A N N U A L   M E E T I N G

TransGlobe Energy Corporation will hold its Annual Meeting on Wednesday, May 7, 2008 at 3:00 p.m. in the Viking Room at the Calgary Petroleum Club, 319 - 5th Avenue S.W., Calgary, Alberta, Canada.

C O N T E N T S

Highlights	Page 1
Message to Shareholders	Page 2
Operations Review	Page 5
Management’s Discussion and Analysis	Page 18
Consolidated Financial Statements	Page 39
Corporate Governance	Page 63
Supplementary Information	Page 64
Corporate Information	Inside Back Cover

This annual report 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. Such statements relate to possible future events. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Although TransGlobe’s forward-looking statements are based on the beliefs, expectations, opinions and assumptions of the Company’s management on the date the statements are made, such statements are inherently uncertain and provide no guarantee of future performance. Actual results may differ materially from TransGlobe’s expectations as reflected in such 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 properties, changes in price of crude oil and natural gas, adverse technical factors associated with exploration, development, production or transportation of TransGlobe’s crude oil and natural gas reserves, changes or disruptions in the political or fiscal regimes in TransGlobe’s areas of activity, changes in tax, energy or other laws or regulations, changes in significant capital expenditures, delays or disruptions in production due to shortages of skilled manpower, equipment or materials, economic fluctuations, and other factors beyond the Company’s control. TransGlobe does not assume any obligation to update forward-looking statements if circumstances or management’s beliefs, expectations or opinions should change, and investors should not attribute undue certainty to, or place undue reliance on, any forward-looking statements. Please consult TransGlobe’s public filings at www.sedar.com and www.sec.gov/edgar.shtml for further, more detailed information concerning these matters.

T R A N S G L O B E  E N E R G Y  C O R P O R AT I O N

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H I G H L I G H T S :

• Created record cash flow of $52 million

• Increased P+P reserves by 41% to 16.5 MMBoe

• Acquired 2,500 Bopd of production in Egypt and became operator

• Listed on the NASDAQ Global Select Market under the symbol TGA

• Decided on divestiture of Canadian assets to focus solely on international opportunities

P R O D U C T I O N  G R O W T H
Boed

 

Throughout the text of this annual report and consolidated financial statements, all dollar values are expressed in United States dollars unless otherwise stated.

In this document, TransGlobe Energy Corporation (“TransGlobe” or the “Company”) applies the widely used Boe conversion ratio of six thousand cubic feet (“Mcf”) to one barrel (“Bbl”). Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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M E S S A G E  T O  S H A R E H O L D E R S

As we close another successful and active year for TransGlobe, we are proud of our achievements in 2007 and confidently look towards 2008.

TransGlobe is a strong exploration and production company, focused on Middle East assets, currently Egypt and Yemen. Our mid-term objective is to reach a production level of 10,000 Bopd. We can achieve this goal through the drill bit, and may consider targeted acquisitions.

Until this year, TransGlobe’s strategy for growth focused on the operated Canadian properties for lower-risk, moderate-reward, and the non-operated Yemen properties for higher-risk, higher-reward opportunities. It has always been our intention to acquire an operated asset in the Middle East as the next step in building the Company. We started a search for an operated venture in the Middle East several years ago and closed our first acquisition of producing properties at West Gharib in Egypt in September 2007. A follow-up acquisition in February 2008 consolidated our interest in the properties.

Operating our own assets provides several distinct advantages. It allows us to control the pace of drilling. It raises our profile in the area - in this case, the extensive area known as West Gharib in Egypt - and gives us better access to opportunities.

With a fully staffed Egyptian operation, we are already well underway to improve operating efficiencies and to accelerate our drilling program.

Our debt facilities were significantly expanded to complete the Egyptian acquisitions. Utilizing debt avoided issuing shares and diluting our shareholders; on the other hand, the use of debt exposes the Company to commodity-price risk and higher interest charges. TransGlobe mitigates commodity-price risk through the use of oil hedges.

Our policy is to employ debt for acquisitions and development activities and maintain a low debt-to-cash-flow ratio. Accordingly, we decided to sell all our Canadian assets in order to strengthen the balance sheet and to focus capital and human resources on our promising Middle East assets. We believe these assets provide a better return at a faster growth rate than the Canadian assets.

Complete divestiture of all the Company’s Canadian assets will be completed early in 2008. This decision will have a major impact on the Company: From a financial standpoint, it allows us to bring our finances back to a less leveraged position, which in turn gives the flexibility to act upon new opportunities. As well, and more importantly, it gives us the ability to leverage our existing skill sets, with more control over process and timing, and upon assets with larger and more immediate returns.

Y E M E N  &  E G Y P T  O I L  P R I C I N G

 

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I believe that by concentrating our investment of funds and human resources on our international assets, we are creating a stronger, more focused company with an enviable land package, financial strength, and technical excellence.

We believe the West Gharib properties represent a significant upgrade in our asset base in the Middle East. Egypt was chosen for its low-risk development potential, exploration upside, and the opportunity to acquire a proven team of Egyptian staff; this allowed us to hit the ground running. Our analysis of the assets showed them to be undercapitalized and in need of a technical retrofit. Only two months into 2008, we are seeing proof that this was a good decision: we have already added 500 Bopd of production, discovered one new productive zone, and one new pool. We hope to add a total of 2,000 Bopd to the 3,000 Bopd we started with. Achieving this ambitious target will depend upon TransGlobe getting a third rig. The wheels have been set in motion, and we anticipate this rig to arrive in July 2008.

We are currently investigating the implementation of various technical and operational improvements, which would extend both reserve life and recovery rates. The Hoshia and Hana fields both show great promise for improvement of oil recoveries. We are investigating the application of certain techniques that are regularly utilized in North America: ASP (alkaline surfactant polymer) flooding and water flooding. If our studies show the reservoirs to be candidates for either of these techniques, oil recoveries may be doubled or more.

In addition, we will be drilling 15 appraisal and exploration wells, and acquiring large areas of 3-D seismic to identify new targets. If a suitable rig can be procured, we will drill at Nuqra again, to follow up on the oil discovery on the lands adjacent to our block.

Turning our attention to Yemen, the Company is eagerly anticipating Yemeni government approval for the development of An Naeem natural gas. These extensive gas reserves were discovered in 2000 and in total could represent a doubling of TransGlobe’s reserves (once they could be booked in their entirety).

In the first quarter of 2008 we are completing a large 3-D seismic survey on Block 72 in Yemen, which is expected to define several drilling prospects for the second half of the year. In early March 2008, the Production Sharing Agreement (“PSA”) for Block 75 was ratified. We expect to commence shooting a large 3-D seismic survey on this area some time in 2008. As for Block 84, we are still waiting for parliamentary approval and ratification of the PSA. The results will provide TransGlobe with numerous drilling opportunities going forward.

The ultimate key to our success will be our people.

TransGlobe employs over 80 Egyptian staff at its operations, including a recently hired new Country Manager for Egypt who has over 20 years of Egyptian experience and an excellent reputation in the country. In Canada, we hired geological, geophysical and engineering staff to bring new talent to work these assets.

We can already see an extraordinary synergy developing between our Egyptian and Canadian teams that is energizing both offices.

All in all, it appears that 2008 will be a very important year in our continued quest for growth and success. I would like to thank the Board of Directors and all members of staff for their hard work and valuable contributions to the Company. The transition to operatorship has required personal sacrifice and dedication from every one involved. We are excited about our Company’s possibilities, and with the great teams now in place, we will make it happen.

Ross G. Clarkson
President, CEO and Director

March 13, 2008

R O S S  G .  C L A R K S O N
President, CEO and Director

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L L OY D W. H E R R I C K
Vice President, COO and Director

O P E R AT I O N S  R E V I E W

I N T E R N AT I O N A L  A C T I V I T Y

TransGlobe’s first international property was acquired in the Republic of Yemen (“Yemen”) in January 1997, through a farm-out and joint venture agreement on Block 32. During the past 11 years, TransGlobe has consistently grown its international portfolio in the Middle East North African region (“MENA”) to an impressive 6.8 million acres (3.1 million net acres) in the Arab Republic of Egypt (“Egypt”) and Yemen.

Through TransGlobe’s wholly-owned subsidiary, TransGlobe Petroleum International Inc. (“TGPI”), the Company has interests in seven production sharing agreements (“PSAs”) in the MENA region, two in Egypt and five in Yemen.

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

I N T E R N AT I O N A L  ( E G Y P T  A N D  Y E M E N )
S U M M A RY  O F  P R O D U C T I O N  S H A R I N G  A G R E E M E N T S

Country	Egypt				Yemen
Block	West Gharib	Nuqra #1	32	72	84	S-1	75
Basin	Gulf of Suez	Nuqra	Masila	Masila	Masila	Marib	Marib
Year acquired	2007	2004	1997	2004/2005	2006/2007***	1998	2007
Status	Development	Exploration	Development	Exploration	Exploration	Development	Exploration
Operator	TransGlobe	TransGlobe	DNO	DNO	DNO	OXY	OXY
TransGlobe WI (%)	100%*	50%**	13.81087%	33%	33%	25%	25%
Block Area (km2)	214	22,500	591	1,822	731	1,152	1,050
Block Area (acres)	52,900	5,500,000	146,070	450,234	183,000	284,700	262,500
Expiry date(s)	2019-26	July 2009	2020	Jan. 2009	N/A	2023	N/A
Extensions:
Exploration	N/A	2nd Extension	N/A	2nd Phase	1st Phase	N/A	2nd Phase
		36 months		36 months	42 months		36 months

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

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The Company is the operator of two production sharing concessions in Egypt. TransGlobe’s first project in Egypt, Nuqra Block 1, is a large exploration concession located in Upper Egypt. The recently acquired West Gharib property is a development concession located in the prolific Gulf of Suez (“GOS”) basin.

H I G H L I G H T S - E G Y P T

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

2 0 0 7  A C T I V I T I E S  A N D  R E S U LT S

During 2007, the Company significantly expanded operations in Egypt with the acquisition of the West Gharib Concession (September 25) and drilled the first two exploration wells on the Nuqra concession in Upper Egypt.

• Acquisitions - On September 25, 2007, TGPI acquired all of the shares of Dublin International Petroleum (Egypt) Limited (“Dublin International”) and Drucker Petroleum Inc. (“Drucker”) for US$59.0 million, plus working capital adjustments, as at July 1, 2007. Dublin and Drucker together hold a 70% working interest in the West Gharib Production Sharing Concession (“PSC”). TransGlobe has assumed operatorship of the West Gharib properties. The West Gharib PSC is located onshore in the western Gulf of Suez rift basin of Egypt. Major oil and gas discoveries have been made in this prolific basin. To date, eight billion barrels of oil and five trillion cubic feet of gas have been discovered. The eight approved West Gharib development leases encompass 178 square kilometers (approximately 44,059 acres) and are valid for 20 years, expiring between 2019 and 2026. One additional development lease at East Hoshia was subsequently approved by the Egyptian Petroleum Minister on January 31, 2008. Eight of the nine development leases (excluding the Hana development lease) are encumbered with a 25% financial interest through an investment agreement between Dublin and a private company. The 25% financial interest is non-voting but otherwise is treated as a 25% participating interest partner.

• Acquisitions - On February 5, 2008, TGPI acquired all of the shares of GHP Exploration (“GHP”) for US$40.2 million, plus working capital adjustments with an effective date of September 30, 2007. GHP holds a 30% working interest in the West Gharib PSC. Following the acquisition of GHP, TransGlobe holds a 100% working interest in the West Gharib PSC, with a working interest of 100% in the Hana development lease and an effective working interest of 75% in the eight non-Hana development leases.

• Consolidated the TransGlobe Egypt and Dublin International Cairo offices and hired an expatriate as Country Manager in Egypt.

• Expanded the Calgary head office technical team to focus on the West Gharib PSC.

• Two wells were drilled on West Gharib during the fourth quarter, resulting in a potential multi-zone oil well in the Hana field and an exploration dry hole on the Hoshia lease. A new development oil well was drilled in the Hana field subsequent to year end. The two new wells at Hana were placed on production in late February, increasing production by approximately 500 Bopd to TransGlobe.

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• Two exploration wells were drilled on the Nuqra block in Upper Egypt resulting in two dry holes. The successful identification of a 460-meter (1,500-foot) interval of mature source rocks in the shallower Cretaceous section of the Narmer #1 exploration well and the discovery of oil on a non-owned block by Dana Gas in the Cretaceous section of Al Baraka #1 on the west side of the Nile has encouraged the Company to continue with additional exploration drilling on the Nuqra Block.

2 0 0 7  D R I L L I N G  A C T I V I T I E S

	W. I. %	Gross wells	Oil	Dry
West Gharib	70 *	2	1	1
Nuqra	50 *	2	-	2
Total		4	1	3

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

2 0 0 7  P R O D U C T I O N

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

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

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W E S T  G H A R I B  P R O D U C T I O N  B Y  Q U A RT E R  ( B o p d )

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

*	Production presented represents 6 days production averaged over the quarter.
**	Under the terms of the West Gharib CSA, royalties, other and taxes are paid out of the government’s share of production sharing oil.

2 0 0 8  O U T L O O K

The Company has budgeted $33.3 million for Egypt in 2008, with $24.3 million (73%) allocated to development and $9.0 million (27%) allocated to exploration. With the addition of West Gharib in 2007, the primary focus in Egypt will shift to the appraisal and development of West Gharib in 2008 and 2009.

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

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

2 0 0 8  C A P I TA L  P R O G R A M

	2008 Budget	Wells	Wells
Firm & Contingent	$ Millions	Exploration	Development	Seismic
West Gharib	29.1	2	16	300+ Km2 new 3-D
Nuqra	4.2	1	-
Total	33.3	3	16	300+ Km2 new 3-D

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

H I G H L I G H T S  -  Y E M E N

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

2 0 0 7  A C T I V I T I E S  A N D  R E S U LT S

During 2007, the Company participated in 13 wells, a new 3-D seismic acquisition program, facility expansions at An Nagyah, Tasour and Godah.

• On Block 32, the operator drilled four oil wells, two exploratory dry holes, and completed the expansion of facilities at the Tasour and Godah central production facilities (“CPF”).
• On Block S-1, the operator drilled six oil wells, re-entered one gas well and completed the An Nagyah CPF expansion. In addition, the operator proposed to the Ministry of Oil and Minerals (“MOM”) that natural gas from An Naeem be injected into the western portion of the An Nagyah pool. The planned gas injection will provide additional pressure support in the western portion of the field to improve production performance and increase recoverable reserves. Subject to MOM approval, gas injection could commence in 2008 when a 25-km pipeline from An Naeem to the An Nagyah CPF is completed.

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• On Block 72, the operator drilled one exploration well (dry) and commenced a 410 km² 3-D seismic acquisition program, which will be completed in early 2008.
• On the new exploration Blocks 75 and 84, the respective PSAs were signed and submitted to MOM and the Government of Yemen for approval and ratification. The Block 75 PSA was ratified on March 8, 2008; it is expected the Block 84 PSA will be approved later in 2008.

D R I L L I N G  A C T I V I T I E S

	W. I. %	Gross wells	Oil	Dry
Block 32	13.8	6	4	2
Block S-1	25.0	6	6	-
Block 72	33.0	1	-	1
Total		13	10	3

2 0 0 7  P R O D U C T I O N

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

B L O C K  3 2  P R O D U C T I O N  B Y  Q U A RT E R  ( B o p d )

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

*        Under the terms of the Block 32 PSA, royalties, other and taxes are paid out of the government’s share of production sharing oil.

T R A N S G L O B E  E N E R G Y  C O R P O R AT I O N

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

B L O C K  S - 1  P R O D U C T I O N  B Y  Q U A R T E R  ( B o p d )

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

*        Under the terms of the Block S-1 PSA, royalties, other and taxes are paid out of the government’s share of production sharing oil.

2 0 0 8  O U T L O O K

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

In addition to the planned capital program, the Block S-1 Joint Venture group is also considering possibilities for a gas sales agreement utilizing known deposits of gas on S-1. At present, TransGlobe has not booked the significant gas reserves associated with the An Naeem discovery. An approved gas development plan is required prior to recognizing the reserves and proceeding with development.

2 0 0 8  C A P I T A L  P R O G R A M

	2008 Budget	Wells	Wells
Firm & Contingent	$ Millions	Exploration	Development	Seismic
Block 32	3.8	3	3
Block S-1	8.7	-	3	200+ Km2 new 3-D
Block 72	5.7	2	-	410 Km2 new 3-D commenced Q4,07
Block 75	1.8	-	-	200+ Km2 new 3-D
Block 84	3.8	-	-	400+ Km2 new 3-D
Total	23.8	5	6	1,200+ Km2 new 3-D

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S U M M A R Y  O F  I N T E R N A T I O N A L  P S A  T E R M S

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

The PSAs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSA. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Each PSA is ring-fenced for cost recovery and production sharing purposes. The remaining production sharing oil (total production, less gross royalty, less cost oil) is shared between the government and the contractor as defined in the specific PSAs.

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

P S A  T E R M S  -  E G Y P T  A N D  Y E M E N
( O i l  P r o d u c t i o n :  F i r s t  P r o d u c t i o n  Tr a n c h e )

Country	Egypt		Yemen
	West		32*
Block	Gharib	Nuqra #1	(original)	72	84	S-1	75
First Tranche	0 - 5	0-25	0-25	0-25	0-25	0-12.5	0-25
(MBopd)
Gross Royalty %	0%	0%	3%/(10%)	3%	6.5%	3%	3%
Max. Cost Oil %	30%	40%	60%/(25%)	50%	35%	50%	50%
Excess Cost Oil	Prod.	Prod.	Prod.	Prod.	Prod.	Prod.	Prod.
	Sharing	Sharing	Sharing	Sharing	Sharing	Sharing	Sharing
Depreciation per
Quarter
Operating	100%	100%	100%	100%	100%	100%	100%
Capital	6.25%	6.25%	12.5%	12.5%	8.333%	12.5%	12.5%
Production
Sharing Oil:
Contractor	30%	30%	33.3%/	32.4%	23.98%	28.9%	34.2%
			(23%)
Government	70%	70%	66.8%/	67.6%	76.02%	71.1%	65.8%
			(77%)

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

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C A N A D A

D I V E S T I T U R E S

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

H I G H L I G H T S

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

2 0 0 7  A C T I V I T I E S  A N D  R E S U LT S

The Company drilled 15 gas wells in the Nevis, Thorsby and Morningside areas in central Alberta.

2 0 0 7  P R O D U C T I O N

Production averaged 1,394 Boepd during 2007. The average production during January and February was approximately 1,492 Boepd.

C A N A D I A N  P R O D U C T I O N  B Y  Q U A R T E R  ( B o e p d )

	Q-1	Q-2	Q-3	Q-4
TransGlobe working interest	1,283	1,389	1,397	1,504
TransGlobe net (after royalties)	1,039	1,144	1,175	1,250

R E S E R V E S  A N D  E S T I M A T E D  F U T U R E  N E T  R E V E N U E S

In 2006 and 2007, DeGolyer and MacNaughton Canada Limited (“DeGolyer”) of Calgary, Alberta, independent petroleum engineering consultants based in Calgary and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company’s Reserves Committee, to independently evaluate 100% of TransGlobe’s reserves as at December 31, 2006 and December 31, 2007.

Total proved reserves for the Company increased 27% from 9,340 MBoe (“MBoe” is thousand barrels of oil equivalent at 6:1) at December 31, 2006 to 11,866 MBoe at December 31, 2007 replacing 222% of the 2,065 MBoe produced during 2007.

Total proved plus probable reserves for the Company increased by 41% from 11,651 MBoe at December 31, 2006 to 16,389 MBoe at December 31, 2007 replacing 330% of 2007 production.

Increases in proved and proved plus probable reserves were primarily associated with the acquisition of two private companies (Dublin and Drucker, announced September 26, 2007 Press Release) with interests in the West Gharib Concession in Egypt. These acquisitions were completed on September 25, 2007.

The Company’s Reserves Committee, comprised of independent directors, has reviewed and recommended acceptance of the 2007 year end reserve evaluations prepared by DeGolyer.

The 2006 and 2007 year end reserves were prepared by the Company’s independent reserve evaluators in accordance with the Canadian National Instrument (NI) 51-101 policy introduced in 2003.

Disclosure provided herein in respect of Boe 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.

The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than, or less than, the estimates provided herein. Note that columns may not add due to rounding.

13

All reserves (gross and net) presented are based on Forecast Pricing.

R E S E R V E S

					2007						2006
	Light &		Heavy		Natural		Natural Gas		Total		Total
	Medium Oil		Oil		Gas		Liquids		2007 Boe		2006 Boe
Company by	Gross*	Net**	Gross*	Net**	Gross*	Net**	Gross*	Net**	Gross*	Net**	Gross*	Net**
Category	MBbls	MBbls	MBbls	MBbls	MMcf	MMcf	MBbls	MBbls	Mboe	Mboe	Mboe	Mboe
Proved
Producing	4,467	2,373	2,145	1,199	7,454	6,153	166	120	8,020	4,718	5,957	3,699
Non-Prod	302	188	141	77	1,996	1,726	41	28	817	581	1,051	740
Undevel	2,294	1,244	509	291	1,257	1,039	17	11	3,029	1,719	2,332	1,322
Total Proved	7,063	3,805	2,795	1,566	10,708	8,918	224	160	11,866	7,018	9,340	5,762
Proved +
Probable	8,129	4,407	5,106	2,816	16,467	13,703	410	288	16,389	9,795	11,651	7,339

*

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

**

Net reserves are the Company’s working interest share after deduction of royalties. Net reserves in Egypt and Yemen include our share of future cost recovery and production sharing oil after the government’s royalty interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.

R E S E R V E S

			2007				2006
	Oil & Liquids		Gas		Total Boe		Total Boe
Company	Gross	Net	Gross	Net	Gross	Net	Gross	Net
By Area	(MBbls)	(MBbls)	(MMcf)	(MMcf)	(Mboe)	(Mboe)	(Mboe)	(Mboe)
Proved
Egypt	2,795	1,566	-	-	2,795	1,566	-	-
Yemen	6,567	3,362	-	-	6,567	3,362	7,048	3,887
Canada	719	603	10,708	8,918	2,504	2,089	2,292	1,874
Total Proved	10,082	5,532	10,708	8,918	11,866	7,018	9,340	5,762
Proved plus Probable
Egypt	5,106	2,816	-	-	5,106	2,816	-	-
Yemen	7,470	3,819	-	-	7,470	3,819	7,999	4,387
Canada	1,068	876	16,467	13,703	3,813	3,160	3,652	2,952
Total Proved plus Probable	13,644	7,511	16,467	13,703	16,389	9,795	11,651	7,339

P R O V E D  R E S E R V E S  R E C O N C I L I AT I O N

	Egypt	Yemen	Canada		Total
	Oil	Oil	Oil & Liquids	Natural Gas	Boe
	Gross	Gross	Gross	Gross	Gross
	(MBbls)	(MBbls)	(MBbls)	(MMcf)	(Mboe)
Reserves at December 31, 2006	-	7,048	624	10,005	9,340
Extensions/Discoveries	-	-	164	2,946	655
Technical revisions	-	915	78	(58)	984
Acquisitions	2,952*	-	-	-	2,952
Divestitures	-	-	-	-	-
Economic factors	-	-	-	-	-
Production	(158)	(1,396)	(147)	(2,185)	(2,065)
Reserves at December 31, 2007	2,795	6,567	719	10,708	11,866

* Acquired September 25, 2007.

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P R O V E D  P L U S  P R O B A B L E  R E S E R V E S  R E C O N C I L I AT I O N

	Egypt	Yemen	Canada		Total
	Oil	Oil	Oil & Liquids	Natural Gas	Boe
	Gross	Gross	Gross	Gross	Gross
	(MBbls)	(MBbls)	(MBbls)	(MMcf)	(Mboe)
Reserves at December 31, 2006	-	7,999	970	16,095	11,651
Extensions/Discoveries	-	-	208	3,501	792
Technical revisions	-	867	38	(944)	748
Acquisitions	5,263*	-	-	-	5,263
Divestitures	-	-	-	-	-
Economic factors	-	-	-	-	-
Production	(158)	(1,396)	(147)	(2,185)	(2,065)
Reserves at December 31, 2007	5,106	7,470	1,068	16,467	16,389

* Acquired September 25, 2007.

E S T I M AT E D  F U T U R E  N E T  R E V E N U E S

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

The estimated future net revenues presented below are calculated using the average price received December 31 of the respective reporting periods. The prices were held constant for the life of the reserves.

		Present Value of Future Net Revenues, Before Income Tax*
		Constant Pricing
		December 31, 2007					December 31, 2006
		Discounted at					Discounted at
	Undis-					Undis-
($MM)	counted	5%	10%	15%	20%	counted	5%	10%	15%	20%
Proved
Egypt*	60.6	52.5	46.0	40.9	36.7	-0	-0	-0	-0	-0
Yemen *	144.6	122.5	105.8	92.8	82.6	94.3	80.4	69.8	61.5	54.9
Canada **	74.4	62.6	53.7	46.9	41.5	48.8	42.3	37.2	33.1	29.7
Total Proved	279.6	237.5	205.6	180.7	160.7	143.1	122.7	107.0	94.6	84.6
Proved plus Probable
Egypt*	104.4	86.9	73.8	63.8	56.0	-0	-0	-0	-0	-0
Yemen *	166.8	139.6	119.3	103.8	91.7	105.5	89.1	76.7	67.1	59.5
Canada **	120.5	95.3	78.3	66.0	56.8	76.3	62.6	52.7	45.3	39.5
Total Proved plus
Probable	391.7	321.7	271.4	233.7	204.4	181.8	151.7	129.4	112.4	99.0

*	Egypt and Yemen future net revenues presented are after Yemen and Egypt income tax respectively.
**	Canadian values converted at the December 31, 2007 and December 31, 2006 exchange rates of 0.9843 and 1.1654 US$/C$ respectively.

15

	Present Value of Future Net Revenues, Before Income Tax*
	Independent Evaluator’s Price Forecast
		December 31, 2007					December 31, 2006
		Discounted at					Discounted at
	Undis-					Undis-
($MM)	counted	5%	10%	15%	20%	counted	5%	10%	15%	20%
Proved
Egypt*	53.5	46.6	41.1	36.6	32.9	-	-	-	-	-
Yemen *	125.4	107.4	93.6	82.7	74.0	94.2	81.1	71.0	63.0	56.5
Canada **	68.0	57.7	49.9	43.8	38.9	63.6	55.3	48.7	43.4	39.0
Total Proved	246.9	211.7	184.6	163.1	145.8	157.8	136.4	119.7	106.3	95.5
Proved plus Probable
Egypt*	91.4	76.3	65.0	56.4	49.6	-	-	-	-	-
Yemen *	142.8	120.8	104.2	91.4	81.2	106.5	90.6	78.5	69.1	61.5
Canada **	108.7	87.4	72.5	61.6	53.3	100.8	82.5	69.5	59.8	52.3
Total Proved plus
Probable	343.0	284.5	241.8	209.4	184.1	207.3	173.1	148.0	128.8	113.8

*	Egypt and Yemen future net revenues presented are after Egypt and Yemen income tax respectively.
**	Canadian values converted at the Dec 31, 2006 exchange rate of 1.1654 US$/C$. The Dec 31, 2007 Canadian values were run at an exchange rate of 1.0 US$/C$, which is the independent evaluators’ forecasted exchange rate.

The following table summarizes the constant pricing used to estimate future net revenues.

	December 31, 2007		December 31, 2006
	Oil	Natural Gas	Oil	Natural Gas
	US$/Bbl	US$/Mcf	US$/Bbl	US$/Mcf
Egypt*	69.60	-	-	-
Yemen **	92.62	-	59.76	-
Canada ***	79.41	7.97	54.26	5.58

*	Egypt prices are based on prices received for production from West Gharib.
**	Yemen prices are based on prices received for production from Block 32 and Block S-1.
***	Canadian values converted at the December 31, 2007 and December 31, 2006 exchange rates of 0.9843 and 1.1654 US$/C$ respectively.

The following table summarizes the independent evaluator’s price forecast used to estimate future net revenues.

	WTI Oil Reference		AECO Spot Gas Reference
	US$/Bbl		US$/Mcf
Year	2007	2006	2007*	2006*
2008	90.00	65.52	6.69	6.79
2009	86.52	64.27	7.29	6.62
2010	84.87	61.73	7.18	6.42
2011	83.32	59.07	7.13	6.59
2012	82.78	59.11	7.19	6.67
2013	82.19	60.29	7.21	6.80
Forecasted	2%/yr	2%/yr	2%/yr	1.9% to 17 then 2%

* Canadian values converted at the Dec 31, 2006 exchange rate of 1.1654 US$/C$. The Dec 31, 2007 Canadian values were run at an exchange rate of 1.0 US$/C$, which is the independent evaluators’ forecasted exchange rate.

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17

D AV I D C . F E R G U S O N
Vice President, Finance,
CFO and Corporate Secretary

M A N A G E M E N T ’ S  D I S C U S S I O N  A N D  A N A L Y S I S

M A R C H  6 ,  2 0 0 8

The following discussion and analysis is management’s opinion of TransGlobe Energy Corporation’s (“TransGlobe” or the “Company”) historical financial and operating results and should be read in conjunction with the audited consolidated financial statements and the notes thereto of the Company for the years ended December 31, 2007 and 2006. 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 16 of the consolidated financial statements. Additional information relating to the Company, including the Company’s Annual Information Form, is available on SEDAR at www.sedar.com. The Company’s annual report on Form 40-F may be found in the Electronic Data Gathering, Analysis and Retrieval (EDGAR) database at www.sec.gov.

F O R WA R D - L O O K I N G  S TAT E M E N T S

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 expressed in forward-looking statements include, but are not limited to, oil and gas prices, well production performance, exploitation and exploration successes, continued availability of capital and financing, and general economic, market or business conditions.

N O N - G A A P  M E A S U R E S

This document contains the term “cash flow from operations”, which should not be considered an alternative to, or more meaningful than, “cash flow from operating activities” as determined in accordance with Generally Accepted Accounting Principles (“GAAP”). 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.

Net operating income is a non-GAAP measure that represents revenue net of royalties, current income taxes (paid through production sharing) and operating expenses. Management believes that net operating income is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Net operating income may not be comparable to similar measures used by other companies.

U S E  O F  B O E  E Q U I VA L E N T S

The calculations of barrels of oil equivalent (“Boe”) are based on a conversion rate of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“Bbl”) of crude oil. Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf : 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

O V E R V I E W

TransGlobe is an independent, public company whose activities are concentrated in three main geographic areas: the Arab Republic of Egypt (“Egypt”), the Republic of Yemen (“Yemen”) and Canada. Egypt and Yemen include the Company’s exploration, development and production of crude oil. Canada includes the Company’s exploration, development and production of natural gas, natural gas liquids and crude oil.

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S E L E C T E D  A N N U A L  I N F O R M AT I O N

($000s, except per-share, price and volume amounts)		%		%
	2007	Change	2006	Change	2005
Average production volumes (Boepd)*	5,651	11	5,093	2	4,991
Average sales volumes (Boepd)*	5,692	12	5,077	2	4,959
Average price ($/Boe)	65.80	12	58.92	18	49.92
Oil and gas sales	136,709	25	109,190	21	90,350
Oil and gas sales, net of royalties and other	87,911	25	70,097	19	58,911
Cash flow from operations**	52,141	12	46,763	23	38,077
Cash flow from operations per share
- Basic	0.87		0.80		0.66
- Diluted	0.86		0.77		0.63
Net income	12,802	(51)	26,195	32	19,850
Net income per share
- Basic	0.21		0.45		0.34
- Diluted	0.21		0.43		0.33
Total assets	204,219	75	116,473	35	86,286
Long-term debt	51,958		-		-
Reserves***
Total Proved (MMBoe)	11.9	27	9.3	19	7.8
Total Proved plus Probable (MMBoe)	16.4	41	11.7	11	10.5

*	The differences in production and sales volumes result from inventory changes.
**	Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.
***	Working interest before royalties.

In 2007, production per day increased 11% over the previous year, mainly from increases realized in Canada and the newly acquired Egyptian properties effective September 25, 2007. During the year, TransGlobe spent $37.0 million on exploration and development activities and drilled 26 successful wells.

TransGlobe replaced 222% of production in 2007 and increased proved reserves by 2.6 MMBoe, including the Egypt Acquisition that closed in September.

Cash flow from operations increased by 12% in 2007 compared with 2006 mainly as a result of higher realized prices, larger production volumes in Canada, and from the September 2007 acquisition of Egyptian assets (the “Egypt Acquisition”), offset by higher royalties, operating costs and taxes paid.

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2 0 0 7  VA R I A N C E S

		$ Per Share	%
	$000s	Diluted	Variance
2006 Net Income	26,195	0.43
Cash items
Volume variance	14,772	0.24	56
Price variance	12,747	0.21	49
Royalties	(9,705)	(0.16)	(37)
Expenses:
Operating	(4,161)	(0.07)	(16)
Realized derivative gain (loss)	(881)	(0.01)	(3)
Cash general and administrative	(2,177)	(0.04)	(8)
Current income taxes	(3,501)	(0.06)	(13)
Realized foreign exchange gain (loss)	(17)	-	-
Settlement of asset retirement obligations	(149)	-	(1)
Interest on long-term debt	(1,450)	(0.02)	(6)
Other income	(100)	-	-
Total cash items variance	5,378	0.09	21
Non-cash items
Unrealized derivative gain (loss)	(7,015)	(0.12)	(27)
Depletion, depreciation and accretion	(12,231)	(0.19)	(47)
Future income taxes	218	-	1
Stock-based compensation (non-cash)	82	-	-
Settlement of asset retirement obligations	149	-	1
Amortization of deferred financing costs	26	-	-
Total non-cash items variance	(18,771)	(0.31)	(72)
2007 Net Income	12,802	0.21	(51)

Net income for 2007 decreased 51% from 2006 mainly due to higher depletion, depreciation and accretion costs resulting from the write-down necessitated by two dry wells drilled in the Nuqra Block in Egypt, higher per-unit-of-production charges in Canada and Yemen, as well as a $7.1 million non-cash unrealized derivative loss on commodity contracts.

C O R P O R AT E  A C Q U I S I T I O N

On September 25, 2007, TransGlobe Petroleum International Inc.(“TGPI”), a wholly-owned subsidiary of TransGlobe Energy Corporation, acquired all the shares of Dublin International Petroleum (Egypt) Limited (“Dublin”) and Drucker Petroleum Inc. (“Drucker”) for US$59 million, plus working capital adjustments, as at July 1, 2007. Dublin and Drucker together hold a 70% working interest in the West Gharib Production Sharing Concession (“PSC”). TransGlobe has assumed operatorship of the West Gharib PSC on September 25, 2007.

The West Gharib PSC is located onshore in the western Gulf of Suez rift basin of Egypt. The eight approved West Gharib development leases encompass 178 square kilometers (approximately 44,059 acres) and are valid for 20 years, expiring between 2019 and 2026. One additional development lease at East Hoshia, was subsequently approved by the Egyptian Petroleum Minister on January 31, 2008. Eight of the nine development leases (excluding the Hana development lease) are encumbered with a 25% financial interest through an investment agreement between Dublin and a private company. The 25% financial interest is non-voting but otherwise is treated as a 25% participating interest partner.

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On February 5, 2008, TGPI acquired all the shares of GHP Exploration (“GHP”) for US$40.2 million, plus working capital adjustments, as at September 30, 2007. GHP holds a 30% working interest in the West Gharib PSC.

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

M A N A G E M E N T  S T R A T E G Y  A N D  O U T L O O K  F O R  2 0 0 8

In 2008, TransGlobe’s strategy is to focus on expanding its international asset base. Historically, TransGlobe has experienced higher growth rates and a higher return on investment from its international properties. To enhance this trend, the Company will allocate all its capital and human resources to explore and develop its international properties and to increase its international asset base. Accordingly, management has decided to divest of the Canadian assets and re-deploy the capital into new international ventures.

2 0 0 8  O U T L O O K  H I G H L I G H T S

• Production is expected to average between 6,900 and 7,100 Boepd.

• Exploration and development spending is budgeted to be $58.6 million, a 40% increase over 2007 (allocated 60% to Egypt and 40% to Yemen).

• Based on price assumptions of $80/Bbl of Brent oil and Cdn$7.00/Mcf of natural gas, cash flow from operations is expected to be between $53.0 million and $57.0 million.

• In February 2008, the Company acquired a further 30% interest in the West Gharib PSC for $40.2 million plus working capital adjustments. The acquisition added approximately 900 Bopd of production to the Company’s total output.

• In February 2008, the Company commenced the sale process for its Canadian assets, with an anticipated sale date early in the second quarter of 2008, subject to satisfactory price being achieved. The Company has engaged Tristone Capital as financial advisor in this potential sale

2 0 0 8  P R O D U C T I O N  O U T L O O K

The production forecast for 2008 is an average of between 6,900 to 7,100 Boepd, including the recent acquisition of an additional 900 Bopd of production in the West Gharib PSC. A number of projects are underway that are anticipated to increase oil production during 2008. The 2008 forecast incorporates the divestment at April 1, 2008 of TransGlobe’s Canadian production totalling approximately 1,400 Boepd. TransGlobe is planning to participate in a total of 28 exploration and development wells in Egypt and Yemen during the year. Also included in the forecast are anticipated production increases from development wells in West Gharib. However, the Company has not included any assumptions of production increases from exploration success or development drilling in Yemen. The Company will update its 2008 forecast quarterly or upon completion of significant facilities and/or developments.

Production Forecast

	2008	2007	Change*
Barrels of oil equivalent per day	6,900-7,100	5,651	24

*    % growth based on mid-point of guidance

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2 0 0 8  C A S H  F L O W  F R O M  O P E R AT I O N S  O U T L O O K

This outlook was developed using the above production forecast,  a dated Brent oil price of $80.00/Bbl and a natural gas price of C$7.00/Mcf.

2008 Cash Flow From Operations Outlook
($ million)	2008	2007	Change*
Cash flow from operations**	53.0-57.0	52.1	6

*	% growth based on mid-point of guidance.
**	Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

While production is forecast to grow by 24% year-over-year, cash flow is only increasing by 6% mainly as a result of higher interest charges resulting from an elevated debt level and lower average netbacks received from the West Gharib medium-gravity oil production.

Variations in production and commodity prices during 2008 could significantly change this outlook. An estimate of the price sensitivity05 06 07 05 06 07 05 06 07 on the production forecast is shown below. During January and February 2008, the dated Brent oil price averaged $93.52/Bbl, and the price for natural gas averaged approximately C$7.23/Mcf. For each dollar of change in dated Brent oil prices, the Company’s annual cash flow changes by approximately $0.4 million.

2008 Capital Budget
($ million)	2008
Egypt	33.3
Yemen	23.8
Canada	1.5
Total	58.6

Total capital expenditures of $58.6 million will be applied to the drilling of up to 18 (16 development and 2 exploration) wells in Egypt and up to 12 wells in Yemen, evenly divided into development wells and exploration wells. The Company attaches a significantly higher risk to the exploratory wells. The 2008 capital budget is expected to be funded from cash flow and working capital. The Company may use additional debt or equity financing in the future to accelerate existing projects or to finance new opportunities.

B U S I N E S S  E N V I R O N M E N T

The Company’s financial results are significantly influenced by fluctuations in commodity prices, including price differentials, and the U.S./Canadian dollar exchange rate. The following table shows select market benchmark prices and foreign exchange rates:

		%		%
	2007	Change	2006	Change	2005
Dated Brent average oil price ($/Bbl)	72.60	12	64.88	19	54.57
WTI average oil price ($/Bbl)	72.27	9	66.09	17	56.46
Edmonton Par average oil price (C$/Bbl)	77.06	5	73.30	6	69.29
AECO average gas price (C$/MMBtu)	6.45	(1)	6.51	(25)	8.73
U.S./Canadian Dollar year-end exchange rate	0.9913	(15)	1.1654	-	1.1630
U.S./Canadian Dollar average exchange rate	1.0740	(5)	1.1343	(6)	1.2114

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World crude oil prices continued to increase significantly in 2007, with global demand for oil remaining strong and outpacing supply increases. As well, geopolitical concerns, mainly in Iraq, Nigeria and Venezuela continued to affect supply uncertainties.

In 2007, TransGlobe sold approximately 95% of its crude oil at dated Brent minus the selling price differentials and the remaining 5% at the Edmonton Par price less quality differentials.

Demand for natural gas was relatively weak during the year and natural gas prices remained relatively flat over 2006. In 2007, TransGlobe sold its natural gas at AECO Index based pricing and fixed pricing.

O P E R AT I N G  R E S U LT S

D A I LY  V O L U M E S ,  W O R K I N G  I N T E R E S T  B E F O R E  R OYA LT I E S  A N D  O T H E R

		2007	2006	% Change
Egypt - Oil sales*	Bopd	432	-	-
Yemen - Oil sales	Bopd	3,826	4,046	(5)
Canada - Oil and liquids sales	Bopd	402	331	22
- Gas sales	Mcfpd	6,193	4,204	47
Canada	Boepd	1,434	1,031	39
Total Company - daily sales volumes	Boepd	5,692	5,077	12

* Egypt represents the operating results for the period of September 25, 2007 to December 31, 2007. In that period, production averaged 1,607 Bopd for a yearly average of 432 Bopd.

C O N S O L I D AT E D  N E T  O P E R AT I N G  R E S U LT S

	Consolidated
	2007		2006
($000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil and gas sales	136,709	65.80	109,190	58.92
Royalties and other	48,798	23.49	39,093	21.09
Current income taxes	12,630	6.08	9,129	4.93
Operating expenses	15,268	7.35	11,107	5.99
Net operating income	60,013	28.88	49,86	26.91

 

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S E G M E N T E D  N E T  O P E R AT I N G  R E S U LT S

In 2007, the Company had producing operations in three geographic areas, segmented into Egypt, Yemen and Canada. The following will discuss each segment separately.

E G Y P T

	2007		2006
($000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	10,731	68.13	-	-
Royalties and other	4,202	26.67	-	-
Current income tax	1,735	11.02	-	-
Operating expenses	722	4.59	-	-
Net operating income	4,072	25.85	-	-

With the Egypt Acquisition completed late in the third quarter of 2007, production of 1,607 Bopd from the West Gharib PSC is included in TransGlobe’s results (September 25, 2007 to December 31, 2007). Calculated as an annual average, the added production from this acquisition totaled 432 Bopd for 2007. The average selling price during that period for this production was $68.13/Bbl, which represents a gravity/quality adjustment of approximately $17.86/Bbl to an average dated Brent price for the period of $85.99/Bbl.

Y E M E N

Yemen operating results are generated from two non-operated Blocks: Block 32 (13.81087% working interest) and Block S-1 (25% working interest).

	2007		2006
($000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	101,440	72.64	93,189	63.10
Royalties and other	40,341	28.89	36,353	24.62
Current income tax	10,895	7.80	9,129	6.18
Operating expenses	10,334	7.40	8,108	5.49
Net operating income	39,870	28.55	39,599	26.81

Net operating income in Yemen increased 1% in 2007 primarily as a result of an oil sales increase over the prior year of 9%. While oil prices grew by 15% over the prior year, sales volumes dropped by 5% primarily as a result of lower sales from Block 32 due to natural declines associated with the Tasour field.

Royalty and current income tax expenses increased 13% mainly due to higher commodity prices. Royalties as a percentage of revenue (royalty rate) increased to 40% in 2007 compared to 39% in 2006 while current income tax as a percentage of revenue increased to 11% compared to 10% in 2006.

Operating expenses on a Boe basis increased 35% to $7.40/Bbl in 2007 compared with $5.49 in 2006.

• Block 32 operating expenses increased to $9.40/Bbl in 2007 compared with $5.18/Bbl in 2006 primarily due to declining oil production in the Tasour field and overall cost increases.
• Block S-1 operating costs increased to $6.48/Bbl in 2007 compared with $5.66/Bbl in 2006 mainly due to overall cost increases.

C A N A D A

	2007		2006
($000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil sales	5,147	66.82	3,178	58.45
Gas sales ($ per Mcf)	15,018	6.64	9,478	6.18
NGL sales	3,954	56.49	3,266	49.24
Other sales	419	-	79	-
	24,538	46.85	16,001	42.51
Royalties and other	4,255	8.12	2,740	7.28
Operating expenses	4,212	8.04	2,999	7.97
Net operating income	16,071	30.69	10,262	27.26

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Net operating income in Canada increased 57% in 2007 primarily as a result of a 39% increase in production and a commodity price increase of 10% per Boe.

Royalty costs increased 12% on a Boe basis. Royalties as a percentage of revenue in 2007 were consistent with the prior year at 17%. The Alberta government discontinued the Alberta Royalty Tax Credit program effective January 1, 2007. As a result, the Company’s royalties increased by C$0.5 million in 2007.

Operating expenses per Boe remained consistent in 2007 with those recorded for 2006.

On October 25, 2007, the Government of Alberta announced changes to the royalty program in Alberta. The proposed changes are scheduled to become effective January 1, 2009 and are not expected to impact TransGlobe’s cash flow in 2008.

S E L E C T E D  Q U A R T E R LY  I N F O R M A T I O N

	2007				2006
($000s, except per-share,
price and volume amounts)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average production volumes (Boepd)*	6,837	5,227	5,353	5,175	5,475	4,952	4,915	5,026
Average sales volumes (Boepd)*	6,837	5,227	5,353	5,341	5,313	4,952	5,522	4,515
Average price ($/Boe)	75.83	67.04	63.68	53.58	55.30	61.88	62.17	55.93
Oil and gas sales	47,699	32,240	31,016	25,754	27,032	28,190	31,238	22,730
Oil and gas sales, net of royalties
and other	29,343	20,764	20,553	17,251	17,647	18,542	18,600	15,308
Cash flow from operations**	13,944	13,373	12,814	12,010	10,448	12,662	12,356	11,297
Cash flow from operations per share
- Basic	0.23	0.22	0.22	0.20	0.18	0.22	0.21	0.19
- Diluted	0.23	0.22	0.21	0.20	0.17	0.21	0.20	0.19
Net income	(719)	5,198	2,343	5,980	4,726	7,366	7,246	6,857
Net income per share
- Basic	(0.02)	0.09	0.04	0.10	0.08	0.13	0.12	0.12
- Diluted	(0.01)	0.08	0.04	0.10	0.08	0.12	0.12	0.11

*	The differences in production and sales volumes result from inventory changes.
**	Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

Cash flow from operations increased in the reporting period by $0.6 million (4%) compared with the third quarter of 2007 mainly as a result of a 31% increase in sales volumes and a 13% hike in average commodity prices, offset by increased royalties, taxes and operating costs.

Net income decreased 114% in the fourth quarter 2007 compared with the prior quarter mainly as a result of a derivative loss on commodity contracts of $6.8 million ($0.11 per diluted share).

Comparing the second quarter of 2007 the first quarter of that year, net income decreased 61% due to the write-off in the second quarter of Egypt capital related to the costs of drilling two dry holes at Nuqra ($0.06 per diluted share).

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C O M M O D I T Y  C O N T R A C T S

TransGlobe uses financial derivatives as part of its risk management approach to manage commodity price fluctuations and stabilize cash flows for future exploration and development programs. The Company has fair valued these financial derivative contracts. As at December 31, 2007, the estimated fair value of these contracts is a liability of $7.1 million, which results in an unrealized loss of $7.1 million being recorded to the income statement for the year ended December 31, 2007 (2006 - $0.1 million). The estimated fair market value at December 31, 2007 was based on a dated Brent oil price of $96.02/Bbl.

The Company has entered into the following financial derivative contracts:

Period	Volume	Type	Dated Brent Pricing
			Put - Call
Crude Oil
May 1, 2007-December 31, 2007	15,000 Bbls/month	Financial Collar	$57.50-$79.80
September 1, 2007-August 31, 2008	15,000 Bbls/month	Financial Collar	$60.00-$78.55
January 1, 2008-December 31, 2008	12,000 Bbls/month	Financial Collar	$60.00-$81.20
January 1, 2009-December 31, 2009	12,000 Bbls/month	Financial Collar	$60.00-$82.10
November 1, 2007-March 31, 2008	5,000 Bbls/month	Financial Collar	$65.00-$89.35
September 1, 2008-January 31, 2009	11,000 Bbls/month	Financial Collar	$60.00-$88.80
February 1, 2009-December 31, 2009	6,000 Bbls/month	Financial Collar	$60.00-$86.10
January 1, 2010-August 31, 2010	12,000 Bbls/month	Financial Collar	$60.00-$84.25
Natural Gas
April 1, 2007-October 31, 2007	2,500 GJ/day	Physical	C$6.97

The hedging program was expanded significantly in September 2007 to protect the cash flows from the added risk of commodity price exposure following a marked increase in TransGlobe’s debt levels resulting from the Egypt Acquisition.

The total volumes hedged per year are listed below:

	2008	2009	2010
Bbls	323,000	221,000	96,000
Bopd	885	605	263

G E N E R A L  A N D  A D M I N I S T R AT I V E  E X P E N S E S

	2007		2006
($000s, except per Boe amounts)	$	$/Boe	$	$/Boe
	05 06 07		05	06 07
G&A (gross)	7,971	3.84	5,914	3.19
Stock-based compensation	1,086	0.52	1,168	0.63
Capitalized G&A	(1,947)	(0.94)	(1,999)	(1.08)
Overhead recoveries	(367)	(0.18)	(409)	(0.22)
G&A (net)	6,743	3.24	4,674	2.52

General and administrative expenses (“G&A”) increased 44% in 2007 (29% increase on a Boe basis) compared with 2006 mainly as a result of increased staffing levels and higher fees caused by compliance requirements (Sarbanes-Oxley). With higher production levels in 2008, G&A costs per Boe are expected to decrease.

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D E P L E T I O N ,  D E P R E C I A T I O N  A N D  A C C R E T I O N  E X P E N S E

	2007		2006
($000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Egypt	3,144	19.96	37	-
Write-off of dryhole costs (Nuqra Block)	4,111	-	-	-
Yemen	12,157	8.71	11,623	7.87
Canada	11,760	22.45	7,281	19.34
	31,172	12.40	18,941	10.22

In Egypt, depletion, depreciation and accretion expense (“DD&A”) increased to $7.2 million in 2007 due to $4.1 million in dry-hole costs related to the Nuqra Block written off during the year. As well, production from the West Gharib PSC resulted in a $3.1 million charge to DD&A in 2007. The DD&A of $3.1 million is due to the fact that DD&A is depleted on proved reserves, while the purchase price for the Egypt Acquisition was based on proved plus probable reserves.

In Yemen, DD&A on a Boe basis increased 11% in 2007 compared with 2006 primarily as a result of less reserve additions in Yemen than in the prior year.

In Canada, DD&A on a Boe basis increased 16% in 2007 compared to 2006 primarily as a result of increased finding and development costs in Canada.

In Egypt, Yemen and Canada, unproven property costs of $9.2 million, $5.0 million and $3.9 million, respectively were excluded from costs subject to depletion and depreciation.

I N C O M E  TA X E S

($000s)	2007	2006
Current income tax - Egypt	1,735	-
- Yemen	10,895	9,129
	12,630	9,129
Future income tax  - Canada	45	263
	12,675	9,392

Current income tax expense in 2007 represents income taxes incurred and paid under the laws of Egypt pursuant to the West Gharib PSC and Yemen pursuant to the PSAs on Block 32 and Block S-1. The increase in Egypt is the result of the addition of the West Gharib concession in 2007. The income tax in Egypt as a percent of Egypt revenue was 16% in 2007. The year-over-year increase in Yemen is primarily the result of higher revenue from that country. The income tax expense in Yemen as a percent of Yemen revenue was 11% in 2007 and 10% in 2006. No income tax was paid in Canada in 2007. At December 31, 2007, the Company has C$54 million in Canadian tax pools.

The future income expense relates to a non-cash expense for taxes to be incurred in the future as Canadian tax pools reverse.

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C A P I TA L  E X P E N D I T U R E S  /  D I S P O S I T I O N S

C A P I TA L  E X P E N D I T U R E S

($000s)	2007	2006	%
Egypt	6,904	5,365	29
Yemen	18,437	26,585	(31)
Canada	11,674	19,605	(41)
	37,015	51,555	(28)
Acquisition	54,823	-	-
Total	91,838	51,555	78

In Egypt, the Company drilled two wells in the West Gharib area and two exploration wells in the Nuqra Block. Late in the third quarter,($/Boe) the Company acquired the shares two private companies (Dublin and Drucker) that hold a working interest in the West Gharib PSC and valued the property, plant and equipment of the acquired companies at $54.8 million. Goodwill of $4.3 million was recorded. Subsequent to year-end, TransGlobe increased its interest in the PSC by a further 30% through the corporate acquisition of GHP Exploration (West Gharib) Ltd.

In Yemen, the Company drilled five wells and re-entered one well on Block S-1; drilled five wells on Block 32; one well on Block 72; and commenced a 3-D seismic program on Block 72 to be completed in the first quarter of 2008. The construction and commissioning of the expanded An Nagyah Central Production Facility (“CPF”) was completed, with all An Nagyah oil now being processed through the CPF.

In Canada, the Company drilled a total of 18 (7.2 net) wells in Central Alberta. The Company also carried out completion and testing work on thirteen wells, completed facility work in Nevis to optimize production, and acquired lands on several new prospects.

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F I N D I N G  A N D  D E V E L O P M E N T  C O S T S  A N D  F I N D I N G ,  D E V E L O P M E N T  
A N D  N E T  A C Q U I S I T I O N  C O S T S

Canadian National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities, specifies how finding and development (F&D) costs should be calculated. Canadian National Instrument 51-101 requires that exploration and development costs incurred in the year along with the change in estimated future development costs be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions and dispositions on both reserves and costs. TransGlobe believes that the provisions of Canadian National Instrument 51-101 do not fully reflect TransGlobe’s ongoing reserve replacement costs. Since acquisitions can have a significant impact on TransGlobe’s annual reserve replacement cost, to not include these amounts could result in an inaccurate portrayal of TransGlobe’s cost structure. Accordingly, TransGlobe has also reported finding, development and acquisition (FD&A) costs that will incorporate all acquisitions net of any dispositions during the year.

P R O V E D

($000s, except volumes and per Boe amounts)	2007	2006	2005
Total capital expenditure	37,015	51,555	32,654
Acquisitions (including goodwill and future capital)	62,821	-	-
Net change from previous year’s future capital	(2,467)	(1,154)	8,418
	97,369	50,401	41,072
Reserve additions and revisions (MBoe)
Exploration and development	1,634	3,371	2,987
Acquisitions	2,953	-	-
Total reserve additons (Mboe)	4,587	3,371	2,987
Average cost per Boe
F&D	21.14	14.95	13.75
FD&A	21.23	14.95	13.75
Three-year average cost per Boe
F&D	15.77	11.85	9.57
FD&A	17.25	11.85	9.57

P R O V E D  P L U S  P R O B A B L E

($000s, except volumes and per Boe amounts)	2007	2006	2005
Total capital expenditure	37,015	51,555	32,654
Acquisitions (including goodwill and future capital)	68,716	-	-
Net change from previous year’s future capital	(6,587)	3,943	9,449
	99,144	55,498	42,103
Reserve additions and revisions (MBoe)
Exploration and development	1,537	3,025	1,879
Acquisitions	5,264	-	-
Total reserve additons (MBoe)	6,801	3,025	1,879
Average cost per Boe
F&D	19.79	18.35	22.41
FD&A	14.58	18.35	22.41
Three-year average cost per Boe
F&D	19.88	12.83	8.19
FD&A	16.81	12.83	8.19

Note: 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 reflect total finding and development costs related to reserves additions for that year.

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R E C Y C L E  R AT I O

P R O V E D

	Three Year
	Average	2007	2006	2005
Netback ($/Boe)	23.86	25.10	25.23	21.04
Proved F&D costs ($/Boe)	15.77	21.14	14.95	13.75
Proved FD&A costs ($/Boe)	17.25	21.23	14.95	13.75
F&D Recycle ratio	1.51	1.19	1.69	1.53
FD&A Recycle ratio	1.38	1.18	1.69	1.53

P R O V E D  P L U S  P R O B A B L E

	Three Year
	Average	2007	2006	2005
Netback ($/Boe)	23.86	25.10	25.23	21.04
Proved plus Probable F&D costs ($/Boe)	19.88	19.79	18.35	22.41
Proved plus Probable FD&A costs ($/Boe)	16.81	14.58	18.35	22.41
F&D Recycle ratio	1.20	1.27	1.38	0.94
FD&A Recycle ratio	1.42	1.72	1.38	0.94

The recycle ratio 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 by the proved finding and development costs or finding, development and acquisition costs on a Boe basis. Netback is defined as net sales less operating, general and administrative (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Boe of production.

($000s, except volumes and per Boe amounts)	2007	2006	2005
Net income	12,802	26,195	19,850
Adjustments for non-cash items:
Depletion, depreciation and accretion	31,172	18,941	16,990
Stock-based compensation	1,086	1,168	723
Future income taxes	45	263	471
Amortization of deferred financing costs	153	179	291
Unrealized loss (gain) on commodity contracts	7,098	83	(83)
Settlement of asset retirement obligations	(215)	(66)	(165)
Netback	52,141	46,763	38,077
Sales volumes (MBoe)	2,078	1,853	1,810
Netback ($/Boe)	25.10	25.23	21.04

O U T S T A N D I N G  S H A R E  D A T A

As at December 31, 2007 TransGlobe had 59,626,539 common shares issued and outstanding.

L I Q U I D I T Y  A N D  C A P I T A L  R E S O U R C E S

Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and proved reserves, to acquire strategic oil and gas assets and to repay debt. TransGlobe’s capital programs are funded principally by cash provided from operating activities.

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The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2007 and 2006:

S O U R C E S  A N D  U S E S  O F  C A S H

($000s)	2007	2006
Cash sourced
Cash flow from operations*	52,141	46,763
Increase in long-term debt	63,000	-
Exercise of options	605	297
Other	218	-
	115,964	47,060
Cash used
Exploration and development expenditures	37,015	51,555
Bank financing costs	1,097	-
Acquisition	68,001	-
Repayment of long-term debt	5,000	-
Purchase of common shares	472	-
Other	-	545
	111,585	52,100
Net cash	4,379	(5,040)
Increase in non-cash working capital	(486)	1,655
Change in cash and cash equivalents	3,893	(3,385)
Cash and cash equivalents - beginning of year	8,836	12,221
Cash and cash equivalents - end of year	12,729	8,836

* Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

Funding for the Company’s capital expenditures and the Egypt Acquisition in the third quarter of 2007 was provided by cash flow from operations, working capital and long-term debt.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2007, the Company had working capital of $5.5 million (2006 - $4.4 million). Accounts receivable grew primarily as a result of the Egypt Acquisition. Accounts payable remained consistent: lower drilling activity in Yemen and Canada was offset by the addition of the accounts payable added to the Company’s balance sheet with the Egypt Acquisition.

During the year, the Company increased its borrowing base from $25.0 million to $50.0 million under the Revolving Credit Agreement and established a new Term Loan of $13.0 million. At December 31, the Revolving Credit Agreement was fully drawn and $8.0 million was drawn against the Term Loan.

($000s)	December 31, 2007	December 31, 2006
Revolving Credit Agreement	50,000	-
Term Loan Agreement	8,000	-
	58,000	-
Unamortized transaction costs	(1,315)	-
	56,685	-
Current portion of long-term debt	4,727	-
Long-term debt	51,958	-

The Company expects to fund its approved 2008 exploration and development program of $58.6 million through the use of working capital and cash flow. The use of additional debt or equity financing during 2008 may also be utilized 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.

Subsequent to year end, the Company increased its Term Loan of $8.0 million to $48.0 million. The Company plans to repay a portion of the long-term debt with any proceeds resulting from the disposition of the Canadian assets in 2008.

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C O M M I T M E N T S  A N D  C O N T I N G E N C I E S

As part of its normal business, the Company entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity, some of which are reflected as liabilities in the Consolidated Financial Statements at year-end. The principal commitments of the Company are in the form of debt repayments, lease commitments relating corporate offices and equipment, abandonment obligations, and minimum work commitments under various international agreements.

Additional discussion of Company’s debt repayment obligations and significant commitments can be found in notes 5 and 13 to the Consolidated Financial Statements. A discussion of the Company’s derivative commodity contracts can be found in the Commodity Contracts section of the MD&A.

The following table includes the Company’s expected future payment commitments as at December 31, 2007 and estimated timing of such payments.

	Payment Due by Period1,2
		Less Than	1-3	4-5	More than
($000s)	Total	1 Year	Years	Years	5 Years
Long-term debt
Term Loan Agreement	8,000	4,727	3,273	-	-
Revolving Credit Agreement	50,000	-	50,000	-	-
Office and equipment leases	1,189	372	796	21	-
Abandonment obligations3	3,563	346	684	2,047	486
Minimum work commitments4	13,700	-	5,300	8,400	-
Total	76,452	5,445	60,053	10,468	486

¹Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivative contracts.
²Payments demoninated in foreign currencies have been translated at the December 31, 2007 exchange rate.
³ The abandonment obligation represents management’s probability weighted, undiscounted best estimate of the cost and timing of future dismantlement, site restoration and abandonment obligations based on engineering estimates and in accordance with existing legislation and industry practice.
⁴Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

S U B S E Q U E N T  E V E N T S

On February 1, 2008, the Company announced that it had engaged a financial advisor to assist in the sale of its Canadian assets. While it is likely that this process will lead to the disposition of all or a portion of the Canadian assets, there is no assurance that this will be the case, nor is any forecast given as to the form of action that will be taken. Any proceeds from a potential sale of the Canadian assets will be applied to reduce debt.

On February 5, 2008, TransGlobe Energy Corporation announced the closing of the acquisition of privately-held GHP Exploration (West Gharib) Ltd. (“GHP”). TransGlobe acquired all the shares of GHP for $40.2 million, plus working capital adjustments, effective September 30, 2007. The acquisition was funded from bank debt and cash on hand. GHP holds a 30% interest in the West Gharib Concession area in Egypt.

Also on February 5, 2008, the Company increased its Term Loan Agreement of $8.0 million to $48.0 million. The Term Loan repayment terms increased to $4.8 million per quarter, commencing June 30, 2008.

C R I T I C A L  A C C O U N T I N G  P O L I C I E S

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.

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O I L  A N D  G A S  R E S E R V E S

TransGlobe’s proved and probable oil and gas reserves are 100% evaluated and reported on by independent reserve evaluators. 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 reflect 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.

F U L L  C O S T  A C C O U N T I N G  F O R  O I L  A N D  G A S  A C T I V I T I E S

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 depleted, depreciated 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 depletion, depreciation 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% 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 ImpairmentsUnder 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.

I N C O M E  TA X  A C C O U N T I N G

The Company has recorded a future income tax asset in 2007 and 2006. 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.

The determination of the Company’s income tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

C U R R E N C Y  T R A N S L AT I O N

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 exchange 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 Income and Retained Earnings.

D E R I VAT I V E  F I N A N C I A L  I N S T U M E N T S

Derivative financial instruments are used by the Company to manage its exposure to market risks relating to commodity prices. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.

Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded at fair values where instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net income. Realized gains or losses from financial derivatives related to commodity prices are recognized in revenues as they occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

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A S S E T  R E T I R E M E N T  O B L I G AT I O N S

The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when identified and a reasonable estimate of the fair value can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion in the Consolidated Statement of Income. Amounts recorded for asset retirement obligations are based on estimates of reserves and on retirement costs which will not be incurred for several years. Actual payment to settle the obligations may differ from estimated amounts.

C H A N G E S  I N  A C C O U N T I N G  P O L I C I E S

The following accounting pronouncements had an impact on the financial statements of the Company in 2007:

F I N A N C I A L  I N S T R U M E N T S ,  C O M P R E H E N S I V E  I N C O M E ,  H E D G E S  A N D  E Q U I T Y

Effective January 1, 2007, the Company adopted the new recommendations of the Canadian Institute of Chartered Accountants (CICA) under CICA Handbook Section 1530, Comprehensive Income, Section 1651, Foreign Currency Translation, Section 3251, Equity, Section 3855, Financial Instruments - Recognition and Measurement, Section 3861, Financial Instruments Disclosure and Presentation and Section 3865, Hedges. These new Handbook Sections provide requirements for the recognition and measurement of financial instruments in the balance sheet, reporting gains or losses in the financial statements and the use of hedge accounting.

Under Section 3855, all financial instruments are initially measured in the balance sheet at fair value. Subsequent measurement of the financial instruments is based on their classification. The Company has classified each financial instrument into one of these five categories: held-for-trading, held-to-maturity investments, loans and receivables, available-for-sale financial assets or other financial liabilities. Loans and receivables, held-to-maturity investments and other financial liabilities are measured at amortized cost using the effective interest rate method. For all financial assets and financial liabilities that are not classified as held-for-trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability are adjusted to the fair value initially recognized for that financial instrument. These costs are expensed using the effective interest rate method and are recorded within interest expense. Held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive income until the instrument is derecognized or impaired. All derivative instruments are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale and usage exemption. All changes in their fair value are recorded in income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income.

As a result of the adoption of these new standards, the Company has classified its derivative commodity contracts and cash and cash equivalents as held-for-trading, which are measured at fair value with changes being recognized in net income. Accounts receivable are classified as loans and receivables; operating bank loans, accounts payable and accrued liabilities, and long-term debt, including interest payable, are classified as other liabilities, all of which are measured at amortized cost. The classification of all financial instruments is the same at inception and at December 31, 2007. The Company has elected to classify all derivatives and embedded derivatives as held-for trading, which are measured at fair value with changes being recognized in net income, and the Company has maintained its policy not to use hedge accounting. The Company elected January 1, 2003 as the transition date for embedded derivatives.

Section 1530 establishes standards for reporting and presenting comprehensive income which is defined as the change in equity from transactions and other events from non-owner sources. Other comprehensive income refers to items recognized in comprehensive income but that are excluded from net income calculated in accordance with generally accepted accounting principles. Due to the issuance of Section 1530, Section 1650 has been replaced by Section 1651 which establishes new standards for presentation of exchange gains and losses arising from the translation of self-sustaining foreign operation in Other Comprehensive Income. Therefore, the Company has restated prior periods to include cumulative translation adjustment on self-sustaining operations as Other Comprehensive Income.

Section 3251, Equity, which replaces Section 3250, Surplus, establishes standards for the presentation of equity and changes in equity during the reporting period. The main feature of this section is a requirement for an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period.

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N E W  A C C O U N T I N G  S TA N D A R D S

The Company has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined that the following may have an impact on the Company:

C A P I TA L  D I S C L O S U R E S

The Accounting Standards Board (AcSB) issued Canadian Institute of Chartered Accountants (CICA) Section 1535, Capital Disclosures. The main features of this section are to establish requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital, quantitative data about what it regards as capital, and whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. The new requirements are effective for annual and interim periods beginning on or after October 1, 2007, and, upon adoption, are not expected to materially impact the Consolidated Financial Statements.

A C C O U N T I N G  C H A N G E S

Effective January 1, 2007, the Company adopted the revised recommendations of Section 1506, Accounting Changes. The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting policies, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007.

The only impact of adopting this section is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862, Financial Instruments Disclosures, and Section 3863, Financial Instruments Presentations, which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected the only effect on the Company will be incremental disclosures regarding the significance of financial instruments for the entity’s financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed.

G O O D W I L L  A N D  I N TA N G I B L E  A S S E T S

In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) issued Section 3064, Goodwill and intangible assets, replacing Section 3062, Goodwill and other intangible assets and Section 3450, Research and development costs. Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new Section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. It establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company is currently evaluating the impact of the adoption of this new Section on its Consolidated Financial Statements.

I N T E R N AT I O N A L  F I N A N C I A L  R E P O R T I N G  S TA N D A R D S

In January 2006, the Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction of accounting standards in Canada. On February 13, 2008, the AcSB has confirmed that effective for interim and annual financial statements related to fiscal years beginning on or after January 1, 2011, International Financial Reporting Standards (“IFRS”) will replace Canada’s current Generally Accepted Accounting Principles (“GAAP”) for all publicly accountable profit-oriented enterprises. The Company is currently evaluating the impact of this changeover on its Consolidated Financial Statements.

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R I S K S

TransGlobe’s results are affected by a variety of business risks and uncertainties in the international petroleum industry including but not limited to:

• Financial risks

- Crude oil and natural gas prices

- Foreign currency exchange and interest rate risk

- Credit risk

• Operational risks

- Exploratory success

- Cost to find, develop, produce and deliver crude oil and natural gas

- Availability of equipment and labour to conduct field activities

- Availability of pipeline capacity

• Environmental, health, safety and security risks

- environmental preservation and safety concerns

- the Kyoto Protocol

- changes of laws affecting foreign ownership

- political risk of operating in domestic and foreign jurisdictions

- government regulation

• Reputational risks

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:

F I N A N C I A L  R I S K S

Commodity price risk
TransGlobe mitigates its exposure to financial risks through the use of various financial instruments and physical contracts. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

The Company uses financial derivatives to manage commodity price fluctuations and stabilize cash flows for future exploration and development programs. To mitigate its price risk, the Company entered into a number of costless collar contracts. The Company also enters into physical fixed price gas sales contracts when deemed appropriate.

Foreign currency exchange and interest rate risk
The Company’s operations are exposed to fluctuations in foreign currency exchange rates. Variations in the foreign currency exchange rate could have a significant positive or negative impact. The Company manages its foreign currency exchange risk by maintaining foreign currency bank accounts and receivable accounts to offset foreign currency payables and planned expenditures.

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable-interest U.S. dollar-denominated debt. No derivative contracts were entered into during the year to mitigate this risk.

Credit Risk
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.

In Egypt, the Company sold all of its 2007 production to one purchaser. In Yemen, the Company sold all of its 2007 Block 32 production to one purchaser and all of its 2007 Block S-1 production to one purchaser. In Canada, the Company sold primarily all of its 2007 gas production to one purchaser and primarily all of its 2007 oil production to another single purchaser.

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O P E R AT I O N A L  R I S K S

TransGlobe mitigates operational risk through a number of policies and processes. As part of its capital approval process, the Company applies rigorous geological, geophysical and engineering analysis to each prospect. The Company utilizes its in-house expertise for all international ventures or employs and contracts professionals to handle each aspect of the Company’s business. The Company retains independent reserve evaluators to determine year-end Company reserves and estimated future net revenues.

The Company also mitigates operational risks by maintaining a comprehensive insurance program according to customary industry practice, but cannot fully insure against all risks.

E N V I R O N M E N TA L ,  H E A LT H ,  S A F E T Y  A N D  S E C U R I T Y  R I S K S

To mitigate environmental risks, the Company conducts its operations to ensure compliance with respective government regulations and guidelines. At this time, it is not possible to predict either the nature of the Kyoto Protocol requirements or impact on the Company.

Security risks are managed through security policies designed to protect TransGlobe’s personnel and assets. The Company has a “Whistleblower” protection policy, which protects employees if they raise any concerns regarding TransGlobe’s operations, accounting or internal control matters.

R E P U TAT I O N A L  R I S K S

TransGlobe takes a proactive approach to the identification and management of issues that affect the Company’s reputation and has established policies such as a code of conduct for the Company in order to mange these issues.

D I S C L O S U R E  C O N T R O L S  A N D  P R O C E D U R E S

As of December 31, 2007, an evaluation was carried out under the supervision, and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

I N T E R N A L  C O N T RO L  O V E R  F I N A N C I A L  R E P O RT I N G

TransGlobe’s Management has designed and implemented internal controls over financial reporting, as defined under Multilateral Instrument 52-109 of the Canadian Securities Administrators. As per Public Accounting Oversight Board Release 2007-005, the private companies acquired on September 25, 2007 are excluded from this scope for 2007 but will be included for 2008.

Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles, including a reconciliation to U.S. generally accepted accounting principles, focusing in particular on controls over information contained in the annual and interim financial statements.

Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company’s internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework on Internal Control – Integrated Framework. Management has excluded from its assessment the internal control over financial reporting at Dublin and Drucker, which were acquired on September 25, 2007 and whose financial statements constitute 55 percent and 35 percent of net and total assets, respectively, 8 percent of revenues, and 9 percent of net income of the Consolidated Financial Statement amounts as of and for the year ended December 31, 2007. Subject to the foregoing, as at the date of this report management is not aware of any change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Based on this assessment, management believes that the internal controls over financial reporting provide reasonable assurance regarding the preparation and presentation of the Consolidated Financial Statements as at December 31, 2007.

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M A N A G E M E N T ’ S  R E P O RT

The Consolidated Financial Statements of TransGlobe Energy Corporation were prepared by management in United States dollars within acceptable limits of materiality and are in accordance with Canadian generally accepted accounting principles. 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 judgments made by management. 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 Company’s Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee, which has a written mandate that complies with the current requirements of Canadian securities legislation and the United States Sarbanes-Oxley Act of 2002. The Audit Committee meets at least on a quarterly basis.

Management is also responsible for the development and implementation of internal controls over the financial reporting process. These controls are designed to provide reasonable assurance that relevant and reliable financial information is produced. To gather and control financial data, management has established accounting and reporting systems supported by internal controls over financial reporting.

All internal controls systems, no matter how well designed have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2007. In making its assessment, Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) framework on Internal Control – Integrated Framework to evaluate the effectiveness of the Company’s internal control over financial reporting. Management has excluded from its assessment the internal control over financial reporting at Dublin International Petroleum (Egypt) Limited and Drucker Petroleum Inc., which were acquired on September 25, 2007 and whose financial statements constitute 55 percent and 35 percent of net and total assets, respectively, 8 percent of revenues, and 9 percent of net income of the Consolidated Financial Statement amounts as of and for the year ended December 31, 2007. Management believes that the internal controls over financial reporting provide reasonable assurance regarding the preparation and presentation of the Consolidated Financial Statements as at that date.

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 both the Consolidated Financial Statements and the Company’s internal control over financial reporting as at December 31, 2007, as stated in their Auditor’s Report. Deloitte & Touche LLP has provided such opinions.

 

Ross G. Clarkson	David C. Ferguson
President &	Vice President, Finance &
Chief Executive Officer	Chief Financial Officer
March 6, 2008

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R E P O R T  O F  I N D E P E N D E N T  R E G I S T E R E D
C H A R T E R E D  A C C O U N T A N T S

To the Board of Directors and Shareholders of TransGlobe Energy Corporation:

We have audited the accompanying consolidated balance sheets of TransGlobe Energy Corporation (the “Company”) as of December 31, 2007 and 2006 and the related consolidated statements of income, retained earnings, comprehensive income and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about 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 TransGlobe Energy Corporation as of December 31, 2007 and 2006, and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.

Independent Registered Chartered Accountants
Calgary, Canada
February 29, 2008

C O M M E N T S  B Y  I N D E P E N D E N T  R E G I S T E R E D
C H A R T E R E D  A C C O U N T A N T S  O N  C A N A D A - U N I T E D
S TAT E S  O F  A M E R I C A  R E P O R T I N G  D I F F E R E N C E S

The standards of the Public Company Accounting Oversight Board (United States) require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have a material effect on the comparability of the Company’s financial statements, such as the changes described in Notes 2 and 16 to the financial statements. Although we conducted our audits in accordance with both Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), our report to the Board of Directors and Shareholders on the consolidated financial statements of TransGlobe Energy Corporation, dated February 29, 2008, is expressed in accordance with Canadian reporting standards which do not require a reference to such changes in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

Independent Registered Chartered Accountants
Calgary, Canada
February 29, 2008

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R E P O R T  O F  I N D E P E N D E N T  R E G I S T E R E D
C H A R T E R E D  A C C O U N TA N T S

To the Board of Directors and Shareholders of TransGlobe Energy Corporation:

We have audited the internal control over financial reporting of TransGlobe Energy Corporation (the “Company”) as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. As described in the Management Report, management excluded from its assessment the internal control over financial reporting at Dublin International Petroleum (Egypt) Limited and Drucker Petroleum Inc., which was acquired on September 25, 2007 and whose financial statements constitute 55 percent and 35 percent of net and total assets, respectively, 8 percent of revenues, and 9 percent of net income of the consolidated financial statement amounts as of and for the year ended December 31, 2007. Accordingly, our audit did not include the internal control over financial reporting at Dublin International Petroleum (Egypt) Limited and Drucker Petroleum Inc.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as at and for the year ended December 31, 2007 of the Company and our report dated February 29, 2008 expressed an unqualified opinion on those financial statements and included a separate report titled Comments by Independent Registered Chartered Accountants on Canada-United States of America Reporting Differences referring to changes in accounting principles.

Independent Registered Chartered Accountants
Calgary, Canada
February 29, 2008

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C O N S O L I D AT E D  S TAT E M E N T S  O F  I N C O M E
A N D  R E T A I N E D  E A R N I N G S

(Expressed in thousands of U.S. Dollars)		Year Ended			Year Ended
		December 31, 2007			December 31, 2006
R E V E N U E
Oil and gas sales, net of royalties and other	$	87,911		$	70,097
Derivative loss on commodity contracts (Note 14)		(7,979	)		(83	)
Other income		183			283
		80,115			70,297
E X P E N S E S
Operating		15,268			11,107
General and administrative		6,743			4,674
Foreign exchange loss (gain)		5			(12	)
Interest on long-term debt		1,450			-
Depletion, depreciation and accretion		31,172			18,941
		54,638			34,710
Income before income taxes		25,477			35,587
I N C O M E  TA X E S  (Note 8)
Current		12,630			9,129
Future		45			263
		12,675			9,392
N E T  I N C O M E		12,802			26,195
Purchase of common shares (Note 7b)		(375	)		-
Retained earnings, beginning of year		45,360			19,165
R E T A I N E D  E A R N I N G S ,  E N D  O F  Y E A R	$	57,787		$	45,360
Net income per share (Note 11)
Basic	$	0.21		$	0.45
Diluted	$	0.21		$	0.43

C O N S O L I D A T E D  S T A T E M E N T S  O F  
C O M P R E H E N S I V E  I N C O M E

(Expressed in thousands of U.S. Dollars)		Year Ended		Year Ended
		December 31, 2007		December 31, 2006
Net income	$	12,802	$	26,195
Other comprehensive income:
Foreign currency translation adjustment		8,554		(430	)
C O M P R E H E N S I V E  I N C O M E	$	21,356	$	25,765

See accompanying notes.

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C O N S O L I D A T E D  B A L A N C E  S H E E T S

(Expressed in thousands of U.S. Dollars)
		December 31, 2007		December 31, 2006
A S S E T S
Current
Cash and cash equivalents	$	12,729	$	8,836
Accounts receivable		17,902		7,742
Product inventory		-		508
Prepaid expenses		1,126		782
		31,757		17,868
Property and equipment (Note 4, 12)		166,286		96,608
Future income tax asset (Note 8)		1,863		1,626
Deferred financing costs (Note 5)		-		371
Goodwill (Note 3)		4,313		-
	$	204,219	$	116,473
L I A B I L I T I E S
Current
Accounts payable and accrued liabilities	$	14,438	$	13,507
Derivative commodity contracts (Note 14)		7,098		-
Current portion of long-term debt (Note 5)		4,727		-
		26,263		13,507
Long-term debt (Note 5)		51,958		-
Asset retirement obligations (Note 6)		2,755		2,171
		80,976		15,678
Commitments and contingencies (Note 13)
S H A R E H O L D E R S ’  E Q U I T Y
Share capital (Note 7)		50,128		49,360
Contributed surplus (Note 7d)		3,562		2,863
Accumulated other comprehensive income (Note 2, 10)		11,766		3,212
Retained earnings		57,787		45,360
		123,243		100,795
	$	204,219	$	116,473

See accompanying notes.

A P P R O V E D  O N  B E H A L F  O F  T H E  B O A R D

  

Ross G. Clarkson, Director	Fred J. Dyment, Director

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C O N S O L I D A T E D  S T A T E M E N T S  O F  C A S H  F L O W S

(Expressed in thousands of U.S. Dollars)		Year Ended			Year Ended
		December 31, 2007			December 31, 2006
C A S H  F L O W S  R E L AT E D  T O  T H E
F O L L O W I N G  A C T I V I T I E S :
O P E R AT I N G
Net income	$	12,802		$	26,195
Adjustments for:
Depletion, depreciation and accretion		31,172			18,941
Amortization of deferred financing costs		153			179
Future income taxes		45			263
Stock-based compensation (Note 7d)		1,086			1,168
Unrealized loss on commodity contracts		7,098			83
Settlement of asset retirement obligations		(215	)		(66	)
Changes in non-cash working capital, net of the
effect of acquisitions (Note 9)		1,477			620
		53,618			47,383
F I N A N C I N G
Increase in long-term debt		63,000			-
Repayment of long-term debt		(5,000	)		-
Purchase of common shares		(472	)		-
Issue of common shares for cash		605			297
Deferred financing costs		(1,097	)		(438	)
		57,036			(141	)
I N V E S T I N G
Exploration and development expenditures		(37,015	)		(51,555	)
Acquisition (Note 3)		(68,001	)		-
Changes in non-cash working capital (Note 9)		(1,963	)		1,035
		(106,979	)		(50,520	)
Effect of exchange rate changes on cash and
cash equivalents		218			(107	)
N E T  I N C R E A S E  I N  C A S H  A N D  C A S H  E Q U I VA L E N T S		3,893			(3,385	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		8,836			12,221
C A S H  A N D  C A S H  E Q U I VA L E N T S ,  E N D  O F  Y E A R	$	12,729		$	8,836
Supplemental Disclosure of Cash Flow Information
Cash interest paid	$	1,384		$	-
Cash taxes paid	$	12,630		$	9,129
Cash and cash equivalents is comprised of cash on hand and
balances with banks	$	12,729		$	8,836

See accompanying notes.

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N O T E S  T O  T H E  C O N S O L I D A T E D
F I N A N C I A L  S T A T E M E N T S

Y E A R S  E N D E D  D E C E M B E R  3 1 , 2 0 0 7  A N D  D E C E M B E R  3 1 ,  2 0 0 6

(Expressed in thousands of U.S. Dollars, unless otherwise stated)

1 . S U M M A RY  O F  S I G N I F I C A N T  A C C O U N T I N G  P O L I C I E S

The Consolidated Financial Statements include the accounts of TransGlobe Energy Corporation and subsidiaries (“TransGlobe” or the “Company”), and are presented in accordance with Canadian generally accepted accounting principles (information prepared in accordance with generally accepted accounting principles in the United States is included in Note 16). In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are expressed in United States (U.S.) dollars. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.

N AT U R E  O F  B U S I N E S S  A N D  P R I N C I P L E S  O F  C O N S O L I D A T I O N

The Company is engaged primarily in oil and gas exploration, development and production and the acquisition of properties. Such activities are concentrated in three geographic areas:

• Nuqra Block 1 and West Gharib area within the Arab Republic of Egypt (“Egypt”).
• Block 32, Block S-1, Block 72, Block 75 and Block 84 within the Republic of Yemen (“Yemen”).
• The Western Canadian Sedimentary Basin within Canada.

J O I N T  V E N T U R E S

Investments in unincorporated joint ventures are accounted for using the proportionate consolidation method, whereby the Company’s proportionate share of revenues, expenses, assets and liabilities are included in the accounts.

C U R R E N C Y  T R A N S L A T I O N

The accounts of the self-sustaining Canadian operations are translated using the current rate method, whereby assets and liabilities are translated at year end exchange rates, while revenues and expenses are translated using average annual rates. Translation gains and losses relating to the self-sustaining Canadian operations are included in accumulated other comprehensive income 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 Statements of Income and Retained Earnings.

R E V E N U E  R E C O G N I T I O N

Revenues associated with the sales of the Company’s crude oil, natural gas and natural gas liquids owned by the Company are recognized when title passes from the Company to its customer. Crude oil and natural gas produced and sold by the Company below or above its working interest share in the related resource properties results in production underliftings or overliftings. Underliftings are recorded as inventory and overliftings are recorded as deferred revenue.

International operations conducted pursuant to production sharing agreements (PSAs) are reflected in the Consolidated Financial Statements based on the Company’s working interest in such operations. Under the PSA’s, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSA establishes specific terms for the Company to recover these costs (Cost Recovery Oil) and to share in the production profits (Profit Oil). Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each fiscal year. Production sharing oil is that portion of production remaining after Cost Recovery Oil and is shared between the joint venture partners and the government of each country, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company’s share and is recorded net of royalty payments to government and other mineral interest owners. For our international operations, all government interests, except for income taxes, are considered royalty payments. Our revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.

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I N C O M E  TA X E S

The Company uses the liability method to account for income taxes. Under this method, future income taxes are based on the difference between assets and liabilities reported for financial accounting purposes from those reported for income tax. Future income tax assets and liabilities are measured using the substantively enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The Company’s contractual arrangements in foreign jurisdictions stipulate that income taxes are paid by the respective national oil company out of its entitlement share of production sharing oil. Such amounts are included in income tax expense at the statutory rate in effect at the time of production.

F L O W- T H R O U G H  S H A R E S

The Company has financed a portion of its prior years’ 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 for the income tax amount related to the renounced deductions.

N E T  I N C O M E  P E R  S H A R E

Basic net income per share is calculated using the weighted average number of shares outstanding during the year. Diluted net income per share is calculated by giving effect to the potential dilution that would occur if stock options were exercised. Diluted net income per share is 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.

C A S H  A N D  C A S H  E Q U I V A L E N T S

Cash and cash equivalents include cash on deposit with banks and short-term investments such as treasury bills with original maturity of less than 90 days.

I N V E N T O R I E S

Product inventories are valued at the lower of average cost and net realizable value on a first-in, first-out basis.

P R O P E RT Y  A N D  E Q U I P M E N T

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, production equipment and overhead charges directly related to acquisition, exploration and development activities.

Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.

D E P R E C I AT I O N ,  D E P L E T I O N ,  A M O R T I Z AT I O N  A N D  I M P A I R M E N T

Capitalized costs within each country are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves as determined by independent reserve evaluators. Gas reserves and production are converted into equivalent units using the energy equivalency conversion method of 6,000 cubic feet of natural gas to one barrel of oil. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value.

Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred.

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 a particular country, in which case a gain or loss on disposal is recorded.

An impairment loss is recognized in net income if the carrying amount of a country (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 is the amount by which the carrying amount exceeds the sum of:

i. the fair value of proved plus probable reserves; and
ii. the costs of unproved properties that have been subject to a separate impairment test and contain no probable reserves.

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

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A S S E T  R E T I R E M E N T  O B L I G AT I O N S

The fair value of the statutory, contractual or legal liability associated with the retirement and reclamation of tangible long-lived assets is recognized when incurred. The asset retirement cost, equal to the estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Asset retirement costs for natural gas and crude oil assets are amortized using the unit-of-production method.

Amortization of asset retirement costs are included in depletion, depreciation and accretion on the Consolidated Statements of Income and Retained Earnings. Increases in the asset retirement obligation resulting from the passage of time are recorded in depletion, depreciation and accretion in the Consolidated Statements of Income and Retained Earnings. Actual expenditures incurred are charged against the accumulated obligation.

S T O C K - B A S E D  C O M P E N S AT I O N

The Company records compensation expense in the Consolidated Financial Statements for stock options granted to employees and directors using the fair value method. Fair values are determined using the lattice-based binomial option pricing model in 2007 and 2006 and the Black-Scholes option pricing model in 2005 and prior years. Compensation costs are recognized over the vesting period.

D E R I V A T I V E  F I N A N C I A L  I N S T R U M E N T S

Derivative financial instruments are used by the Company to manage its exposure to market risks relating to commodity prices. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.

Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded at fair values where instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net income. Realized gains or losses from financial derivatives related to commodity prices are recognized in revenues as they occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

G O O D W I L L

Goodwill, which represents the excess of cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed, is assessed at least annually for impairment. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impaired amount. Goodwill is not amortized.

M E A S U R E M E N T  U N C E R T A I N T Y

Timely preparation of the financial statements in conformity with Canadian generally accepted accounting principles requires that Management make estimates and assumptions and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depletion, depreciation and amortization, asset retirement costs and obligations, future income taxes, and amounts used for ceiling test and impairment calculations are based on estimates of oil and natural gas reserves and future costs required to develop those reserves. By their nature, these estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

2 .  C H A N G E S  I N  A C C O U N T I N G  P O L I C I E S

      F I N A N C I A L  I N S T R U M E N T S ,  C O M P R E H E N S I V E  I N C O M E ,  
       H E D G E S  A N D  E Q U I T Y

Effective January 1, 2007, the Company adopted the new recommendations of the Canadian Institute of Chartered Accountants (CICA) under CICA Handbook Section 1530, Comprehensive Income, Section 1651, Foreign Currency Translation, Section 3251, Equity, Section 3855, Financial Instruments - Recognition and Measurement, Section 3861, Financial Instruments Disclosure and Presentation and Section 3865, Hedges. These new Handbook Sections provide requirements for the recognition and measurement of financial instruments in the balance sheet, reporting gains or losses in the financial statements and the use of hedge accounting.

47

Under Section 3855, all financial instruments are initially measured in the balance sheet at fair value. Subsequent measurement of the financial instruments is based on their classification. The Company has classified each financial instrument into one of these five categories: held-for-trading, held-to-maturity investments, loans and receivables, available-for-sale financial assets or other financial liabilities. Loans and receivables, held-to-maturity investments and other financial liabilities are measured at amortized cost using the effective interest rate method. For all financial assets and financial liabilities that are not classified as held-for-trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or liability are adjusted to the fair value initially recognized for that financial instrument. These costs are expensed using the effective interest rate method and are recorded within interest expense. Held-for-trading financial assets are measured at fair value and changes in fair value are recognized in net income. Available-for-sale financial instruments are measured at fair value with changes in fair value recorded in other comprehensive income until the instrument is derecognized or impaired. All derivative instruments are recorded in the balance sheet at fair value unless they qualify for the expected purchase, sale and usage exemption. All changes in their fair value are recorded in income unless cash flow hedge accounting is used, in which case changes in fair value are recorded in other comprehensive income.

As a result of the adoption of these new standards, the Company has classified its derivative commodity contracts and cash and cash equivalents as held-for-trading, which are measured at fair value with changes being recognized in net income. Accounts receivable are classified as loans and receivables; operating bank loans, accounts payable and accrued liabilities, and long-term debt, including interest payable, are classified as other liabilities, all of which are measured at amortized cost. The classification of all financial instruments is the same at inception and at December 31, 2007. The Company has elected to classify all derivatives and embedded derivatives as held-for trading, which are measured at fair value with changes being recognized in net income, and the Company has maintained its policy not to use hedge accounting. The Company elected January 1, 2003 as the transition date for embedded derivatives.

Carrying value and fair value of financial assets and liabilities as at December 31, 2007 are summarized as follows:

Classification ($000s)		Carrying Value		Fair Value
Held-for-trading	$	5,631	$	5,631
Loans and receivables		17,902		17,902
Held-to-maturity		-		-
Available-for-sale		-		-
Other liabilities		70,880		72,195

Section 1530 establishes standards for reporting and presenting comprehensive income which is defined as the change in equity from transactions and other events from non-owner sources. Other comprehensive income refers to items recognized in comprehensive income but that are excluded from net income calculated in accordance with generally accepted accounting principles. Due to the issuance of Section 1530, Section 1650 has been replaced by Section 1651 which establishes new standards for presentation of exchange gains and losses arising from the translation of self-sustaining foreign operation in Other Comprehensive Income. Therefore, the Company has restated prior periods to include cumulative translation adjustment on self-sustaining operations as Other Comprehensive Income.

Section 3251, Equity, which replaces Section 3250, Surplus, establishes standards for the presentation of equity and changes in equity during the reporting period. The main feature of this section is a requirement for an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period.

VA R I A B L E  I N T E R E S T  E N T I T I E S

Effective January 1, 2007, the Company adopted EIC 163, Determining the variability to be considered in applying AcG-15 (Variable Interest Entities). The EIC provides guidance on those arrangements where application of either the cash flow method or the fair value method does not result in a clear determination as to whether those arrangements are variable interests or creators of variability. The Committee reached a consensus that variability to be considered should be based on the design of the entity as determined through analyzing the nature of the risks in the entity and the purpose for which the entity was created, as well as the variability (created by the risks) the entity is designed to create and pass along to its interest holders. The adoption of EIC 163 had no effect on the Company’s Consolidated Financial Statements.

R E C E N T  A C C O U N T I N G  P R O N O U N C E M E N T S

C A P I TA L  D I S C L O S U R E S

The Accounting Standards Board (“AcSB”) issued Canadian Institute of Chartered Accountants (“CICA”) Section 1535, Capital Disclosures. The main features of this section are to establish requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital, quantitative data about what it regards as capital, and whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. The new requirements are effective for annual and interim periods beginning on or after October 1, 2007, and, upon adoption, are not expected to materially impact the Consolidated Financial Statements.

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A C C O U N T I N G  C H A N G E S

Effective January 1, 2007, the Company adopted the revised recommendations of Section 1506, Accounting Changes. The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting policies, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007.

The only impact of adopting this section is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862, Financial Instruments Disclosures, and Section 3863, Financial Instruments Presentations, which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected the only effect on the Company will be incremental disclosures regarding the significance of financial instruments for the entity’s financial position and performance; and the nature, extent and management of risks arising from financial instruments to which the entity is exposed.

G O O D W I L L  A N D  I N T A N G I B L E  A S S E T S

In February 2008, the Canadian Institute of Chartered Accountants (“CICA”) issued Section 3064, Goodwill and intangible assets, replacing Section 3062, Goodwill and other intangible assets and Section 3450, Research and development costs. Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new Section will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. It establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company is currently evaluating the impact of the adoption of this new Section on its Consolidated Financial Statements.

I N T E R N A T I O N A L  F I N A N C I A L  R E P O R T I N G  S T A N D A R D S

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. On February 13, 2008, the AcSB has confirmed that effective for interim and annual financial statements related to fiscal years beginning on or after January 1, 2011, International Financial Reporting Standards will replace Canada’s current Generally Accepted Accounting Principles (“GAAP”) for all publicly accountable profit-oriented enterprises. The Company is currently evaluating the impact of this changeover on its Consolidated Financial Statements.

3 . B U S I N E S S  C O M B I N A T I O N

On September 25, 2007, TransGlobe acquired all of the common shares of two private companies, Dublin International Petroleum (Egypt) Limited (“Dublin”) and Drucker Petroleum Inc., (“Drucker”) for cash consideration of $67.7 million. The results of Dublin’s and Drucker’s operations have been included in the consolidated financial statements since that date. Dublin and Drucker hold interests in eight development leases and associated infrastructure in the West Gharib Concession area in Egypt (Dublin is the operator of this Concession). TransGlobe funded the acquisition from cash on hand and bank debt of $63.0 million.

The acquisition has been accounted for using the purchase method and the purchase price was allocated to the fair value of the assets acquired and the liabilities assumed as follows:

Cost of acquisition (000s)
Cash paid, net of cash acquired	$	67,684
Transactions costs		317
	$	68,001
Allocation of purchase price (000s)
Property and equipment	$	54,823
Goodwill		4,313
Working capital, net of cash acquired		8,865
	$	68,001

In December 2007, TransGlobe adjusted its estimate of acquisition costs and settlement of the post-closing adjustments relating to the acquisition. This resulted in a decrease to goodwill of $0.2 million.

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4 .  P R O P E R T Y  A N D  E Q U I P M E N T

E G Y P T

(000s)		2007			2006
Oil and gas properties	$	68,460		$	7,683
Furniture and fixtures		1,144			199
Accumulated depreciation		(3,177	)		(43	)
Write-off of dry hole costs		(4,111	)		-
	$	62,316		$	7,839

During the year, the Company acquired all the shares of Dublin and Drucker who together hold a 70% working interest in the West Gharib Production Sharing Concession (“PSC”). TransGlobe has assumed operatorship of the West Gharib Concession Agreement. The eight approved West Gharib development leases are valid for 20 years, expiring between 2019 and 2026. One additional development lease at East Hoshia was subsequently approved by Egyptian Petroleum Minister on January 31, 2008. Eight of the nine development leases (excluding the Hana development lease) are encumbered with a 25% financial interest through an investment agreement between Dublin and a private company. The 25% financial interest is non-voting but otherwise is treated as a 25% participating interest partner.

The Contractor is in the first three year extension period of the Nuqra Concession Agreement which expires in July 2009. One additional extension period of three years is available to the Contractor at its option.

The Company capitalized general and administrative costs relating to exploration and development activities of $0.8 million (2006 - $1.1 million). The remaining costs related to drilling preparation and geological and geophysical activity. Unproven property costs in the amount of $13.3 million of which $4.1 million of dry hole costs were considered impaired during the year and written off to depletion, depreciation and accretion, leaving $9.2 million in 2007 (2006 - $7.7 million) of unproven property costs that were excluded from costs subject to depletion and depreciation.

Y E M E N

(000s)		2007			2006
Oil and gas properties
- Block S-1	$	63,909		$	54,410
- Block 32		40,449			34,060
- Block 72		5,301			2,373
- Block 75		571			250
- Block 84		41			15
- Other		129			96
Accumulated depletion and depreciation		(57,237	)		(45,080	)
	$	53,163		$	46,124

The Company has working interests in five blocks in Yemen: Block 32, Block S-1, Block 72, Block 75 and Block 84. The Block 32 (13.81087%) Production Sharing Agreement (“PSA”) continues to 2020, with provision for a five year extension. The Block S-1 (25%) PSA continues to 2023, with provision for a five year extension. The Contractor (Joint Venture Partners) is in the first exploration period of the Block 72 (33%) PSA which has been extended to January 2009, at which time the Contractor can elect to proceed to the second exploration period. The Block 84 (33%) and Block 75 (25%) PSAs are in the ratification process with the Republic of Yemen.

During the year the Company capitalized overhead costs relating to exploration and development activities of $0.7 million (2006 - $0.4 million). Unproven property costs in the amount of $5.0 million in 2007 ($2.6 million in 2006) were excluded in the costs subject to depletion and depreciation representing some of the costs incurred at Block 72, Block 75 and Block 84.

C A N A D A

(000s)		2007			2006
Oil and gas properties	$	80,570		$	57,624
Furniture and fixtures		1,260			1,004
Accumulated depletion and depreciation		(31,023	)		(15,983	)
	$	50,807		$	42,645

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During the year the Company capitalized overhead costs relating to exploration and development activities of $0.5 million (2006 - $0.5 million). Unproven property costs in the amount of $3.9 million in 2007 (2006 - $nil) were excluded in the costs subject to depletion and depreciation.

C E I L I N G  T E S T

An impairment test calculation was performed on property and equipment at December 31, 2007 in which the estimated undiscounted future net cash flows based on estimated future prices associated with the proved reserves exceed the carrying amount of oil and gas property and equipment for each cost centre.

The following table outlines prices used in the impairment test at December 31, 2007:

		Oil		Gas	Condensate
Year	Egypt	Yemen	Canada	Canada	Canada
2008	$ 64.86	$ 88.12	$ 83.25	$ 7.34	$ 92.81
2009	62.29	84.80	80.62	8.04	87.41
2010	61.08	83.23	78.94	7.93	85.47
2011	59.93	81.83	77.30	7.89	83.64
2012	59.53	81.30	76.58	7.99	83.01
Thereafter(1)	2%	2%	2%	2%	2%

(1) Percentage change represents the increase in each year after 2012 to the end of the reserve life.

5 .  L O N G - T E R M  D E B T

(000s)		2007			2006
Revolving Credit Agreement	$	50,000		$	-
Term Loan Agreement		8,000
		58,000			-
Unamortized transaction costs		(1,315	)		-
		56,685			-
Current portion of long-term debt		4,727
	$	51,958		$	-

In September 2007, the Company increased its initial borrowing base of $25.0 million to $50.0 million under the Revolving Credit Agreement and established a new Term Loan Agreement of $13.0 million, which both expire on September 19, 2010. Both borrowing facilities are secured by a first floating charge debenture over all assets of the Company, a general assignment of book debts, security pledge of the Company’s subsidiaries and certain covenants. The Revolving Credit Agreement and the Term Loan Agreement bear interest at the Eurodollar Rate plus three percent and plus six percent, respectively. The Company incurred fees of $1.1 million to establish the long-term debt and reclassified previously unamortized financing costs in the amount of $0.3 million.

The future debt payments on long-term debt, as of December 31, 2007, are as follows:

(000s)
2008	$	4,727
2009	$	3,273
2010	$	50,000

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6 .  A S S E T  R E T I R E M E N T  O B L I G AT I O N S

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties:

(000s)		2007			2006
Asset retirement obligations, beginning of year	$	2,171		$	1,503
Liabilities incurred		238			632
Liabilities settled		(215	)		(66	)
Accretion		164			124
Foreign exchange (gain) loss		397			(22	)
Asset retirement obligations, end of year	$	2,755		$	2,171

At December 31, 2007, the estimated total undiscounted amount required to settle the asset retirement obligations was $3.6 million (2006 - $3.0 million). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extend up to 9 years into the future. This amount has been discounted using a credit-adjusted risk-free interest rate of 6.5% .

7 . S H A R E  C A P I TA L

A )  A U T H O R I Z E D

The Company is authorized to issue an unlimited number of common shares with no par value.

B )  I S S U E D

	2007					2006
	No. of					No. of
(000s)	Shares			Amount		Shares		Amount
Balance, beginning of year	58,883		$	49,360		58,473	$	48,922
Stock options exercised (c)	860			605		410		297
Stock based compensation on exercise	-			260		-		141
Purchase of common shares	(116	)		(97	)	-		-
Balance, end of year	59,627		$	50,128		58,883	$	49,360

During the year ended December 31, 2007, TransGlobe repurchased 115,900 common shares of the Company pursuant to a Normal Course Issuer Bid for a total of $0.5 million. The cost to repurchase common shares in excess of their average book value has been charged to retained earnings.

C )  S T O C K  O P T I O N S

The Company adopted a stock option plan in May 2007 (the “Plan”). The maximum number of common shares to be issued upon the exercise of options granted under the Plan is 5,888,300 common shares. All incentive stock options granted under the Plan have a per-share exercise price not less than the trading market value of the common shares at the date of grant. Stock options granted prior to February 1, 2005 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. Effective February 1, 2005 all new grants of stock options vest one-third on each of the first, second and third anniversaries of the grant date.

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The following tables summarize information about the stock options outstanding and exercisable at December 31, 2007:

	2007			2006
	Number		Weighted-	Number		Weighted-
	of		Average	of		Average
(000s except per share amounts)	Options		Exercise Price	Options		Exercise Price
Options outstanding at beginning of year	3,110		$ 3.12	3,361		$ 2.76
Granted	1,091		$ 4.44	297		$ 4.60
Exercised	(860	)	$ 0.53	(410	)	$ 0.63
Forfeited	(405	)	$ 5.01	(138	)	$ 4.85
Options outstanding
at end of year	2,936		$ 4.11	3,110		$ 3.12
Options exercisable
at end of year	1,602		$ 3.69	2,143		$ 2.20

	Options Outstanding			Options Exercisable
		Weighted-			Weighted-
	Number	Average			Average
	Outstanding	Remaining	Weighted-	Number	Remaining	Weighted-
	at Dec. 31,	Contractual	Average	Exercisable at	Contractual	Average
	2007	Life	Exercise	Dec. 31, 2007	Life	Exercise
Exercise Prices	(000’s)	(Years)	Price	(000’s)	(Years)	Price
C$0.63	20	0.5	C$0.63	20	0.5	C$0.63
C$3.26-C$4.91	1,647	2.7	C$3.82	875	1.2	C$3.32
C$6.03-C$7.74	975	2.8	C$6.20	667	2.8	C$6.20
C$5.19-C$5.31	294	4.5	C$5.24	-	-	-
	2,936	2.9	C$4.73	1,562	1.9	C$4.51

D )  S T O C K - B A S E D  C O M P E N S AT I O N

Compensation expense of $1.1 million has been recorded in general and administrative expenses in the Consolidated Statements of Income and Retained Earnings in 2007 (2006- $1.2 million). The fair value of all common stock options granted is estimated on the date of grant using the lattice-based binomial option pricing model. The weighted average fair value of options granted during the year and the assumptions used in their determination are as noted below:

	2007	2006
Weighted average fair market value
per option (C$)	$ 1.94	$ 2.23
Risk free interest rate (%)	4.60	4.09
Expected lives (years)	5.00	5.00
Expected volatility (%)	45.92	48.79
Dividend per share	0.00	0.00
Early exercise (Year 1/Year 2/Year
3/Year 4/Year 5)	0%/10%/20%/30%/40%	0%/10%/20%/30%/40%

During the year, employees exercised 860,000 stock options. In accordance with Canadian generally accepted accounting principles, the fair value related to these options was $0.3 million at time of grant and has been transferred from contributed surplus to common shares.

(000s)		2007			2006
Contributed surplus, beginning of year	$	2,863		$	1,908
Stock-based compensation expense		959			1,096
Transfer of stock-based compensation expense to common
shares related to stock options exercised		(260	)		(141	)
Contributed surplus, end of year	$	3,562		$	2,863

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8 .  I N C O M E  TA X E S

The Company’s future Canadian income tax assets are as follows:

(000s)		2007		2006
Temporary differences related to:
Oil and gas properties	$	1,727	$	1,292
Non-capital losses carried forward		-		214
Share issue expenses		136		120
	$	1,863	$	1,626

The Company has deductible temporary differences of C$0.5 million related to share issuance expenses and C$6.1 million related to income tax pools in excess of the carrying value of the Company’s Canadian property and equipment. The Company also has $12.8 million of income tax losses in the United States of America. The United States of America losses carried forward expire between 2008 and 2020.

Current income taxes in the amount of $12.6 million (2006 - $9.1 million) represents income taxes incurred and paid under the laws of Yemen pursuant to the PSA on Block 32 and Block S-1 and Egypt pursuant to the PSC on the West Gharib Concession.

Income taxes vary from the amount that would be computed by applying the Canadian statutory income tax rate of 32.12% (2006 - 34.5%) to income before taxes as follows:

(000s)		2007		2006
Income taxes calculated at the Canadian statutory rate	$	8,184	$	12,276
Increases (decreases) in income taxes resulting from:
Non-deductible Crown charges (net of Alberta Royalty Tax Credit)		-		196
Resource allowance		-		(239	)
Non-deductible stock-based compensation expense		349		403
Different tax rates in Yemen and Egypt		4,014		(3,523	)
Other differences		128		279
	$	12,675	$	9,392

9 .  S U P P L E M E N TA L  C A S H  F L O W  I N F O R M AT I O N

Changes in operating non-cash working capital consisted of the following:

(000s)		2007			2006
Operating activities
Decrease (increase) in current assets
Accounts receivable	$	(10,530	)	$	(556	)
Prepaid expenses		(525	)		61
Product inventory		199			(60	)
Working capital acquired		9,108			-
Increase in current liabilities
Accounts payable and accrued liabilities		3,225			1,175
	$	1,477		$	620
Investing activities
Decrease (increase) in current assets
Accounts receivable	$	369		$	228
Prepaid expenses		180			(379	)
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities		(2,512	)		1,186
	$	(1,963	)	$	1,035

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10 .  AC C U M U L AT E D  OT H E R  C O M P R E H E N S I V E  I N C O M E

The balance of accumulated other comprehensive income consists of the following:

(000s)		2007		2006
Accumulated other comprehensive income, beginning of year	$	3,212	$	3,642
Other comprehensive income:
Foreign currency translation adjustment		8,554		(430	)
Accumulated other comprehensive income, end of year	$	11,766	$	3,212

11 .  N E T  I N C O M E  P E R  S H A R E

In calculating the net income per share basic and diluted, the following weighted average shares were used:

(000s)	2007		2006
Weighted average number of shares outstanding	59,595		58,663
Shares issuable pursuant to stock options	1,941		2,662
Shares to be purchased from proceeds of stock options
under treasury stock method	(1,011	)	(763	)
Weighted average number of diluted shares outstanding	60,525		60,562

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. In calculating the weighted average number of diluted common shares outstanding for the year ended December 31, 2007, the Company excluded 2,187,000 options (2006 - 1,109,000) because their exercise price was greater than the annual average common share market price in this period.

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12 .  S E G M E N T E D  I N F O R M A T I O N

In 2007, the Company had oil and natural gas production in three geographic segments, Egypt, Yemen and Canada.

The results of operations for the year ended December 31, 2007 and December 31, 2006 are comprised of the following:

(000s)		Egypt						Yemen				Canada				Total
		2007			2006			2007		2006		2007		2006		2007			2006
Oil and gas sales, net of
royalties and other	$	6,529		$	-		$	61,099	$	56,836	$	20,283	$	13,261	$	87,911		$	70,097
Other income		61			-			39		210		45		39		145			249
		6,590			-			61,138		57,046		20,328		13,300		88,056			70,346
Segmented expenses
Operating expenses		722			-			10,334		8,108		4,212		2,999		15,268			11,107
Depletion, depreciation
and accretion		7,255			37			12,157		11,623		11,760		7,281		31,172			18,941
Income taxes		1,735			-			10,895		9,129		45		263		12,675			9,392
Total segmented expenses		9,712			37			33,386		28,860		16,017		10,543		59,115			39,440
Segmented income	$	(3,122	)	$	(37	)	$	27,752	$	28,186	$	4,311	$	2,757		28,941			30,906
Non-segmented expenses
Derivative loss on commodity
contracts (Note 14)																7,979			83
General and administrative																6,743			4,674
Interest on long-term debt																1,450			-
Foreign exchange loss (gain)																5			(12	)
Other income																(38	)		(34	)
Total non-segmented expenses																16,139			4,711
Net income															$	12,802		$	26,195
Capital expenditures	$	6,904		$	5,365		$	18,437	$	26,585	$	11,674	$	19,605	$	37,015		$	51,555
Acquisition		-			-			-		-		-		-		68,001			-
	$	6,904		$	5,365		$	18,437	$	26,585	$	11,674	$	19,605	$	105,016		$	51,555
Property and equipment	$	62,316		$	7,839		$	53,163	$	46,124	$	50,807	$	42,645	$	166,286		$	96,608
Goodwill		4,313			-			-		-		-		-		4,313			-
Other		13,464			357			5,906		7,453		8,765		7,584		28,135			15,394
Segmented assets	$	80,093		$	8,196		$	59,069	$	53,577	$	59,572	$	50,229		198,734			112,002
Non-segmented assets																5,485			4,471
Total assets															$	204,219		$	116,473

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13 .  C O M M I T M E N T S  A N D  C O N T I N G E N C I E S

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

($000s)
2008	372
2009	355
2010	301
2011	140
2012	21

Pursuant to the Nuqra Concession Agreement in Egypt, TransGlobe had a letter of credit in the amount of $0.3 million outstanding at December 31, 2007. As of January 9, 2008 the letter of credit has been cancelled.

Pursuant to the East Hoshia Development Lease in Egypt, the Company and its partners have committed to drilling three exploration wells and submitted a letter of production guarantee for $4.0 million as security (expiring June 1, 2009).

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 $0.3 million.

Pursuant to the PSA for Block 72, Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $4.0 million ($1.3 million to TransGlobe) during the first exploration period which has been extended to January 12, 2009, for exploration work consisting of seismic acquisition (completed) and one remaining exploration well.

Pursuant to the bid awarded for Block 75, Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $7.0 million ($1.8 million to TransGlobe) for the signature bonus and first exploration period work program consisting of seismic acquisition and one exploration well. The first 36 month exploration period will commence when the PSA has been approved and ratified by the government of Yemen, anticipated to occur during 2008. The Company issued a $1.5 million letter of credit (expiring November 15, 2011) to guarantee the Company’s performance under the first exploration period. The letter is secured by a guarantee granted by Export Development Canada.

Pursuant to the bid awarded for Block 84, Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $20.1 million ($6.6 million to TransGlobe) for the signature bonus and first exploration period work program consisting of seismic acquisition and four exploration wells. The first 42 month exploration period will commence when the PSA has been approved and ratified by the government of Yemen, anticipated to occur in 2008.

14 .  F I N A N C I A L  I N S T R U M E N T S  A N D  R I S K  M A N A G E M E N T

C A R R Y I N G  V A L U E S  A N D  E S T I M A T E D  F A I R  VA L U E S  O F 
F I N A N C I A L  A S S E T S  A N D  L I A B I L I T I E S

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

C R E D I T  R I S K

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.

In Egypt, the Company sold all of its 2007 production to one purchaser. In Yemen, the Company sold all of its 2007 Block 32 production to one purchaser and all of its 2007 Block S-1 production to one purchaser. In Canada, the Company sold primarily all of its 2007 gas production to one purchaser and primarily all of its 2007 oil production to another single purchaser.

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C O M M O D I T Y  P R I C E  R I S K  M A N A G E M E N T

The Company has commodity price risk associated with its sale of crude oil and natural gas.

The Company has entered into various financial derivative contracts and physical contracts to manage fluctuations in commodity prices in the normal course of operations.

			Dated Brent
			Pricing
Period	Volume	Type	Put Call
Crude Oil
September 1, 2007-August 31, 2008	15,000 Bbls/month	Financial Collar	$60.00-$78.55
January 1, 2008-December 31, 2008	12,000 Bbls/month	Financial Collar	$60.00-$81.20
January 1, 2009-December 31, 2009	12,000 Bbls/month	Financial Collar	$60.00-$82.10
November 1, 2007-March 31, 2008	5,000 Bbls/month	Financial Collar	$65.00-$89.35
September 1, 2008-January 31, 2009	11,000 Bbls/month	Financial Collar	$60.00-$88.80
February 1, 2009-December 31, 2009	6,000 Bbls/month	Financial Collar	$60.00-$86.10
January 1, 2010-August 31, 2010	12,000 Bbls/month	Financial Collar	$60.00-$84.25

The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheet with any change in the unrealized positions recorded to income. The fair values of these transactions are based on an approximation of the amounts that would have been paid to or received from counter parties to settle the transactions outstanding as at the Consolidated Balance Sheet date with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates.

F O R E I G N  C U R R E N C Y  E X C H A N G E  A N D  I N T E R E S T  R AT E  R I S K

The Company’s operations are exposed to fluctuations in the foreign currency exchange rates. Variations in the foreign currency exchange rate could have a significant positive or negative impact. The Company manages its foreign currency exchange risk by maintaining foreign currency bank accounts and receivable accounts to offset foreign currency payable and planned expenditures.

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable interest U.S. dollar-denominated debt. No derivative contracts were entered into during 2007 to mitigate this risk.

15 . S U B S E Q U E N T  E V E N T S

On February 1, 2008, the Company announced that it had engaged a financial advisor to assist in the sale of its Canadian assets. While it is likely that this process will lead to the disposition of all or a portion of the Canadian assets, there is no assurance that this will be the case, nor is any forecast given as to the form of action that will be taken. Any proceeds from a potential sale of the Canadian assets will be applied to reduce debt.

On February 5, 2008, TransGlobe Energy Corporation announced the closing of the acquisition of privately-held GHP Exploration (West Gharib) Ltd. (“GHP”). TransGlobe acquired all the shares of GHP for $40.2 million, plus working capital adjustments, effective September 30, 2007. The acquisition is funded from bank debt and cash on hand. GHP holds a 30% interest in the West Gharib Concession area in Egypt.

On February 5, 2008, the Company increased its Term Loan Agreement of $8.0 million to $48.0 million. The Term Loan repayment terms increased to $4.8 million per quarter, commencing June 30, 2008.

16 .  D I F F E R E N C E S  B E T W E E N  G E N E R A L LY  A C C E P T E D  
        A C C O U N T I N G  P R I N C I P L E S  I N  C A N A D A  A N D
        T H E  U N I T E D  S TAT E S  O F  A M E R I C A

The Consolidated Financial Statements have been prepared in accordance with Canadian generally accepted accounting principles (Canadian GAAP or Cdn. GAAP) which differ in certain material respects from those principles that the Company would have followed had its Consolidated Financial Statements been prepared in accordance with United States of America generally accepted accounting principles (U.S. GAAP) as described below:

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CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

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

(000s, except per share amounts)		2007			2006
Net income for the year under Canadian GAAP	$	12,802		$	26,195
Adjustments:
Impairment of Property and equipment and goodwill - Egypt (a)		(10,615	)		-
Net income for the period under U.S. GAAP		2,187			26,195
Purchase of common shares		(375	)		-
Retained earnings, beginning of year - U.S. GAAP		45,565			19,370
Retained earnings, end of year - U.S. GAAP	$	47,377		$	45,565
Net income per share under U.S. GAAP
- Basic	$	0.04		$	0.45
- Diluted	$	0.04		$	0.43

S TAT E M E N T  O F  O T H E R  C O M P R E H E N S I V E  I N C O M E

(000s)		2007		2006
Net income - U.S. GAAP	$	2,187	$	26,195
Currency translation adjustment (d)		8,554		(430	)
Other comprehensive income	$	10,741	$	25,765

C O N S O L I D AT E D  B A L A N C E  S H E E T S

Had the Company followed U.S. GAAP, the balance sheet would have been reported as follows:

(000s)		2007				2006
		Cdn. GAAP		U.S. GAAP		Cdn. GAAP		U.S. GAAP
Current assets	$	31,757	$	31,757	$	17,868	$	17,868
Property and equipment        - Egypt (a)		62,316		56,014		7,839		7,839
- Yemen		53,163		53,163		46,124		46,124
- Canada		50,807		50,807		42,645		42,645
Future income tax asset		1,863		1,863		1,626		1,626
Deferred financing costs (f)		-		1,315		371		371
Goodwill (a)		4,313		-0		-		-
	$	204,219	$	194,919	$	116,473	$	116,473
Current liabilities	$	26,263	$	26,263	$	13,507	$	13,507
Long-term debt (f)		51,958		53,273		-		-
Asset retirement obligation		2,755		2,755		2,171		2,171
		80,976		82,291		15,678		15,678
Share capital (b, c)		50,128		51,831		49,360		51,063
Contributed surplus (b)		3,562		1,654		2,863		955
Accumulated other comprehensive income (d)		11,766		11,766		3,212		3,212
Retained earnings (b, c)		57,787		47,377		45,360		45,565
		123,243		112,628		100,795		100,795
	$	204,219	$	194,919	$	116,473	$	116,473

The reconciling items between share capital and retained earnings for Canadian and U.S. GAAP are $0.8 million related to escrowed shares, and $1.3 million related to flow through shares. The reconciling items between contributed surplus and deficit for Canadian and U.S. GAAP are $0.3 million for the adoption of stock-based compensation under Canadian GAAP and $2.0 million for the 2005 and 2004 stock-based compensation expense under Canadian GAAP, which was not expensed in 2005 under U.S. GAAP APB Opinion No. 25 as interpreted by FASB Interpretation No. 44. The reconciling item between share capital and contributed surplus is $0.4 million for the transfer of compensation expense related to options exercised in 2005 and prior.

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A)  F U L L  C O S T  A C C O U N T I N G

The full cost method of accounting for crude oil and natural gas operations under Canadian and U.S. GAAP differ in the following respect. Under U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum of the present value, discounted at 10%, of the estimated unescalated future net operating revenue from proved reserves plus unimpaired unproved property costs less future development costs, related production costs and applicable taxes. Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecasted pricing and before tax to determine whether impairment exists. In Canada, the impaired amount is measured using the fair value of reserves.

There are no impairment charges under Canadian GAAP as at December 31, 2007. Under U.S. GAAP, the unamortized capitalized cost of the Company’s Egyptian oil and gas properties and goodwill exceeded the full cost ceiling limitation by $10.6 million, net of taxes, which was written off for U.S. GAAP purposes. Because of the volatility of oil and natural gas prices, no assurance can be given that the Company will not experience a writedown in future periods.

B)  S T O C K - B A S E D  C O M P E N S AT I O N

The Company has a stock-based compensation plan as more fully described in Note 7. Under Canadian GAAP, compensation costs have been recognized in the financial statements for stock options granted to employees and directors since January 1, 2002. For U.S. GAAP, the Company has adopted SFAS No. 123R effective January 1, 2006. As permitted by SFAS No. 123R, the Company has applied this change using modified prospective application for new awards granted after January 1, 2006 and for the compensation cost of awards that were not vested at December 31, 2005. In 2005 and prior periods, the Company used the intrinsic value method of accounting for stock options granted to employees and directors whereby no costs were recognized in the financial statements, per APB Opinion No. 25 as interpreted by FASB Interpretation No. 44.

The effect of applying APB Opinion No. 25 in 2005 and prior years to the Company’s U.S. GAAP financial statements resulted in a decrease to stock-based compensation in 2005 by $0.7 million (2004 - $1.3 million) and a corresponding decrease to the contributed surplus account. Also, the deficit would decrease by $0.3 million in 2004 with a corresponding decrease to the contributed surplus account relating to the 2004 adoption entry for Canadian GAAP that is not required for U.S. GAAP. Also, the share capital would decrease by $0.4 million for options exercised since the compensation expense was transferred into common shares for Canadian GAAP, this is not required for U.S. GAAP.

C)  F U T U R E  I N C O M E  TA X E S

The Company records the renouncement of tax deductions related to flow through shares by reducing share capital and recording a future tax liability in the amount of the estimated cost of the tax deductions flowed to the shareholders. U.S. GAAP 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. 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 $Nil in 2007, $Nil in 2006, $Nil in 2005, $Nil in 2004, $0.9 million in 2003, $0.1 million in 2002 and $0.3 million in 2000 representing the tax effect of the flow through shares and a corresponding increase to share capital and decrease to future tax liability by $Nil in 2007, $Nil in 2006, $Nil in 2005, $Nil in 2004, $0.9 million in 2003, $0.1 million in 2002 and $0.3 million in 2000 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.

Under U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted tax rates. The effect of this change between Canadian and U.S. GAAP would result in an increase in future income tax expense and future tax liability of $Nil in 2007, $0.2 million in 2006, $0.2 million in 2005, $0.2 million in 2004 and $0.4 million in 2003 representing the higher enacted tax rates over the substantively enacted tax rates and a corresponding reduction in future income tax expense and future tax liability of $Nil in 2007, $0.2 million in 2006, $0.2 million in 2005, $0.2 million in 2004 and $0.4 million in 2003 to record an additional valuation allowance against the increased tax asset.

D)  E S C R O W E D  S H A R E S

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 188,000 escrow shares were released resulting in an increase in share capital of $0.8 million with the offset to deficit.

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E)  A C C O U N T I N G   F O R   U N C E R T A I N T Y   I N   I N C O M E   TA X E S

Effective January 1, 2007, the Company adopted FASB Interpretation 48, Accounting For Uncertainty in Income Taxes (the “Interpretation” or “FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109, Accounting for Income Taxes. The interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.

Under FIN 48, a company recognizes a tax benefit in the financial statements for an uncertain tax position only if management’s assessment is that the position is “more likely than not” (i.e., a likelihood greater than 50 percent) to be allowed by the tax jurisdiction based solely on the technical merits of the position. The term “tax position” in FIN 48 refers to a position in a previously filed tax return or a position expected to be taken in a future tax return that is reflected in measuring current or deferred income tax assets and liabilities for interim or annual periods. The Interpretation also provides guidance on measurement methodology, derecognition thresholds, financial statement classification and disclosures, recognition of interest and penalties, and accounting for the cumulative-effect adjustment at the date of adoption. Upon adoption, it was determined that there was no effect to TransGlobe.

Tax positions for TransGlobe and its subsidiaries are subject to income tax audits by tax jurisdictions throughout the world. For the Company’s major tax jurisdictions, examinations of tax returns for certain prior tax periods had not been completed as of December 31, 2007. In this regard, examinations had not been finalized for years beginning after 2003 for the Company’s Canadian federal income taxes. The Canadian Revenue Agency had commenced an examination of the Company’s Canadian income tax returns for 2005 to 2006 that is anticipated to be completed in 2008. For other tax jurisdictions, the earliest years for which income tax examinations had not been finalized were as follows: Egypt - 2007 and Yemen - 2007.

F)  D E F E R R E D  F I N A N C I N G  C O S T S

The Company has accounted for transaction costs different for Canadian and U.S. GAAP. Under Canadian GAAP, transaction costs are included with the associated financial instrument whereas under U.S. GAAP transaction costs are presented separately.

G)  R E C E N T  A C C O U N T I N G  P R O N O U N C E M E N T S

THE FAIR VALUE OPTION FOR FINANCIAL ASSETS AND FINANCIAL LIABILITIES

The FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities. The Statement permits entities to choose to measure many financial instruments and certain other items at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. This Statement is expected to expand the use of fair value measurement, which is consistent with the Board’s long-term measurement objectives for accounting for financial instruments.

The Statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The Company is currently assessing the impact of these new requirements on the Consolidated Financial Statements.

F A I R  V A L U E  M E A S U R E M E N T S

The FASB issued SFAS 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements. However, for some entities, the application of this Statement will change current practice.

The Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently assessing the impact of these new requirements on the Consolidated Financial Statements.

O F F S E T T I N G  A M O U N T S  R E L A T E D  T O  C E R T A I N  C O N T R A C T S

The FASB issued an amendment to FIN 39, Offsetting Amounts Related to Certain Contracts to permit a reporting entity to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement that have been offset in accordance with this Interpretation.

The Amendment is effected for fiscal years beginning after November 15, 2007. The Company is currently assessing the impact of these new requirements on the Consolidated Financial Statements.

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B U S I N E S S  C O M B I N AT I O N S

In December 2007, the Financial Accounting Standards Board released FASB 141-R, Business Combinations. This Statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008, which is business combinations in the year ending December 31, 2009 for the Company. The objective of this Statement is to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. The Company will assess the impact of this standard for Business Combinations occurring after January 1, 2009.

N O N  C O N T R O L L I N G  I N T E R E S T S  I N  C O N S O L I D A T E D  F I N A N C I A L  S T A T E M E N T S

In December 2007, the Financial Accounting Standards Board released FASB 160, Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008, which for the Company is the year ending December 31, 2009 and the interim periods within that fiscal year. The objective of this Statement is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements. This standard currently does not impact the Company as it has full controlling interest of all of its subsidiaries.

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R O B E R T  A.  H A L P I N
Chairman of the Board of Directors

C O R P O R AT E  G O V E R N A N C E

At TransGlobe, we strongly believe in good corporate governance. Our Board of Directors is composed of highly experienced individuals with extensive knowledge in the oil and gas exploration and production field as well as finance. The majority of TransGlobe’s six board members are independent directors.

Our Board members are Messrs. Robert A. Halpin, Chairman; Geoffrey C. Chase; Fred J. Dyment; Erwin L. Noyes; Ross G. Clarkson, President and Chief Executive Officer of TransGlobe; and Lloyd W. Herrick, Vice President, and Chief Operating Officer of the Company.

The following Committees are in place:

• Audit Committee, headed by Mr. Fred Dyment, a veteran of the oil and gas industry and a financial expert. He is a member of the board of several public companies.
  This Committee’s primary function is to assist the full Board in fulfilling its oversight responsibilities with respect to financial information provided to shareholders; the system of internal controls established by management; and the audit process.

• Reserves Committee, with Mr. Geoffrey Chase as Chair. Mr. Chase has over 35 years of experience in the oil and gas industry and was with Ranger Oil Limited from 1978 to 2000, retiring as Senior Vice President, Business Development.
  The Reserves Committee’s primary role is to assist the Board of Directors with the annual review of the Company’s petroleum and natural gas reserves.

• Compensation Committee, chaired by Mr. Robert Halpin, a retired petroleum engineer and currently President and Owner of Halpin Energy Resources Ltd., a private international consulting firm.
  The Compensation Committee is responsible for reviewing and overseeing the administration of compensation or remuneration strategies.

• Governance and Nominating Committee, chaired by Mr. Erwin Noyes. Mr. Noyes retired from a long career in both domestic and international oil and gas exploration.
  This Committee is mandated to assist the Board of Directors in discharging its responsibilities by determining the size and composition of the Board; identifying the skills, experience and capability required of Board members; the process of recruiting and orienting new Board members; and structuring the membership and chairmanship of the various Board Committees.

All our committees are composed of independent directors.

TransGlobe has a comprehensive disclosure policy in place to ensure that communications to investors are timely, factual, accurate and broadly disseminated in accordance with all legal and regulatory requirements. Additionally, we have implemented a “whistleblower policy” that allows concerned individuals such as employees or contractors to alert the Board of Directors anonymously to improper accounting or financial practices.

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S U P P L E M E N T A R Y  I N F O R M A T I O N

(000s, except per share amounts)	Year Ended December 31,
Financial	2007	2006	2005	2004	2003
Oil and gas sales	136,709	109,190	90,350	49,495	27,336
Oil and gas sales, net of royalties and other	87,911	70,097	58,911	31,630	17,162
Operating expense	15,268	11,107	10,253	7,064	3,706
General and administrative expense	6,743	4,674	2,821	1,664	1,206
Depletion, depreciation & accretion expense	31,172	18,941	16,990	10,346	6,253
Income taxes	12,675	9,392	8,353	4,995	307
Cash flow from operations**	52,141	46,763	38,077	17,325	9,347
Basic per share	0.87	0.80	0.66	0.32	0.18
Diluted per share	0.86	0.77	0.63	0.31	0.17
Net operating income (by Segment)***
Egypt	4,072	-	-	-	-
Yemen	39,870	39,599	31,283	14,237	8,858
Canada	16,071	10,262	9,493	5,049	1,842
Net income	12,802	26,195	19,850	5,919	5,905
Basic per share	0.21	0.45	0.34	0.11	0.11
Diluted per share	0.21	0.43	0.33	0.10	0.11
Capital expenditures	37,015	51,555	32,654	26,367	13,787
Acquisition	68,001	-	-		-
Working capital	5,494	4,361	9,471	2,840	2,537
Long-term debt	51,958	-	-	-	-
Shareholders’ equity	123,243	100,795	73,637	50,779	30,603
Common shares outstanding
Basic (weighted average)	59,595	58,663	57,903	54,388	52,071
Diluted (weighted average)	60,525	60,562	60,330	56,719	53,779
Total Assets	204,219	116,473	86,286	60,522	35,601
Reserves (MMBoe)
Total Proved	11.9	9.3	7.8	6.7	3.7
Total Proved plus probable	16.4	11.7	10.5	10.4	7.0
Production and Sales Volumes
Total production (Boepd)(6:1)*	5,651	5,093	4,991	3,865	2,635
Total sales (Boepd)(6:1)*	5,692	5,077	4,959	3,796	2,635
Oil and liquids (Bopd)	4,660	4,377	4,312	3,298	2,435
Average price ($ per barrel)	71.30	62.37	50.82	36.24	28.06
Gas (Mcfpd)	6,193	4,204	3,880	2,987	1,200
Average price ($ per Mcf)	6.64	6.18	7.27	5.19	5.24
Operating expense ($ per Boe)	7.35	5.99	5.67	5.09	3.85

*	The differences in production and sales volumes result from inventory changes.
**	Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.
***	Net operating income is a non-GAAP measure that represents revenue net of royalties, current income taxes (paid through prodution sharing) and operating expenses.

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C O R P O R AT E  I N F O R M AT I O N

O F F I C E R S  A N D  D I R E C T O R S	T R A N S F E R  A G E N T  &  R E G I S T R A R
Robert A. Halpin1,2,3	Computershare Trust Company of Canada
Director, Chairman of the Board	Calgary, Toronto, Vancouver
Ross G. Clarkson
Director, President & CEO	L E G A L  C O U N S E L
Lloyd W. Herrick	Burnet, Duckworth & Palmer LLP
Director, Vice President & COO	Calgary, Alberta
Erwin L. Noyes2,3,4
Director	B A N K E R
Geoffrey C. Chase1,2,4	Standard Bank Plc
Director	London, England
Fred J. Dyment1,3,4
Director
	A U D I T O R
David C. Ferguson
Vice President, Finance, CFO	Deloitte & Touche LLP
& Corporate Secretary	Calgary, Alberta
1. Audit Committee
2. Reserves Committee	E V A L U A T I O N  E N G I N E E R S
3. Compensation Committee
4. Governance and Nominating Committee	DeGolyer and MacNaughton Canada Limited
	Calgary, Alberta
S T O C K  E X C H A N G E  L I S T I N G S
	H E A D  O F F I C E
TSX:                              TGL
NASDAQ:                    TGA	TransGlobe Energy Corporation
	#2500, 605 - 5th Avenue S.W.
	Calgary, Alberta, Canada, T2P 3H5
T R A N S F E R  A G E N T  & R  E G I S T R A R
	Telephone: (403) 264-9888
	Facsimile: (403) 264-9898
Computershare Trust Company of Canada
Calgary, Toronto, Vancouver
I N V E S TO R  R E L A T I O N S	E G Y P T  O F F I C E
	8, Abd El-Hamid Hassan St.
Anne-Marie Buchmuller	8th District
Manager, Investor Relations & Assistant Corporate Secretary	Nasr City, Cairo, Egypt
Telephone:                   (403) 268-9868
Email:                              anne-marieb@trans-globe.com
	Web site: www.trans-globe.com