States upon judgements of United

Page 8 of 62

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.

ITEM 4. INFORMATION ON THE COMPANY

A. History and Development of the Company

TransGlobe Energy Corporation (referred to herein as “TransGlobe” or the “Company”) and its wholly owned subsidiaries, TransGlobe Oil and Gas Corporation, TransGlobe Petroleum International Inc., TransGlobe International (Holdings) Inc., and TG Holdings Yemen Inc. (“TG Yemen”), are primarily engaged in the exploration for, development, and production of, oil and gas in Canada and the Republic of Yemen.

The address of the Company’s registered office is:
                            28^th Floor
                            666 Burrard Street
                            Vancouver, British Columbia
                            V6C 2Z7

The address and telephone number of the Company’s principal place of business is:
                            2900, 330 – 5^th Avenue S.W.
                            Calgary, Alberta
                            T2P 0L4
                            Telephone:            (403) 264-9888

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 in the province of British Columbia, Canada. In 1992 the Company entered into the oil and gas exploration and development field in the United States and later in the Republic of Yemen and Canada and ceased operations as a mining company. The United States oil and gas properties were sold in the year 2000 to fund opportunities in Yemen. The Company changed its name to TransGlobe Energy Corporation on April 2, 1996.

A description of the Company’s operating and financial results by country, for the past three years can be found in Item 5. The description in Item 5, also includes the amount invested, of the Company’s capital expenditures and divestitures

B. Business Overview

TransGlobe is an independent oil and gas exploration company with production operations in Canada and the Republic of Yemen. During 2002, the Company participated in the drilling of three wells (one was drilling over year end) and seismic acquisition surveys on Block 32, and the drilling of three wells (one was drilling over year end) on Block S-1, in Yemen. In Canada, the Company drilled three wells resulting in one producing gas well, one producing oil well, and one non producing gas well.

A description of the Company’s operating and financial results by country, for the past three years can be found in Item 5. The description in Item 5 also includes the amount invested of the Company’s capital expenditures and divestitures.

Page 9 of 62

C. Organizational Structure

TransGlobe Energy Corporation is a Canadian public company with several wholly-owned subsidiaries as follows:

Name of Subsidiary	Country of Incorporation	Ownership
TransGlobe Oil & Gas Corporation	Washington State, United States	100%
TransGlobe Petroleum International Inc.	Turks & Caicos Islands, B.W.I.	100%
TransGlobe International (Holdings) Inc.	Turks & Caicos Islands, B.W.I. Dissolved December 5, 2002	100%
TG Holdings Yemen Inc.	Turks & Caicos Islands, B.W.I.	100%

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

D. Property, Plants and Equipment

TransGlobe’s major operations and principal activities are in the oil and gas exploration and production business. The Company has operated in three countries over the past three years: Canada, United States of America and the Republic of Yemen.

Republic of Yemen

Block S-1, Republic of Yemen

The Company, The Yemen Company (“YOC”) and the Yemen Ministry of Oil and Minerals (“MOM”) signed a Production Sharing Agreement (“PSA”) for the Damis S-1 Block (“Block S-1”) on December 21, 1997. The PSA was approved by the Yemen Cabinet on May 21, 1998, was ratified by the Yemen Parliament on June 14, 1998, and was signed by the President of Yemen on June 28, 1998.

On February 12, 1998 the Company signed a farm out agreement for Block S-1 with a wholly owned subsidiary of Vintage Petroleum Inc., a large US independent exploration and production company based in Tulsa, Oklahoma and listed on the New York Stock Exchange. The farm out agreement allowed Vintage to earn a 75 percent working interest in Block S-1 by funding the first period exploration work commitments under the PSA and spending a minimum of $20 million, which Vintage has done. The Company retains a 25% working interest in Block S-1. Both the Company’s and Vintage’s working interests are subject to the underlying royalties payable to the Republic of Yemen through the MOM explained below.

Page 10 of 62

Block S-1 Production Sharing Agreement

The Block S-1 PSA grants the Company the exclusive right to conduct petroleum operations in Block S-1, subject to certain conditions. Upon any commercial development of Block S-1, the Company and Vintage will pay 100% of the costs in respect of Block S-1. The Company, Vintage and The Yemen Company, an operating arm of the MOM (collectively, the “Block S-1 Contractors”) will share the production sharing oil, as defined in the Block S-1 PSA.

The exploration period of the Block S-1 PSA is segregated into two periods of 2½ years. Each 2½ year period may be extended for six months by submitting a request to the MOM. During the first exploration period of 2½ years, Vintage and TransGlobe were obliged to spend a minimum of $11 million to acquire existing data, reprocess the data as necessary and re-map the data acquired; process and interpret 150 square kilometers of new 3D seismic data; and drill and evaluate three exploration wells, which they did. During the optional second exploration period, Vintage and TransGlobe were also obliged to spend a minimum of $11 million on acquiring and interpreting a minimum of 100 square kilometers of new 3D seismic data and drill and evaluate three exploration wells, which has been done At the end of the first exploration period, Vintage and TransGlobe were required to relinquish to the MOM 25% of the Block S-1 area. At the end of the second exploration period, the Block S-1 Contractors must relinquish the remainder of Block S-1 except for the development areas.

Upon any commercial development of Block S-1, the Block S-1 Contractors (including The Yemen Company) will share revenues and expenses as follows: Details of the royalty payable to the MOM relating to Block S-1 (the “Block S-1 Royalty”) are as follows:

	Production Rate	Block S-1 Royalty

	0-12,500 bopd	3%⁽¹⁾
	12,500 - 25,000 bopd	4%⁽²⁾
	25,000 - 50,000 bopd	6%⁽²⁾
	50,000 - 100,000 bopd	8%⁽²⁾
	100,000 + bopd	10%⁽²⁾

Notes:
(1)	of the portion or increment of production up to and including 12,500 bopd
(2)	of that additional portion or increment of production between the amounts indicated in the left hand column

After payment of the Block S-1 Royalty, Vintage and TransGlobe are entitled to recover their costs against the lesser of :

(a)	50% of revenue per quarter; or
(b)	the aggregate of :
	(i)	100% operating expenses;
	(ii)	50% of cumulative exploration expenditures, amortized over two years; and
	(iii)	50% of cumulative development expenditures, amortized over two years.

If the costs recoverable in any quarterly period, including costs carried forward from previous quarters, exceed the value determined according to the above formula, the unrecovered excess is carried forward for recovery in the next succeeding quarter or quarters until fully recovered, but cannot be recovered after termination of the Block S-1 PSA. Page 11 of 62

The balance of revenues from oil production is shared by MOM and the Block S-1 Contractors as follows:

Production Level (bopd)	MOM	Block S-1 Contractors⁽¹⁾

0 - 12,500	65%	35%
12,500 - 25,000	70%	30%
25,000 - 50,000	72.5%	27.5%
50,000 - 75,000	75%	25%
75,000 - 100,000	77.5%	22.5%
100,000+	80%	20%

Note:

(1)

Pursuant to the Block S-1 PSA, The Yemen Company will receive 17.5% of the Block S-1 Contractors’ percentage (e.g. 35%) of the production sharing oil and Vintage and TransGlobe will receive 82.5% of the remaining production sharing oil from Block S-1. The Company and Vintage are responsible for 100% of the costs and expenditures incurred during the term of petroleum operations conducted under the Block S-1 PSA.

In addition to the Block S-1 Royalty, Vintage and TransGlobe are required to pay to the MOM a fixed percentage tax equivalent to 3% of all the actual exploration expenditures. The MOM assumes and pays Vintage’s and TransGlobe’s Yemeni income taxes out of the MOM’s share of revenues. Also, Vintage and TransGlobe are required to pay to the MOM the following bonuses:

	Amount of Bonus	Type of Bonus

	$2,000,000	signature bonus payable 1 month after signing Block S-1 PSA
		(paid)
	$150,000 per year	training bonus for training Yemeni employees of the MOM
	$150,000 per year	institutional bonus
	$150,000 per year	social development bonus
	$1,000,000	upon a declaration of commerciality
	$1,500,000	production rate exceeds 25,000 bopd
	$2,000,000	production rate exceeds 50,000 bopd
	$3,000,000	production rate exceeds 75,000 bopd
	$5,000,000	production rate exceeds 100,000 bopd

In 1995 previous management of the Company had signed a local agency agreement and fee agreement with De Marino Associates, Inc. and three other individuals (the “De Marino Group”), amended in December 1997. The terms of the agreement obligate the Company to pay the De Marino Group a cash signing bonus of $1 million upon the signing of the Block S-1 PSA (which TransGlobe paid, 75% of which was reimbursed by Vintage) and an additional fee of $1.5 million (of which Vintage will pay 75% assuming it earns into Block S-1 as expected) if the Company receives a report in a form acceptable to the Canadian stock exchanges from independent experts that Block S-1 contains proven recoverable reserves of at least 40 million barrels of oil. The fee is payable at the option of the Company in cash or Common Shares priced at the closing price of the Company’s Common Shares on the 10 trading days immediately preceding a public announcement by the Company that Block S-1 contains proven recoverable reserves of at least 40 million barrels of oil.

In 1995, as amended and restated in December 1997, the Company entered into an agency agreement (the “Local Agency Agreement”) with A1 Salam Establishment for Trading and General Agencies (the “Al Ahmar Group”), a corporation incorporated under the laws of the Yemen, under which the Al Ahmar Group agreed to perform agency services for the purpose of obtaining a PSA from the government of Yemen in respect of Block S-1.

The Local Agency Agreement requires the Company to assign to the Al Ahmar Group a 2% interest in the Company’s net share of the “production sharing oil” (the crude oil to be shared between the MOM, the Company and Vintage under the Block S-1 PSA). The Al Ahmar Group may elect to take delivery of its share of production sharing oil or allow the Company to market the Al Ahmar Group’s share of the production sharing oil and accept payment in US dollars.

Page 12 of 62

Block S-1 Joint Operating Agreement

On February 11, 1998 the Company’s subsidiary TG Holdings Yemen Inc. completed a farm out agreement for Block S-1 with Vintage Petroleum International Inc. (“Vintage”), a 100 percent subsidiary of Vintage Petroleum Inc., a large U.S. independent exploration and production company based in Tulsa, Oklahoma and listed on the New York Stock Exchange. The agreement allowed Vintage to earn a 75 percent working interest in Block S-1 by funding 100 percent of the first exploration period commitments and a minimum of $20,000,000 of the Block S-1 exploration work, which Vintage has done. After ratification of the PSA, Vintage and the Company completed the first period exploration work commitments consisting of 150 square kilometers of 3-D seismic and the drilling of three exploratory wells.

Further, on February 11, 1998, the Company entered into a joint operating agreement (“JOA”) with Vintage in respect of Block S-1. The JOA establishes Vintage as the operator of Block S-1. Vintage assumed operatorship of the joint operation in Block S-1 and accepted the liabilities and obligations in connection with the interests it had assumed. As operator, Vintage carries out all joint operations. Vintage may resign as operator with 120 days notice. All parties are entitled to withdraw from the JOA. Vintage acts as an independent contractor with regard to the terms and conditions of the Block S-1 PSA and the JOA.

The JOA provides that only joint operations and certain approved exclusive operations may be conducted in furtherance of the Block S-1 PSA. All proposed operations on Block S-1 must be open to both the Company and Vintage and only where one party declines to participate in a given operation may an exclusive operation be permitted in accordance with the required approval process.

If either the Company or Vintage fails to pay its portion of the joint operating expenses when such expenses become due, that party will be in default under the JOA. If the defaulting party does not pay the amount owing plus all interest accrued within 30 days of receiving a notice of default from the non-defaulting party, the non-defaulting party may require the defaulting party to transfer its entire interest under the JOA and Block S-1 PSA to the non-defaulting party. If the non-defaulting party does not elect to acquire the defaulting party’s interest, the non-defaulting party may continue to pay the expenses of the defaulting party in connection with the joint operations with debt accruing to the defaulting party. In the alternative, if the non-defaulting party does not elect to acquire the defaulting party’s interest nor does it wish to bear the defaulting party’s expenses, then joint operations between Vintage and the Company in connection with Block S-1 will be abandoned and each party will pay its share of costs associated with abandoning the joint operations.

Page 13 of 62

Block S-1 Exploration History

The Block S-1 is located near existing pipelines and adjacent to the Yemen Hunt Oil Co. Marib al Jawf production area. Block S-1, which initially covered an area of 4,484 square kilometers (1.12 million acres), was explored previously by Shell Oil between 1990 and 1993 and by a Soviet oil prospecting expedition between 1983 and 1990. A total of eight wells were drilled on Block S-1, some of which encountered oil shows.

During the 1999 fiscal year Vintage, as operator, reprocessed the 360 square kilometers (141 square miles) of existing 3-D seismic data and approximately 410 kilometers (255 miles) of existing 2-D seismic data made available by the MOM. A new 150 square kilometer (58 square mile) 3-D seismic survey was completed by Vintage in May 1999.

In 2000 the Block S-1 Joint Venture Group drilled four exploration wells resulting in one oil well (Harmel #1), two gas wells (An Naeem #1 and #2) and one dry hole (Fordus #1). The first well, An Naeem #1, encountered 30.5 meters (100 feet) of net pay in two Alif zones. The well flow tested at a combined rate of 40 MMcfpd of gas and 1,020 barrels per day of condensate from the lower portion of the Alif zones. No water was recovered during the test period. The second exploration well, Harmel #1, tested medium gravity sweet crude oil from three shallow horizons previously untested in the region. The third exploration well, Fordus #1, was completed in December 2000. Four separate zones were tested without recovering any significant hydrocarbons. The well was subsequently plugged and abandoned. The fourth exploration well, An Naeem #2, was drilled to evaluate the possible existence of an oil rim approximately 50 meters (165 feet) down dip of the An Naeem #1 well drilled earlier in 2000. The An Naeem #2 well encountered approximately 36 meters (120 feet) of net pay in the Alif formation. The Alif zone tested at combined flow rates of 27.7 MMcfpd of gas and 880 barrels per day of condensate.

In 2001 the Block S-1 Joint Venture Group acquired an additional 230 square kilometers (90 square miles) of 3-D seismic. The 3-D seismic program carried out during 2001 evaluated a trend of the Alif and Lam prospects identified on existing 2-D seismic. The trend extends from the adjacent Jannah Hunt, Dhahab and Al Nasr oil fields southeast to the Shell discovery at An Nagyah. In 2001, the Dhahab and Al Nasr fields were producing in excess of 40,000 Bopd. Approximately 400 square kilometers of additional 3-D seismic data on the adjacent blocks (including the Dhahab and Al Nasr fields) were acquired through data trades with Jannah Hunt Oil Company and with a subsidiary of Occidental Petroleum Corporation. The first exploration period ended on March 28, 2002 and the Block S-1 Joint Venture Group elected to proceed with a second exploration period of 2 1/2 years. The An Naeem #2 well drilled in 2000 pre-qualified as a second exploration period commitment well. The 2001 3-D seismic survey also qualified as a second exploration period commitment.

Block S-1 originally encompassed an area of 4,484 square kilometers (approximately 1.12 million acres). Upon entering the second exploration period a mandatory 25% relinquishment reduced the area to 3,363 square kilometers (approximately 861,000 acres). The relinquished lands were not considered prospective for oil by the Company.

The 3-D seismic acquired in 2001 was interpreted during the first half of 2002 and drilling locations were selected. In September 2002 the Block S-1 Joint Venture Group initiated the second drilling campaign on the block. Two wells were drilled and tested and one well was still drilling at the end of 2002. The first well, Osaylan #1, was drilled to a total depth of 1,902 meters and was abandoned after encountering minor oil shows. The primary target, the Alif reservoir sandstone, was encountered however the logs did not indicate hydrocarbons were present. The second exploration well, An Nagyah #2, was drilled to a total depth of 1,624 meters and discovered light 46 degree oil in the Upper Lam formation. The well was suspended as a potential future oil producer after testing up to 1,100 Bopd from the Upper Lam formation. The third exploration well, An Naeem #3, was drilled to a total depth of 1,623 meters to evaluate a potential oil rim on the An Naeem structure. The An Naeem #3 well tested gas and condensate from the Alif zone and did not encounter the anticipated oil rim. The fourth well of the program, An Nagyah #3, commenced drilling in February 2003 to appraise the light oil discovery made at An Nagyah #2. The well was drilled to a total depth of 1,292 meters and encountered the Upper Lam sandstones in a structurally higher position than the An Nagyah #2 well. Although the Upper Lam sandstones had a thicker gross reservoir section and better indicated porosity and permeability than found at An Nagyah #2, the Upper Lam was not flow tested as it was entirely above the gas/oil contact found in the An Nagyah #2 well. The An Nagyah #3 well did test 240 Bopd of light 42 degree oil from a new pool in the Lower Lam. The core and test data indicate the Lower Lam reservoir has less porosity and permeability than the Upper Lam reservoir and therefore may require stimulation to enhance production. The discovery of a new productive horizon in the Lower Lam should augment development economics. The fifth well in the program, An Nagyah #4, was drilled to a total depth of 1,547 meters and tested 1,320 barrels of light oil (45 degrees API) from the Upper Lam reservoir. The An Nagyah #4 well encountered a much thicker gross sand package and defined a 60 meter (197 feet) total oil column in the Nagyah pool. The successful appraisal well at

Page 14 of 62

An Nagyah #4 is anticipated to lead to development of the field. The diagram below indicates the relative positions of the An Nagyah wells and the northward dipping Upper and Lower Lam zones.

The An Nagyah structural closure is mapped by 3-D seismic data and the four wells drilled on the structure to date. An estimate of reserves can be calculated for the pool now that the gas/oil and the oil/water contacts are defined by the wells. TransGlobe management has mapped the Upper Lam oil pool over an area of 15 square kilometers (6 square miles). An independent reservoir engineering firm has been contracted to determine proven and probable reserves. TransGlobe has also contracted an engineering firm with experience in Yemen oil development projects to prepare a facility design and preliminary cost estimate for the development of the An Nagyah field. The reserves estimates and development cost estimates will determine if sufficient reserves have been discovered to declare commerciality and proceed with development.

Potential Development Scheme

Management of the Company is optimistic that the An Nagyah light oil discovery could provide the Company with its first oil production from Block S-1 as early as the second half of 2004. This is contingent upon the results of future appraisal drilling, particularly at An Nagyah #4.

The development plan envisions an integrated, phased project which includes the light oil discovered at An Nagyah, the natural gas/condensate discovery at An Naeem and the shallow medium gravity oil discovery at Harmel #1. The An Nagyah discovery could initially produce 6,000 to 10,000 Bopd (1,500 to 2,500 Bopd to TransGlobe) exported through the Hunt Oil Co. operated pipeline system to the tanker loading facility on the Red Sea. The nearest potential tie in point to the export pipeline system is approximately 28 kilometers (18 miles) from An Nagyah.

Natural gas and condensate from the An Naeem discovery would be pipelined to An Nagyah. Gas would be separated for injection into the Upper Lam formation to maintain reservoir pressure and increase oil recovery. Stabilized condensate from An Naeem would be sold with the An Nagyah light oil production and used to blend with the medium gravity oil discovered at Harmel. With An Nagyah as the anchor project, the Harmel #1 shallow oil well could be placed on early production. Initially the Harmel oil would be trucked to the An Nagyah facility for blending with An Naeem condensate and sold with the An Nagyah production.

Additional Harmel shallow oil wells could be drilled and placed on production until sufficient reservoir information is obtained to properly evaluate the merits of a full scale commercial development of the Harmel shallow oil discovery. The Harmel #1 well tested medium gravity crude from three shallow horizons at a depth of approximately 400 to 700 meters. The horizons were mapped on good quality 3-D seismic and display a structural closure of up to 25 square kilometers (10 square miles). Should full commercial development proceed, forty to eighty additional shallow wells could be required to exploit the large structure.

Page 15 of 62

Concurrent with the appraisal and evaluation of a potential light oil development scheme at An Nagyah, we are studying the feasibility of developing the large gas reserves found in the An Naeem #1, #2 and #3 wells. The gas could be utilized in Yemen for electricity generation or exported to nearby markets utilizing CNG (“Compressed Natural Gas”) technology. Both possibilities are under investigation. A gas development project of this magnitude will require significantly more time to evaluate, design and construct than conventional oil production. However it could be a significant addition to the Company’s longer-term asset portfolio.

The primary focus for 2003 will be the appraisal and testing of the An Nagyah light oil discovery which could lead to the declaration of a commercial oil project prior to year end. The Lam reservoir encountered at An Nagyah is a new producing horizon in Yemen. Its discovery opens up a new exploration focus for Block S-1. In addition to the An Nagyah appraisal work, the current drilling program results are being integrated into the Company’s extensive seismic database to define future exploration drilling prospects.

Block 32, Republic of Yemen

In January 1997, the Company entered into a farm-out agreement and joint venture concerning an exploration concession, Block 32, in the Republic of Yemen. The joint venture now consists of TG Holdings Yemen Inc. (a 100% subsidiary of the Company) as to 13.81087%; Ansan Wikfs Hadramaut Ltd. as to 45.18913%; and DNO ASA as to 41% (the “Block 32 Joint Venture Group”). The Company has since participated in the acquisition of seismic data and the drilling of fourteen wells in Block 32 resulting in seven oil producing wells in the Tasour field discovery and seven dry holes.

In 1998, the first oil discovery, Tasour #1 was drilled near the southern boundary of Block 32 in the producing Sayun Basin in the Republic of Yemen, adjacent to Nexen Inc.’s Masila Block Sunah field. The Tasour #1 well was suspended as a potential producer and subsequently completed as a producing oil well as part of the production development plan in 2000.

An appraisal program consisting of additional 2-D seismic data acquisition, reprocessing of older seismic data and the drilling of three appraisal wells was carried out during fiscal 1999. The three-well appraisal program was completed in October 1999 resulting in one additional oil well (Tasour #3), one well cased as a water injector (Tasour W #1) and one dry hole (Tasour #2). The Tasour #3 well has been completed as a producing oil well as part of the production development plan.

Block 32 Production Sharing Agreement

In August 1999 the MOM revised the terms of the Block 32 Production Sharing Agreement (“PSA”) to encourage development of the Tasour field. The new terms significantly improved the economics of the Tasour project. Details of the Block 32 original and revised PSA terms as announced in August 1999 are summarized in the table below:

Page 16 of 62

Licence Terms	Original Terms	Revised Terms August 1999

Royalty	10%	3%⁽¹⁾
Cost Recovery	25% (25% amortization)	60% (50% amortization)
Production Sharing
· 0 - 25,000 Bopd	23%	35%⁽²⁾
· 25,000 - 50,000 Bopd	21%	21%
Development/Production Period	20 + 5 years extension	20 + 5 years extension
Production Bonus
· Initial production	$2.0 million	$2.0 million (paid)
· Production at 50,000 bopd	$4.0 million	$4.0 million
· Production at 100,000 bopd	$6.0 million	$6.0 million

1)	For all levels exceeding 25,000 Bopd the Royalty remains at 10%
2)	If Proven Recoverable Reserves exceed 30 million barrels of oil or Monthly Average Daily Net Production exceeds 25,000 bopd, the original terms of the PSA prevail and continue to apply. The definition of Proven Recoverable Reserves is the same as that used in US Securities and Exchange Commission regulations. The Yemen Oil Company, a subsidiary of MOM, will receive 5% of the 35% Production Sharing oil and the Block 32 Joint Venture Group will receive 95% of the 35% Production Sharing oil.

As per the revised Block 32 PSA terms, after payment of the Block 32 Royalty, the Block 32 Joint Venture Group is entitled to recover their costs against the lesser of:

(a)	60% of revenue per quarter; or

(b)	the aggregate of:
	(i)	100% operating expenses;
	(ii)	50% of cumulative development expenditures, amortized over two years; and
	(iii)	50% of cumulative exploration expenditures, amortized over two years.

If the costs recoverable in any quarterly period, including costs carried forward from previous quarters, exceed the value determined according to the above formula, the unrecovered excess is carried forward for recovery in the next succeeding quarter or quarters until fully recovered, but cannot be recovered after termination of the Block 32 PSA. The balance of revenues from oil production is shared by the MOM and the Block 32 Joint Venture Group as follows:

Production level (bopd)	MOM	Block 32 Joint Venture Group

0 to 25,000	65%	35%
25,000 to 50,000	79%	21%
50,000 to 75,000	81%	19%
75,000 to 100,000	83%	17%
100,000 to 150,000	85%	15%
150,000 to 200,000	87%	13%
200,000+	90%	10%

In addition to the Block 32 Royalty, the Yemeni government will receive a production bonus of $2.0 million on commencement of initial production and bonuses of $4.0 million, $6.0 million, and $6.0 million should the production rate exceed 50,000, 100,000, and 200,000 bopd of oil, respectively. The Yemeni government also receives the proceeds of a 3% tax levied on exploration expenditures by the Block 32 Joint Venture Group. The Block 32 Joint Venture Group must pay to the MOM $200,000 annually for the purpose of training Yemeni employees of the MOM. The Block 32 Joint Venture Group must pay to the MOM $200,000 annually as an institutional bonus.

Page 17 of 62

The Block 32 Joint Venture Group must also pay a 2% gross overriding royalty to Highstown International Inc., a private Panama company, based on their share of oil revenues (less operating cost deductions), for local agent’s services rendered during the awarding of Block 32.

No additional Yemeni taxes are payable, since the MOM assumes and pays the Block 32 Joint Venture Group’s Yemeni income taxes out of MOM’s share of revenues pursuant to the Block 32 PSA.

If any of the Block 32 Joint Venture Group fails to pay its portion of the joint operating expenses when such expenses become due, that party will be in default under the Block 32 joint operating agreement. The operator is authorised at its election to deduct from the proceeds of sale of petroleum accruing to the defaulting party, up to any amount owed by such party, including accrued interest thereon. If the defaulting party does not pay the amount owing plus all interest accrued within 45 days of receiving a notice of default from the non-defaulting party(s), the non-defaulting party(s) may require the defaulting party to transfer its entire interest under the Block 32 joint operating agreement and Block 32 PSA to the non-defaulting party(s). If the non-defaulting party does not elect to acquire the defaulting party’s interest, the non-defaulting party(s) may continue to pay the expenses of the defaulting party in connection with the joint operations with debt accruing to the defaulting party. In the alternative, if the non-defaulting party(s) do not elect to acquire the defaulting party’s interest nor do they wish to bear the defaulting party’s expenses, then joint operations between the other Block 32 Joint Venture Group members and the defaulting party in connection with Block 32 will be abandoned and each party will pay its share of costs associated with abandoning the joint operations.

On November 15, 2000 the Company announced signing a letter agreement to purchase an additional 4% working interest in Block 32 for a total of $2.13 million. The transaction was effective January 1, 2000 and increased the Company’s interest to 13.81087 % on the entire block, including the producing Tasour field. The Company made an initial payment of $1.17 million. A potential future obligation totalling $960,000 will be due in six payments of $160,000 for each cumulative million barrels of gross oil production commencing at 7 million barrels to a maximum of 12 million barrels. The purchase also includes the proportionate historical cost pools attributable to the interest acquired. During 2002 the Company made the first payment of $160,000 and subsequent to December 31, 2002 a second and a third payment of $160,000 each were made. The Company expects that the remaining payments will be made during 2003.

Block 32 Development

The Block 32 development plan and development area of 570 square kilometers (approximately 228 square miles) was approved by the Ministry of Oil and Minerals (“MOM”) in the Republic of Yemen on February 5, 2000. The development area encompassed all of the Tasour structure and eleven additional prospects that were identified at the time. The remainder of the Block 32 exploration area was relinquished. The approved development/production period extends until the year 2020 with an optional five year extension to 2025.

In 2000, the Block 32 Joint Venture Group shot a small seismic program, drilled three wells (one of which was drilling over year end 2000) and constructed the Tasour central production facility (“CPF”) and a 60 kilometer pipeline to Nexen Inc.’s CPF and export facilities. Initial field production commenced on November 3, 2000 from three producing wells (Tasour #1, #3 and #4).

In 2001, the Block 32 Joint Venture Group shot a 120 kilometer 2-D seismic program in the third quarter of 2001 and drilled three wells, of which one was drilling over year end 2001. The first well, Tasour #5, drilled in the first quarter, was completed for production and brought on stream in February 2001 at an initial rate of 7,060 Bopd. The second well, Tasour #6, was drilled on the east portion of the Tasour structure. It was equipped and placed on production at an initial rate of 7,200 Bopd in December 2001. The third well, Asswairy #1, commenced drilling in late December 2001.

In 2002, the Block 32 Joint Venture Group drilled three wells in 2002, one of which was drilling over the year end. One well encountered oil and was placed on production (Tasour #7), one well was dry and abandoned and the third well (Tasour #8) was completed as an oil producer early in 2003.

The first well, Asswairy #1, was drilled in early 2002. Although several zones with oil shows were tested, no hydrocarbons were recovered so the well was abandoned. The second well, Tasour #7, was drilled in September to evaluate a potential field extension to the south of the mapped limits of the Tasour field (see figure below). The Tasour #7 well encountered the main producing zone (Qishn S-1A sandstone) in a structurally higher position than the previously mapped crest of the field. The well also encountered a new productive zone in an underlying sand, the

Page 18 of 62

Qishn S-1C. As can be seen from the cross section and revised maps, the size of the Tasour field was enlarged considerably and several new development drilling locations in the southern extension were identified. The first of the new development wells was successfully completed at Tasour #8 in January 2003 at an initial rate of 9,000 Bopd. A second development well targeting the southern field extension at Tasour #9 commenced production in April 2003 at an initial rate of 1,500 Bopd.

The extension of the Tasour field to the southern, bounding fault has increased the size of the field to over 20 million barrels. When commerciality was declared in 2000 the field proven plus probable reserves were estimated at only 6.9 million barrels. This represents a 300% increase in the estimated size of the Tasour field. The Tasour field had produced 7.5 million barrels by December 31, 2002. The remaining proven plus probable reserves are now estimated at 13.3 million barrels (1.836 million barrels to TransGlobe).

The Tasour #7, #8 and #9 wells have changed the structural mapping of the Tasour field. The revised structural picture of the field has set up a number of potential exploration prospects to the west and the east of the Tasour field along the main bounding fault. Additional seismic reprocessing and remapping work is underway to select new exploration drilling locations. It is anticipated the first of these locations will be drilled in Q-2, 2003 as a potential extension of the Tasour field to the west (probably named Tasour #10).

In addition to the new potential along the main Tasour south bounding fault trend, the Block 32 Joint Venture Group shot a 120 kilometer 2-D seismic program to further delineate prospects on the eastern portion of the block. The data was processed in Q-1 2003 and is being interpreted. It is expected that some of these prospects will be ready to drill in the future. The eastern prospects will not be drilled until at least 2004, depending upon the results in and around the Tasour field.

Page 19 of 62

Production

In Block 32, TransGlobe’s working interest production increased 37% from an average of 1,131 Bopd in 2001 to an average of 1,545 Bopd in 2002, with an exit rate of 1,996 Bopd for the month of December 2002. Production increases in 2002 are primarily attributed to the field extension and to the new pool discovery drilled at Tasour #7 in September 2002.

With the completion of Tasour #8 in January 2003 the production potential of the six wells exceeded the facility capacity. Tasour field production was restricted to 16,000 Bopd (2,210 Bopd to TransGlobe) during January and February 2003 due to limited export pump capacity. In March production averaged 17,870 Bopd (2,468 Bopd to TransGlobe) as shut in wells were returned to production and two wells were worked over to replace submersible pumps. The Tasour central production facility (“CPF”) was initially designed to process 15,000 Bopd with expansion capability to match the sales pipeline capacity of 25,000 Bopd. The facility was expanded in early 2002 to handle additional water and oil production. A second facility expansion to increase export pumping capacity to greater than 20,000 Bopd was completed in late February 2003. In addition to the CPF expansion, a water disposal/injection scheme was initiated in 2002, with the majority of the water being injected into Tasour #4. The produced oil and water is separated at the Tasour CPF and the sales oil is pumped to the Nexen Inc. CPF where it enters the Nexen Inc. export pipeline. The oil is pumped to the tanker loading facilities at Riyan on the Indian Ocean for export and sale.

The Block 32 PSA allows for the recovery of historical costs out of production. With the significantly increased oil production and higher oil prices in late 2002 and early 2003 it is expected that all of the historical costs will be recovered early in the second quarter of 2003. A diagram of the production sharing splits before and after full cost recovery is shown on the figure below. In general terms the Block 32 Joint Venture Groups’ (“Contractors”) share of oil will reduce from 71.1% to an estimated 40% to 50% of production, depending upon gross revenue, operating costs and future eligible capital expenditures. All qualifying new capital expenditures, such as new seismic or new wells within the Block 32 development area, can be recovered out of cost oil. Therefore the cost oil portion of production can increase or decrease depending on future expenditures.

The 2003 Block 32 Joint Venture budget and work program includes drilling two development/appraisal wells, two exploration wells and one contingency well. To date, two wells have been drilled resulting in a producing oil well at Tasour #8 and an exploratory dry hole at Haibish. The development/appraisal well at Tasour #9 commenced drilling in April 2003. It is expected that an exploratory well to the west of the Tasour field will be drilled in the June 2003 (Tasour #10). Another contingent well could be drilled in the fourth quarter of 2003.

Page 20 of 62

Canada

Background

TransGlobe acquired its Canadian operations in April 1999. The majority of the Canadian operations are operated by TransGlobe and are focused almost exclusively in the southern/central part of the province of Alberta. The Canadian operations have been successfully expanded to provide increased cash flow and asset value. Although Canadian production is now dwarfed by our international production, the Canadian operations will continue to be expanded to capitalize on the North American gas market. In addition to developing and exploiting our producing areas, the Company has acquired land and has generated a number of drillable prospects within its core focus areas.

Drilling activity in Canada was curtailed during 2002 due to allocation of resources to the projects in Yemen and due to depressed natural gas prices in North America during the first three quarters of 2002. The Company drilled three wells in 2002 resulting in two producers at Nevis and one shut-in gas well at Morningside.

At Cherhill, the Company completed and tied in a 100% working interest gas well drilled in late 2001. The well commenced production in February 2002 and is currently producing 55 to 60 Boepd.

At Morningside, the Company drilled and completed a marginal shallow gas well (58% working interest) which may be pipeline-connected in the future. Also at Morningside, the Company plans to install a three mile pipeline to connect a 100% working interest gas well which should initially produce 100+ Boepd. It is expected to be connected by the fall of 2003, pending the successful resolution of ongoing landowner negotiations which have delayed the project to date.

At Nevis, the Company drilled two wells in the latter half of 2002 which were placed on production in early 2003. Additional acreage was acquired in the area in late 2002 and early 2003. The Company plans to acquire additional acreage in the area and to drill a minimum of two wells with contingency for another six to eight wells, all focused on natural gas.

The Company sold minor non-core producing properties at Provost, Alberta and Wildmint, British Columbia in 2002.

Page 21 of 62

With record cash flow from Yemen in 2002 and early 2003, the Company expanded the Canadian budget to focus on natural gas projects. To date, the Company acquired mineral rights on 7,200 net acres in 2003 and farmed-in on an additional 4,480 (2,240 net) acres. The Company plans to acquire additional mineral rights and is negotiating several farm in proposals. The majority of the land is located in Central Alberta on three main prospects, of which two are new focus areas for the Company.

It is anticipated that the Company will drill a minimum of four to six wells, with contingency for an additional six to eight wells. All the prospects are focused towards natural gas. It is expected that drilling will commence in June. Successful wells could be on production by late 2003 as all the prospects are near to existing infrastructure and can be accessed year round.

United States

The focus of oil and gas exploration and development in North America was shifted from United States to Canada with the acquisition of Moiibus in 1999. During 2000 and 1999 TransGlobe divested of all its oil and gas properties in the United States with proceeds re-invested in Yemen.

Summary of Oil and Gas Sales, Net of Royalties, by Country

	Year Ended		Year Ended	Year Ended
	December 31, 2002		December 31, 2001	December 31, 2000

Canada	$ 1,015,394	$	$1,553,409	$1,151,400
United States	-		-	$ 302,827
Yemen	$12,238,711	$	$7,000,676	$ 949,039

Reserves

Outtrim Szabo Associates Ltd. of Calgary, Alberta, independent petroleum engineering consultants, evaluated the Company’s North American reserves at December 31, 2002, December 31, 2001, and December 31, 2000. In Canada, proven reserves after royalies declined 21% from year end 2001 to year end 2002. The decline is primarily due to production, well performance and the divestiture of minor properties during 2002.

The main differences between the reports in 2001 and 2000, aside from production, were the natural gas reserve additions as a result of successful exploration and exploitation efforts.

The United States properties were sold effective October 31, 2000.

Fekete Associates Inc. of Calgary, Alberta, independent petroleum engineering consultants, evaluated the Company’s Block 32 reserves in Yemen at December 31, 2002, December 31, 2001 and December 31, 2000. In 2002, TransGlobe’s proven reserves before royalties in the Tasour field (13.81087% working interest) in the Republic of Yemen are up 91% from year end 2001 to year end 2002. The increase in Yemen reserves is attributable to the excellent field performance, field extension and new pool discovery at Tasour #7 on Block 32. The main differences between the reports in 2001 and 2000, aside from production, were the increase in reserves attributed to overall field performance and successful development drilling in the Tasour Field. Although a light oil discovery at An Nagyah #2 on Block S-1 was announced December 10, 2002, a medium gravity oil pool was found at Harmel #1 and a gas-condensate pool at An Naeem #1, #2 and #3, proven reserves will not be assigned to Block S-1 until additional appraisal drilling and project evaluation are completed.

Page 22 of 62

	Reserves, Working Interest After Royalties
	December 31, 2002		December 31, 2001		December 31, 2000

	Oil &		Oil &		Oil &
	Liquids	Natural Gas	Liquids	Natural Gas	Liquids	Natural Gas
	(MBbls)	(MMcf)	(MBbls)	(MMcf)	(MBbls)	(MMcf)

Proven
Canada	136.7	2,780	104.5	3,934	120.8	2,808
United States	-	-	-	-	-	-
Yemen *	1,574.9	-	823.4	-	591.1	-
Total proven *	1,711.6	2,780	927.9	3,934	711.9	2,808

* Yemen reserves presented are for TransGlobe’s working interest share in the Block 32 Tasour field only before royalty. Net of royalty has not been calculated because it is a production sharing agreement.

Production

The Company’s net production after royalties for the last three fiscal years was as follows:

	Year Ended		Year Ended		Year Ended
	December 31, 2002		December 31, 2001		December 31, 2000

	Oil & NGL’S	Gas	Oil & NGL’S	Gas	Oil & NGL’S	Gas
	(Bbl)	(MMcf)	(Bbl)	(MMcf)	(Bbl)	(MMcf)

Yemen	485,979	-	316,236	-	35,451	-
Canada	11,718	280	16,393	326	21,839	147
United States	-	-	-	-	1,582	8

	497,697	280	332,629	326	58,872	155

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the audited consolidated financial statements of the Company (See Item 17) for the years ended December 31, 2002, 2001 and 2000, together with the notes related thereto. All dollar values are expressed in U.S. dollars, unless otherwise stated. All references to daily production are before royalty, unless stated otherwise.

The Company changed its year end in 1999 to December 31 from September 30. The change in year end was made to accommodate the ability to compare the Company’s results with those of its peers in the industry with the same reporting period.

The Company’s accounting principles are described in Note 1 to Notes to the Consolidated Financial Statements in Item 17. The Company prepares its Consolidated Financial Statements in conformity with GAAP in Canada, which conform in all material respects to United States GAAP except for those items disclosed in Note 14 to Notes to the Consolidated Financial Statements. For United States readers the Company has detailed the differences and has also provided a reconciliation of the differences between United States and Canadian GAAP in Note 14 to the Consolidated Financial Statements.

The preparation of the Company’s Consolidated Financial Statements requires it make estimates and judgements that affect its reported amounts of assets, liabilities, revenue and expenses. On an ongoing basis the Company evaluates its estimates, including those related to asset impairment, revenue recognition, allowance for doubtful accounts and contingencies and litigation. These estimates are based on information that is currently available to the Company and on various other assumptions that it believed to be reasonable under the circumstances. Actual results could vary from those estimates under different assumptions and conditions.

The Company has identified the following critical accounting policies that affect the more significant judgements and estimates used in preparation of its Consolidated Financial Statements.

Full Cost Accounting — The Company follows the full cost method of accounting for its oil and gas operations (as more fully described in Note 1 to the Consolidated Financial Statements), as compared to the other generally accepted method, successful efforts. Under the full cost method, costs associated with drilling successful and unsuccessful wells are capitalized on a country-by-country basis. As a consequence the Company may be more

Page 23 of 62

exposed to potential impairments if the book value of capitalized costs exceeds its future expected cash flows. This may occur if recoverable reserve estimates decrease, commodity prices decline or future estimates for capital, operating and income taxes increase, to levels that would significantly affect anticipated future cash flows.

Oil and Gas Reserves — The process of estimating quantities of proved reserves is inherently uncertain and the reserve estimates included in this document are only estimates. You should not assume that the present value of the Company’s future cash flows is the current market value of its estimated proved oil and gas reserves. In accordance with GAAP the Company bases the estimated future net cash flow from proved reserves on prices and costs on the date of estimate. Actual future prices and costs may be materially higher or lower than the prices and costs at the date of estimate.

Depletion — The Company’s rate of recording depletion is dependent upon its estimate of proved reserves. If the estimates of proved reserves decline, the rate at which it records its depletion expense increases, reducing net income. Such a decline in proved reserves may occur from lower product prices, which may make it non-economic to drill for and produce higher cost fields.

A. Results of Operations

Net income for 2002 was $5,426,389 ($0.11 per share basic and $0.10 per share diluted) compared to a net income of $3,062,237 ($0.06 per share, basic and diluted) in 2001 and $307,967 ($0.01 per share, basic and diluted) in 2000. Cash flow from operations for 2002 was $9,709,852 ($0.19 per share basic and diluted) compared to $5,840,455 ($0.12 per share basic and $0.11 per share diluted) in 2001 and $929,529 ($0.02 per share, basic and diluted) in 2000. The increase in net income and cash flow in 2002 is primarily a result of increased production (27%), increased commodity prices and from cost oil reallocation with partners in the Republic of Yemen. The increase in net income and cash flow in 2001 is primarily a result of a full year of Block 32 production in the Republic of Yemen, which commenced production November 3, 2000.



	2002		2001		2000

	$	$/Boe	$	$/Boe	$	$/Boe

Oil and gas sales	15,386,359	24.34	11,045,880	22.11	3,051,704	24.81
Royalties	2,132,254	3.37	2,491,795	4.99	648,438	5.27
Operating expenses	1,843,273	2.92	1,540,369	3.08	499,254	4.06

Net operating income*	11,410,832	18.05	7,013,716	14.04	1,904,012	15.48

*	Net operating income amounts do not reflect Yemen income tax expense which is paid through oil allocations with MOM in the Republic of Yemen (2002 - $986,862, $1.56/Boe; 2001 - $634,716, $1.27/Boe; 2000 $86,038, $0.70/Boe).

In 2002 and 2001 the Company operated in two geographic areas, segmented as the Republic of Yemen and Canada In 2000 the Company also operated in the United States. Management’s discussion and analysis will follow under each of these segments.

Republic of Yemen

	Year Ended		Year Ended		Year Ended
	December 31, 2002		December 31, 2001		December 31, 2000

	$	$/Boe	$	$/Boe	$	$/Boe

Oil sales	14,206,217	25.18	9,137,800	22.14	1,238,541	24.34
Royalties	1,967,506	3.49	2,137,124	5.18	289,502	5.69
Operating expenses	1,394,379	2.47	1,133,092	2.74	106,108	2.08

Net operating income*	10,844,332	19.22	5,867,584	14.22	842,931	16.57

*	Net operating income amounts do not reflect Yemen income tax expense which is paid through oil allocations with MOM in the Republic of Yemen ($2002 - $986,862, $1.75/Boe; 2001 $634,716, $1.54/Boe; 2000 -$86,038, $1.69/Boe).

TransGlobe commenced production on Block 32 on November 3, 2000. Production from the block is shared between the Block 32 Joint Venture Group and MOM pursuant to a PSA. The PSA provides for MOM to receive a 3% royalty of gross production (10% over 25,000 Bopd) with the remaining 97% of revenue split between cost recovery oil and production sharing oil. Cost recovery oil is up to a maximum of 60% of the revenue after deducting

Page 24 of 62

royalty. Cost recovery oil allows the Block 32 Joint Venture Group to recover operating costs and exploration and development expenditures as outlined in the PSA. The remaining oil is allocated to production sharing oil shared 65% by MOM and 33.25% by the Block 32 Joint Venture Group and 1.75% to YOC. The net result of the entire production sharing agreement is that 71.1% of the oil is allocated to the Block 32 Joint Venture Group during recovery of historical costs. The Block 32 Joint Venture Group’s Yemen income taxes are paid out of the MOM’s share of production sharing oil. These terms remain in place until gross proven recoverable reserves exceed 30 million barrels of oil or until gross production exceeds 25,000 Bopd.

With significantly increased production, higher oil prices and a 91% increase in proven reserves, management expects to have recovered all the historical costs early in the second quarter of 2003. Following the recovery of the historical exploration and development costs, any new expenditures are recovered out of cost oil from production. Operating expenses are recovered out of cost oil immediately and future eligible expenditures within the Block (such as new wells or facilities) can be recovered out of future production within two years of the expenditures. The Block 32 Joint Venture Group’s share of production following the recovery of historical costs will vary from year to year, depending upon gross revenues, operating costs and eligible capital expenditures within the PSA area. After recovery of historical costs management anticipates that the revenues from the Tasour field that could be allocated to cost recovery will exceed any new expenditures. This will result in a lower cost oil allocation and a larger production sharing oil allocation. The net result is expected to be a reduction of the Block 32 Joint Venture Group’s total share of oil from 71.1% to an estimated 40% to 50% of production, depending upon gross revenue, operating costs and eligible capital expenditures (see diagram on Page 20).

Oil production was 1,545 Bopd to TransGlobe in 2002 compared to 1,131 Bopd in 2001 and 139 Bopd in 2000 (862 Bopd for the two month period produced in 2000) with an average selling price of $25.18 per barrel (2001 - $22.14 per barrel, 2000 - $24.34 per barrel). Oil exported for sale (Masila blend) is marketed by Nexen Marketing International Ltd. and the price is based on an average dated Brent price less a quality/transportation differential between the dated Brent and the Masila blend. This differential averaged $0.47 per barrel in 2002, $1.49 per barrel in 2001 and $1.35 per barrel in 2000. TransGlobe expects 2003 gross production from the Tasour field to average 16,000 Bopd (2,210 Bopd to TransGlobe), not including production from future drilling success.

A decrease in royalty expense to $1,967,506 in 2002 compared to $2,137,124 in 2001 is a direct result of reallocations made between the Block 32 Joint Venture Group partners for historical cost pool recoveries during 2002. TransGlobe received a total reallocation of $1,349,077 in 2002 from the Block 32 Joint Venture Group. The majority of the 2002 historical cost pool reallocation represents the recovery of TransGlobe’s original farm-in costs on Block 32 in 1997. It is anticipated that the balance of the historical cost pools dating back to 1992 will be recovered in early 2003, which will result in a final historical cost pool reallocation between the Block 32 Joint Venture Group partners. When the remaining historical costs are recovered in 2003, TransGlobe will have a lower interest in the old historical cost pools (8.88302% versus 13.81087%) and therefore TransGlobe will have a cost sharing reallocation of approximately $1,245,000 to the other partners in the Block 32 Joint Venture Group. Thereafter all future expenditures paid out of cost oil will be allocated at TransGlobe’s working interest (13.81087%).

The royalty expense is comprised of the MOM’s 3% royalty, a portion of MOM’s share of production sharing oil representing a royalty, the YOC’s share of production sharing oil and a 2% royalty to the agent of the Block 32 Joint Venture Group (less operating cost deductions). Royalties averaged $3.49 per barrel for 2002 compared to $5.18 per barrel in 2001. Royalties before historical cost pool reallocation would have averaged $5.88 per barrel for 2002 with the increase over 2001 attributable to increased oil prices. The decrease in royalty expense per barrel in 2001 compared to 2000 is attributable to decreased oil prices.

Operating costs of $1,394,379 averaged $2.47 per barrel in 2002 compared to $2.74 per barrel in 2001. The decreased cost per barrel is attributed to the allocation of fixed operating costs over increased production volumes. The Transportation and Facilities Usage Contract with Nexen Inc. and the MOM allows for an increase in the export pipeline and loading terminal tariff following recovery of historical costs. Currently the tariff is approximately $0.70 per barrel and it is expected to increase to approximately $1.10 per barrel following historical cost recovery in the second quarter of 2003. The increased cost per barrel in 2001 as compared to 2000 is a function of overhead costs from the operator in Yemen being charged to operating costs, whereas in 2000 these costs were capitalized in the pre-production phase.

Page 25 of 62

Canada

	Year Ended		Year Ended		Year Ended
	December 31, 2002		December 31, 2001		December 31, 2000

	$	$/Boe	$	$/Boe	$	$/Boe

Oil sales	210,827	22.01	246,310	21.61	415,758	27.70
Gas sales (6:1)	901,138	16.60	1,487,615	22.07	759,894	24.16
NGL sales	68,177	16.84	174,155	21.51	207,865	22.73

	1,180,142	17.38	1,908,080	21.96	1,383,517	24.71
Royalties	164,748	2.43	354,671	4.08	232,117	4.15
Operating expense	448,894	6.61	407,277	4.69	289,988	5.18

Net operating income	566,500	8.34	1,146,132	13.19	861,412	15.38

A 19% decrease in gas volumes and a 25% decrease in average natural gas prices in 2002 resulted in a 39% decrease in gas sales. Gas production averaged 892 Mcfpd in 2002 compared to 1,108 Mcfpd for 2001 and 516 Mcfpd in 2000. The decrease in production in 2002 is primarily attributed to natural production declines, divestiture of minor properties and to shut-in production during the year in response to low gas prices in the summer while the increase in production in 2001 is due to a full year’s production from drilling and exploitation in 2000. The average natural gas price for 2002 was $2.77 per Mcf compared to $3.68 per Mcf for 2001 and $4.03 per Mcf for 2000. To ensure continuous gas production during the traditionally weaker summer market, the Company has entered into a fixed price natural gas sales contract for 500 GJ/day (approximately 500 Mcfpd, or less than 50% of current production) at a price of Cdn$7.65/GJ for the period March 1, 2003 to November 1, 2003.

Oil production averaged 26 Bopd in the year 2002 compared to 31 Bopd in 2001 and 41 Bopd in 2000. The decrease in 2002 is a result of natural production declines and divestiture of minor properties. The average oil price in 2002 was $22.01 per barrel compared to $21.61 per barrel in 2001 and $27.70 per barrel in 2000.

Natural gas liquids production averaged 11 barrels per day in 2002 compared to 22 barrels per day in 2001 and 26 barrels per day in 2000. Natural gas liquid prices averaged $16.84 per barrel in 2002, $21.51 per barrel in 2001 and $22.73 per barrel in 2000.

Royalty expenses averaged $2.43 per Boe in 2002 compared to $4.08 per Boe in 2001 and $4.15 per Boe in 2000. In 2002 this reduction is a reflection of lower prices and gas cost allowance adjustments.

The Company’s operating costs of $448,894 during 2002 averaging $6.61 per Boe compared to $4.69 per Boe in 2001 and $5.18 per Boe in 2000. In 2002 this increase is the result of increased water handling and allocating fixed operating costs over lower production volumes.

United States

	Year Ended		Year Ended		Year Ended
	December 31, 2002		December 31, 2001		December 31, 2000

	$	$/Boe	$	$/Boe	$	$/Boe

Oil sales	-	-	-	-	400,024	28.36
Gas sales (6:1)	-	-	-	-	29,137	14.70
NGL sales	-	-	-	-	485	19.28

	-	-	-	-	429,646	26.67
Royalties	-	-	-	-	126,819	7.87
Operating expense	-	-	-	-	103,158	6.40

Net operating income	-	-	-	-	199,669	12.40

The Company sold all its assets in the United States effective October 31, 2000. The proceeds were reinvested in the Tasour development.

Oil production averaged 39 Bopd in 2000, with an average oil price of $28.36 per barrel. Gas production averaged 32 Mcfpd in 2000, with an average natural gas price of $2.45 per Mcf.

Page 26 of 62

General And Administrative Expenses

General and administrative expenses (“G&A”) increased 44% in 2002 to $820,691 from $570,609 in 2001, mainly due to an increase in salary and consulting costs, office rent, insurance and professional services. Management expects G&A to stabilize at this level for 2003.

	Year Ended								Year Ended
	December 31, 2002				December 31, 2001				December 31, 2000

					$		$/Boe		$		$/Boe

Gross G&A	1,213,094		1.92		985,902		1.97		1,437,673		11.69
Capitalized G&A	(392,403	)	(0.66	)	(415,293	)	(0.83	)	(298,074	)	(2.42	)

Net G&A	820,691		1.30		570,609		1.14		1,139,599		9.27

Depletion And Depreciation Expense

Depletion and depreciation expense was $4,277,000 in 2002 compared to $2,762,000 in 2001 and $635,400 in 2000. The increase in 2002 is attributable to the inclusion of additional costs in the depletable base in the Republic of Yemen. In Yemen unproven properties in the amount of $7,184,372 were excluded from costs subject to depletion and depreciation in 2002 (2001 - $9,080,536; 2000 - $10,113,633). In 2002, this represents a portion of the costs incurred in Block S-1. These costs will be included in the depletable base as Block S-1 is developed or as impairment is determined.

	Year Ended		Year Ended		Year Ended
	December 31, 2002		December 31, 2001		December 31, 2000

	$	$/Boe	$	$/Boe	$	$/Boe

Republic of Yemen	3,960,000	7.02	2,405,000	5.83	242,000	4.76
Canada	317,000	4.67	357,000	4.11	311,000	5.55
United States	-	-	-	-	82,400	5.12

	4,277,000	6.77	2,762,000	5.53	635,400	5.17

Income Taxes

Current income tax expense represents income taxes paid in the Republic of Yemen which increased to $986,862 during 2002 from $634,716 in 2001 and $86,038 in 2000 as a result of increased production and revenues in Yemen. Future income tax recovery of $67,168 in 2002 is a result of offsetting unrecorded future tax benefits in Canada against the future tax effect of tax renunciations to flow through shareholders.

At year end 2002, the Company has non-capital losses and tax pools for carry forward against future taxable income in Canada in the amount of Cdn$18,674,000 and tax losses in the United States of $13,100,000.

The Company will not record the future tax benefit of these tax losses and pools in the consolidated financial statements until additional producing reserves are added in Canada.

Capital Expenditures/Dispositions

Capital Expenditures

	Year Ended	Year Ended	Year Ended
	December 31, 2002	December 31, 2001	December 31, 2000

Republic of Yemen	$5,435,398	$3,406,363	$4,855,141
Canada	1,041,146	1,375,888	1,118,266
United States	-	-	17,909

	$6,476,544	$4,782,251	$5,991,316

Capital expenditures in the year 2002 in the Republic of Yemen were split mainly between Block 32 and Block S-1. On Block 32 expenditures of $2,022,323 were incurred on a three well drilling program comprised of Asswairy #1, Tasour #7 and Tasour #8, facility expansion, water disposal well, additional working interest payment described below and various well workovers. Capital expenditures of $1,472,611 in 2001 on Block 32 were incurred on a three well drilling program comprised of Tasour #5, Tasour #6 and a portion of Asswairy #1, plus a 120 kilometer 2-D

Page 27 of 62

seismic program. Capital expenditures of $3,063,495 in 2000 on Block 32 were incurred for construction of a central processing facility and pipeline, a three well drilling program and acquisition of an additional 4% working interest.

Effective January 1, 2000, the Company entered into an agreement to purchase an additional 4% working interest in Block 32 for a total purchase price of $2,136,163, increasing the Company’s working interest to 13.81087%. The Company made an initial payment of $1,176,163. A potential future obligation totalling $960,000 will be due in six payments of $160,000 for each cumulative million barrels of gross oil production commencing at 7 million barrels to a maximum of 12 million barrels. The purchase also includes the proportionate historical cost pools attributable to the interest acquired. During 2002 the Company made the first payment of $160,000 and subsequent to December 31, 2002 a second and a third payment of $160,000 each were made. The Company expects that the remaining payments will be made during 2003.

On Block S-1 the Company incurred $3,404,599 primarily on drilling three wells comprised of Osaylan #1, An Nagyah #2 and An Naeem #3, contractual government payments, pre-drilling inventory and geological/geophysical/geochemical studies. Capital expenditures on Block S-1 in 2001 were $1,890,684 primarily on field acquisition of a 230 square kilometer 3-D seismic program, Harmel #1 production test and various contractual government payments. Capital expenditures on Block S-1 in 2000 were $1,251,646 to participate in drilling An Naeem #2 and expenditures relating to testing on Harmel #1.

Canadian capital expenditures of $1,041,146 in 2002 relate to several mineral lease acquisitions, drilling two wells at Nevis and one well at Morningside and tie in costs at Cherhill, Morinville and Morningside areas. Canadian capital expenditures in 2001 related to several mineral lease acquisitions, drilling of five wells and three recompletions. Capital expenditures in 2000 in Canada relate to mineral lease acquisitions, seismic and drilling of five wells.

Dispositions

In 2002, proceeds on disposal of oil and gas properties represents dispositions in Canada of minor properties at Wildmint and Provost.

During the year 2000 the Company sold all its oil and gas properties in the United States for net proceeds of $606,059, resulting in a gain on sale of $254,132. Proceeds from the sale were utilized to partially fund the acquisition of an additional 4% working interest in Block 32, Yemen.

Finding And Development Costs

	Three Year
	Average	2002	2001	2000

Total capitalized costs		$6,476,544	$4,782,251	$5,973,407
Proved reserve additions
and revisions (MBoe) *		1,209.7	946.2	754.3
Proved plus probable reserve
additions and revisions (MBoe) *		1,390.2	700.5	1,075.3
Average cost per Boe - proved	$5.92	$5.35	$5.05	$7.92
- proved plus
probable	$5.44	$4.66	$6.83	$5.55

* Proven working interest reserves before royalties.

Page 28 of 62

Recycle Ratio

		Three Year
		Average		2002		2001		2000

Netback ($/Boe)	$	13.14	$	15.36	$	11.69	$	7.56
Proved finding and development costs	$	5.92	$	5.35	$	5.05	$	7.92
($/Boe)
Recycle ratio		2.22		2.87		2.31		0.95

The recycle ratio measures the efficiency of TransGlobe’s capital program by comparing the cost of finding and developing proved reserves before royalties with the netback from production before royalties. The ratio is calculated by dividing the netback by the proved finding and development cost on a Boe basis. Netback is defined as net sales revenues less operating, general and administrative, foreign exchange (gain) loss, interest and current income tax expense per Boe of production.

Liquidity And Capital Resources

Funding for the Company’s capital expenditures in 2002 was provided by cash flow from operations and working capital.

At December 31, 2002 the Company had working capital of $4,748,933, nil debt and a revolving credit facility of Cdn$2,500,000 and an acquisition/development credit facility of Cdn$2,000,000.

The Company expects to fund its 2003 exploration and development program (budgeted at $10 million firm and contingent) through the use of working capital, cash flow and debt as required. Should cash flow be negatively impacted by reduction in production volumes or commodity prices, the Company has significant flexibility to adjust its Canadian capital budget of $2.7 million.

In December 2002, the Company announced the approval of a Normal Course Issuer Bid to acquire up to 4,855,435 common shares over a 12 month period expiring December 8, 2003. In 2003 the Company acquired 100,000 common shares at a price of Cdn$0.60/share. The acquired shares have been returned to treasury and cancelled.

Commitments And Contingencies

As part of its normal business, the Company entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity. The principal commitments of the Company are as follows:

		2003			2004		2005		2006		2007

Office and equipment leases	$	112,000		$	114,000	$	114,000	$	114,000	$	40,000
Expected contingent payments
on Block 32 additional interest
acquisition in 2000		800,000	⁽¹⁾		-		-		-		-

	$	912,000		$	114,000	$	114,000	$	114,000	$	40,000

⁽¹⁾In 2003, $320,000 has been paid to date.

The Block S-1 second exploration period letter of credit issued in 2002 in the amount of $1,500,000 was fully released in 2003.

New Accounting Pronouncements

In December 2001, the Canadian Institute of Chartered Accountants (CICA) issued Accounting Guideline 13, “Hedging Relationships” (AcG-13). AcG-13 establishes certain conditions for when hedge accounting may applied. The guideline is effective for fiscal years beginning on or after July 1, 2003. Adoption of AcG-13 is not expected to have a material impact on our financial position or results of operations.

In September 2002, the CICA approved Section 3063, “Impairment of Long-Lived Assets” (S.3063). S.3063 establishes standards for the recognition, measurement and disclosure of the impairment of long-lived assets, and applies to long-lived assets held for use. An impairment loss is recognized when the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. The new Section is effective for fiscal years beginning on or after

Page 29 of 62

April 1, 2003. Adoption of this Section is not expected to have a material impact on our financial position or results of operations.

In December 2002, the CICA approved Section 3110, “Asset Retirement Obligations” (S.3110). S.3110 requires liability recognition for retirement obligations associated with our property, plant and equipment. These obligations are initially measured at fair value, which is the discounted future value of the liability. This fair value is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until we expect to settle the retirement obligation. S. 3110 is effective for fiscal years beginning on or after January 1, 2004. The total impact of our financial statements has not yet been determined.

The following standards and revisions issued by the CICA do not impact us:

•	Amendments to S.3025 - “Impaired Loans”, effective for asset foreclosures on or after May 1, 2003
•	Section 3475 - “Disposal of Long-Lived Assets and Discontinued Operations”, effective for disposal activities initiated by commitments to plans on or after May 1, 2003.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. Directors and Senior Management

The names, age, positions, terms of office of the officers and directors of the Company during the year 2002 are as follows:

NAME, AGE	POSITION	TERM
Robert A. Halpin, 67	Board Member	03/21/97 to present
	Chairman of the Board	01/06/99 to present
Geoffrey C. Chase, 61	Board Member	08/15/00 to present
Ross G. Clarkson, 49	President and Chief Executive Officer	12/06/96 to present
	Board Member	10/11/95 to present
Lloyd W. Herrick, 50	Vice President and Chief Operating Officer	04/28/99 to present
	Board Member	04/28/99 to present
Erwin L. Noyes, 65	Vice-President, International Operations	11/08/96 to 07/31/00
	Corporate Secretary	12/04/96 to 28/09/99
	Board Member	10/11/95 to present
David C. Ferguson, 50	V.P. Finance, Chief Financial Officer and	06/01/01 to present
	Corporate Secretary

There are no family relationships among the directors and officers of the Company.

Robert A. Halpin, Director, Chairman of the Board

Mr. Halpin brings to the Company over 45 years’ experience in the petroleum industry world-wide as a self-employed consultant (1993 to present); as Vice-President of International Exploration & Production with Petro-Canada Resources of Calgary, Alberta (1988 to October, 1993) and in similar positions with Trend International Ltd., of Denver, Colorado; Saga Petroleum A.S. of Oslo, Norway; Amerada Hess Corporation and American Independent Oil Company, both of New York; Chevron Canada Ltd. in Saskatchewan and Manitoba and Mobil Oil Corporation in New York, Libya and Alberta. Mr. Halpin was a director of Fountain Oil Inc., a public company listed on the Nasdaq Stock Market Inc., from March 1995 to June 1999 and was Chairman of its Board from November 1995 to February 1997; and was a director of Pacific Tiger Energy Inc., a public company listed on the Montreal Exchange, from June 1997 to March 2001 and Chairman of its Board from March 1998 to March 2001; and was a director of Syner-Seis Technologies Inc., a public company listed on the Canadian Venture Exchange, from May 1997 to June 1999.

Ross G. Clarkson, P. Geol., Director, President & Chief Executive Officer

Mr. Clarkson was initially retained by the Company as a technical advisor to assist its Yemen concession prospect (now Block S-1) and assist in negotiations with the Ministry of Oil and Mineral Resources, Republic of Yemen. He was appointed as President and Chief Executive Officer of the Company on December 4, 1996 and has served as a director of the Company since October 1995. Mr. Clarkson was formerly employed (1988 to 1996) as a senior geological advisor with Petro-Canada, a major Canadian oil company, and has in excess of 25 years domestic and international oil and gas exploration experience, including Resident Manager of Petro-Canada (Yemen) Inc. (1990 to 1993); Senior Project Geologist with Canadian Occidental Petroleum Ltd., now Nexen Inc., in Yemen in 1987

Page 30 of 62

and supervisor of international exploration/geologist with Ranger Oil Limited (1979 to 1986). His international familiarity extends to Oman and the United Arab Emirates, Indonesia, Thailand, China, Australia, the North Sea, South America and Africa.

Lloyd W. Herrick, P. Eng., Director, Vice President, Chief Operating Officer

Prior to joining TransGlobe in April 1999 Mr. Herrick was President, Chief Executive Officer and member of the Board of Moiibus Resource Corporation (“Moiibus”) (1997 to 1999), a public company which TransGlobe acquired in April 1999. He is a professional engineer with more than 25 years of oil and gas experience, primarily in North America. Prior to Moiibus, Mr. Herrick had been with Ranger Oil Limited since 1982, serving in a variety of technical and management/executive positions including Vice President - Canadian Production from 1993 onward. Prior thereto, he was a petroleum engineer with Rupertsland Resources Ltd. (1981 to 1982) and a production, evaluations engineer with Hudson’s Bay Oil & Gas Ltd. (1975 to 1981).

Geoffrey C. Chase, P. Eng., Director

Mr. Chase joined the Board in August 2000. He brings over 35 years of oil and gas operations experience to the Company. Prior to taking early retirement, Mr. Chase worked for Ranger Oil Limited for 28 years in numerous positions, overseeing both domestic and international operations. In his most recent position with Ranger Oil Limited, he was Senior Vice President, Business Development, responsible for identifying, assessing and negotiating international petroleum development opportunities. In addition to his duties at Ranger, Mr. Chase also served on the board of Direct Energy Marketing Ltd., a private gas marketing company, and was Chairman of its Board from 1990 to 1994.

Erwin L. Noyes, Director

Mr. Noyes was initially engaged by the Company as a consultant to assess its Yemen concessions and to assist with related negotiations. He was appointed acting President on November 8, 1996, pending Mr. Clarkson’s appointment as President, and Vice-President, Operations of the Company (on a part-time basis) from November 8, 1996 to April 26, 1999 and has served as a director since October, 1995. Mr. Noyes’ title was changed to Vice President, International Operations on April 26, 1999 and he retired from the Company on July 31, 2000. Mr. Noyes brings to the Company over of 30 years of oil and gas exploration and production experience in both domestic and international operations; including as General Manager in the Republic of Yemen for Canadian Occidental Petroleum Ltd., now Nexen Inc., (1987 to 1991), during which time he managed that company’s oil exploration program, as a self-employed consultant (1991 to 1996), and with several Canadian Occidental affiliates, as Production Manager in Calgary (1982 to 1986) and as Gas Operations Manager for Canada Cities Service, responsible for all gas production/processing, pipeline and facilities construction (1978 to 1982).

David C. Ferguson, C.A., Vice President Finance, Chief Financial Officer, Corporation Secretary

Mr. Ferguson joined TransGlobe in June 2001. He is a professional Chartered Accountant with more than 24 years of financial management/reporting experience. From 1999 to 2000 he was Chief Financial Officer with NorthStar Drilling Systems Inc., with Myriad Energy Corporation 1998 to 1999 as Chief Financial Officer and director, Archean Energy Ltd. as Vice President of Finance from 1994 to 1997 and Eagle Resources Ltd. from 1982 to 1994 as Vice President of Finance and Controller. Prior to entering the oil and gas industry, Mr. Ferguson was with David Dahl & Partners, Chartered Accountants, 1980 to 1982 and Touche Ross & Co., Chartered Accountants, 1975-1980.

Page 31 of 62

B. Compensation

The following table outlines the compensation paid or payable, stock options and Common Shares held for directors and management of TransGlobe for the fiscal year ended December 31, 2002.

Common Shares
Owned

Compensation

Securities Under Option ⁽¹⁾

Name and
Position with
Company

Salary
(Cdn$)

Other
(Cdn$)

Number
of Options

Exercise
Price

Expiry
Date

Number

%
Owned⁽²⁾

ROBERT A. HALPIN

Nil

$8,800⁽³⁾

140,000

$0.22

Jun 18/03

367,585

⁽²⁾

Chairman, Director

15,000

$0.22

Jan 08/04

120,000

Cdn.$0.50

Apr 16/07

ROSS G. CLARKSON

152,500

$153,500⁽⁴⁾

307,500

$0.22

Jun 18/03

1,701,072

3.3%

President, Chief

154,500

Cdn.$0.73

Aug 11/05

Executive Officer,

250,000

Cdn.$0.50

Apr 16/07

Director

LLOYD W. HERRICK

152,500

$36,000⁽⁴⁾

270,000

$0.22

Apr 28/04

285,000

⁽²⁾

Vice President, Chief

135,000

Cdn.$0.73

Aug 11/05

Operating Officer,

250,000

Cdn.$0.50

Apr 16/07

Director

ERWIN L. NOYES

Nil

$8,000⁽³⁾

257,500

$0.22

Jun 18/03

130,747

⁽²⁾

Director

150,000

Cdn.$0.73

Aug 11/05

120,000

Cdn.$0.50

Apr16/07

GEOFFREY C. CHASE

Nil

$8,000⁽³⁾

140,000

Cdn.$0.73

Aug 11/05

153,000

⁽²⁾

Director

120,000

Cdn.$0.50

Apr 16/07

DAVID C. FERGUSON

119,974

$28,320⁽⁴⁾

200,000

Cdn.$0.55

Jun 01/06

110,000

⁽²⁾

Vice Pres. Finance,

200,000

Cdn.$0.50

Apr 16/07

Chief Financial

Officer, Corporate

Secretary

⁽¹⁾	There are no outstanding restricted shares or units and the Company does not have a long-term incentive plan, pension plan or other compensatory plan for its executive officers.
⁽²⁾	Represents less than one percent of outstanding Common Shares of the Company.
⁽³⁾	Other compensation includes outside director fees.
⁽⁴⁾	Other compensation includes performance bonuses.

C. Board Practices

Directors serve for a term of one year, but are eligible for re-election annually by the shareholders. Pursuant to section 111 of the Company Act (British Columbia), advance notice of the Company’s 2002 Annual General Meeting to be held May 29, 2003 was published in the Province newspaper on April 2, 2003 inviting written nominations for directors. No such nominations have been received by the Company.

The directors have fixed the number of directors to be elected at five. The persons named in the following table are management of the Company’s nominees to the Board of Directors. All of Messrs. Halpin, Clarkson, Herrick, Noyes and Chase are ordinarily resident in Canada.

Mr. Ross Clarkson was appointed President and Chief Executive Officer of the Company on December 4, 1996, which appointment will continue until December 31, 2007. Pursuant to Mr. Clarkson's employment contract effective December 1, 2002 with the Company, in return for a full-time commitment to the Company, he received a monthly salary of Cdn.$15,000 (approx. U.S. $9,550). Mr. Clarkson is entitled to a performance bonus in such amount as may be determined by the Compensation Committee. Mr. Clarkson was also entitled to a performance bonus under his previous contract payable in fully paid Common Shares of the Company, upon the Company's cash flow reaching specified amounts as follows:

Page 32 of 62

Cash Flow*	Bonus

U.S.$500,000	50,000 Common Shares
U.S.$2,000,000	An additional 100,000 Common Shares
U.S.$5,000,000	An additional 150,000 Common Shares

*Cash Flow is defined as that amount determined in the Company's annual audited financial statements as "cash flow generated from operations" within Canadian generally accepted accounting principles.

Pursuant to the employment contract, the Company issued to Mr. Clarkson 250,000 Common Shares during Fiscal 2002.

Mr. Lloyd Herrick was appointed Vice President and Chief Operating Officer of the Company on April 28, 1999, which appointment will continue until December 31, 2007 unless extended or sooner terminated as provided in his employment contract. Pursuant to Mr. Herrick's employment contract effective December 1, 2002 with the Company, in return for a full-time commitment to the Company, he received a monthly salary of Cdn.$15,000 (approx. U.S. $9,550). Mr. Herrick is entitled to a performance bonus in such amount as may be determined by the Compensation Committee.

Mr. David Ferguson was appointed Vice-President, Finance, Chief Financial Officer and Secretary of the Company on June 1, 2001, which appointment will continue until December 31, 2007 unless extended or sooner terminated as provided in his employment contract. Pursuant to Mr. Ferguson's employment contract effective December 1, 2002 with the Company, in return for a full-time commitment to the Company, he received a monthly salary of Cdn.$11,800 (approx. U.S. $7,500). Mr. Ferguson is entitled to a performance bonus in such amount as may be determined by the Compensation Committee.

Each of the employment contracts may be terminated by the executive officer on 30 days written notice. In addition, if any person together with his or its associates acquires beneficial ownership (as defined in the contract) of 20% or more of the outstanding Common Shares of the Corporation, other than a current insider of the Corporation. Messrs. Clarkson, Herrick and Ferguson may, within six months after that event, elect to terminate the contract and his employment, and the Company will pay to him a retirement allowance in an amount equal to 24 months, of his then current salary and benefits. If the executive officer should die during the term of the contract, the Company is required to pay his estate an amount equal to six months of his then current salary. The employment contracts also provide for the customary medical, dental and life insurance benefits and vacation entitlement.

The Company’s audit committee consists of Geoffrey Chase (Chair), Robert Halpin, and Erwin Noyes, all independent Directors. The audit committee’s mandate is to review and monitor management in carrying out its responsibilities to design and implement an effective system of internal controls, to review and approve quarterly financial reports and related press releases, to review the annual financial statements, and meet with the outside auditors independent of management, as defined in the “Charter of Audit Committee”.

The compensation committee is comprised of Robert Halpin (Chair), Geoffrey Chase and Erwin Noyes, all independent Directors. The compensation committee conducts an annual review of the senior officers and considers appropriate development programs, reviews employment and remuneration for senior officers, reviews remuneration for directors, and allocation of stock options, as defined in the “Charter of Compensation Committee”.

The governance and nominating committee is comprised of Erwin Noyes (Chair), Robert Halpin and Geoffrey Chase, all independent Directors. The governance and nominating committee’s mandate is to identify possible new individuals qualified to become Board of Director members, provide a list of Board nominees for each annual meting, ensure that each of the Audit, Compensation and Governance and Nominating committees adhere to their respective charter and review on an annual basis the corporate governance policies and procedures of the Company, as defined in the “Charter of Governance and Nominating Committee”.

D. Employees

At December 2002, TransGlobe had seven full time employees located in the Calgary head office, working on the properties in both Yemen and Canada.

Page 33 of 62

E. Share Ownership

Share ownership and stock options granted and outstanding to the officers and directors of the Company are outlined in the table in Item 6.B.

Incentive Stock Options and SARs

Subject to shareholder approval at the May 29, 2003 shareholders meeting, the Board of Directors of the Company approved a new Stock option plan dated April 15, 2003. The new share option plan (the "2003 Plan") which will supersede and replace the existing stock option plan of the Company (the "Old Plan"). The Old Plan, as amended, was originally approved by the shareholders in April of 1997, with the latest amendments to the plan ratified by shareholders on March 22, 2001. As of April 15, 2003, the Company had outstanding options (both within and outside the Company's existing option plan) to purchase 3,142,000 Common Shares. If the 2003 Plan is approved as proposed, the outstanding options will remain in effect and be exercisable in accordance with their terms and all such options will be deemed to be issued under the terms of the 2003 Plan. Approval of the 2003 Plan will also constitute ratification of all outstanding share options including any granted, if any, in excess of the maximum number of Common Shares issuable under the Old Plan. The new Stock Option Plan dated April 15, 2003 is filed as Exhibit 10.8.

The 2003 Plan contains terms and conditions substantially the same as those of the Old Plan, except that (i) the Company will be increasing the maximum number of Common Shares that may be issued upon the exercise of options granted pursuant to the 2003 Plan in order to meet its business objective of awarding share options to directors, officers, employees and consultants in a total amount up to a maximum of 10% of its total outstanding Common Shares; and (ii) the 2003 Plan will provide the Company with the flexibility to effect the "cashless" exercise of stock options, by providing to optionees the difference (either in cash or Common Shares) between the exercise price of the options and the current trading price of the Common Shares.

The Company intends to seek shareholder approval each year to increase the maximum number of Common Shares issuable pursuant to the exercise of options granted to ensure that up to approximately 10% of the Company's total outstanding Common Shares may be issuable pursuant to the 2003 Plan.

The board of directors has approved an amendment to the 2003 Plan to increase the number of Common Shares reserved for issuance pursuant to the 2003 Plan by 2,051,000 Common Shares, which reflects the Common Shares issued by the Company since the initial approval of the Old Plan, as well as deficits under the Old Plan. Options to purchase a total of 3,142,000 Common Shares are outstanding under the Old Plan at April 15, 2003. After the increase of 2,051,000 Common Shares, the maximum number of Common Shares which will be available for issuance under the 2003 Plan will be equal to 10% of the issued and outstanding Common Shares, with 3,142,000 outstanding options, and an additional 2,045,730 Common Shares available for additional option grants.

Consistent with the Old Plan and the rules of The Toronto Stock Exchange, the following restrictions apply in connection with the issuance of Common Shares under the 2003 Plan:

(a)	the maximum number of Common Shares that may be issued to insiders pursuant to the 2003 Plan and any other Common Share compensation arrangement is 10% of the number of Common Shares outstanding;

(b)	the maximum number of Common Shares that may be issued to insiders under the 2003 Plan and any other Common Share compensation arrangement within a one (1) year period is 10% of the number of Common Shares outstanding; and

(c)	the maximum number of Common Shares that may be issued to any one insider under the 2003 Plan and any other Common Share compensation arrangement within a one (1) year period is 5% of the number of Common Shares outstanding.

ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. Major Shareholders

To the knowledge of the Company, there are no share holders who own beneficially, directly or indirectly, more than 5% of the Common Shares of the Company. In 2001, the only person who owned beneficially, directly or indirectly, more than 5% of the Common Shares of the Company was Mr. Tom Kusumoto. Mr. Kusumoto was a major shareholder of Moiibus and acquired TransGlobe Common Shares when the Company purchased Moiibus in

Page 34 of 62

April, 1999. At the time of the Moiibus acquisition, Mr. Kusumoto owned beneficially, directly or indirectly, or exercised control or direction over 11.0% of the Company’s Common Shares. Mr. Kusumoto participated in a private placement in August, 1999 increasing his ownership to 13.4%. In August, 2000 Mr. Kusumoto exercised warrants to purchase Common Shares and had 10.5% of the Company’s outstanding Common Shares at that time. In October, 2000, DHN Services Ltd., a company that holds TransGlobe Common Shares and which Mr. Kusumoto exercises control of, reorganized resulting in Mr. Kusumoto owning directly or indirectly 7.4% of the Company’s Common Shares. Mr Kusumoto has advised the Company that during 2002 and 2003 he has sold a portion of his shareholdings, such that he currently has less than 5 % of the Common Shares of the Company.

To the knowledge of the Company, 21,327,957 Common Shares are held by registered shareholders in the United States representing 41.11 percent of total Common Shares currently outstanding.

To the knowledge of the Directors and Officers of the Company, there have been no transfers of Common Shares which have materially affected control of the Company since the last Annual and Extraordinary General Meeting of Members of the Company held on May 30, 2002.

B. Related Party Transactions

Other than transactions carried out in the normal course of business of the Company, no other director or senior officer of the Company or of its subsidiaries, nor any of their associates or affiliates has since the commencement of the Company’s last completed financial year had any material interest, direct or indirect, in any other transactions which materially affected the Company or in any proposed transaction which has or would materially affect the Company.

ITEM 8. FINANCIAL INFORMATION

A. Consolidated Statements and Other Financial Information

The consolidated financial statements for the year ended December 31, 2002 have been audited by an independent auditor, are accompanied by an audit report, and are attached and incorporated herein.

On May 14, 2003, the Company released its 2003 first quarter results for the three month period ended March 31, 2003. These quarterly results were filed with the Commission on Form 6-K and are incorporated by reference herein.

The Company is not a party to any material legal proceedings and none are known to be contemplated, threatened or pending, nor are there currently any arbitration proceedings.

The Company has never paid dividends to shareholders nor is there a policy in place to do so.

B. Significant Changes

There have been no significant changes to the Company since December 31, 2002.

Page 35 of 62

ITEM 9. THE OFFER AND LISTING

A. Offer and Listing Details

The following table sets forth the reported high and low sale prices as reported by the principal trading markets in Canada and the United States for Fiscal 1998 to 2000, for each of the quarters in Fiscal 2001 and 2002 and for each of the six months ending April 30, 2003. The Company’s Common Shares were listed in Canada on the Vancouver Stock Exchange (the “VSE”) from August 15, 1969 to February 3, 1997, on the Alberta Stock Exchange and its successor the Canadian Venture Exchange from July 7, 1997 until January 31, 2000, and on The Toronto Stock Exchange since November 10, 1997. The Company’s Common Shares were listed in the United States on the NASDAQ Small Cap Market from March 1984 until August 31, 1998 and trade on the OTC BB since September 1, 1998.

	ASE or TSX		Nasdaq or OTC BB
	Price Range (Cdn$)		Price Range (US$)
	High	Low	High	Low
Fiscal year ended September 30, 1998	2.20	0.18	1.50	0.06
Fiscal year ended December 31, 1999	0.78	0.16	0.52	0.09
Fiscal year ended December 31, 2000	1.63	0.40	1.03	0.31
Quarter ended March 2001	0.72	0.40	0.47	0.25
Quarter ended June 2001	0.70	0.40	0.48	0.25
Quarter ended September 2001	0.56	0.27	0.35	0.19
Quarter ended December 2001	0.67	0.25	0.43	0.17
Quarter ended March 2002	0.82	0.40	0.52	0.24
Quarter ended June 2002	0.60	0.48	0.40	0.28
Quarter ended September 2002	0.60	0.40	0.39	0.24
October 2002	0.58	0.47	0.38	0.30
November 2002	0.55	0.40	0.36	0.27
December 2002	0.75	0.40	0.50	0.26
January 2003	0.83	0.56	0.50	0.38
February 2003	0.69	0.55	0.47	0.38
March 2003	0.72	0.60	0.50	0.40
April 2003	0.71	0.65	0.50	0.43

B. Plan of Distribution

Not applicable.

C. Markets

The authorized capital of the Company consists of 500,000,000 Common Shares without par value, of which 51,494,801 Common Shares are issued and outstanding as of December 31, 2002.

The principal trading markets for the Common Shares are the TSX, on which they have been listed since October 1997, and the OTC Bulletin Board in the U.S., on which they have been quoted since September 1998. Prior to September 1998 the Common Shares were listed on the NASDAQ Small Cap Market. The Common Shares were also listed on the Canadian Venture Exchange (“CDNX”). On January 31, 2000 the Common Shares were delisted from the CDNX pursuant to the restructuring of the Canadian stock exchanges. After January 31, 2000, TransGlobe Common Shares were only listed on the TSX in Canada and on the OTC Bulletin Board in the U.S. The Common Shares trade under the symbol TGL in Canada and TGLEF in the U.S. Warrants issued pursuant to a Canadian public offering dated July 4, 2000 traded on the TSE under the symbol TGL.WT until their expiry on January 28, 2002.

ITEM 10. ADDITIONAL INFORMATION

A. Share Capital

Not applicable.

Page 36 of 62

B. Memorandum and Articles of Association

The Articles of Association have been previously filed with Form 20-F dated March 24, 2000.

C. Material Contracts

Other than contracts entered into in the ordinary course of business, the Company has not entered into any contracts in the two years prior to the date hereof which can reasonably be regarded as presently material to the Company.

D. Exchange Controls

There is no law or governmental decree or regulation in Canada that restricts the export or import of capital, or affects the remittance of dividends, interest or other payments to a non-resident holder of Common Shares of the Company, other than withholding tax requirements. See “Item 10.E – “Taxation”.

There is no limitation imposed by Canadian law or by the charter or other constituent documents of the Company on the right of a non-resident to hold or vote Common Shares of the Company, other than as provided in the Investment Canada Act (Canada) (the “Investment Act”). The following discussion summarizes the principal features of the Investment Act for a non-resident who proposes to acquire Common Shares of the Company. It is general only, it is not a substitute for independent advice from an investor’s own advisor, and it does not anticipate statutory or regulatory amendments.

The Investment Act generally prohibits implementation of a reviewable investment by an individual, government or agency thereof, corporation, partnership, trust or joint venture (each an “entity”) that is not a “Canadian” as defined in the Investment Act (a “non-Canadian”), unless after review the minister responsible for the Investment Act is satisfied that the investment is likely to be of net benefit to Canada. An investment in Common Shares of the Company by a non-Canadian other than a “WTO Investor” (as defined in the Investment Act and which term includes entities which are nationals of or are controlled by nationals of member states of the World Trade Organization) when the Company was not controlled by a WTO Investor, would be reviewable under the Investment Act if it was an investment to acquire control of the Company and the value of the assets of the Company, as determined in accordance with the regulations promulgated under the Investment Act, was Cdn$5 million or more, or if an order for review was made by the federal cabinet on the grounds that the investment related to Canada’s cultural heritage or national identity, regardless of the value of the assets of the Company. An investment in Common Shares of the Company by a WTO Investor, or by a non-Canadian when the Company was controlled by a WTO Investor, would be reviewable under the Investment Act if it was an investment in 2002 to acquire control of the Company and the value of the assets of the Company, as determined in accordance with the regulations promulgated under the Investment Act, exceeds Cdn$218 million. A non-Canadian would acquire control of the Company for the purposes of the Investment Act through acquisition of Common Shares if the non-Canadian acquired a majority of the Common Shares of the Company. The acquisition of less than a majority but one third or more of the Common Shares of the Company would be presumed to be an acquisition of control of the Company unless it could be established that, on the acquisition, the Company was not controlled in fact by the acquirer through the ownership of Common Shares.

Certain transactions relating to Common Shares of the Company would be exempt from the Investment Act, including

(a)	acquisition of Common Shares of the Company by a person in the ordinary course of that person’s business as a trader or dealer in securities,

(b)	acquisition of control of the Company in connection with the realization of security granted for a loan or other financial assistance and not for a purpose related to the provisions on the Investment Act, and

(c)	acquisition of control of the Company by reason of an amalgamation, merger, consolidation or corporate reorganization following which the ultimate direct or indirect control in fact of the Company, through the ownership of Common Shares, remained unchanged.

E. Taxation

The discussion under this heading summarizes the principal Canadian federal income tax consequences of acquiring, holding and disposing of Common Shares of the Company for a shareholder of the Company who is not resident in Canada and who is resident in the United States. It is based on the current provisions of the Income Tax Act (Canada) (the “Tax Act”) and the regulations thereunder. The provisions of the Tax Act are subject to income tax

Page 37 of 62

treaties to which Canada is a party, including the Canada-United States Income Tax Convention (1980) (the “Convention”). This discussion is general only and is not a substitute for independent advice from a shareholder’s own tax advisor. Management of the Company considers that the following discussion fairly describes the principal and material Canadian federal income tax consequences applicable to shareholders of the Company who are residents of the United States and are not residents of Canada and do not hold, and are deemed not to hold, shares of the Company in connection with carrying on a business in Canada (a “non-resident”).

Generally, dividends paid by Canadian corporations to non-resident shareholders are subject to a Canadian withholding tax of 25% of the gross amount of such dividends. However, Article X of the Convention reduces to 15% the withholding tax on the gross amount of dividends paid to residents of the United States. The withholding tax rate on the gross amount of dividends is reduced to 5% of the amount of the gross dividend when a U.S. corporation owns at least 10% of the voting stock of the Canadian corporation paying the dividends.

A non-resident who holds shares of the Company as capital property will not be subject to tax on capital gains realized on the disposition of such shares unless such shares are “taxable Canadian Property” within the meaning of the Tax Act and no relief is afforded under any applicable tax treaty.

The shares of the Company would be taxable Canadian property of a non-resident if at any time during the five year period immediately preceding a disposition by the non-resident of such shares not less than 25% of the issued shares of any class of the Company belonged (a) to the non-resident, (b) to a person with whom the non-resident dealt did not deal at arm’s length, or (c) to the non-resident and any person with whom the non-resident did not deal at arm’s length.

Certain United States Federal Income Tax Consequences

The following is a general discussion of the material United States Federal income tax laws for U.S. holders that hold such Common Shares as a capital asset, as defined under United States Federal income tax law and is limited to discussion of U.S. Holders that own less than 10% of the common stock. This discussion does not address all potentially relevant U.S. Federal income tax matters and it does not address consequences peculiar to persons subject to special provisions of U.S. Federal income tax law, such as those described below as excluded from the definition of a U.S. Holder. In addition, this discussion does not cover any state, local or foreign tax consequences.

The following discussion is based upon the sections of the Internal Revenue Code of 1986, as amended (United States) to the date hereof (the “Code”), Treasury Regulations, published Internal Revenue Service (“IRS”) rulings, published administrative positions of the IRS and court decisions that are currently applicable, any or all of which could be materially and adversely changed, possibly on a retroactive basis, at any time. In addition, this discussion does not consider the potential effects, both adverse and beneficial, of any future legislation which, if enacted, could be applied, possibly on a retroactive basis, at any time. The following discussion is for general information only and it is not intended to be, nor should it be construed to be, legal or tax advice to any holder or prospective holder of Common Shares of the Company and no opinion or representation with respect to the United States Federal income tax consequences to any such holder or prospective holder is made. Accordingly, U.S. holders and prospective U.S. holders of Common Shares of the Company should consult their own tax advisors about the U.S. Federal, state, local, and foreign, tax consequences of purchasing, owning and disposing of Common Shares of the Company.

U.S. Holders

As used herein, a “U.S. Holder” is a holder of Common Shares of the Company who or which is a citizen or individual resident (or is treated as a citizen or individual resident) of the United States for U.S. federal income tax purposes, a corporation or partnership created or organized (or treated as created or organized for U.S. federal income tax purposes) in the United States, including only the States and District of Columbia, or under the law of the United States or any State or Territory or any political subdivision thereof, or a trust or estate the income of which is includable in its gross income for U.S. federal income tax purposes without regard to its source, if, (i) a court within the United States is able to exercise primary supervision over the administration of the trust and (ii) one or more United States trustees have the authority to control all substantial decisions of the trust. For purposes of this discussion, a U.S. Holder does not include persons subject to special provisions of U.S. Federal income tax law, such as tax-exempt organizations, qualified retirement plans, financial institutions, insurance companies, real estate investment trusts, regulated investment companies, broker-dealers and Holders who acquired their stock through the exercise of employee stock options or otherwise as compensation.

Page 38 of 62

Distributions on Common Shares of the Company

U.S. Holders receiving dividend distributions (including constructive dividends) with respect to Common Shares of the Company are required to include in gross income for United States Federal income tax purposes the gross amount of such distributions to the extent that the Company has current or accumulated earnings and profits, without reduction for any Canadian income tax withheld from such distributions. Such Canadian tax withheld may be credited, subject to certain limitations, against the U.S. Holder’s United States Federal income tax liability or, alternatively, may be deducted in computing the U.S. Holder’s United States Federal taxable income by those who itemize deductions. (See more detailed discussion at “Foreign Tax Credit” below). To the extent that distributions exceed current or accumulated earnings and profits of the Company, they will be treated first as a return of capital up to the U.S. Holder’s adjusted basis in the Common Shares and thereafter as gain from the sale or exchange of the Common Shares. Preferential tax rates for long-term capital gains are applicable to a U.S. Holder which is an individual, estate or trust. There are currently no preferential tax rates for long-term capital gains for a U.S. Holder which is a corporation.

Dividends paid on the Common Shares of the Company will not generally be eligible for the dividends received deduction provided to corporations receiving dividends from certain United States corporations. A U.S. Holder which is a corporation may, under certain circumstances, be entitled to a 70% deduction of the United States source portion of dividends received from the Company if such U.S. Holder owns shares representing at least 10% of the voting power and value of the Company. The availability of this deduction is subject to several complex limitations which are beyond the scope of this discussion.

Foreign Tax Credit

A U.S. Holder who pays (or has withheld from distributions) Canadian income tax with respect to the ownership of Common Shares of the Company may be entitled, at the option of the U.S. Holder, to either a deduction or a tax credit for such foreign tax paid or withheld. Generally, it will be more advantageous to claim a credit because a credit reduces United States Federal income taxes on a dollar-for-dollar basis, while a deduction merely reduces the taxpayer’s income subject to tax. This election is made on a year-by-year basis and applies to all foreign taxes paid by (or withheld from) the U.S. Holder during that year. There are significant and complex limitations which apply to the credit, among which is the general limitation that the credit cannot exceed the proportionate shares of the U.S. Holder’s United States income tax liability that the U.S. Holder’s foreign source income bears to his or its worldwide taxable income. In the determination of the application of this limitation, the various items of income and deduction must be classified into foreign and domestic sources. Complex rules govern this classification process. There are further limitations on the foreign tax credit for certain types of income such as “passive income,” “high withholding tax interest,” “financial services income,” “shipping income” and certain other classifications of income. The availability of the foreign tax credit and the application of the limitations on the credit are fact specific and holders and prospective holders of Common Shares of the Company should consult their own tax advisors regarding their individual circumstances.

Disposition of Common Shares of the Company

A U.S. Holder will recognize gain or loss upon the sale of Common Shares of the Company equal to the difference, if any, between the amount of cash plus the fair market value of any property received, and the Holder’s tax basis in the Common Shares of the Company. This gain or loss will be capital gain or loss if the Common Shares are a capital asset in the hands of the U.S. Holder. Any capital gain will be a short-term or long-term capital gain or loss depending upon the holding period of the U.S. Holder. Gains and losses are netted and combined according to special rules in arriving at the overall capital gain or loss for a particular tax year. Deductions for net capital losses are subject to significant limitations. For U.S. Holders which are individuals, any unused portion of such net capital loss may be carried over to be used in later tax years until such net capital loss is thereby exhausted. For U.S. Holders which are corporations (other than corporations subject to Subchapter S of the Code), an unused net capital loss may be carried back three years from the loss year and carried forward five years from the loss year to be offset against capital gains until such net capital loss is thereby exhausted.

F. Dividends and Paying Agents

Not applicable.

G. Statement by Experts

Not applicable.

Page 39 of 62

H. Documents on Display

Documents concerning the Company which are referred to in this document may be inspected at the offices of TransGlobe Energy Corporation, #2900, 330 – 5^th Avenue S.W., Calgary, Alberta, Canada T2P 0L4.

I. Subsidiary Information

A list of subsidiaries of the Company is identified in Item 3 above and in Exhibit 21 and in Note 1 of the notes to the consolidated financial statements in Item 17.

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

The Company has adopted a new shareholder protection rights plan agreement dated effective April 16, 2003 (the "Rights Plan") between the Company and Computershare Trust Company of Canada (the "Rights Agent"). Capitalized terms not otherwise defined in this section shall have the same meaning ascribed to such terms in the full text of the Rights Plan. The Rights Plan has been adopted by the Board of Directors of the Company and will become effective, when ratified by shareholders, on May 29, 2003.

The Rights Plan was adopted by the Company to encourage the fair treatment of shareholders if there is an unsolicited Take-over Bid for the Voting Shares of the Company. The Rights Plan was also adopted by the Company to (i) provide all shareholders of the Company with an equal opportunity to share in any premium paid upon an acquisition of control; (ii) allow both the shareholders and the Board of Directors adequate time to assess a Take-over Bid made for the Voting Shares of the Company in relation to the circumstances and prospects of the Company; and (iii) allow a reasonable period of time for the Board of Directors to explore and develop alternative courses of action in an attempt to maximize shareholder value, if the Board of Directors is of the opinion that it is appropriate to do so. The adoption of this plan does not affect the duty of the Board of Directors to act in good faith with a view to the best interests of the Company and its shareholders.

The Board of Directors is not aware of any specific Take-over Bid for the Voting Shares that has been made or is contemplated.

The Board of Directors believes that under the existing statutory rules relating to Take-over Bids there is insufficient time for the directors to fully assess an offer and to explore and develop alternatives for shareholders in the event of a Take-over Bid. The time required to consider and complete a change of control transaction must be considered from both the perspective of the Company and of potential purchasers. Under the statutory Take-over Bid rules, a take-over bid must remain open in most jurisdictions in Canada for a minimum of 35 days. The result is that shareholders may fail, in the absence of the Rights Plan, to fully assess the circumstances of the Company or to realize the maximum value for their Voting Shares. Accordingly, the directors believe that the Rights Plan which provides that any bid remain open for a minimum of 60 days is an appropriate mechanism to ensure that they will be able to discharge their responsibilities to assist shareholders in responding to a Take-over Bid.

If a potential acquirer does not meet the requirements of a Permitted Bid, then the Rights become operative, with each Right entitling a shareholder, in certain circumstances, the ability to acquire one (1) share at an exercise price

Page 40 of 62

of $0.00001 per share, subject to adjustment in certain events. Through the operation of the Rights, the Board of Directors may negotiate with the acquirer to ensure the fairness of the terms of a Take-over Bid.

ITEM 15. CONTROLS AND PROCEDURES

As required by Section 302(a) of the Sarbanes-Oxley Act of 2002, our Chief Executive Officer and Chief Financial Officer will be making certifications related to the information in our annual report on Form 20-F. As part of such certification, the Chief Executive Officer and Chief Financial Officer must certify that they are responsible for establishing and maintaining disclosure controls and procedures to ensure that material information with respect to us is made known to them and that they have evaluated the effectiveness of our disclosure controls and procedures as of a date within 90 days prior to filing our annual report. Disclosure controls and procedures are intended to ensure that information required to be disclosed by us in our annual report is recorded, processed, summarized and reported within the time periods required. We have adopted or formalized such controls and procedures as we believe are necessary and consistent with our business and internal management and supervisory practices.

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-14(c) and 15d-14(c)) as of a date within 90 days prior to the filing date of this report, have concluded that, as of such date, our disclosure controls and procedures were adequate and effective to ensure that material information relating to us would be made known to them by others within the Company.

Changes in Internal Controls

There were no significant changes in our internal controls or in other factors that could significantly affect our internal controls subsequent to the date of their evaluation, nor do we believe that there are any significant deficiencies or material weaknesses in our internal controls. As a result, no corrective actions were required or undertaken.

ITEM 16. RESERVED

PART III

ITEM 17. FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

	Page
Auditors’ Report	46
Consolidated Statements of Income and Deficit	47
Consolidated Balance Sheets	48
Consolidated Statements of Cash Flows	49
Notes to the Consolidated Financial Statements	50

The financial statements and Report of the independent Auditors are filed as part of the Company’s Annual Report.

ITEM 18. FINANCIAL STATEMENTS

See financial statements in Item 17.

Page 41 of 62

ITEM 19. EXHIBITS

EXHIBITS AND REPORTS ON FORM 6-K

a) Exhibits

Exhibits marked with an asterisk have been previously filed with the Securities and Exchange Commission by the Company, and are incorporated by reference, as indicated.

INDEX TO EXHIBITS

		Page
Exhibit 1*	Certificate of Incorporation as amended and Memorandum and Articles of Incorporation.	-
Exhibit 4.1	Employment Agreement of Lloyd W. Herrick dated December 1, 2002.	63
Exhibit 4.2	Employment Agreement of David C. Ferguson dated December 1, 2002.	68
Exhibit 4.3	Employment Agreement of Ross Clarkson dated December 1, 2002	73
Exhibit 4.4	Stock Option Plan dated April 15, 2003	78
Exhibit 4.5	Shareholders’ Protection and Rights Plan April 16, 2003	86
Exhibit 8	List of subsidiaries of the Registrant.	122
Exhibit 99.1	Certification Pursuant to 18 U.S.C. 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	123

Page 42 of 62

SIGNATURE

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, as amended, the Registrant, TRANSGLOBE ENERGY CORPORATION, certifies that it meets the requirements for filing on Form 20-F and has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

TRANSGLOBE ENERGY CORPORATION
Registrant

By:          /s/ Ross Clarkson

Name:    Ross Clarkson

Title:       President and CEO

Date: May 13, 2003

A. CERTIFICATIONS

I, Ross G. Clarkson, certify that:

1. I have reviewed this annual report on Form 20-F of TransGlobe Energy Corporation;

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

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

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a.	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b.	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c.	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a.	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b.	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Page 43 of 62

6. The registrant's other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 16, 2003	/s/ Ross Clarkson
	President & CEO

B. CERTIFICATIONS

I, David C. Ferguson, certify that:

1. I have reviewed this annual report on Form 20-F of TransGlobe Energy Corporation;

a.	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b.	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c.	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

a.	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b.	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

Page 44 of 62

Date: May 16, 2003	/s/ David C. Ferguson
	Vice President, Finance & CFO

Page 45 of 62

Auditors’ Report

To the Shareholders of TransGlobe Energy Corporation:

We have audited the consolidated balance sheets of TransGlobe Energy Corporation as at December 31, 2002 and 2001 and the consolidated statements of income and deficit and cash flows for each of the years in the three year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with Canadian and United States generally accepted auditing standards. These standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2002 in accordance with Canadian generally accepted accounting principles. As required by the Company Act (British Columbia), we report that, in our opinion, these principles have been applied, except for the accounting policy change as described in Note 1 to the consolidated financial statements, on a consistent basis.

Calgary, Alberta	(Signed) “Deloitte & Touche LLP”
February 28, 2003	Chartered Accountants

COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA- U.S. REPORTING DIFFERENCES

In the United States of America, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) outlining changes in accounting policies that have been implemented in the financial statements. As discussed in Note 1 to the consolidated financial statements, in 2002 the Company has adopted the new Canadian Institute of Chartered Accountants Handbook recommendations for stock compensation.

Calgary, Alberta	(Signed) “Deloitte & Touche LLP”
February 28, 2003	Chartered Accountants

Page 46 of 62

TRANSGLOBE ENERGY CORPORATION
Consolidated Statements of Income and Deficit

		Year Ended			Year Ended			Year Ended
		Dec. 31,			Dec. 31,			Dec. 31,
		2002			2001			2000



REVENUE
Oil and gas sales, net of royalties	$	13,254,105		$	8,554,085		$	2,403,266
Other income		42,108			16,470			278,514

		13,296,213			8,570,555			2,681,780


EXPENSES
Operating		1,843,273			1,540,369			499,254
General and administrative		820,691			570,609			1,087,963
Foreign exchange (gain) loss		(6,988	)		(3,800	)		51,636
Interest		16,154			4,424			13,522
Depletion and depreciation		4,277,000			2,762,000			635,400

		6,950,130			4,873,602			2,287,775


Net income before income taxes		6,346,083			3,696,953			394,005
Income taxes (Note 6)
- future		(67,168	)		-			-
- current		986,862			634,716			86,038

		919,694			634,716			86,038

NET INCOME		5,426,389			3,062,237			307,967

Deficit, beginning of year		(17,724,698	)		(20,786,935	)		(21,429,922	)


Change in accounting policy
- future income taxes		-			-			335,020

Deficit, end of year	$	(12,298,309	)	$	(17,724,698	)	$	(20,786,935	)


Net income per share (Note 8)
Basic	$	0.11		$	0.06		$	0.01
Diluted	$	0.10		$	0.06		$	0.01

Page 47 of 62

TRANSGLOBE ENERGY CORPORATION
Consolidated Balance Sheets

		December 31, 2002			December 31, 2001


ASSETS
Current
Cash	$	2,595,170		$	1,174,846
Accounts receivable		2,984,000			975,773
Prepaid expenses		88,837			60,687

		5,668,007			2,211,306

Capital assets
Canada (Note 2)		3,651,305			3,044,746
Republic of Yemen (Note 3)		15,066,835			13,591,437

		18,718,140			16,636,183


	$	24,386,147		$	18,847,489


LIABILITIES
Current
Accounts payable and accrued liabilities	$	919,074		$	828,959

Provision for site restoration & abandonment		122,209			106,209


		1,041,283			935,168


SHAREHOLDERS’ EQUITY
Share capital (Note 5)		35,643,173			35,637,019
Deficit		(12,298,309	)		(17,724,698	)

		23,344,864			17,912,321


	$	24,386,147		$	18,847,489

APPROVED BY THE BOARD

“Ross Clarkson”	“Lloyd Herrick”

Ross G. Clarkson, Director	Lloyd W. Herrick, Director

Page 48 of 62

TRANSGLOBE ENERGY CORPORATION
Consolidated Statements of Cash Flows

		Year Ended			Year Ended			Year Ended
		Dec. 31,			Dec. 31,			Dec. 31,
		2002			2001			2000


CASH FLOWS RELATED TO THE
FOLLOWING ACTIVITIES:

OPERATING
Net income	$	5,426,389		$	3,062,237		$	307,967
Adjustments for:
Depletion and depreciation		4,277,000			2,762,000			635,400
Performance bonus expense paid in shares (Note 5)		73,631			16,218			-
Interest expense paid in common shares (Note 5)		-			-			5,294
Non-cash portion of settlement (Note 5)		-			-			235,000
Future income taxes		(67,168	)		-			-
Gain on sale of oil and gas properties		-			-			(254,132	)

Cash flow from operations (Note 8)		9,709,852			5,840,455			929,529

Changes in non-cash working capital (Note 7)		(2,478,700	)		621,196			(885,137	)

		7,231,152			6,461,651			44,392


FINANCING
Issue of share capital (Note 5)		(308	)		210,797			4,293,146
Issue of convertible debentures		-			-			(8,802	)
Issuance (repayment) of long-term debt		-			(77,634	)		77,634
Change in non-cash working capital (Note 7)		-			-			19,196

		(308	)		133,163			4,381,174


INVESTING
Purchase of capital assets
Yemen		(5,435,398	)		(3,406,363	)		(4,855,141	)
Canada		(1,041,146	)		(1,375,888	)		(1,118,266	)
United States		-			-			(17,909	)
Proceeds on disposal of oil and gas properties		133,587			-			606,059
Changes in non-cash working capital (Note 7)		532,437			(702,631	)		584,999

		(5,810,520	)		(5,484,882	)		(4,800,258	)


NET INCREASE IN CASH		1,420,324			1,109,932			(374,692	)

CASH, BEGINNING OF YEAR		1,174,846			64,914			439,606


CASH, END OF YEAR	$	2,595,170		$	1,174,846		$	64,914


Cash flow from operations per share (Note 8)
Basic	$	0.19		$	0.12		$	0.02
Diluted	$	0.19		$	0.11		$	0.02

Page 49 of 62

Notes to the Consolidated Financial Statements

1. SIGNIFICANT ACCOUNTING POLICIES

Basis of consolidation

These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, TransGlobe Oil and Gas Corporation, TransGlobe Petroleum International Inc., TransGlobe International (Holdings) Inc., and TG Holdings Yemen Inc.

Accounting principles

These consolidated financial statements are prepared in accordance with accounting principles generally accepted in Canada, which conform in all material respects with accounting principles generally accepted in the United States, except as disclosed in Note 14.

Oil and gas properties

The Company follows the full cost method of accounting for oil and gas operations whereby all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities.

The capitalized costs, together with the costs of production equipment, are depleted and depreciated on the unit-of-production method based on the estimated gross proven reserves and determined by independent petroleum engineers. Oil and gas reserves and production were converted into equivalent units of 6,000 cubic feet of natural gas to one barrel of oil based upon relative energy content.

Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation. These costs are assessed periodically to ascertain whether impairment has occurred. When proven reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and depreciation.

The capitalized costs less accumulated depletion and depreciation, future income taxes and the provision for future site restoration costs in each cost centre are limited to an amount equal to the estimated future net revenue from proven reserves plus the cost (net of impairment) of unproven properties.

The total capitalized costs less accumulated depletion and depreciation, future income taxes and the provision for future site restoration costs of all cost centres is further limited to an amount equal to the estimated future net revenue from proven reserves plus the cost (net of impairment) of unproven properties of all costs centres less estimated future site restoration costs, general and administrative expenses, financing costs and income taxes.

Proceeds from the sale of oil and gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would alter the rate of depletion and depreciation by more than 20 percent, in which case a gain or loss on disposal is recorded.

Substantially all of the Company’s exploration, development and production activities are conducted jointly with others and accordingly, these consolidated financial statements reflect only the Company’s proportionate interest in such activities.

Estimated future site restoration costs are provided for using the unit-of-production method and remaining proven reserves. Costs are estimated by the Company based on current regulations, costs, technology and industry standards. The annual charge is included in the provision for depletion and depreciation. Actual site restoration expenditures are charged to the accumulated provision account as incurred.

Furniture and fixtures are depreciated at declining balance rates of 20 to 30 percent.

Page 50 of 62

Foreign currency

The Company uses the United States dollar as its reporting currency since the majority of the Company’s business is transacted in United States dollars. The Company and its subsidiaries are considered to be integrated operations and the accounts are translated using the temporal method. Under this method, monetary assets and liabilities are translated at the rates of exchange in effect at the balance sheet date; non-monetary assets at historical rates and revenue and expense items at the average rates for the period, other than depletion and depreciation which are translated at the same rates of exchange as the related asset. The net effect of the foreign currency translation is included in current operations.

Cash and cash equivalent

Cash includes actual cash held and short-term investments such as treasury bills with maturity of less than three months.

Revenue recognition

The Company records oil and gas revenue at the time of physical transfer to purchaser.

Income taxes

Effective January 1, 2000 the Company adopted the Canadian Institute of Chartered Accountants accounting recommendations with respect to income taxes. The new recommendations were applied retroactively without restatement of the prior year consolidated financial statements.

The Company records income taxes using the liability method. Under this method, future income tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled.

Flow through shares

The Company has financed a portion of its exploration and development activities in Canada through the issue of flow through shares. Under the terms of these share issues, the tax attributes of the related expenditures are renounced to subscribers. To recognize the foregone tax benefits, share capital is reduced and a future income tax liability is recorded as the related expenditures are made. The Company has sufficient tax losses for which the future tax benefit is not recorded to offset the increase in future taxes due to the renouncement of expenditures.

Stock options

The Company has a stock option plan as described in Note 5. No compensation expense has been recorded upon the granting of the options at market prices. Effective January 1, 2002, the Company adopted CICA 3870 “Stock Based Compensation and Other Stock Based Payments”. As permitted by CICA 3870, the Company has applied this change prospectively for new awards granted on or after January 1, 2002. For 2002 the Company has calculated the impact on net earnings and earnings per share on a proforma basis (Note 5(l)). For periods prior to January 1, 2002 the Company did not recognize any compensation expense when stock options were issued to employees.

Per share amounts

Effective January 1, 2001, the Company retroactively adopted the new recommendations of the Canadian Institute of Chartered Accounts with respect to the computation, presentation and disclosure of earnings and cash flow from operations per share. Under the new standard, the treasury stock method is used instead of the imputed earnings method to determine the dilutive effect of stock options and warrants.

Net income and cash flow from operations per share are calculated using the weighted average number of shares outstanding during the year. Diluted net income and cash flow from operations per share are calculated using the treasury stock method. The treasury stock method assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price.

Page 51 of 62

Measurement uncertainty

The amounts recorded for depletion and depreciation of property and equipment, the provision for site restoration costs and the ceiling test calculation are based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in such estimates in future periods could be significant.

2. CAPITAL ASSETS – CANADA

		2002			2001

Oil and gas properties	$	4,618,485		$	3,725,222
Furniture and fixtures		201,539			187,243
Accumulated depletion and depreciation		(1,168,719	)		(867,719	)

	$	3,651,305		$	3,044,746

During the year the Company capitalized overhead costs relating to exploration and development activities of $153,569 (2001 - $156,311).

Depletion and depreciation expense includes $16,000 (2001 - $24,000) related to the provision for site restoration which is calculated based on a total future estimated cost of $319,000 (2001 - $297,000).

3. CAPITAL ASSETS – REPUBLIC OF YEMEN

		2002			2001


Block 32	$	13,575,336		$	11,553,012
Block S-1		8,016,556			4,611,957
Other		81,943			73,468
Accumulated depletion and depreciation		(6,607,000	)		(2,647,000	)

	$	15,066,835		$	13,591,437

The Company commenced production on Block 32 in November 2000. This represents the early stages of a major development program contracted under the Production Sharing Agreement (“PSA”) for the next twenty years. On Block S-1, the second period of the exploration program will be undertaken during 2002, 2003 and 2004. The Company and its partner on Block S-1 have elected to enter the second exploration period effective March 28, 2002. Unproven properties in the amount of $7,184,372 were excluded from costs subject to depletion and depreciation representing a portion of the costs incurred in Block S-1. During the year the Company capitalized overhead costs relating to exploration and development activities of $238,834 (2001 - $258,982).

Block 32

The PSA provides for the Ministry of Oil and Mineral Resources (the “MOM”) in the Republic of Yemen to receive a royalty of 3% (10% over 25,000 barrels of oil per day ("Bopd")) of gross production with the remaining 97% of revenue split between cost recovery oil and production sharing oil. Cost recovery oil is up to a maximum of 60% of 97% of the revenue limited to operating costs and allocated recoverable exploration and development expenditures as outlined in the PSA. Cost recovery oil is 100% for the account of the Block 32 Contractor (Joint Venture Partners) to recover operating costs and exploration and development expenditures. The remaining production sharing oil is shared 65% by MOM and 35% by the Block 32 Contractor which is further shared 5% Yemen Oil Company ("YOC")/95% Block 32 Contractor. These terms remain in place as long as proven recoverable reserves do not exceed 30 million barrels of oil (gross) or production of 25,000 Bopd.

Block S-1

The PSA provides MOM with a sliding scale royalty of 3%-10% based on daily oil production between 0-100,000 Bopd with the remaining revenue split between cost recovery oil and production sharing oil. Cost recovery oil is up to a maximum of 50% of after royalty revenue limited to operating costs and allocated recoverable exploration and development expenditures, as outlined in the PSA, to be utilized 100% by the Block S-1 Contractor. The balance of

Page 52 of 62

the revenue is allocated to production sharing oil and is shared 65%-80% by MOM and 35%-20% by the Block S-1 Contractor (which is further shared 17.5% YOC/82.5% Block S-1 Contractor) based on the production level.

4. LONG-TERM DEBT

Effective January 1, 2002, Canadian accounting standards require that revolving debt with terms of 364 days or less is to be included in current liabilities.

The Company has a Cdn$2,500,000 revolving loan facility and a Cdn$2,000,000 non-revolving acquisition/development facility with a Canadian chartered bank. The loan facilities bear interest at the bank’s Canadian prime rate plus three quarters of one percent and Canadian prime rate plus one percent, respectively, and are secured by a first floating charge debenture over all Canadian assets of the Company, a general assignment of book debts and certain negative pledges. At December 31, 2002 $nil (2001 - $nil) was drawn on these loan facilities.

The Company has a $1,500,000 letter of credit issued in support of the commitments of the second exploration period on Block S-1 in the Republic of Yemen which is secured by a guarantee obtained from Export Development Canada. Subsequent to December 31, 2002 this letter of credit was reduced to $750,000 (see Note 10).

5. SHARE CAPITAL

a) Authorized

The authorized share capital is 500,000,000 common shares with no par value.

b) Issued

	Number
	of shares		Amount

Balance, December 31, 1999	33,417,244	$	30,471,982
Tax effect of flow through shares	-		(335,020	)
Rights offering, net of issue costs (c)	2,601,283		842,666
Conversion of convertible debentures, net of issue costs (d)	4,989,354		739,603
Issued for consideration of interest on convertible debenture (d)	12,769		5,294
Prospectus offering, net of issue costs (e)	4,477,612		1,726,469
Private placement, net of issue costs (f)	875,000		344,899
Shares issued for settlement agreement, net of expenses (g)	500,000		232,498
Exercise of warrants (j)	2,769,778		1,090,250
Exercise of stock options (i)	410,000		90,200
Exercise of compensation options (e)	447,761		201,163

Balance, December 31, 2000	50,500,801		35,410,004
Exercise of stock options (j)	125,000		27,500
Exercise of warrants (f)	50,000		27,500
Performance bonus expense paid in shares (i)	50,000		16,218
Private placement, net of issue costs (h)	519,000		155,797

Balance, December 31, 2001	51,244,801		35,637,019
Future tax effect (h)	-		(67,168	)
Share issue costs	-		(309	)
Performance bonus expense paid in shares (i)	250,000		73,631

Balance, December 31, 2002	51,494,801	$	35,643,173

c) In January 2000, the Company completed a rights offering issuing 2,601,283 shares at $0.36 per share, for proceeds net of issue costs, of $842,666.

d) On January 21, 2000 the Company called the convertible debenture for redemption on February 29, 2000 and issued 4,989,354 common shares at $0.15 per share representing the full amount of principal and issued 12,769 common shares to insiders for the accrued interest.

Page 53 of 62

e) In July 2000, the Company closed a prospectus offering of 4,477,612 units at Cdn$0.67 per unit. Each unit consisted of one common share and one-half of a transferrable warrant. Each whole warrant entitles the holder to purchase one common share of the Company for Cdn$0.85 until January 27, 2001, and Cdn$1.15 until January 27, 2002. There warrants expired unexercised on January 27, 2002, except for 99,000 exercised in 2000.

The underwriter received compensation options whereby they had an option to exercise 447,761 common shares at Cdn$0.70 per share. All of the compensation options were exercised prior to December 31, 2000.

f) In August 2000, the Company issued 875,000 units in a private placement at $0.40 per unit for net proceeds of $344,899 net of issue costs. Each unit consisted of one common share and one non-transferrable warrant. Each warrant entitles the holder to purchase one common share of the Company for $0.55 per share, expiring on August 25, 2001.

The Company extended the expiration date of 775,000 of the 875,000 warrants whereby the holder exercised 50,000 warrants at $0.55 in exchange for a one year extension of 775,000 warrants to August 25, 2002 subject to a call whereby the warrants would expire on the earlier of (a) August 25, 2002 or (b) the 30^th calendar day following the period in which the 10-day weighted average trading price of the Company’s common shares on the Toronto Stock Exchange exceeds Cdn$1.0483.

g) In September 2000, the Company issued 500,000 units valued at $0.47 per unit and paid cash in the amount of $75,000 to a shareholder in the State of Florida pursuant to a settlement agreement. Each unit consisted of one common share and three non-transferrable warrants. The settlement agreement satisfied the shareholder’s claim relating to a 1996 private placement transaction concluded by previous management. Each warrant entitles the holder to purchase one common share of the Company for $0.47 until September 8, 2002. The valuation of the units and exercise price of the warrants represents the market price of the common shares of the Company at the time the settlement was negotiated.

h) In December 2001, the Company issued 519,000 flow through common shares in a private placement at Cdn$0.49 per share for net proceeds of US$155,797, subscribed by insiders of the Company. The terms of the flow through shares provide that the Company renounce Canadian tax deductions in the amount of Cdn$254,310 to the subscribers with the entire amount to be expended by the Company by December 31, 2002. As at December 31, 2002, the entire amount was spent. As described in Note 1, share capital is reduced and future income taxes are increased by the estimated amount of the future income taxes payable by the Company ($67,168) as a result of renouncing the expenditures to subscribers.

i) Pursuant to an employment contract and the Company meeting certain performance criteria, the Company issued 250,000 and 50,000 common shares to the President of the Company in 2002 and 2001, respectively, recorded at market prices at respective dates of issue.

j) Share purchase options

The Company established a stock option plan in April 1997, with subsequent amendments (the “Plan”). The maximum number of common shares to be issued upon the exercise of options granted under the Plan is 5,052,580 common shares. All incentive stock options granted under the Plan will have a per-share exercise price not less than the trading market value of the common shares at the date of grant and will vest as to 50% of the options, six months after the grant date, and as to the remaining 50%, one year from the grant date.

Page 54 of 62


	2002			2001			2000

			Weighted-			Weighted-			Weighted-
	Number		Average	Number		Average	Number		Average
	of		Exercise	of		Exercise	of		Exercise
	Options			Options		Price	Options		Price

Options outstanding at
beginning of year	2,379,500		$0.31	2,806,500		$0.32	2,257,000		$0.21
Granted	1,400,000		0.32	240,000		0.34	959,500		0.50
Exercised	-		-	(125,000	)	0.22	(410,000	)	0.22
Expired	(155,000	)	0.22	(542,000	)	0.38	-		-

Options outstanding at
end of year	3,624,500		$0.32	2,379,500		$0.31	2,806,500		$0.32

Options exercisable at
end of year	2,924,500			2,239,500			1,872,000

The following table summarizes information about the stock options outstanding at December 31, 2002:

	Options Outstanding				Options Exercisable

	Number	Weighted-				Weighted-
	Out-	Average		Weighted-	Number	Average		Weighted-
Range of	standing	Remaining		Average	Exercisable at	Remaining		Average
Exercise	at Dec. 31,	Contractual		Exercise	Dec. 31, 2002	Contractual		Exercise
Prices	2002	Life		Price		Life		Price

$0.22	1,285,000	0.7	$	0.22	1,285,000	0.7	$	0.22
Cdn0.45	20,000	1.8		Cdn0.45	20,000	1.8		Cdn0.45
Cdn0.55	200,000	3.4		Cdn0.55	200,000	3.4		Cdn0.55
Cdn0.39	40,000	3.8		Cdn0.39	40,000	3.8		Cdn0.39
Cdn0.73	679,500	2.6		Cdn0.73	679,500	2.6		Cdn0.73
Cdn0.50	1,400,000	4.3		Cdn0.50	700,000	4.3		Cdn0.50

	3,624,500	2.7	$	0.32	2,924,500	2.3	$	0.32

k) Share purchase warrants

The following table summarizes the share purchase warrants exercised and expired during the years ended and as at December 31, 2002 and 2001:

	Number of Warrants

Dec. 31,				Dec. 31,	Warrant	Expiry
2001	Granted	Expired	Exercised	2002	Price	Date

2,139,806	-	2,139,806	-	-	Cdn$1.15	Jan. 27, 2002
775,000	-	775,000	-	-	$0.55	Aug. 25, 2002
1,500,000	-	1,500,000	-	-	0.47	Sept. 8, 2002

4,414,806	-	4,414,806	-	-

	Number of Warrants

Dec. 31,				Dec. 31,	Warrant	Expiry
2000	Granted	Expired	Exercised	2001	Price	Date

2,139,806	-	-	-	2,139,806	Cdn$1.15	Jan. 27, 2002
875,000	-	50,000	50,000	775,000	$0.55	Aug. 25, 2002
1,500,000	-	-	-	1,500,000	$0.47	Sept. 8, 2002

4,514,806	-	50,000	50,000	4,414,806

Page 55 of 62

l) Stock-based compensation

The Company accounts for its stock-based compensation plans using the intrinsic-value of the options granted whereby no costs have been recognized in the financial statements for stock options granted to employees and directors at market values. Effective January 1, 2002 under Canadian generally accepted accounting principles, the impact of using the fair value method on compensation costs and recorded net earnings must be disclosed. If the fair value method had been used, the Company’s net earnings per share would approximate the following pro forma amounts (the pro forma amounts shown do not include the compensation costs associated with stock options granted prior to January 1, 2002):

		2002

Compensation costs	$	140,000
Net earnings:
As reported		5,426,389
Pro forma		5,286,389
Net earnings per common shares:
As reported - Basic	$	0.11
- Diluted	$	0.10
Pro forma - Basic and diluted	$	0.10

The fair value of each option granted on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants is as follows:


Risk free interest rate (%)	5.05
Expected lives (years)	5.00
Expected volatility (%)	66.35
Dividend per share	0.00

6. INCOME TAXES

The Company has deductible temporary differences for which no future income tax asset has been recorded. Those deductible temporary differences are Cdn$2,260,000 in non-capital losses and approximately Cdn$5,645,000 of income tax pools in excess of the carrying value of the Company’s Canadian capital assets. The Company also has $13,100,000 of income tax losses in the United States. The Canadian loss carryforwards expire between 2006 and 2010 and the United States loss carryforwards expire between 2006 and 2020. In total, these temporary differences would generate a future income tax asset of Cdn$3,624,400 on Canadian operations for which a valuation allowance of an identical amount would be recorded.

Current income taxes in the amount of $986,862 (2001 - $634,716) represents income taxes incurred and paid under the laws of the Republic of Yemen.

The components of expected income tax expense are as follows:

		2002			2001


Computed Canadian expected income tax
expense at 42.15% (2001 – 42.67%)	$	2,674,874		$	1,577,490
Non-deductible Crown charges (net of ARTC)		64,036			127,518
Resource allowance		(2,773	)		(99,174	)
Lower tax rates in the Republic of Yemen		(1,872,869	)		(829,858	)
Future income taxes recovered		(67,168	)		-
Other		123,594			(141,260	)

	$	919,694		$	634,716

Page 56 of 62

7. SUPPLEMENTAL CASH FLOW INFORMATION

		2002			2001			2000


Operating activities
Decrease (increase) in current assets
Accounts receivable	$	(2,317,826	)	$	732,992		$	(1,085,920	)
Prepaid expenses		(28,150	)		(9,577	)		29,652
Increase (decrease) in current liabilities
Accounts payable		(132,724	)		(102,219	)		171,131

	$	(2,478,700	)	$	621,196		$	(885,137	)

Financing activities
Decrease (increase) in current assets
Prepaid expenses	$	-		$	-		$	67,364
Increase (decrease) in current liabilities
Accounts payable		-			-			(48,168	)

	$	-		$	-		$	19,196

Investing activities
Decrease (increase) in current assets
Accounts receivable	$	309,598		$	(91,856	)	$	(84,335	)

Increase (decrease) in current liabilities
Accounts payable		222,839			(610,775	)		669,334

	$	532,437		$	(702,631	)	$	584,999


Interest paid	$	16,154		$	4,424		$	12,390


Taxes paid	$	986,862		$	634,716		$	86,038

8. NET INCOME AND CASH FLOW PER SHARE

		2002		2001		2000

Basic
Net income per share	$	0.11	$	0.06	$	0.01
Cash flow from operations per share	$	0.19	$	0.12	$	0.02
Weighted average number of shares
outstanding		51,449,596		50,640,877		44,066,100

Diluted
Net income per share	$	0.10	$	0.06	$	0.01
Cash flow from operations per share	$	0.19	$	0.11	$	0.02
Weighted average number of shares
outstanding		51,944,926		51,118,289		46,429,961

Page 57 of 62

9. SEGMENTED INFORMATION

In 2002 the Company operated in two geographic segments, Canada and the Republic of Yemen. The capital assets in each geographic segment are disclosed in Notes 2 and 3. The Company’s revenue in the Republic of Yemen is based on a 30 day dated Brent average oil price less pricing quality differential and is paid monthly by operator.

The results of operations for the year ended December 31, 2002 are comprised of the following:

		Republic of Yemen		Canada		Total

REVENUE
Oil and gas sales, net of royalties	$	12,238,711	$	1,015,394	$	13,254,105

EXPENSES
Operating		1,394,379		448,894		1,843,273
Depletion and depreciation		3,960,000		317,000		4,277,000

Segmented operations	$	6,884,332	$	249,500		7,133,832
Other income						42,108

						7,175,940
General and administrative						820,691
Foreign exchange (gain) loss						(6,988	)
Interest						16,154
Income taxes (Note 6)						919,694

NET INCOME					$	5,426,389

The results of operations for the year ended December 31, 2001 are comprised of the following:

		Republic of Yemen		Canada		Total

REVENUE
Oil and gas sales, net of royalties	$	7,000,676	$	1,553,409	$	8,554,085

EXPENSES
Operating		1,133,092		407,277		1,540,369
Depletion and depreciation		2,405,000		357,000		2,762,000

Segmented operations	$	3,462,584	$	789,132		4,251,716
Other income						16,470

						4,268,186
General and administrative						570,609
Foreign exchange (gain) loss						(3,800	)
Interest						4,424
Income taxes (Note 6)						634,716

NET INCOME					$	3,062,237

Page 58 of 62

The results of operations for the year ended December 31, 2000 are comprised of the following:

		Republic of				United
		Yemen		Canada		States		Total

REVENUE
Oil and gas sales, net of royalties	$	949,039	$	1,151,400	$	302,827	$	2,403,266

EXPENSES
Operating		106,108		289,988		103,158		499,254
Depletion and depreciation		242,000		311,000		82,400		635,400

Segmented operations	$	600,931	$	550,412	$	117,269		1,268,612
Other income								278,514

								1,547,126
General and administrative								1,087,963
Foreign exchange (gain) loss								51,636
Interest								13,522
Income taxes								86,038

NET INCOME							$	307,967

10. COMMITMENTS AND CONTINGENCIES

The Company is committed to office and equipment leases over the next five years as follows:

	2003	$112,000
	2004	114,000
	2005	114,000
	2006	114,000
	2007	40,000

The Company has issued a three year letter of credit in the amount of $1,500,000 in support of the commitments of the second exploration period on Block S-1 in the Republic of Yemen. This letter of credit is secured by a guarantee obtained from Export Development Canada. The Company’s obligation to Export Development Canada is secured by a first floating charge debenture (subordinated to the Bank’s interest in the Canadian assets and first to the foreign assets). The Block S-1 second exploration period commitments were fulfilled during 2002 and subsequent to December 31, 2002 the Company’s letter of credit was reduced to $750,000. It is expected that the remaining balance of $750,000 will be released in the first quarter of 2003.

Effective January 1, 2000, the Company entered into an agreement to purchase an additional four percent working interest, increasing the Company’s working interest to 13.81087% in Block 32 for a total purchase price of $2,136,163. The Company made an initial payment of $1,176,163. A potential future obligation totalling $960,000 will be due in six payments of $160,000 for each cumulative million barrels of gross oil production from Block 32 commencing at 7 million barrels to a maximum of 12 million barrels. During 2002 the Company made the first payment of $160,000 and subsequent to December 31, 2002 a second payment of $160,000 was made. The Company expects that the remaining payments will be made during 2003.

11. FINANCIAL INSTRUMENTS

Carrying values of financial instruments, which include accounts receivable, accounts payable and accrued liabilities approximate their fair value due to the short-term or the floating interest rate nature of these amounts.

The Company has foreign exchange risk due to the fact that it operates internationally using foreign currencies. The Company has commodity price risk associated with its sale of crude oil and natural gas.

Page 59 of 62

The majority of the accounts receivable are in respect of oil and gas operations. The Company generally extends unsecured credit to these customers and therefore the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

12. COMPARATIVE FIGURES

Certain of the prior period’s comparative figures have been reclassified to conform with the current period’s presentation.

13. SUBSEQUENT EVENT

Subsequent to December 31, 2002, the Company entered into a contract to sell 500 gigajoules (GJ) per day of natural gas in Canada from March 1 to October 31, 2003 for Cdn$7.65/GJ.

14. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES IN CANADA AND THE UNITED STATES

The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP) which differ in certain respects from those principles and practices that the Company would have followed had its consolidated financial statements been prepared in accordance with United States generally accepted accounting principles and practices (U.S. GAAP).

Escrowed shares

For U.S. GAAP purposes, escrowed shares would be considered a separate compensatory arrangement between the Company and the holder of the shares. Accordingly, the fair market value of shares at the time the shares are released from escrow will be recognized as a charge to income in that year with a corresponding increase in share capital. The difference in share capital between Canadian GAAP and U.S. GAAP represents the effect of applying this provision in 1995 when 187,500 escrow shares were released resulting in an increase in share capital of $833,333 with the offset to deficit.

Stock based compensation

In 1995, the United States Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation.” The Company has a stock-based compensation plan as more fully described in Note 5. With regard to its stock option plan, the Company applies APB Opinion No. 25 as interpreted by FASB Interpretation No. 44 in accounting for this plan and accordingly no compensation cost has been recognized. Had compensation expense been determined based on fair value at the grant dates for the stock option grants consistent with the method of SFAS No. 123, the Company’s net income would have been decreased by $171,000 (December 31, 2001 net income would have been decreased by $302,000). Basic net income per share would have been reduced to $0.10 and diluted net income per share would be unchanged (2001 basic and diluted net income per share would have been reduced to $0.05).

The foregoing information is calculated in accordance with the Black-Scholes option pricing model, using the following data and assumptions: volatility, as of the date of grant, computed using the prior one to three-year monthly average prices of the Company’s common shares, which ranged from 113% to 114%; expected dividend yield – 0%; option terms to expiry - 5 years as defined by the option contracts; risk-free rate of return as of the date of grant – 5.05% to 6.03%.

Page 60 of 62

Gain on sale of oil and gas properties

The Company sold all of its oil and gas properties in the United States in the year 2000. The gain on sale under United States GAAP was $145,000 less than under Canadian GAAP arising from ceiling test differences. Under SEC regulations, the future net revenue as calculated for the ceiling test excludes future overhead costs and must be discounted at 10%. This is not required under Canadian GAAP. The effect of applying this provision to the Company’s financial statements in previous years resulted in a higher net book value of capital assets in the United States by $145,000.

Flow through shares

The Company records the renouncement of deductions related to flow through shares by reducing the share capital and recording a future tax liability in the amount of the estimated cost of the tax deductions flowed to the shareholders in the period in which the expenditures are renounced. United States practice requires that the share capital on flow through shares be stated at the quoted market value of the shares at the date of issuance. In addition, the temporary difference that arises as a result of the renouncement of the deductions, less any proceeds received in excess of the quoted market value of the shares is recognized in the determination of income tax expense for the period. In 2000, the effect of applying this provision to the Company’s financial statements would result in an increase in income tax expense and future tax liability by $335,020 representing the tax effect of the flow through shares and a corresponding decrease to income tax expense and future tax liability by $335,020 to record the recognition of the benefit of tax losses available to the Company equal to the liability arising from renouncing tax pools to the subscribers. In 2002, the effect of applying this provision to the Company’s financial statements would result in an increase in income tax expense and future tax liability by $67,168 representing tax effect of the flow through shares and a corresponding decrease to income tax expense and future tax liability by $67,168 to record the recognition of the benefit of tax losses available to the Company equal to the liability arising from renouncing tax pools to the subscriber.

Had the Company followed U.S. GAAP, the shareholders’ equity would have been reported as follows:

		2002						2001
		Cdn. GAAP			U.S. GAAP			Cdn. GAAP			U.S. GAAP


Share capital	$	35,643,173		$	36,878,694		$	35,637,019		$	36,805,372
Deficit		(12,298,309	)		(13,533,830	)		(17,724,698	)		(18,893,051	)

	$	23,344,864		$	23,344,864		$	17,912,321		$	17,912,321

The reconciling items between share capital and deficit for Canadian and United States GAAP are $833,333 related to escrowed shares and $402,188 related to flow through shares as described above. There are no other balance differences.

Had the Company followed U.S. GAAP, the statement of operations would have been reported as follows:

		2002		2001		2000


Net income for the year under Canadian GAAP	$	5,426,389	$	3,062,237	$	307,967

Net income for the year under U.S. GAAP		5,359,221		3,062,237	$	162,967

Net income per share under U.S. GAAP	$	0.10	$	0.06	$	-

Recent accounting pronouncements

In August 2001, the FASB approved SFAS No. 143, “Accounting for Asset Retirement Obligations”, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Management does not believe that SFAS No. 143 will have a material impact on the Company’s financial statements.

Page 61 of 62

In October 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, resolving significant implementation issues related to FASB Statement No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of”, and supersedes the accounting and reporting provisions of APB Opinion No. 30, “Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions”, for the disposal of a business segment. SFAS No. 144 is effective for the fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. Management does not believe that SFAS No. 144 will have material impact on the Company’s financial statements.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” SFAS No. 4, “Reporting Gains and Losses from Extinguishment of Debt”, addressed income statement classification of gains and losses from extinguishment of debt. SFAS No. 64 amended SFAS No. 4 and is no longer necessary due to the rescission of SFAS No. 4. SFAS No. 145 also amended SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. Management believes that SFAS No. 145 will have no retroactive impact on the Company’s financial statements.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”, which requires the recognition of a liability when incurred for costs associated with an exit or disposal activity. Management does not believe that SFAS No. 146 will have a material impact on the Company’s financial statements.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-based Compensation Transition and Disclosure - an Amendment of FASB Statement No. 123”, to provide alternative methods of accounting for stock-based employee compensation. SFAS No. 148 is effective for fiscal years ending after December 15, 2002 and interim periods beginning after December 15, 2002. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Management does not believe that SFAS No. 148 will have a material impact on the Company’s financial statements.

Page 62 of 62