Management's Discussion and Analysis

                March 9, 2005

                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 message to the shareholders, the operations review, the audited consolidated financial statements of the Company for the years ended December 31, 2004 and 2003, together with the notes related thereto. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada in the currency of the United States (except where indicated as being another currency). The effect of significant differences between Canadian and United States accounting principles is disclosed in Note 15 of the consolidated financial statements. Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The calculations of barrels of oil equivalent (“Boe”) are based on a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Boe’s may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

                This Management’s Discussion and Analysis (MD&A) may include certain statements that may be deemed to be “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. All statements in this annual report, other than statements of historical facts, that address future production, reserve potential, exploration drilling, exploitation activities and events or developments that the Company expects, are forward-looking statements. Although TransGlobe believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Factors that could cause actual results to differ materially from those in forward-looking statements include, but are not limited to, oil and gas prices, exploitation and exploration successes, continued availability of capital and financing, and general economic, market or business conditions.

OVERVIEW

                Cash flow from operations for 2004 increased 85% to $17,325,000 ($0.32 per share basic and $0.31 per share diluted) compared to $9,347,000 ($0.18 per share basic and $0.17 per share diluted) in 2003. Net income for 2004 was unchanged at $5,919,000 ($0.11 per share basic and $0.10 per share diluted) compared to net income of $5,905,000 ($0.11 per share basic and $0.11 per share diluted) in 2003. The Company’s oil and gas revenues, net of royalties, increased 84% to $31,630,000 in 2004 compared to 2003.

                The following is a brief summary of the primary changes that occurred during 2004 that will be discussed in more detail throughout this MD&A:

• Cash Flow From Operations and Net Income items: 

– Oil and gas sales, net of royalties, increased $14,468,000 (84%) as a direct result of sales volumes increasing 44% and commodity prices increasing 25%.

– Operating costs increased $3,358,000 (32% on a Boe basis) in 2004 compared to 2003 as a result of increased volumes and Block S-1 having a higher cost per Boe during the trucking phase.

– Current income tax expense increased $2,525,000 in 2004 compared to 2003 as a result of higher volumes with Block S-1 production commencing in 2004.

• Additional Net Income items: 

– Depletion, depreciation and accretion, a non-cash expense, increased $4,093,000 (15% on a Boe basis) in 2004 compared to 2003 due mainly to higher capital costs in the depletable base.

– Future income tax recovery, a non-cash recovery, decreased $2,163,000 in 2004 compared to 2003 due to the initial recognition of a Canadian future income tax asset in 2003.

– Stock-based compensation, a non-cash expense, amounted to $1,310,000 in 2004 without a corresponding amount in the same period in 2003.

                Furthermore, the Company’s financial condition remained strong as working capital continued to be in excess of $2.5 million and the Company continued to have no long-term debt outstanding. During the fourth quarter of 2004, the Company issued 2,910,000 shares through a public offering for net proceeds of $9.8 million.

                Operating Segments

                TransGlobe reports its results of operations under three main geographic segments: Republic of Yemen, Canada and Arab Republic of Egypt.

                Yemen includes the Company’s exploration for, as well as development and production of, crude oil. In 2004, the Company spent $15.3 million or 58% of its capital expenditures in Yemen. Of this, $12.1 million was spent at Block S-1 primarily to develop the An Nagyah field and $3.1 million was spent at Block 32 primarily to develop the Tasour field. Oil sales, net of royalties, less operating costs and depletion, depreciation and accretion increased 86% to $11.4 million in 2004 compared to $6.1 million in 2003 primarily due to Block S-1 commencing production at the end of the first quarter of 2004 and higher crude oil prices in 2004 compared to 2003.

                Canada includes the Company’s exploration for, as well as development and production of, natural gas, natural gas liquids (“NGLs”) and crude oil. In 2004, the Company spent $10.1 million or 38% of its capital expenditures in Canada primarily on the exploration for natural gas and NGL’s. Oil and gas sales, net of royalties, less operating costs and depletion, depreciation and accretion increased 159% to $2.9 million in 2004 compared to $1.1 million in 2003 primarily due to successful exploration drilling which increased production 158% in 2004 compared to 2003.

                Egypt includes the Company’s exploration for natural gas, natural gas liquids and crude oil. In 2004, the Company spent $1.0 million primarily on acquisition costs and geological and geophysical activity for Nuqra Block 1.

                Business Environment

                Commodity Price and Foreign Exchange Benchmarks

		%			%
	2004	Change		2003	Change	2002
Dated Brent average oil price ($ per barrel)	38.58	34		28.87	13	25.47
WTI average oil price ($ per barrel)	41.42	33		31.14	19	26.09
Edmonton Par average oil price (C$ per barrel)	52.91	22		43.23	8	40.12
AECO average gas price (C$ per thousand cubic feet)	6.54	(2	)	6.67	64	4.07
U.S./Canadian Dollar Year End Exchange Rate	0.8319	8		0.7713	22	0.6339
U.S./Canadian Dollar Average Exchange Rate	0.7685	8		0.7138	12	0.6368

                World crude oil prices continued to increase significantly in 2004 as Asia and North America demand remained strong and, during the fourth quarter, concerns increased over the supply of winter heating oil supplies. Also in the fourth quarter, supply uncertainties in the Middle East and West Africa, combined with reduced supply from the Gulf of Mexico, the North Sea, Russia and Canada, increased the lack of confidence concerning future world crude oil supply, resulting in the continued upward pressure on prices in 2004.

                In 2004, TransGlobe sold approximately:

• 5% of its crude oil at fixed prices; 

• 92% at dated Brent minus the Yemen government official selling price differentials; and 

• the remaining 3% at the Edmonton Par price less quality differentials. 

                Historically high natural gas prices continued in 2004 since North American demand remained strong which, combined with a lack of supply and high crude oil prices, infl uenced natural gas prices.

                In 2004, TransGlobe sold approximately:

•  29% of its natural gas at fixed prices; and 

•  the remaining 71% at AECO Index based pricing. 

                The year end U.S./Canadian dollar exchange rate increased by 8% in 2004 to US$0.8319/C$ 1 compared to US$0.7713/C$ 1 in 2003 and increased 22% in 2003 to US$0.7713/C$ 1 compared to US$0.6339/C$ 1 in 2002. The increases in each year were primarily the result of the economic slowdown in the U.S., continuing differences between Canadian and U.S. interest rates and the U.S. current account deficits.

                Management Strategy

                In 2005, the capital budget is expected to be focused on the completion of the central production facility and related pipeline on the An Nagyah field in Block S-1, as well as growing reserves and production in Yemen and Canada. Also, a significant portion of the 2005 capital budget will be spent defining leads on Nuqra Block 1 in Egypt through geological field studies, reprocessing of existing 2-D seismic and field acquisition of additional 2-D seismic to identify drilling locations for the 2006 exploration program.

                The success of these strategies is subject to numerous risk factors such as (including but not limited to) exploration success, fl uctuations in commodity prices and foreign exchange rates, in addition to credit, operational and safety and environmental risks.

SELECTED ANNUAL AND QUARTERLY INFORMATION

		%	2003	%
($000’s, except per share amounts and % change)	2004	Change	Restated	Change		2002
Average sales volumes (Boepd)	3,796	44	2,635	52		1,731
Average price ($/Boe)	35.63	25	28.43	17		24.34
Oil and gas sales	49,495	81	27,336	78		15,386
Oil and gas sales, net of royalties	31,630	84	17,162	29		13,254
Cash flow from operations	17,325	85	9,347	(4	)	9,710
Cash flow from operations per share
- Basic	0.32		0.18			0.19
- Diluted	0.31		0.17			0.19
Net income	5,919	-	5,905	9		5,426
Net income per share
- Basic	0.11		0.11			0.11
- Diluted	0.10		0.11			0.10
Total assets	60,522	70	35,601	46		24,386

		2004
($000’s, except per share amounts)		Q-4		Q-3		Q-2		Q-1
Average sales volumes (Boepd)		5,384		3,918		3,103		2,760
Average price ($/Boe)	$	37.45	$	37.12	$	34.25	$	31.44
Oil and gas sales	$	18,548	$	13,380	$	9,670	$	7,897
Oil and gas sales, net of royalties	$	11,756	$	8,227	$	5,779	$	5,868
Cash flow from operations	$	6,326	$	4,363	$	2,749	$	3,887
Cash flow from operations per share
- Basic	$	0.12	$	0.08	$	0.05	$	0.07
- Diluted	$	0.11	$	0.08	$	0.05	$	0.07
Net income	$	768	$	2,541	$	447	$	2,163
Net income per share
- Basic	$	0.01	$	0.05	$	0.01	$	0.04
- Diluted	$	0.01	$	0.04	$	0.01	$	0.04

		2003
($000’s, except per share amounts)		Q-4		Q-3		Q-2		Q-1
Average sales volumes (Boepd)		2,819		2,698		2,499		2,517
Average price ($/Boe)	$	28.90	$	28.29	$	26.39	$	30.08
Oil and gas sales	$	7,496	$	7,021	$	6,002	$	6,817
Oil and gas sales, net of royalties	$	4,489	$	4,159	$	4,139	$	4,375
Cash flow from operations	$	1,894	$	2,193	$	2,369	$	2,891
Cash flow from operations per share
- Basic	$	0.04	$	0.04	$	0.05	$	0.06
-Diluted	$	0.03	$	0.04	$	0.05	$	0.06
Net income	$	3,413	$	291	$	776	$	1,425
Net income per share
- Basic	$	0.06	$	0.01	$	0.01	$	0.03
- Diluted	$	0.06	$	0.01	$	0.01	$	0.03

                Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital. We consider this a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment. Cash flow from operations may not be comparable to similar measures used by other companies.

                Discussion of Annual Information:

                Cash flow from operations increased by $7,978,000 (85%) in 2004 compared to 2003 mainly as a result of:

• increased volumes from drilling success in both Yemen and Canada; 

• increased commodity prices; and 

• increased operating costs and current taxes due to higher volumes that offset the above cash increases. 

                Net income was unchanged in 2004 compared to 2003 mainly as result of:

• the above items affecting cash flow also increased net income, and are offset by: 

– increased depletion, depreciation and accretion due to higher capital costs in the depletable base; 

– increased stock-based compensation, a non-cash expense, due to a new Canadian accounting standard; and 

– decreased non-cash future income tax recovery in 2004 compared to 2003. 

                Discussion of Quarterly Information:

                Oil and gas sales, net of royalties, and cash flow from operations increased in the third and fourth quarters of 2004 due to increased production relating primarily to Block S-1 commencing production at the end of the first quarter with increased trucking capacity each quarter, increasing production in Canada due to the success of the drilling program and crude oil prices increasing throughout 2004.

                Net income is higher in the third quarter of 2004 due a non-cash future income tax recovery booked that relates to the Company recognizing a portion of the future tax benefits in Canada as a direct result of the successful Canadian drilling program carried out in 2004. Net income is also higher in the fourth quarter of 2003 due a non-cash future income tax recovery booked that relates to the Company recognizing a portion of the future tax benefits in Canada as a direct result of the successful Canadian drilling program carried out in 2003 and recording a gain in the United States on disposal of seismic data.

OPERATING RESULTS

                Daily Production, before royalties

		2004	2003	% Change
Yemen   - Oil	Bopd	3,119	2,372	31
Canada  - Oil and liquids	Bopd	179	63	184
- Gas	Mcfpd	2,987	1,200	149
Barrels of oil equivalent (6:1)	Boepd	3,796	2,635	44

                Consolidated Net Operating Results

	Consolidated
	2004		2003
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil and gas sales	49,495	35.63	27,336	28.43
Royalties	17,865	12.86	10,174	10.58
Operating expenses	7,064	5.09	3,706	3.85
Net operating income*	24,566	17.68	13,456	14.00

*      Net operating income amounts do not refl ect Yemen income tax expense which is paid through oil allocations with MOM in Yemen (2004 - $5,269,000, $3.79/Boe; 2003 - $2,755,000, $2.87/Boe).

                Segmented Net Operating Results

                In 2004 the Company had producing operations in two geographic areas, segmented as Yemen and Canada. Also, the Company had start-up operations in a third geographic segment, Egypt. MD&A will follow under each of these segments.

                Republic of Yemen

	2004		2003
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil sales	41,472	36.33	24,356	28.13
Royalties	16,506	14.46	9,731	11.24
Operating expenses	5,449	4.77	3,012	3.48
Net operating income*	19,517	17.10	11,613	13.41

*      Net operating income amounts do not refl ect Yemen income tax expense which is paid through oil allocations with MOM in Yemen (2004 - $5,269,000, $4.62/Boe; 2003 - $2,755,000, $3.18/Boe.)

Net operating income in Yemen increased 68% in 2004 primarily as a result of the following:

•	Oil sales increased 70% mainly as a result of the following:
	1.	Sales volumes increased 31% in 2004 primarily as a result of Block S-1 production commencing at the end of the first quarter 2004. During 2004 sales volumes for Block S-1 and Block 32 were 666 Bopd and 2,453 Bopd, respectively.
	2.	Oil prices increased 29%.
•	Royalty costs increased 70%. Royalties as a percentage of revenue were consistent at 40% in 2004 and 2003.
•	Operating expenses on a Boe basis increased 37% mainly as a result of the following:
	1.	Block 32 operating expenses averaged $4.11 per barrel in 2004 compared to $3.48 per barrel in 2003 primarily due to diesel costs which increased approximately $0.42 per barrel. A plant is being constructed in 2005 to manufacture diesel from produced crude oil which will reduce the cost of purchased diesel. The plant is expected to be commissioned in the third quarter of 2005.
	2.	Block S-1 has significantly higher operating costs during the initial trucking phase, averaging $7.96 per barrel. This is a refl ection of higher costs associated with trucking and higher fixed costs per barrel until volumes are increased when full scale production commences in 2005. Average cost per barrel is expected to be significantly reduced after commissioning of the pipeline and with increased production in mid 2005.

                TransGlobe commenced production on Block 32 on November 4, 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 production split between cost recovery oil and production sharing oil. Cost recovery oil is up to a maximum of 60% of the production after deducting 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 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 proved recoverable reserves exceed 30 million barrels of oil (assessed every two years) or until gross production exceeds 25,000 Bopd at which time the terms would revert to the original PSA terms in place prior to the 1999 PSA amendment. The original PSA terms provided for a 10% royalty on gross production with the remaining 90% of production split between cost recovery oil and production sharing oil. Cost recovery oil would be to a maximum of 25%, with the remaining oil allocated to production sharing oil shared 77% by MOM and 23 % by the Block 32 Joint Venture Group. The proved recoverable reserve determination is conducted every 2 years from the anniversary of first oil production (November 4, 2000). At November 4, 2004, the proved recoverable reserves recognized by the MOM approved independent third party audit was less than 10 million barrels. The next Block 32 MOM audit will be conducted effective November 4, 2006.

                The current Block 32 Production Sharing agreement allows for the recovery of operating costs and capital costs from oil production. Operating costs are recovered in the quarter expended. The capital costs are amortized over two years with 50% recovered in the quarter expended and the remaining 50% recovered in the first quarter of the following calendar year. The Company will receive a larger share of production in the first quarter of each year as 50% of the previous year’s historical costs are recovered. The amount of oil required to recover capital and operating costs will vary depending upon the prevailing oil prices. The Company received 43% of its working interest share of production (after royalty and tax) in 2004 compared to 49% in 2003. The Company expects to receive between 65% to 71% share of production (after royalty and tax) in the first quarter of 2005 and then decrease to between 39% to 45% share of production (after royalty and tax) in the balance of the year depending upon production volumes, oil prices, operating costs and eligible capital expenditures.

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

                The Block S-1 Production Sharing agreement allows for the recovery of operating costs and capital costs from oil production. Operating costs are recovered in the quarter expended. New capital costs are amortized over eight quarters with one eighth (12.5%) recovered each quarter. In addition to current ongoing investments, the Company will also recover eligible historical costs on a “last in, first out” basis. The Company received maximum cost oil for all of 2004. The amount of oil required to recover capital and operating costs will vary depending upon the prevailing oil prices, operating costs and the amount of new capital invested. It is expected that the Company will continue to receive the maximum cost oil resulting in a 62.5% of its working interest share of production (net barrels, after royalty and tax) for 2005.

                Canada

	2004		2003
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil sales	1,201	38.34	345	27.00
Gas sales (6:1)	5,675	31.14	2,293	31.44
NGL sales	1,070	31.37	236	23.42
Other sales	77	-	106	-
	8,023	32.40	2,980	31.10
Royalties	1,359	5.49	443	4.62
Operating expense	1,615	6.52	694	7.25
Net operating income	5,049	20.39	1,843	19.23

                Net operating income in Canada increased 174% in 2004 primarily as a result of the following:

•	Sales increased 169% mainly as a result of the following:
	1.	Sales volumes increased 158% as a direct result of the 2003 and 2004 drilling programs.
	2.	Commodity prices increased 4% on a Boe basis. More specifically, gas prices decreased 1% to average $5.19 per Mcf in 2004 compared to $5.24 per Mcf in 2003 while oil and natural gas liquids prices increased 42% and 34%, respectively.

• Royalty costs increased 19% on a Boe basis. Royalties as a percentage of revenue increased to 17% in 2004 compared to 15% in 2003 mainly as a result of the new wells that were placed on production in the second half of 2004, which have a higher royalty rate as a percentage of revenue than the previous wells on production.

• Operating costs decreased 10% on a Boe basis as a result of wells that were placed on production in 2004, which have a lower operating cost than the previous wells on production. This was offset by the strengthening of the Canadian dollar which increased Canada’s operating costs when converted to US dollars at a higher rate.

                Egypt

                TransGlobe Petroleum Egypt Inc. (“TransGlobe Egypt”), a wholly owned subsidiary of TransGlobe Energy Corporation, entered into a Farmout Agreement which provides TransGlobe Egypt the opportunity to participate and earn a 50% working interest in the Nuqra Concession by paying 100% of the initial $6.0 million of expenditures in the Stage 1 and Stage 2 work programs. TransGlobe Egypt is the operator of the Nuqra Block. The Nuqra Concession Agreement Stage 1 work program requires a minimum expenditure of $2.0 million to reprocess existing seismic and to shoot new seismic within the first two years. Upon expiry of the Stage 1 term, there is an option to proceed to the Stage 2 work program. Stage 2 requires completion of a two well drilling program, with a minimum expenditure of $4.0 million, over a period of three years. Upon expiry of the Stage 2 term there is an option to proceed to the Stage 3 work program. Stage 3 requires completion of a two well drilling program, with a minimum expenditure of $5.0 million, over a final three year term. Exploitation of discovered commercial fields will continue under a Development Lease for a further 20 years.

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

                The Company spent $992,000 in 2004 primarily on acquisition costs and geological and geophysical activities related to the Nuqra Block. The proposed work program for 2005 consists of geological field studies, re-processing of existing 2-D seismic and field acquisition of additional 2-D seismic data. It is anticipated that exploration drilling will commence late 2006.

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

GENERAL AND ADMINISTRATIVE EXPENSES

	2004				2003
(000’s, except per Boe amounts)	$		$/Boe		$		$/Boe
G&A (gross)	2,862		2.06		1,569		1.63
Capitalized G&A	(1,011	)	(0.73	)	(278	)	(0.29	)
Overhead recoveries	(187	)	(0.13	)	(84	)	(0.09	)
G&A (net)	1,664		1.20		1,207		1.25

                General and administrative expenses (“G&A”) increased 38% in 2004 compared to 2003 and decreased 4% on a Boe basis, as a result of the following:

• Increases were experienced in personnel costs with additional employees and consultants, office overhead costs and insurance costs.

• Public company administration costs increased 16% in 2004 and are anticipated to be higher in 2005 due to additional work associated with Sarbanes Oxley compliance.

• Capitalized general and administrative expenses and overhead recoveries increased due to the increased capital activity in both  Yemen and Canada.

• The strengthening of the Canadian dollar against the United States dollar increased net G&A costs by $0.10 per Boe through currency conversion.

STOCK-BASED COMPENSATION

                Effective January 1, 2004 the Company adopted the new accounting standard of Canadian Institute of Chartered Accountants (“CICA”) section 3870, “Stock-based Compensation and Other Stock-based Payments”, retroactively without restatement of prior periods. This Canadian accounting standard requires the Company to record a compensation expense over the vesting period based on the fair value of options granted to employees and directors since January 1, 2002. Non-cash stock compensation expense amounted to $1,310,000 ($0.94/Boe) for 2004.

DEPLETION, DEPRECIATION AND ACCRETION EXPENSE

	2004		2003
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Republic of Yemen	8,162	7.15	5,516	6.37
Canada	2,184	8.82	737	7.69
	10,346	7.45	6,253	6.50

                In Yemen, depletion, depreciation and accretion (“DD&A”) on a Boe basis increased 12% in 2004 compared to 2003 primarily as a result of an increased asset base as all remaining costs associated with the Block S-1 major development project were included in the depletable base. In 2003, major development project costs of $11,684,000 were excluded from costs subject to depletion and depreciation representing a portion of the costs incurred in Block S-1.

                In Canada, DD&A on a Boe basis increased 15% in 2004 compared to 2003 primarily as a result of the strengthening of the Canadian dollar against the United States dollar which increased DD&A $0.59 per Boe (8%) through currency conversion.

INCOME TAXES

($000’s)	2004		2003
Future income tax	(285	)	(2,448	)
Current income tax	5,280		2,755
	4,995		307

                The future income tax recovery of $285,000 in 2004 and $2,448,000 in 2003 is a result of recognizing a portion of the future tax benefits in Canada. The recording of these future tax benefits in Canada is a direct result of the successful Canadian drilling program carried out in 2004 and 2003. The Company has unrecognized future tax benefits in Canada in the amount of $599,000 which may be recognized in the future with continued drilling successes in Canada.

                Current income tax expense in 2004 of $5,280,000 (2003 - $2,755,000) represents income taxes of $5,269,000 (2003 - $2,755,000) incurred and paid under the laws of Yemen pursuant to the PSA on Block 32 and Block S-1 and $11,000 paid in Canada. The increase in Yemen is primarily the result of the following:

• Increased volumes mainly as a result of production start up on Block S-1. 

• Increase in oil prices. 

• An increase in the Yemen government’s share of production sharing oil on Block 32 as a result of recovery of all historical costs during Q2-2003. The Yemen government’s share of production sharing oil includes royalties and taxes.

CAPITAL EXPENDITURES/DISPOSITIONS

                Capital Expenditures

($000’s)	2004	2003
Republic of Yemen	15,275	9,012
Canada	10,100	5,217
Egypt	992	-
	26,367	14,229
Proceeds on sale of property and equipment	-	(442	)
Net capital expenditures	26,367	13,787

                Capital expenditures in 2004 are mainly comprised of the following:

Block 32, Yemen ($3,110,000)

• 3-D seismic program at Tasour, Tasour facility upgrades and drilling 3 oil wells at Tasour.

Block S-1, Yemen ($12,131,000)

• Drilling and completing of eight oil wells at An Nagyah, drilling one oil well at Harmel, drilling one D&A well at Al Hareth and costs associated with commercial development of the An Nagyah field.

Other, Yemen ($34,000)

• Mainly costs associated with obtaining Block 72 in Yemen.

Nuqra Block 1, Egypt ($992,000)

• Mainly costs associated with acquiring the Block, plus geological and geophysical costs.

Canada ($10,100,000)

• Costs mainly related to the drilling of fifteen wells (11.4 net wells) and related tie-in of seven of these wells (five gas, two oil) as part of the 2004 exploration and development program.

• Costs also related to the re-completion of four wells, of which three (two gas, one oil) came on production, and the tie-in of two wells (one gas, one oil) drilled in prior years.

• Other costs related to oil and gas lease acquisitions for future drilling associated with the 2004 and 2005 exploration and development programs.

                The dispositions of $442,000 in 2003 are related to proceeds on disposal of minor oil and gas properties in Canada for $79,000 and proceeds on disposal of seismic data in the United States for $363,000. A gain on disposition of the seismic data in the United States was recorded in other income as there is no associated cost base in this cost centre.

FINDING AND DEVELOPMENT COSTS

                Proved

($000’s, except per Boe and $/Boe amounts)	2004	2003	2002
Total capital expenditure	26,367	14,229	6,477
Net change from previous year’s future capital	8,796	2,159	634
	35,163	16,388	7,111
Reserve additions and revisions (MBoe)	4,332	2,360	1,210
Average cost per Boe	8.12	6.94	5.88
Three year average cost per Boe	7.42	6.40	6.75
Proved plus Probable
($000’s, except per Boe and $/Boe amounts)	2004	2003	2002
Total capital expenditure	26,367	14,229	6,477
Net change from previous year’s future capital	597	11,303	466
	26,964	25,532	6,943
Reserve additions and revisions (MBoe)	4,804	4,872	1,390
Average cost per Boe	5.61	5.24	4.99
Three year average cost per Boe	5.37	5.47	6.36

                The finding and development costs shown above have been calculated in accordance with Canadian National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities introduced in 2003.

                The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not refl ect total finding and development costs related to reserves additions for that year.

RECYCLE RATIO

		Three Year
Proved		Average		2004		2003		2002
Netback ($/Boe)	$	12.19	$	12.46	$	9.72	$	15.36
Proved finding and development costs ($/Boe)	$	7.42	$	8.12	$	6.94	$	5.88
Recycle ratio		1.64		1.53		1.40		2.61
		Three Year
Proved plus Probable		Average		2004		2003		2002
Netback ($/Boe)	$	12.19	$	12.46	$	9.72	$	15.36
Proved plus Probable finding and development costs ($/Boe)	$	5.37	$	5.61	$	5.24	$	4.99
Recycle ratio		2.27		2.22		1.85		3.08

                The 2004 recycle ratio was consistent with 2003. The decrease in the 2003 recycle ratio to 1.40 compared to 2002 of 2.61 mainly relates to a lower netback in Yemen in 2003 which is a result of historical cost pool allocations between partners and achieving full historical cost pool recovery during Q2 2003.

                The recycle ratio is a non-GAAP measure that measures the efficiency of TransGlobe’s capital program by comparing the cost of finding and developing proved reserves with the netback from production. The ratio is calculated by dividing the netback per Boe by the proved or proved plus probable finding and development cost on a Boe basis. Netback is defined as:

($000’s, except volumes and per Boe amounts)	2004		2003		2002
Net income	5,919		5,905		5,426
Adjustments for non-cash items:
Depletion, depreciation and accretion	10,346		6,253		4,277
Stock-based compensation	1,310		-		-
Future income taxes	(285	)	(2,448	)	(67	)
Amortization of deferred financing costs	35		-		-
Gain on sale of property and equipment	-		(363	)	-
Performance bonus expense paid in shares	-		-		74
Netback	17,325		9,347		9,710
Sales Volumes	1,389,920		961,588		632,018
Netback per Boe	12.46		9.72		15.36

OUTSTANDING SHARE DATA

                Common Shares issued and outstanding as at March 9, 2005 are 57,200,939.

FOURTH QUARTER

                During the fourth quarter of 2004, gross oil and gas sales increased 39% to $18,548,000 compared to the third quarter 2004 primarily due to sales volumes increasing 37% to 5,384 Boe per day in the fourth quarter 2004 from 3,918 Boe per day in the third quarter 2004. The increased sales volumes related primary to Block S-1 in Yemen where the Company increased trucking capacity and in Canada due to the success of the 2004 summer drilling program.

                Net operating income (revenues less royalties and operating expenses) per Boe remained consistent in the fourth quarter 2004 at $18.05 per Boe compared to $17.91 in the third quarter 2004.

                General and administrative expenses increased 204% in the fourth quarter 2004 to $680,000 compared to $224,000 in the third quarter 2004 primarily as a result increased personnel, insurance and public company costs.

                Stock-based compensation expense increased 19% to $452,000 in the fourth quarter 2004 compared to $381,000 in the third quarter 2004 due to new employee stock option grants.

                Depletion, depreciation and accretion increased 61% to $4,197,000 in the fourth quarter 2004 compared to $2,601,000 in the third quarter 2004 primarily due to increased production volumes and increased capital costs. On a Boe basis, DD&A increased 17% to $8.47 per Boe in the fourth quarter 2004 compared to $7.22 per Boe in the third quarter 2004.

                A future income tax asset was recorded in the third quarter 2004 for $1,160,000. Since a portion of the asset was utilized in the fourth quarter, the Company recorded $874,000 in future income tax expense in the fourth quarter 2004 and reduced the future income tax asset.

                During the fourth quarter 2004, the Company issued 2,910,000 shares through a public offering for net proceeds of $9,842,000 (net of costs) and entered into a new $7,000,000 loan facility.

LIQUIDITY AND CAPITAL RESOURCES

                Funding for the Company’s capital expenditures in 2004 was provided by cash flow from operations, working capital and equity financing.

                At December 31, 2004 the Company had working capital of $2,839,000, zero debt and an unutilized loan facility of $7,000,000. Working capital remained consistent with the prior year. Accounts receivable increased due primarily to Block S-1, Yemen, revenue receivables. This was offset by increased accounts payable due primarily to increased capital expenditures in late 2004 related to the An Nagyah facility and pipeline at Block S-1, Yemen, and increased operating activity in Canada.

                The Company expects to fund its 2005 exploration and development program (budgeted at $32 million firm and contingent) through the use of working capital, cash flow and debt. The use of our credit facilities during 2005 is expected to remain within conservative guidelines of a debt to cash flow ratio of less than 0.5:1. The Company raised $9.8 million (net after costs) on a bought deal equity financing in November and December 2004 to partially fund the Egyptian, Yemen and Canadian exploration program. This amount is included in the working capital at December 31, 2004. Equity financing may be utilized in the future to accelerate existing projects or to finance new opportunities. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources.

                In December 2003, the Company issued flow through shares with terms providing that the Company renounce Canadian tax deductions in the amount of C$3,000,000 to subscribers with the entire amount to be expended by the Company by December 31, 2004. As at December 31, 2004 the Company has fulfilled this expenditure commitment.

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:

($000’s)	2005	2006	2007	2008	2009
Office and equipment leases	191	243	235	328	348

                In June 2004, the Company entered into a one year fixed price contract to sell 10,000 barrels of oil per month in Block 32 commencing July 1, 2004 at $33.90 per barrel for dated Brent plus or minus the Yemen Government’s official selling price differential.

                In December 2003, the Company issued flow through shares with terms providing that the Company renounce Canadian tax deductions in the amount of C$3,000,000 to subscribers with the entire amount to be expended by the Company by December 31, 2004. The Company has fulfilled this expenditure commitment.

                Pursuant to the Company’s farm-in agreement on the Nuqra Concession in Egypt, the Company is committed to spend $6 million over the next 5 years to earn its 50% working interest. As part of this commitment the Company issued a $2 million letter of credit on July 8, 2004 to Ganoub El Wadi Holding Petroleum Company which expires on February 14, 2007. This letter of credit is secured by a guarantee granted by Export Development Canada.

                Upon the determination that proved recoverable reserves are 40 million barrels or greater for Block S-1, Yemen, the Company will be required to pay a finders’ fee to third parties in the amount of $281,000.

CRITICAL ACCOUNTING POLICIES

                The preparation of financial statements in accordance with generally accepted accounting principles requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. The following is included in MD&A to aid the reader in assessing the critical accounting policies and practices of the Company. The information will also aid in assessing the likelihood of materially different results being reported depending on management’s assumptions and changes in prevailing conditions which affect the application of these policies and practices. Significant accounting policies are disclosed in Note 1 of the consolidated financial statements.

                Oil and Gas Reserves

                TransGlobe’s proved and probable oil and gas reserves are 100 percent evaluated and reported on by independent petroleum engineering consultants. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to refl ect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.

                Full Cost Accounting for Oil and Gas Activities

                Depletion and Depreciation Expense
                TransGlobe follows the Canadian Institute of Chartered Accountants’ guideline on full cost accounting in the oil and gas industry to account for oil and gas properties. Under this method, all costs associated with the acquisition of, exploration for, and the development of natural gas and crude oil reserves are capitalized on a country-by-country cost centre basis and costs associated with production are expensed. The capitalized costs are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves. Reserve estimates can have a significant impact on earnings, as they are a key component in the calculation of depreciation, depletion and amortization. A downward revision in a reserve estimate could result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserve estimates (see asset impairment discussion below), the excess must be written off as an expense charged against earnings. In the event of a property disposition, proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20 percent or greater.

                Unproved Properties
                Certain costs related to unproved properties and major development projects are excluded from costs subject to depletion and depreciation until the earliest of a portion of the property becomes capable of production, development activity ceases or impairment occurs. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.

                Asset Impairments
                Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized costs in each cost centre do not exceed their fair value. An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than carrying amount, the impairment loss is limited to an amount by which the carrying amount exceeds the sum of:

                 i) the fair value of reserves; and
                 ii) the costs of unproved properties that have been subject to a separate impairment test.

                Income Tax Accounting
                The Company has recorded a future income tax asset in 2003 and 2004. This future income tax asset is an estimate of the expected benefit that will be realized by the use of deductible temporary differences in excess of carrying value of the Company’s Canadian property and equipment against future estimated taxable income. These estimates may change substantially as additional information from future production and other economic conditions such as oil and gas prices and costs become available.

                Currency Translation
                The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at year-end exchange rates, and revenues and expenses are translated using average annual rates. Translation gains and losses relating to the self-sustaining operations are included as a separate component of shareholders’ equity.

                Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings.

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

                Asset Retirement Obligations
                Effective January 1, 2004 the Company retroactively adopted the Canadian Institute of Chartered Accountants (“CICA”) section 3110, “Asset Retirement Obligations”. The new recommendations require the recognition of the fair value of obligations associated with the retirement of tangible long-lived assets be recorded in the period the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is accreted over time for changes in the fair value of the liability through charges to accretion expense which is included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and depreciation of the underlying asset. Previously the Company used the unit-of-production method to match estimated future retirement costs with revenues generated from producing assets. Note 2a discloses the impact of the adoption of CICA section 3110 on the financial statements.

                Property and Equipment
                 Effective January 1, 2004 the Company adopted Accounting Guideline 16, “Oil and Gas Accounting - Full Cost” (“AcG-16”), which replaces Accounting Guideline 5, “Full Cost Accounting in the Oil and Gas Industry”. AcG-16 modifies how the ceiling test is performed and is consistent with CICA section 3063, “Impairment of Long-lived Assets”. The recoverability of a cost centre is tested by comparing the carrying value of the cost centre to the sum of the undiscounted cash flows expected from the cost centre’s use and eventual disposition. If the carrying value is unrecoverable the cost centre is written down to its fair value. This approach incorporates risks and uncertainties in the expected future cash flows which are discounted using a risk free rate. The adoption of AcG-16 had no effect on the Company’s financial results.

                Impairment of Long Lived Assets
                 Effective January 1, 2004 the Company adopted CICA section 3063, “Impairment of Long-lived Assets”, which had no effect on the consolidated financial statements.

                Stock-based Compensation
                 Effective January 1, 2004 the Company adopted the new accounting standard of CICA section 3870, “Stock-based Compensation and Other Stock-based Payments”, retroactively without restatement of prior periods. This Canadian accounting standard requires the Company to record a compensation expense over the vesting period based on the fair value of options granted to employees and directors since January 1, 2002. Note 2d discloses the impact of the adoption of CICA section 3870 on the financial statements.

                Currency Translation
                 As a result of the increase in cash flow from Canadian operations, the Company reviewed its accounting practices for operations in Canada and determined that such operations are self-sustaining. The accounts of self-sustaining Canadian operations are translated using the current rate method, whereby assets and liabilities are translated at period-end exchange rates and revenues and expenses are translated using average rates for the period. Translation gains and losses relating to the operations are deferred and included as a separate component of shareholders’ equity. Note 2e discloses the impact of the change in accounting practise related to currency translation.

                Previously, Canadian operations were considered to be integrated and translated using the temporal method. Under the temporal method, monetary assets and liabilities were translated at the period end exchange rate, other assets and liabilities at the historical rates and revenues and expenses at the average monthly rates except depreciation, depletion and amortization, which were translated on the same basis as the related assets.

                Accounting for Derivative Instruments and Hedging Activities
                 Effective January 1, 2004 the Company adopted CICA Accounting Guideline 13, “Hedging Relationships” (“AcG-13”). AcG-13 has essentially the same criteria to be satisfied before the application of hedge accounting is permitted as the corresponding requirements of the Financial Accounting Standards Board (“FASB”) Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“FAS 133”).

                This accounting standard requires that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded on the balance sheet as either an asset or liability measured at fair value. These standards further establish that changes in the fair value be recognized currently in earnings unless the arrangement can meet the “effective hedge” criteria. The adoption of AcG-13 had no effect on the Company’s financial results.

NEW ACCOUNTING STANDARDS

                On November 1, 2004, a new CICA Accounting Guideline AcG-15 “Consolidation of Variable Interest Entities” was introduced. AcG-15 defines a variable interest entity (“VIE”) as a legal entity in which either the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by other parties or the equity owners lack a controlling financial interest. The guideline requires the enterprise which absorbs the majority of a VIE’s expected gains or losses, the primary beneficiary, to consolidate the VIE.

                The adoption of AcG-15 is expected to have no effect on the Company’s financial results.

RISKS

                The Company is exposed to a variety of business risks and uncertainties in the international petroleum industry including commodity prices, exploration success, production risk, foreign exchange, interest rates, government regulation, changes of laws affecting foreign ownership, political risk of operating in foreign jurisdictions, taxes, environmental preservation and safety concerns.

                Many of these risks are not within the control of management, but the Company has adopted several strategies to reduce and minimize the effects of these factors:

• The Company applies rigorous geological, geophysical and engineering analysis to each prospect. 

• The Company utilizes its in-house expertise for all international ventures and employs and contracts professionals to handle each aspect of the Company’s business. 

• The Company maintains U.S. dollar bank accounts which is its main operating currency. 

• The Company maintains a conservative approach to debt financing and currently has no long-term debt. 

• The Company maintains insurance according to customary industry practice, but cannot fully insure against all risks. 

• The Company conducts its operations to ensure compliance with government regulations and guidelines. 

• The Company retains independent petroleum engineering consultants to determine year-end Company reserves and estimated future net revenues.

• The Company manages commodity prices by entering physical fixed price sales contracts when deemed appropriate. 

OUTLOOK

                2005 Production Outlook

		2005	2004	Change (*)
Barrels of oil equivalent (6:1)	Boepd	5,800 to 6,200	3,796	58%

(*) % growth based on mid point of guidance

                2005 Cash Flow From Operations Outlook

($000’s)	2005(*)	2004	Change (*)
Cash flow from operations	32,000	17,325	85%

(*) Based on an average of 6,000 Boepd, a dated Brent oil price of $38.00/Bbl and an AECO gas price of C $6.00/Mcf.

	2005 Cash Flow
Sensitivity	from
	Operations
($ 000’s)	Increase
$1.00 per barrel increase in dated Brent	815
C$0.10 per Mcf increase in AECO	120

2005 Capital Budget
($000’s)	2005
Canada	9,000
Yemen   - Block S1	11,000
- Block 32	4,000
- Block 72	2,000
Egypt	5,600
Other	400
Total	32,000

                TransGlobe plans to continue increasing crude oil production on Block 32 and Block S-1 in Yemen and natural gas production in Canada to deliver near term growth, with Block 72 in Yemen contributing to medium term growth and Nuqra Block 1 in Egypt adding to longer term growth. For the near term growth, the Company expects to drill 15 wells in Yemen during 2005 of which 7 wells will be development wells and 8 wells will be exploration wells. In Canada, the Company plans on drilling 15 wells during 2005 split evenly between development and exploration wells. The Company attaches a significantly higher risk to the exploratory wells. The 2005 capital budget of $32 million is expected to be funded from working capital, cash flow and debt. Equity financing may be utilized in the future to accelerate existing projects or to finance new opportunities.

Management’s Report

                The consolidated financial statements of TransGlobe Energy Corporation were prepared by management within acceptable limits of materiality and are in accordance with Canadian generally accepted accounting principles. Management is responsible for ensuring that the financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements.

                The consolidated financial statements have been prepared by management in accordance with the accounting policies as described in the notes to the consolidated financial statements. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. When necessary, such estimates are based on informed judgements made by management.

                Management has designed and maintains an appropriate system of internal controls to provide reasonable assurance that all assets are safeguarded and financial records properly maintained to facilitate the preparation of consolidated financial statements for reporting purposes.

                Deloitte & Touche LLP, an independent firm of Chartered Accountants appointed by the shareholders, have conducted an examination of the corporate and accounting records in order to express their opinion on the consolidated financial statements. The Audit Committee, consisting of three independent directors, has met with representatives of Deloitte & Touche LLP and management in order to determine if management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The Board of Directors has approved the consolidated financial statements.

Ross G. Clarkson	David C. Ferguson
President &	Vice President, Finance &
Chief Executive Officer	Chief Financial Officer
March 9, 2005