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

EX-99.1 2 exhibit99-1.htm ANNUAL REPORT FOR THE YEAR ENDED DECEMBER 31, 2005 Filed by Automated Filing Services Inc. (604) 609-0244 - TransGlobe Energy Corporation - Exhibit 99.1

Consistent Growth

2005 Annual Report

C O N T E N T S

1	Highlights

2	Message to the Shareholders

4	Operations Review

22	Management’s Discussion and Analysis

41	Consolidated Financial Statements

60	Corporate Information

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. All statements in this annual report, other than statements of historical facts, that address future production, reserve potential, exploration drilling, exploitation activities and events or developments that the Company expects, are forward-looking statements. Although TransGlobe believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Factors that could cause actual results to differ materially from those in forward-looking statements include, but are not limited to, oil and gas prices, well production performance, exploitation and exploration successes, continued availability of capital and financing, and general economic, market or business conditions.

A N N U A L M E E T I N G

TransGlobe Energy Corporation will hold its Annual Meeting on Wednesday, May 10, 2006 at 3:00 p.m. The meeting will be held in the Viking Room at the Calgary Petroleum Club located at 319 - 5th Avenue S.W., Calgary, Alberta, Canada.

H I G H L I G H T S

Average production increased 29%.
Cash flow increased 120%.
Profits increased 235%.
Working capital of $9.5 million with no debt.
Block S-1 pipeline completed.
46 wells drilled.
New discovery on Block 32 in February 2006.
Aggressive exploration and development program planned for 2006.

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

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.

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

I am pleased to submit the 2005 Annual Report to the shareholders. The past year focused on asset development and on preparation for an exciting 2006 drilling program. TransGlobe enters 2006 as a much larger and stronger company prepared to embark upon the largest exploration program in the Company’s history.

In retrospect, 2005 was a year of preparation: preparation to improve exploitation of existing fields; and preparation for the discovery of new fields in 2006.

To improve the exploitation of Block S-1, development wells were drilled and pipeline construction was completed which increased production capacity and lowered operating costs. Block S-1 facility construction and expansion is ongoing to match processing capability to the increased production capability of the An Nagyah field. On Block 32, construction of a diesel topping plant extended the productive life of the pool by lowering operating costs by approximately $3.00 per barrel. Facility expansion on both Blocks 32 and S-1 will increase production in early 2006. An additional benefit of these upgrades is that new fields can now be readily produced once they are tied in.

To prepare for exploration in 2006, seismic acquisition and/or reprocessing were undertaken in all project areas. On Block 32, a new 2-D acquisition and reprocessing has finalized three exploration locations. On Block 72, new 2-D acquisition and reprocessing was undertaken to define two exploration locations. On Nuqra Block 1, reprocessing of 3,190 km of old data and an 800 km 2-D acquisition program prepares for exploration drilling in late 2006. On Block S-1, 3-D surveys were reprocessed and remapped to define drilling locations for 2006. In Canada, the Company successfully drilled its first Coal Bed Methane (“CBM”) wells which required extensive testing work to prepare for further exploitation drilling in 2006.

Four dry exploration wells were drilled in 2005. While every dry hole is a disappointment, it should be remembered that TransGlobe drilled six wells on Block 32 and eight wells on Block S-1 before declaring commerciality. It is impossible for us to find something with every well, but we do learn valuable information with every well. The data from several unsuccessful wells led us to the discovery at Godah #1 in early 2006.

In addition to all the preparation work for the 2006 exploration program, a large portion of the 2005 budget was devoted to development and exploitation of the existing fields. Sixteen development wells (all oil wells) were completed and placed on production and three service wells were completed for water injection. The pipeline was installed connecting the An Nagyah field to the export pipeline and the field’s oil production increased to over 10,000 barrels per day. The production performance of the Lam reservoirs has exceeded our initial expectations for the field, much as Tasour performance has exceeded expectations.

As a result TransGlobe’s production climbed 29% from 2004, exceeding 5,000 Boepd at year end. The increases came primarily from the An Nagyah field on Block S-1 and to a lesser degree from Canada. Block S-1 will continue to be the growth area for 2006. The increased production rates and a 40% increase in oil and gas prices raised the Company’s cash flow and profits to record levels. TransGlobe’s strengthened financial capability has allowed us to increase exploration and development investments in all operating areas.

The challenge of 2005 and of the future is adapting to the “overheated“ business environment created by record commodity prices. High activity levels caused delays and increased costs in every operational area of the Company. Drilling, completion and pipeline equipment crews are all working at 100% utilization, leading to delays in Canadian production increases. Timelines for Government approvals have stretched out, leading to delays in both Yemen and Canada. The pipeline construction and facility expansion

on Block S-1 were affected by delays in approvals and by slower equipment deliveries. The change in the partnership on Block S-1 also stalled some work. As a result the Company’s exit production rate of 5,000 Boepd was lower than anticipated, and production increases from new wells in Canada and Yemen are not expected to be realized until mid 2006. The Company has increased staffing levels by almost 100% in order to adapt to this hectic, highly competitive environment. Longer timelines and higher costs are the new reality in this business environment of higher oil prices.

The Year Ahead

In 2006 we embark on the largest exploration program in the Company’s history. Revenues have increased dramatically with higher volumes and record prices, leading to an expanded exploration budget for 2006.

To maintain our high growth rate we must find new reserves. Therefore the next two years will see a much greater focus on exploration drilling. We expect to drill twelve “wildcat” exploration wells in 2006, testing prospects with estimated sizes varying between 10 and 80 million barrels. Not all will be successful. It takes only one major success to fundamentally change Company performance.

The first exploration well of 2006, Godah #1 on Block 32, is a new discovery. If the appraisal drilling proves Godah to be a commercial discovery, it will increase production and reserves, and will also extend the life of the mature Tasour field. With a new producing field, the tail end of production from Tasour can be economically produced. Without an offsetting discovery, the fixed operating cost of the facility might have squeezed profitability at an earlier date.

It takes courage and tenacity to operate in a business where one discovery in ten ventures is the norm for exploration drilling. To mitigate risk we concentrate on oil prone areas where we have years of experience. We use intense geological screening, maintain a broad portfolio of prospects, both domestic and international, and partner to broaden our chances. The more wells drilled the greater chance of encountering a commercial deposit.

Development work will continue into 2006, with expansion of facilities planned for Block S-1 and Block 32 and in Canada. Additional work is also planned to unlock the unrealized value in Block S-1. The An Naeem gas/condensate is a near term development opportunity that could increase production. Further study may also determine a way forward for the Harmel pool. The 2006 Canadian program will focus on development of our conventional oil and gas properties and a new program of coal bed methane development drilling. The program in Canada is mainly low risk development or appraisal drilling. Canadian production provides balance and diversification to our international ventures and has proven to be an excellent investment.

When the 2006 drilling program is complete, only a small fraction of our land base will have been explored. There are still years of work in front of us. TransGlobe’s land base distinguishes the Company from much of its competition. The competition for new lands is intense and TransGlobe obtained its enviable position at lower prices than found in today’s market. Our producing properties in Yemen and Canada provide a solid foundation of financial strength to pursue international exploration.

I mentioned that high reward international exploration requires courage and tenacity. It also requires financial resources, time, expertise and perseverance. TransGlobe has the financial resources and technical acumen to undertake high reward international exploration. More importantly the TransGlobe staff meet the task with courage, tenacity and optimism.

Ross G. Clarkson
President, CEO and Director

March 8, 2006

O P E R AT I O N S R E V I E W

INTERNATIONAL ACTIVITY

BLOCK 32, REPUBLIC OF YEMEN

Tasour production averaged 13,946 Bopd (1,926 Bopd to TransGlobe).
Drilled seven wells (2 oil, 2 injectors, 1 potential oil and 2 dry).
Diesel topping plant completed.
New discovery at Godah #1 (2006).

Background

TransGlobe entered into its first international project in January 1997 through a farmout agreement and joint venture on Block 32. The Company has since participated in acquisition of seismic data, drilling of twenty-six wells and construction of production facilities. The Tasour field commenced production in November, 2000. The joint venture currently consists of TG Holdings Yemen Inc. (a wholly-owned subsidiary of TransGlobe Energy Corporation) with a 13.81087% working interest and partners Ansan Wikfs Hadramaut Ltd. and DNO ASA holding the balance (“the Block 32 Joint Venture Group”). DNO ASA (an independent Norwegian oil company) is the operator of the Block. The Yemen Oil Company (“YOC” - a Yemen government oil company) has a 5% interest in the Block 32 Joint Venture Group’s production sharing oil.

The Block 32 development area covers 591 square kilometers (146,070 acres). The development area encompasses all of the Tasour structure and several additional prospects. The approved development/production period extends until the year 2020, with an optional five-year extension to 2025.

PSA Summary (13.81087% working interest)

TransGlobe commenced production on Block 32 in November, 2000. Production from the block is shared between the Block 32 Joint Venture Group and the Ministry of Oil and Minerals, Republic of Yemen (“MOM”) pursuant to a Production Sharing Agreement (“PSA”). The PSA provides for MOM to receive a 3% royalty of gross production. The balance of production is split between cost recovery oil and production sharing oil. Cost recovery oil is up to a maximum of 60% of the production after deducting the 3% royalty. Cost recovery oil allows the Block 32 Joint Venture Group to

recover operating costs and exploration and development expenditures as outlined in the PSA. The remaining oil is allocated to production sharing oil shared 65% by MOM, 33.25% by the Block 32 Joint Venture Group and 1.75% to YOC. The Block 32 Joint Venture Group’s Yemen royalties and income taxes are paid out of MOM’s share of production sharing oil. These terms remain in place until gross proved recoverable reserves exceed 30 million barrels of oil (assessed every two years) or until gross production exceeds 25,000 Bopd at which time the terms would revert to the original PSA terms in place prior to the 1999 PSA amendment. The original PSA terms provided for a 10% royalty on gross production with the remaining 90% of production split between cost recovery oil and production sharing oil. Cost recovery oil would be to a maximum of 25%, with the remaining oil allocated to production sharing oil shared 77% by MOM and 23% by the Block 32

Joint Venture Group. The proved recoverable reserve determination is conducted every two years from the anniversary of first oil production. At November 4, 2004, the proved recoverable reserves recognized by an independent third party audit were less than 10 million barrels. This audit was approved by MOM. The next Block 32 MOM audit will be conducted effective November 4, 2006.

2005 Activities and Results

During 2005, the Block 32 Joint Venture Group work program consisted of a 70 km 2-D seismic program north and west of the Tasour field and the drilling of seven wells. In the Tasour area three development wells (2 oil wells and 1 suspended), two dedicated water injectors and one dry hole (appraisal of an eastern extension to Tasour) were drilled. The Balan #1 exploration well was drilled and abandoned after failing to test hydrocarbons from the Saar or Basement zones. The well was located approximately 11 km northwest of the Tasour field.

2005 Drilling Results

			Initial Production
Well	Well Type	Status	Test (Bopd - gross)	Formation
Tasour #15	Injector	Water Injector	N/A	Qishn
Tasour #16	Development	Suspended	N/A	Qishn
Tasour #17	Appraisal	D&A	N/A	Qishn
Tasour #18	Development	Oil Producer	3,000	Qishn 1-C
Tasour #19	Development	Oil Producer	1,300	Qishn 1-A
Tasour #20	Injector	Water Injector	N/A	Qishn
Balan #1	Exploration	D&A	N/A	Sarr/Basement

Production

The Tasour field averaged 13,946 Bopd (1,926 Bopd to TransGlobe) during 2005. With the boundaries of the Tasour field defined and production maturing, two facility optimization projects were constructed at the central production facility (“CPF”) during 2005. The first project, a diesel topping plant, was installed to reduce operation costs by manufacturing diesel from produced crude oil. The diesel topping plant was commissioned in December 2005 and is currently producing 380 Bpd of diesel which is used to generate electricity to run all

the pumps and facilities on the Block. The second project, to expand CPF fluid handling and water injection capacity, will be completed in April 2006. Several dedicated water injectors were drilled to handle increased volumes associated with the expansion. It is expected that production from the Tasour field will average approximately 8,000 Bopd during 2006 assuming the CPF expansion is operational in April.

2005 Tasour Production by Quarter (Bopd)

	Q-1	Q-2	Q-3	Q-4
Gross field production rate	16,167	13,838	14,302	11,527
TransGlobe working interest	2,233	1,911	1,975	1,592
TransGlobe net (after royalties)	1,567	1,060	1,100	834
TransGlobe net (after royalties and tax)	1,357	775	809	573

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

2006 Outlook

The Block 32 Joint Venture Group approved a six well drilling program (firm and contingent) for 2006 focused primarily on exploration (five exploration wells and one development well).

The first exploration well of 2006 at Godah #1 (side track) tested 1,839 Bopd from the Qishn formation. A second well, Godah #2 will be drilled approximately 1,100 meters northeast of Godah #1 to appraise the new oil pool. It is expected that Godah #2 will commence drilling in April. Additional drilling on the Godah structure will be dependent upon the results of Godah #2. The operator is currently evaluating production options, however it is expected that the Godah discovery could be connected to the Tasour CPF with a 23 km pipeline in the latter half of 2006.

In addition to the appraisal/potential development of Godah, a second drilling rig will commence drilling Tasour #21 in late March. Tasour #21 will be drilled on the south eastern flank of the Tasour field to evaluate a deeper Sarr prospect. An exploration well, Tasour #22, will be drilled south of the Tasour field to evaluate a fractured basement prospect.

BLOCK 72, REPUBLIC OF YEMEN

PSA became effective July 12, 2005.
255 km of 2-D seismic completed.
Exploration drilling planned for late 2006.

Background

Block 72 was acquired in a bid round in 2004 by a Joint Venture Group comprised of DNO ASA (34%), TG Holdings Yemen Inc. (33%) and Ansan Wikfs (Hadramaut) Limited (33%) (“Block 72 Joint Venture Group”). TG Holdings Yemen Inc. is a wholly owned subsidiary of TransGlobe Energy Corporation. The YOC has a 10% interest in the Block 72 Joint Venture Group’s production sharing oil. The Block 72 PSA was ratified by the Yemen parliament on June 18, 2005 and became law following the Presidential decree on July 12, 2005. Block 72 encompasses 1,822 square kilometers (approximately 450,234 acres) located in the western Masila Basin adjacent to the billion barrel Nexen Masila Block. The Block 72 Joint Venture Group committed to a seismic acquisition program and the drilling of two exploration wells during the first exploration period of thirty months.

PSA Summary (33% working interest)

Production from the Block will be shared between the Block 72 Joint Venture Group and MOM pursuant to a PSA. The PSA provides for MOM to receive a 3% royalty of gross production up to 25,000 Bopd in a month (escalating thereafter), with the remaining 97% of production split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum of 50% of the production after deducting the 3% royalty. The remaining oil allocated to production sharing oil is shared 64% MOM, 32.4% Block 72 Joint Venture Group and 3.6% to YOC (increasing share to the government on incremental production more than 25,000 Bopd).

2005 Activities and Results

A 255 km 2-D seismic acquisition program commenced in the fourth quarter of 2005 and was completed in January 2006.

2006 Outlook

The new seismic data is currently being processed along with 500 km of existing 2-D seismic data. Interpretation and mapping is expected to be completed during the second quarter of 2006. A two well exploration program is scheduled to commence drilling in the fourth quarter of 2006.

BLOCK S-1, REPUBLIC OF YEMEN

Field production averaged 8,792 Bopd (2,198 Bopd to TransGlobe).
Pipeline connection to export line completed.
Drilled eight wells (5 oil and 3 dry).
Lam B successfully appraised with a horizontal well.
New operator effective January 30, 2006.

Background

TransGlobe entered into its second international exploration venture in 1997 by signing a PSA for the Damis S-1 Block (“Block S-1”) with MOM. TG Holdings Yemen Inc. (a wholly owned subsidiary of TransGlobe Energy Corporation) entered into a joint venture arrangement for Block S-1 with a subsidiary of Vintage Petroleum Inc. (“Vintage”), a U.S. independent exploration and production company (“Block S-1 Joint Venture Group”). During 2000 Vintage earned a 75% working interest in Block S-1 by funding 100% of the work commitments for the first exploration period of the Block S-1 PSA and by spending a minimum of $20 million. TransGlobe has retained a 25% working interest in Block S-1. In September 2005 Occidental Petroleum Corporation (“Oxy”) announced the acquisition of Vintage. The acquisition closed on January 30, 2006. Oxy through its wholly owned subsidiary (Vintage) is now the operator of Block S-1. The YOC has a 17.5% interest in the Block S-1 Joint Venture Group’s share of production sharing oil.

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

To date, the Company has participated in two 3-D seismic surveys, drilling of 27 wells, the construction of production facilities and commencement of production in March 2004.

PSA Summary (25% working interest)

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

2005 Activities and Results

During 2005, the Block S-1 Joint Venture Group reprocessed the 1999 An Naeem 3-D seismic program and drilled eight wells resulting in five oil wells and three dry holes. The main focus in 2005 was the use of horizontal drilling to develop the An Nagyah Lam A pool (3 wells in 2005) and to evaluate the potential of the Lam B pool (1 well in 2005). In addition to the Lam A and B drilling, oil was tested from the Lam B formation south of the main bounding fault, which may be appraised in the future.

2005 Drilling Results

			Initial Production
Well	Well Type	Status	Test (Bopd - gross)	Formation
An Nagyah #14	Appraisal	Oil	80	Lam B
An Nagyah #15Hz	Development	Oil	2,625	Lam A
An Nagyah #16Hz	Development	Oil	2,520	Lam A
An Nagyah #17Hz	Development	Oil	3,250	Lam A
An Nagyah #18Hz	Appraisal	Oil	1,300	Lam B
Malaki #1	Exploration	D&A	N/A	Alif/Lam
Markhah #1	Exploration	D&A	Non-commercial oil	Shuqra and Basement
Hatat #1	Exploration	D&A	N/A	Basement

Production

Production from Block S-1 averaged 8,792 Bopd (2,198 Bopd to TransGlobe) during 2005. Production increased throughout the year with the addition of wells and facilities. Production during 2005 was partially constrained, initially by the early production trucking operations and later by insufficient capacity at the processing facility. A 30 km (18 mile) 10 inch pipeline connecting the An Nagyah field with the Jannah Hunt operated Halewah production facility and export pipeline was constructed during the first half of 2005. The pipeline has an ultimate capacity of 80,000 Bopd to provide expansion capabilities for future developments. The pipeline became operational in early July and the trucking operations ceased, thereby reducing operating costs. The CPF was expanded throughout 2005 to handle 10,000 Bopd and re-injection of associated gas production. Production increased during 2005 to a level of 12,300 Bopd (3,075 Bopd to TransGlobe) in early December. Facility constraints associated with cooler temperatures in late December and in January restricted production to approximately 9,300 Bopd (2,325 Bopd to TransGlobe). Field production increased to 12,000 Bopd, following the installation of additional treating capacity at the CPF in late February 2006. Additional equipment was ordered to increase the CPF capacity to 15,000 Bopd in the third quarter 2006.

2005 Production by Quarter (Bopd)

	Q-1	Q-2	Q-3	Q-4
Gross field production rate	7,332	8,164	8,939	10,704
TransGlobe working interest	1,833	2,041	2,235	2,676
TransGlobe net (after royalties)	1,284	1,421	1,558	1,472
TransGlobe net (after royalties and tax)	1,146	1,247	1,389	1,258

Production equipment was installed at Harmel #1 and Harmel #2 in March 2005. The initial Harmel #1 production rate of approximately 100 Bopd has declined to a rate of less than 15 Bopd. The Harmel #2 well encountered a poorer quality reservoir and has less productive capacity than the Harmel #1 well. Although the production rates are disappointing, it is expected that new wells may be drilled targeting deeper prospects (Alif and Basement) on the Harmel structure. Future wells could provide additional reservoir information on the shallow medium gravity oil (22 degree API) pool. The Harmel pool (500 to 800 meters in depth) encompasses 15 square miles as defined by 3-D seismic and represents a potentially significant accumulation of oil in place. The shallow zones require several more wells (vertical and/or horizontal) to fully evaluate the economic viability of the oil accumulation. For 2006 the partnership plans to focus on developing the light oil discovery at An Nagyah as well as other potential leads. Therefore no additional work on Harmel is currently planned for 2006.

2006 Outlook

The Block S-1 Joint Venture Group approved a capital budget of $48 million ($12 million to TransGlobe) for 2006 projects (firm and contingent). The program includes additional 3-D seismic acquisition over the southern portion of Block S-1, a continuous drilling program (a mixture of development horizontal wells and exploration wells) and expansion of the production facilities. Vintage (the operator of Block S-1) was acquired and merged into Oxy effective January 30, 2006. Oxy is currently reviewing the Block S-1 prospects and approved 2006 work program. It is expected that the Joint Venture Group will meet in the next few months to discuss the 2006 work program. TransGlobe is very pleased to have Oxy as a new partner in Block S-1. In addition to being a very successful international oil and gas exploration company, Oxy also brings a vast regional knowledge of Yemen from their ownership in two producing blocks in the prolific Masila Basin (Block 14 and Block 10) and more recently, their drilling in Block 20 immediately north west of Block S-1. Oxy was also awarded Block 75 in 2005, which bounds Block S-1 to the south.

During the first quarter of 2006, two horizontal development wells (An Nagyah #19 and #20) targeting the Lam A pool have been drilled and tested at rates of 3,226 Bopd and 2,992 Bopd, respectively. The drilling rig is currently drilling the An Nagyah #21 Lam B development well. Following An Nagyah #21 the rig will drill another development well and Wadi Bayhan. The Wadi Bayhan prospect is an Alif/Lam prospect. It is expected that up to ten wells will be drilled on Block S-1 during 2006.

The approved 2006 work program included funds to evaluate the feasibility of producing additional stabilized condensate from the An Nagyah solution gas and possible make-up gas from the An Naeem gas condensate pool. An Naeem gas (make-up gas) could be used to maintain reservoir pressure and improve oil recoveries from the An Nagyah pool. A gas cycling scheme to recover additional condensate from the An Naeem gas condensate pool may also be studied.

Block S-1 Prospects

CPF - Central Production Facility --- Pipeline

NUQRA BLOCK 1, ARAB REPUBLIC OF EGYPT

Surface geological field work completed.
3,190 km of historical 2-D seismic data reprocessed.
800 km 2-D seismic acquisition commenced.

Background

In July 2004, TransGlobe Petroleum Egypt Inc. (“TransGlobe Egypt”), a wholly owned subsidiary of TransGlobe Energy Corporation, entered into a Farmout Agreement with Quadra Egypt Limited (“QEL”), a subsidiary of Quadra Resources Corp. headquartered in Calgary, and Rampex Petroleum International (“Rampex”) headquartered in Cairo, Egypt (“Nuqra Block 1 Joint Venture Group”). Quadra Resources was subsequently acquired by Arsenal Energy Inc. (“Arsenal”) of Calgary in 2005 and the Rampex interest was assigned to Petrosina Limited and Wantapex Limited in 2004. QEL is a wholly owned subsidiary of Arsenal.

Under the terms of this agreement TransGlobe Egypt earns a 50% interest in the Nuqra Concession by paying 100% of the initial $6.0 million of expenditures in the Period One and the Period Two work programs. After the initial $6.0 million has been spent, costs will be shared 60% TransGlobe Egypt and 40% Arsenal. Petrosina and Wantapex will be carried until first production. The cost of the Petrosina and Wantapex carry will be recovered by TransGlobe Egypt and Arsenal from 100% of the Petrosina and Wantapex cost oil and 50% of the Petrosina and Wantapex production sharing oil. TransGlobe Egypt is the Operator of the Nuqra Block.

The Nuqra Concession Agreement Period One work program requires expenditure of $2.0 million to reprocess existing seismic and to acquire new seismic within the first two years. Upon expiry of the Period One term, there is an option to proceed to the Period Two work program. Period Two requires completion of a two well drilling program, with a minimum expenditure of $4.0 million over a period of three years. Upon expiry of the Period Two term there is an option to proceed to the Period Three work program. Period Three requires completion of a two well drilling program, with a minimum expenditure of $5.0 million over a final three year term. Exploitation of discovered commercial fields will continue under a Development Lease for a further 20 years.

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

Concession Agreement Summary (50% working interest)

Production from the Block will be shared between the Nuqra Block 1 Joint Venture Group and the government pursuant to a Concession Agreement. The Concession Agreement terms allow for the recovery of costs up to a maximum of 40% of gross production. The remaining balance of production is then shared on a 70:30 basis between the government and the Nuqra Block 1 Joint Venture Group, respectively, for the first 25,000 Bopd. Production sharing above 25,000 Bopd is shared on an 80:20 basis.

2005 Activities

TransGlobe completed the reprocessing of 3,190 km of existing 2-D seismic data on the Nuqra Block 1 in the summer of 2005. The reprocessed seismic data has been mapped and interpreted, resulting in eight identified leads in the central area of the basin.

2006 Outlook

An 800 km 2-D seismic acquisition program commenced in early January 2006 and is expected to be completed by the end of March. To save on mobilization and demobilization costs the seismic acquisition program was bid jointly with Centurion Energy who holds the exploration concession adjacent to the Nuqra Block. TransGlobe is preparing for a two well exploration drilling program to commence in late 2006. Tenders for long lead items and a drilling rig are out for bid. It is expected that the availability of a suitable drilling rig will determine when drilling commences.

The Company has already exceeded the Period One work commitments of $2.0 million and plans to commit to Period Two at the end of Period One on July 18, 2006. There is a mandatory relinquishment of 25% of the Block at the end of Period One.

Nuqra Sub Basin

2006 2-D Seismic Program, 800 km

CANADA

Production averaged 867 Boepd.
Drilled 31 wells (21 gas, 7 oil and 3 dry).
Successful Horseshoe Canyon CBM wells at Nevis and Morningside.

Background

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

2005 Activities and Results

In early 2005 the Canadian budget and work program was increased from 10-15 wells to 30-35 wells due to increased corporate cash flow associated with record commodity prices. The Company participated in a total of 31 wells resulting in 21 gas, 7 oil and 3 dry for an overall success rate of 90%. The majority of the wells were drilled in the Nevis, Gadsby and Morningside areas of central Alberta. Of the 31 wells drilled, TransGlobe had an average working interest of 79% in 26 wells and a carried interest after payout in five wells which were farmed out to a third party. Included in the 31 wells were eight successful coal bed methane (“CBM”) wells targeting the Horseshoe Canyon coals in the Nevis (1 well) and Morningside (7 wells) areas.

The Company acquired 15,100 net acres of exploration land in 2005, bringing the Company’s total net undeveloped land to 33,300 acres at year end.

2005 Drilling Results

	Oil			Gas			Dry			Total
Area	Gross	(Net)		Gross	(Net)		Gross	(Net)		Gross	(Net)
Nevis	5	(4.7	)	8**	(6.6	)	1	(1.0	)	14**	(12.3	)
Gadsby*	1	(1.0	)	4**	(2.0	)	1	(1.0	)	6**	(4.0	)
Morningside**	1	(0.8	)	7**	(1.4	)	-	-0		8**	(2.2	)
Other	-	-0		2**	(1.6	)	1	(0.5	)	3**	(2.1	)

Total	7	(6.5	)	21**	(11.6	)	3	(2.5	)	31**	(20.6	)

* Includes 2 farm out wells.
** Includes 3 farm out wells.

The Canadian drilling budget was increased from 10-15 wells to 30-35 wells in the second quarter of 2005, resulting in the majority of the wells being drilled in the fourth quarter.

2005 Wells (excluding farm outs)	Q-1	Q-2	Q-3	Q-4	Total
Total drilled	0	7	4	15	26
Successful drilled	0	6	3	14	23
Pipeline connected	0	2	1	4	7

Production

In Canada, production increased 28% from an average of 677 Boepd in 2004 to 867 Boepd (75% natural gas) in 2005. In December, production averaged 889 Boepd. Several wells were connected during late December and January which increased Canadian production to approximately 1,100 Boepd in February. There are an additional 14 (11 net) wells, representing 400 Boepd to the Company, still requiring pipeline connections. This work is anticipated to be carried out during the first half of 2006.

2005 Canadian Production by Quarter (Boepd)

	Q-1	Q-2	Q-3	Q-4
TransGlobe working interest	821	706	1,075	864
TransGlobe net (after royalties)	673	600	887	691

2006 Outlook

The approved 2006 Canadian budget of $20.4 million is primarily focused on development drilling, completions and facilities. It is expected that 25-30 wells will be drilled during 2006 including 12-16 wells targeting the Horseshoe Canyon coals in the Nevis and Morningside areas. Approximately 20% of the budget is dedicated to exploration drilling and land acquisitions.

Up to mid-March of 2006 the Company participated in drilling 4 (2 net) potential gas wells. To ensure the 2006 program can be carried out the Company has secured access to drilling rigs in central Alberta with several other companies. The Company commenced drilling in the Nevis area in March, and expects to drill 8-10 wells in central Alberta during the next two to three months depending on surface access conditions associated with spring breakup. In addition, the Company has filed applications to drill four CBM wells per section in the Nevis area. It is expected that the CBM Nevis drilling program (10-12 wells) will commence in the second or third quarter.

CONSOLIDATED PRODUCTION

The following table is a summary of working interest production, before royalty, by country, for the years ended 2005 and 2004:

2005

2004

Oil & Liquids

Gas

Total

Oil & Liquids

Gas

Total

Bopd

Mcfpd

Boepd

Bopd

Mcfpd

Boepd

Yemen

4,124

3,188

Canada

220

3,880

867

179

2,987

677

Total

4,344

3,880

4,991

3,367

2,987

3,865

RESERVES AND ESTIMATED FUTURE NET REVENUES

In 2004 and 2005, DeGolyer and MacNaughton Canada Limited (“DeGolyer”) of Calgary, Alberta, independent petroleum engineering consultants based in Calgary and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company’s Reserve Committee, to independently evaluate 100% of TransGlobe’s reserves as at December 31, 2004 and December 31, 2005.

Total Proved reserves for the Company increased 18% from 6,664 MBoe (“MBoe” thousand barrels of oil equivalent at 6:1) at December 31, 2004; to 7,828 MBoe at December 31, 2005 replacing 164% of the 1,822 Mboe produced during 2005. The major increases in proved reserves were attributable to the An Nagyah field on Block S-1, Yemen and new drilling in Canada. The An Nagyah increases were primarily associated with the development drilling in the Lam A pool and new reserves in the Lam B pool. In Canada, new reserve additions associated with the 2005 drilling program at Nevis and Morningside, were offset by downward revisions at Gadsby.

Total Proved plus Probable reserves for the Company increased by 1% from 10,427 MBoe at December 31, 2004 to 10,482 MBoe at December 31, 2005 replacing 103% of 2005 production. Increases in Probable reserves associated with the An Nagyah field on Block S-1, Yemen, and new drilling in Canada, were offset by the removal of Probable reserves attributed to the eastern extension of the Tasour field on Block 32, Yemen, and the reassignment of Probable reserves to Proved reserves through development drilling in Canada and in Yemen on the An Nagyah field.

The Company’s Reserves Committee, comprised of independent directors, has reviewed and recommended acceptance of the 2005 year end reserve evaluations prepared by DeGolyer.

The 2004 and 2005 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.

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.

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

Reserves

2005

2004

Light & Medium

Natural Gas

Total

Total

Crude Oil

Natural Gas

Liquids

2005 Boe

2004 Boe

Company

Gross*

Net**

Gross*

Net**

Gross* Net**

Gross*

Net**

By Category

(MBbls)

(MMcf)

(MBbls)

(MBoe)

(MBoe)

Proved

Producing

3,117

1,834

5,835

4,700

193

140

4,283

2,758

4,074

2,876

Non-producing

870

520

2,485

1,978

1,326

879

444

297

Undeveloped

1,721

898

2,869

2,427

2,219

1,316

2,146

1,455

Total Proved

5,708

3,252

11,189

9,105

255

183

7,828

4,953

6,664

4,628

Total Proved plus Probable

7,269

4,042

16,975

13,754

384

273

10,482

6,608

10,427

6,916

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

Reserves

2005

2004

Oil & Liquids

Gas

Total Boe

Total Boe

Company

Gross

Net

Gross

Net

Gross

Net

Gross

Net

By Area

(MBbls)

(MMcf)

(MBoe)

(MBoe)

Proved

Yemen

5,342

2,927

5,342

2,927

4,421

2,884

Canada

621

508

11,189

9,105

2,486

2,026

2,243

1,744

Total Proved

5,963

3,435

11,189

9,105

7,828

4,953

6,664

4,628

Proved plus Probable

Yemen

6,814

3,636

6,814

3,636

7,217

4,441

Canada

839

680

16,975

13,754

3,668

2,972

3,210

2475

Total Proved plus Probable

7,653

4,315

16,975

13,754

10,482

6,608

10,427

6,916

Proved Reserves Reconciliation

	Yemen		Canada				Total
	Oil		Oil & Liquids		Natural Gas		Boe
	Gross		Gross		Gross		Gross
	(MBbls)		(MBbls)		(MMcf)		(Mboe)
Reserves at Dec. 31, 2004	4,421		433		10,860		6,664
Extensions/Discoveries	1,518		397		6,782		3,045
Technical Revisions	921		(45	)	(5,014	)	40
Acquisitions	-		-		-		-
Divestitures	-		-		-		-
Economic Factors	(13	)	(84	)	(23	)	(100	)
Production	(1,505	)	(80	)	(1,416	)	(1,821	)
Reserves at Dec. 31, 2005	5,342		621		11,189		7,828

Proved Plus Probable Reserves Reconciliation

	Yemen		Canada				Total
	Oil		Oil & Liquids		Natural Gas		Boe
	Gross		Gross		Gross		Gross
	(MBbls)		(MBbls)		(MMcf)		(Mboe)
Reserves at Dec. 31, 2004	7,217		585		15,752		10,427
Extensions/Discoveries	1,848		478		9,110		3,845
Technical Revisions	(698	)	(28	)	(6,434	)	(1,798	)
Acquisitions	-		-		-		-
Divestitures	-		-		-		-
Economic Factors	(48	)	(116	)	(37	)	(171	)
Production	(1,505	)	(80	)	(1,416	)	(1,821	)
Reserves at Dec. 31, 2005	6,814		839		16,975		10,482

Estimated Future Net Revenues

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 price received December 31 of the respective reporting periods. The prices were held constant for the life of the reserve.

Present Value of Future Net Revenues, Before Income Tax*

					Constant Pricing
		Dec. 31, 2005					Dec. 31, 2004
		Discounted at					Discounted at
	Undis-					Undis-
($MM)	counted	5%	10%	15%	20%	counted	5%	10%	15%	20%
Proved
Yemen *	78.5	71.0	64.6	59.0	54.1	49.4	45.3	41.6	38.4	35.6
Canada **	69.9	59.6	51.6	45.2	40.0	52.8	43.7	37.2	32.3	28.4
Total Proved	148.4	130.6	116.1	104.2	94.0	102.2	89.0	78.8	70.7	64.0
Proved plus Probable
Yemen *	108.0	96.0	86.0	77.5	70.2	78.5	69.8	62.5	56.3	51.1
Canada **	106.2	87.5	73.7	63.1	54.8	75.1	59.7	49.6	42.3	36.8
Total Proved plus Probable	214.1	183.5	159.7	140.6	125.0	153.6	129.5	112.1	98.6	87.9

* Yemen future net revenues presented are after Yemen income tax.
** Canadian values converted at the December 31, 2005 and December 31, 2004 exchange rates of 1.1630 and 1.2020 $US/$C respectively.

The estimated future net revenues presented below are calculated using the independent engineering evaluator’s price forecast.

		Present Value of Future Net Revenues, Before Income Tax*
			Independent Evaluator’s Price Forecast
		Dec. 31, 2005					Dec. 31, 2004
		Discounted at					Discounted at
	Undis-					Undis-
($MM)	counted	5%	10%	15%	20%	counted	5%	10%	15%	20%
Proved
Yemen *	75.6	68.7	62.8	57.6	53.0	43.5	40.3	37.5	34.9	32.6
Canada **	70.4	61.3	54.1	48.2	43.4	43.4	36.6	31.6	27.8	24.8
Total Proved	146.0	130.0	116.8	105.8	96.4	86.9	76.9	69.1	62.7	57.4
Proved plus Probable
Yemen *	96.6	86.6	78.1	70.8	64.6	65.7	59.4	54.1	49.4	45.4
Canada **	104.0	87.7	75.4	65.9	58.3	61.7	49.7	41.8	36.2	31.9
Total Proved plus Probable	200.6	174.3	153.5	136.7	122.9	127.4	109.1	95.9	85.6	77.3

* Yemen future net revenues presented are after Yemen income tax.
** Canadian values converted at the December 31, 2005 and December 31, 2004 exchange rates of 1.1630 and 1.2020 $US/$C respectively.

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

December 31, 2005

December 31, 2004

Oil

Natural Gas

Oil

Natural Gas

US$/Bbl

US$/Mcf

US$/Bbl

US$/Mcf

Yemen *

56.42

39.58

Canada **

52.49

8.08

37.05

5.93

* Yemen prices are based on prices received for Tasour production from Block 32 and for An Nagyah production from Block S-1.
** Canadian prices are based on prices received for Canadian production converted at the December 31, 2005 and December 31, 2004 exchange rates of 1.1630 and 1.2020 $US/$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	2005	2004	2005*	2004*
2006	58.00	40.80	8.92	5.55
2007	56.38	36.41	8.29	5.37
2008	52.53	34.49	7.33	4.89
2009	51.69	32.47	6.76	4.58
2010	52.72	33.12	6.12	4.51
2011	53.78	33.78	5.92	4.53
Forecasted	2%/yr	2%/yr	1.8% to 17	1.1% to 12
			then 2%	1.5% to
				then 2%

* Canadian values converted at the December 31, 2005 and December 31, 2004 exchange rates of 1.1630 and 1.2020 $US/$C respectively.

MANAGEMENT’S DISCUSSION AND ANALYSIS

March 8, 2006
The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the message to the shareholders, the operations review, the audited consolidated financial statements of the Company for the years ended December 31, 2005 and 2004, together with the notes related thereto. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada in the currency of the United States (except where indicated as being another currency). The effect of significant differences between Canadian and United States accounting principles is disclosed in Note 14 of the consolidated financial statements. Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com.

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

          Non-GAAP Measures
          This document contains the term “cash flow from operations”, which should not be considered an alternative to, or more meaningful than “cash flow from operation 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 and operating expenses. Management believes that net operating income is a useful supplemental measure to analyse 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.

Use of Boe Equivalents
The calculations of barrels of oil equivalent (“Boe”) are based on a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Boe 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.

OVERVIEW

TransGlobe is an independent, public company whose activities are concentrated in three main geographic segments: Republic of Yemen, Canada and Arab Republic of Egypt. Yemen includes 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. Egypt includes the Company’s exploration for natural gas, natural gas liquids and crude oil.

*Selected Annual Information*
($000’s, except per share amounts,			%		%
volumes and % change)		2005	Change	2004	Change	2003
Average production volumes (Boepd)*		4,991	29	3,865	47	2,635
Average sales volumes (Boepd)*		4,959	31	3,796	44	2,635
Average price ($/Boe)		49.92	40	35.63	25	28.43

Oil and gas sales		90,350	83	49,495	81	27,336

Oil and gas sales, net of royalties		58,911	86	31,630	84	17,162

Cash flow from operations**		38,077	120	17,325	85	9,347
Cash flow from operations per share
	- Basic	0.66		0.32		0.18
	- Diluted	0.63		0.31		0.17

Net income		19,850	235	5,919	-	5,905
Net income per share
	- Basic	0.34		0.11		0.11
	- Diluted	0.33		0.10		0.11
Total assets		86,286	43	60,522	70	35,601
* The differences in production and sales volumes result from inventory changes at Block S-1, Yemen. ** 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 by 120% in 2005 compared to 2004 mainly as a result of a 31% increase in sales volumes attributed to the pipeline completion and development drilling on Block S-1, Yemen, new wells in Canada and a 40% increase in commodity prices, which were offset in part by increases in royalties, operating costs and taxes associated with the increased volumes and prices, as displayed below:

		$ Per Share	%
	$000’s	Diluted	Variance
2004 Cash flow from operations**	17,325	0.31
Volume variance	17,683	0.29	102
Price variance	23,172	0.39	134
Royalties	(13,574)	(0.23)	(78)
Expenses:
Operating	(3,189)	(0.05)	(18)
Cash general and administrative	(901)	(0.02)	(5)
Current income taxes	(2,602)	(0.04)	(15)
Realized foreign exchange gain (loss)	247	-	1
Settlement of asset retirement obligations	(165)	-	(1)
Other	81	-	-
Change in weighted average number of diluted shares outstanding-**	-	(0.02)	-
2005 Cash flow from operations**	38,077	0.63	120
** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before change

          Net income for 2005 increased 235% mainly as a result of the above cash flow from operations increase and reduced stock-based compensation which both increased net income, offset in part by increased non-cash expenses for depletion, depreciation and accretion and future income tax expense which reduced net income.

          Management Strategy
          In 2006, the capital budget is focused on growing reserves and production in Yemen and in Canada. Also, a portion of the 2006 capital budget will be spent defining leads and drilling two exploration wells on Nuqra Block 1 in Egypt.

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

          Business Environment
          The Company’s financial results are significantly influenced by the oil industry business environment. Risks include, but are not limited to:

	•	Crude oil and natural gas prices.
	•	The price differential and demand related to various crude oil qualities.
	•	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.

Commodity Price and Foreign Exchange Benchmarks

		%		%
	2005	Change	2004	Change	2003
Dated Brent average oil price ($ per barrel)	54.57	41	38.58	34	28.87
WTI average oil price ($ per barrel)	56.46	36	41.42	33	31.14
Edmonton Par average oil price (C$ per barrel)	69.29	31	52.91	22	43.23
AECO average gas price (C$ per thousand cubic feet)	8.73	33	6.54	(2)	6.67
U.S./Canadian Dollar Year End Exchange Rate	1.1630	(3)	1.2020	(7)	1.2965
U.S./Canadian Dollar Average Exchange Rate	1.2114	(7)	1.3013	(7)	1.4010

World crude oil prices continued to increase significantly in 2005. An active hurricane season resulted in substantial interruptions to U.S. Gulf Coast production and refineries, which added to fluctuations in oil and gas prices. Oil prices are expected to continue to be volatile during 2006 since global demand for oil remains very strong and supply uncertainties continue in the Middle East and West Africa.

In 2005, TransGlobe sold approximately:

          • 4% of its crude oil at fixed prices.
          • 94% at dated Brent minus the selling price differentials.
          • the remaining 2% at the Edmonton Par price less quality differentials.

Historically high natural gas prices continued in 2005. In 2005, prices increased with concern over North America’s ability to grow gas supply despite high drilling levels. A warm summer across North America and a cold December in the U.S. Northeast increased demand for power and two successive hurricanes damaged gas supply infrastructure in the U.S. Gulf Coast. Combined with high oil prices these factors caused the AECO gas price to average C$8.73/Mcf in 2005, a 33% increase from 2004. In December 2005 to February 2006 the weather in North America was extremely mild which reduced demand for natural gas. As a result, natural gas prices moderated to approximately C$6.00 per Mcf at the time of this report.

          In 2005, TransGlobe sold approximately:

          • 26% of its natural gas at fixed prices.
          • the remaining 74% at AECO Index based pricing.

OPERATING RESULTS

Daily Volumes, Working Interest Before Royalties


			2005	2004	% Change
Yemen	- Oil production	Bopd	4,124	3,188	29
	- Inventory change	Bopd	(32)	(69)	-
Yemen	- Oil sales	Bopd	4,092	3,119	31
Canada	- Oil and liquids sales	Bopd	220	179	23
	- Gas sales	Mcfpd	3,880	2,987	30
Canada		Boepd	867	677	28
Total Company - daily sales volumes		Boepd	4,959	3,796	31

Consolidated Net Operating Results

	Consolidated
	2005		2004
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil and gas sales	90,350	49.92	49,495	35.63
Royalties	31,439	17.37	17,865	12.86
Operating expenses	10,253	5.67	7,064	5.09
Net operating income*	48,658	26.88	24,566	17.68
* Net operating income amounts do not reflect Yemen income tax expense which is paid through oil allocations with MOM in $4.36/Boe, 2004 - $5,269,000, $3.79/Boe).

          Segmented Net Operating Results
          In 2005 the Company had producing operations in two geographic areas, segmented as Yemen and Canada. Also, the Company had start-up operations in a third geographic segment, Egypt. MD&A will follow under each of these segments.

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

	2005		2004
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil sales	76,300	51.09	41,472	36.33
Royalties	28,916	19.36	16,506	14.46
Operating expenses	8,219	5.50	5,449	4.77
Net operating income*	39,165	26.23	19,517	17.10

* Net operating income amounts do not reflect Yemen income tax expense which is paid through oil allocations with MOM in $5.28/Boe, 2004 - $5,269,000, $4.62/Boe.)

	Net operating income in Yemen increased 101% in 2005 primarily as a result of the following:

	•	Oil sales increased 84% mainly as a result of the following:
		1.	Sales volumes increased 31% in 2005 primarily as a result of:
			-	Block S-1 sales volumes increased 225% from 666 Bopd in 2004 to 2,166 Bopd in 2005 as a result of drilling success and pipeline completion in June 2005.
			-	offset by natural declines at Block 32 which decreased sales volumes by 21% from 2,453 Bopd in 2004 to 1,926 Bopd in 2005.
		2.	Oil prices increased by 41%.

	•	Royalty costs increased 75% as a result of increased volumes and prices. Royalties as a percentage of revenue (royalty rate) decreased to 38% in 2005 compared to 40% in 2004. This was a result of a significant increase in Block S-1 production which has a lower royalty rate than Block 32. Royalty rates fluctuate in Yemen due to changes in the amount of cost sharing oil, whereby the Block 32 and Block S-1 PSA’s allow for the recovery of operating and capital costs through a reduction in MOM take of oil production as discussed below:

	1.	Block 32:
		-	Operating costs are recovered in the quarter expended.
		-	The capital costs are amortized over two years with 50% recovered in the quarter expended and the remaining 50% recovered in the first quarter of the following calendar year. As a result, the Company will receive a larger share of production in the first quarter of each year as 50% of the previous year’s historical costs are recovered.
		-	In 2005, the Company’s royalty rate was 42% compared to 43% in 2004.
		-	In 2006, the Company’s royalty rate is expected to average between 25% and 28% in the first quarter and increase to between 41% to 45% for the balance of the year depending upon production volumes, oil prices, operating costs and eligible capital expenditures.
	2.	Block S-1:
		-	Operating costs are recovered in the quarter expended.
		-	New capital costs are amortized over eight quarters with one eighth (12.5%) recovered each quarter.
		-	Historical exploration costs, which consist of the costs expended before the Contractor declared commerciality of the Block, are recovered on a “last in, first out” basis.
		-	For the first three quarters of 2005 and all of 2004, the Company’s royalty rate was 30%. At the end of the third quarter, the Company had recovered its historical exploration cost pools which resulted in an increase to royalty rate of 46% for the fourth quarter.
		-	In 2006, the Company’s royalty rate is expected to average between 38% and 46% depending upon production volumes, oil prices, operating costs and eligible capital expenditures.
		-	The Company anticipates recovery of the majority of historical development cost pools to occur in 2006.

•	Operating expenses on a Boe basis increased 15% mainly as a result of the following:
	1.	Block 32 operating expenses averaged $5.80 per barrel in 2005 compared to $4.11 per barrel in 2004 primarily due to increased diesel costs. A diesel topping plant was constructed in 2005 to manufacture diesel from produced crude oil which will reduce diesel costs significantly on a go forward basis. The plant became operational in December 2005.
	2.	An increased percentage of the Yemen production was from Block S-1 in 2005 (53% in 2005 compared 21% in 2004) which had a higher operating cost per Boe than Block 32. Block S-1 operating costs averaged $5.17 per barrel in 2005 compared to $7.96 per barrel in 2004 (first half of 2005 was $5.90 per barrel with the second half of 2005 at $4.56 per barrel). This reduction is a reflection of increased volumes and commissioning of the pipeline in June 2005.

*Canada*
	2005		2004
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Oil sales	1,886	52.04	1,201	38.34
Gas sales ($ per Mcf)	10,292	7.27	5,675	5.19
NGL sales	1,785	40.46	1,070	31.37
Other sales	87	-	77	-
	14,050	44.41	8,023	32.40
Royalties	2,523	7.97	1,359	5.49
Operating expenses	2,034	6.43	1,615	6.52
Net operating income	9,493	30.01	5,049	20.39

Net operating income in Canada increased 88% in 2005 primarily as a result of the following:

•	Sales increased 75% mainly due to:
	1.	Sales volumes increased 28% as a direct result of successful drilling during 2004 and 2005.
	2.	Commodity prices increased 37% on a Boe basis.
•	Royalty costs increased 45% on a Boe basis. Royalties as a percentage of revenue were consistent at 18% in 2005 compared to 17% in 2004.
•	Operating costs decreased 1% on a Boe basis.

GENERAL AND ADMINISTRATIVE EXPENSES

	2005		2004
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
G&A (gross)	4,754	2.63	2,862	2.06
Capitalized G&A	(1,675)	(0.93)	(1,011)	(0.73)
Overhead recoveries	(258)	(0.14)	(187)	(0.13)
G&A (net)	2,821	1.56	1,664	1.20

General and administrative expenses (“G&A”) increased 70% in 2005 (30% increase on a Boe basis) compared to 2004 as a
result of the following:

	•	Personnel and office overhead costs increased due to additional staff.
	•	Public company costs increased mainly due to the Company preparing for the new Sarbanes Oxley compliance requirements.
	•	Deferred financing cost amortization commenced in Q4-2004.
	•	Capitalized general and administrative expenses increased mainly as a result of expansion in the Egypt operations and overhead recoveries increased due to the increased capital activity in Canada.
	•	The strengthening of the Canadian dollar against the United States dollar increased net G&A costs by $0.08 per Boe through currency conversion.

STOCK-BASED COMPENSATION

Effective January 1, 2004 the Company adopted the new accounting standard of Canadian Institute of Chartered Accountants (“CICA”) section 3870, Stock-based Compensation and Other Stock-based Payments. This Canadian accounting standard requires the Company to record a compensation expense over the vesting period based on the fair value of options granted to employees and directors. Non-cash stock compensation expense amounted to $723,000 ($0.40/Boe) for 2005 compared to $1,310,000 ($0.94/Boe) for 2004. The decrease is mainly due to options granted in mid March 2004 which were fully expensed by March 2005.

DEPLETION, DEPRECIATION AND ACCRETION EXPENSE (DD&A)

	2005		2004
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Republic of Yemen	13,172	8.82	8,162	7.15
Canada	3,812	12.05	2,184	8.82
Arab Republic of Egypt	6	-	-	-
	16,990	9.39	10,346	7.45

           In Yemen, DD&A on a Boe basis increased 23% in 2005 compared to 2004 primarily as a result of an increased asset base as all the remaining costs associated with the Block S-1 major development project were included in the depletable base for all 2005 and increased finding and development costs in Yemen.
           In Yemen (Block 72) and Egypt (Nuqra Block 1) major development costs of $1,479,000 and $2,457,000 respectively, were excluded from costs subject to depletion and depreciation.
           In Canada, DD&A on a Boe basis increased 37% in 2005 compared to 2004 primarily as a result of increased finding and development costs in Canada and the strengthening of the Canadian dollar against the United States dollar which increased DD&A $0.74 per Boe (8%) through currency conversion.

INCOME TAXES

($000’s)	2005	2004
Future income tax	471	(285)
Current income tax	7,882	5,280
	8,353	4,995

The future income expense was $1,065,000 in 2005 (2004 - $798,000) which relates to a non-cash expense for taxes to be incurred in the future as Canadian tax pools reverse. This was offset by the recognition of future tax benefits of $594,000 for 2005 (2004 - $1,083,000). The Company has recognized all its future tax assets in Canada as at December 31, 2005.
Current income tax expense in 2005 of $7,882,000 (2004 - $5,269,000) represents income taxes incurred and paid under the laws of Yemen pursuant to the PSA on Block 32 and Block S-1. The increase in Yemen is primarily the result of sales volume increases on Block S-1, Yemen and oil price increases. The income tax expense in Yemen as a percent of revenue was 10% in 2005 compared to 13% in 2004. The decrease in the percent is due to Block S-1 being in the cost recovery period which reduces the tax paid to the government (8% at Block S-1 compared to 14% at Block 32). In Canada, there was no tax paid in 2005 and $11,000 paid in 2004. As at December 31, 2005 the Company has C $39.8 million in tax pools. It is estimated that C $18.0 million of these pools will be available to deduct against 2006 taxable Canadian income.

CAPITAL EXPENDITURES/DISPOSITIONS

*Capital Expenditures*
			2005				2004
		Geological	Drilling	Facilities
	Land and	and	and	and
($000’s)	Acquisition	Geophysical	Completions	Pipelines	Other	Total	Total
Republic of Yemen
Block S-1	-	140	8,083	3,932	332	12,487	12,132
Block 32	-	195	2,767	535	502	3,999	3,109
Block 72	495	756	-	-	202	1,453	26
Other	-	-	-	-	-	-	8
	495	1,091	10,850	4,467	1,036	17,939	15,275
Canada	1,571	190	9,531	1,006	891	13,189	10,100
Arab Republic of Egypt	-	474	-	-	1,052	1,526	992
	2,066	1,755	20,381	5,473	2,979	32,654	26,367

          In Yemen, the Company drilled 7 gross (1.0 net) wells and completed the diesel topping plant on Block 32 plus drilled 8 gross (2.0 net) wells and completed the pipeline on Block S-1. On Block 72, the Company spent $495,000 to acquire its 33% working interest in the Block and another $956,000 primarily on geological and geophysical activity to define drilling locations.
          In Canada, the Company drilled 26 gross (20.4 net) working interest wells and 5 carried interest to payment wells mainly in the Nevis, Morningside and Gadsby areas. This program resulted in 21 gas, 7 oil and 3 dry wells for an overall success rate of 90%.
          In Egypt, the Company spent $1,526,000 primarily on acquisition costs and geological and geophysical activities related to the Nuqra Block to define drilling locations for the 2006 drilling program.

FINDING AND DEVELOPMENT COSTS

*Proved*
($000’s, except per Boe and $/Boe amounts)	2005	2004	2003
Total capital expenditure	32,654	26,367	14,229
Net change from previous year’s future capital	8,418	8,796	2,159
	41,072	35,163	16,388
Reserve additions and revisions (MBoe)	2,987	4,332	2,360
Average cost per Boe	13.75	8.12	6.94
Three year average cost per Boe	9.57	7.42	6.40

*Proved Plus Probable*
($000’s, except per Boe and $/Boe amounts)	2005	2004	2003
Total capital expenditure	32,654	26,367	14,229
Net change from previous year’s future capital	9,449	597	11,303
	42,103	26,964	25,532
Reserve additions and revisions (MBoe)	1,879	4,804	4,872
Average cost per Boe	22.41	5.61	5.24
Three year average cost per Boe	8.19	5.37	5.47

The finding and development costs shown above have been calculated in accordance with Canadian National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities introduced in 2003.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

RECYCLE RATIO

	Three Year
Proved	Average	2005	2004	2003
Netback ($/Boe)	$ 15.56	$ 21.04	$ 12.46	$ 9.72
Proved finding and development costs ($/Boe)	$ 9.57	$ 13.75	$ 8.12	$ 6.94
Recycle ratio	1.63	1.53	1.53	1.40

	Three Year
Proved Plus Probable	Average	2005	2004	2003
Netback ($/Boe)	$ 15.56	$ 21.04	$ 12.46	$ 9.72
Proved plus Probable finding and development
costs ($/Boe)	$ 8.19	$ 22.41	$ 5.61	$ 5.24
Recycle ratio	1.90	0.94	2.22	1.85

The 2005 proved recycle ratio was consistent with 2004. The decrease in the 2005 proved plus probable recycle ratio to 0.94 compared to 2004 of 2.22 mainly relates to a higher finding and development cost.
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 cost 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.

($000’s, except volumes and per Boe amounts)	2005	2004	2003
Net income	19,850	5,919	5,905
Adjustments for non-cash items:
Depletion, depreciation and accretion	16,990	10,346	6,253
Stock-based compensation	723	1,310	-
Future income taxes	471	(285)	(2,448)
Amortization of deferred financing costs	291	35	-
Gain on sale of property and equipment	-	-	(363)
Unrealized gain on commodity contracts	(83)	-	-
Settlement of asset retirement obligations	(165)	-	-
Netback	38,077	17,325	9,347
Sales volumes	1,809,779	1,389,920	961,588
Netback per Boe	$ 21.04	$ 12.46	$ 9.72

OUTSTANDING SHARE DATA

Common Shares issued and outstanding as at March 8, 2006 are 58,522,439.

SELECTED QUARTERLY INFORMATION

	2005				2004
($000’s, except per share amounts and volumes)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average production volumes (Boepd)*	5,132	5,285	4,658	4,887	4,979	4,303	3,389	2,765
Average sales volumes (Boepd)*	4,935	5,533	4,375	4,985	5,384	3,918	3,103	2,760
Average price ($/Boe)	54.58	56.57	44.99	42.04	37.45	37.12	34.25	31.44

Oil and gas sales	24,781	28,796	17,911	18,863	18,548	13,380	9,670	7,897

Oil and gas sales, net of royalties	14,442	19,147	11,778	13,544	11,756	8,227	5,779	5,868

Cash flow from operations**	8,603	13,142	7,263	9,070	6,326	4,363	2,749	3,887
Cash flow from operations per share
- Basic	0.15	0.23	0.13	0.16	0.12	0.08	0.05	0.07
- Diluted	0.14	0.22	0.12	0.15	0.11	0.08	0.05	0.07

Net income	4,331	7,539	3,474	4,507	768	2,541	447	2,163
Net income per share
- Basic	0.07	0.13	0.06	0.08	0.01	0.05	0.01	0.04
- Diluted	0.07	0.13	0.06	0.08	0.01	0.04	0.01	0.04
* The differences in production and sales volumes result from inventory changes at Block S-1, Yemen.
** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working

In the first quarter of each calendar year the Company’s royalty and income tax rate decreases at Block 32, Yemen due to the addition of the recovery of 50% of the capital costs from the prior year as well as 50% of the capital costs from the first quarter. This results in an increase to cash flow from operations and net income in the first quarter of each year. The second through fourth quarters recover 50% of the capital costs incurred with the balance recovered in the first quarter of the following year.
Cash flow from operations and net income increased 43% to $9,070,000 and 487% to $4,507,000, respectively, in Q1-2005 compared to Q4-2004 mainly as a result of royalty and income tax costs decreasing at Block 32, Yemen in Q1-2005 due to the recovery of 50% of the 2004 capital costs from oil production as part of the Block 32 PSA, as discussed above.

Fourth Quarter 2005
Cash flow from operations decreased in 2005 Q-4 by $4,539,000 (35%) compared to 2005 Q-3 mainly as a result of the following:

	•	A 4% decrease in average commodity prices.
	•	An 11% decrease in sales volumes (mainly a result of inventory draw in Q-3 and inventory build in Q-4).
	•	TransGlobe’s percentage of the cost oil on Block S-1 Yemen in Q-4 2005 was reduced as a result of recovering its historical exploration cost pools. This resulted in an approximately $2.0 million reduction in cash flows from operations.

LIQUIDITY AND CAPITAL RESOURCES

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 repay debt. TransGlobe’s capital programs are funded principally by cash provided from operating activities.

The following table illustrates TransGlobe’s sources and uses of cash during the years ended December

*Sources and Uses of Cash*
($000’s)	2005	2004
Cash sourced
Cash flow from operations*	38,077	17,325
Issue of common shares	1,218	10,006
	39,295	27,331

Cash used
Exploration and development expenditures	32,654	26,367
Other	155	871
	32,809	27,238
Net cash	6,486	93
Increase in non-cash working capital	747	443
Increase in cash and cash equivalents	7,233	536
Cash and cash equivalents - beginning of year	4,988	4,452
Cash and cash equivalents - end of year	12,221	4,988
* 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 in 2005 was provided by cash flow from operations, working equity financing in 2004.
          Working capital is the amount by which current assets exceed current liabilities. At December 31, 2005 working capital of $9,471,000 (2004 - $2,839,000), zero debt and an unutilized loan facility of $7,000,000. Accounts due primarily to higher revenue receivables as a result of volume and his was offset by. price increases T increased accounts payable primarily to increased capital expenditures in late 2005 related to the Canadian drilling program, increased operating and Yemen due to higher volumes, offset by reduced Yemen capital payables compared to 2004 mainly due to construction on Block S-1 which was completed in June 2005.
           The Company expects to fund its approved 2006 exploration and development program of $45.3 million flowuse of our credit facilities or equity financing during 2006 are expected to be utilized only to accelerate working capital and cash existing projects or to finance new opportunities. Fluctuations in commodity prices, product demand, foreign exchange and various other risks may impact capital resources.

COMMITMENTS AND CONTINGENCIES

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

($000’s)	2006	2007	2008	2009	2010
Office and equipment leases	270	243	339	359	353

          In September 2005, the Company entered into a crude oil costless collar for 15,000 barrels per month from January 1, 2006 to December 31, 2006. The transaction consisted of the purchase of a $50.00 per barrel dated Brent put (floor) and a $77.93 per barrel dated Brent call (ceiling).
          Upon the determination that proved recoverable reserves are 40 million barrels or greater for Block S-1, Yemen, the Company will be required to pay a finders’ fee to third parties in the amount of $281,000.
          Pursuant to the Company’s farm-in agreement on the Nuqra Concession in Egypt, the Company is committed to spend $6 million before July 1, 2009 to earn its 50% working interest. As at December 31, 2005, the Company has spent $2,065,000 of earning expenditures. As part of this commitment the Company issued a $2 million letter of credit on July 8, 2004 to a division of the Ministry of Oil (Ganoub El Wadi Holding Petroleum Company) which expires on February 14, 2007. This letter of credit is secured by a guarantee granted by Export Development Canada.
          Pursuant to the PSA for Block 72, Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $4 million ($1.32 million to TransGlobe) during the first exploration period of 30 months for exploration work, including reprocessing of seismic data, acquisition of new seismic data and drilling two exploration wells.

CRITICAL ACCOUNTING POLICIES

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

Oil and Gas Reserves

TransGlobe’s proved and probable oil and gas reserves are 100% evaluated and reported on by independent petroleum engineering consultants. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to 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.

Full Cost Accounting for Oil and Gas Activities

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

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

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

          Income Tax Accounting
          The Company has recorded a future income tax asset in 2005, 2004 and 2003. 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.

          Currency Translation
          The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at year-end exchange rates and revenues and expenses are translated using average annual 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 Earnings.

          Derivative Financial Instruments
          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 natural gas and crude oil revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimation of the fair value of certain derivative financial instruments requires considerable judgement. The estimation of the fair value of commodity price instruments requires sophisticated financial models that incorporate forward price and volatility data. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

          Asset Retirement Obligations
          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.

NEW ACCOUNTING STANDARDS

          Non-Monetary Transaction
         The Accounting Standards Board (AcSB) issued Canadian Institute of Chartered Accountants (CICA) Section 3831 Non-Monetary Transactions. The standard, which is harmonized with the equivalent United States Financial Accounting Standards Board (FASB) Statement 153 Exchanges of Non-Monetary Assets, removes the culmination of the earnings process criteria and replaces it with the commercial substance criteria as the test for fair value measurement. A transaction is determined to have commercial substance if it causes an identifiable and measurable change in the economic circumstances, or expected cash flows, of the entity. The new requirements are effective for non-monetary transactions initiated in periods beginning on or after January 1, 2006 and, upon adoption, are not expected to materially impact the Consolidated Financial Statements.

          Financial Instruments, Comprehensive Income and Hedges
          The AcSB has issued new accounting standards for financial instruments standards that comprehensively address when an entity should recognize a financial instrument on its balance sheet, or how it should measure the financial instrument once recognized. The new standards comprise three handbook sections:
          CICA Section 3855 Financial Instruments - Recognition and Measurement establishes the criteria for recognizing and measuring financial assets, financial liabilities and non-financial derivatives. It also specifies how financial instrument gains and losses are to be presented.
          CICA Section 3865 Hedges provides optional alternative treatments to Section 3855 for entities which choose to designate qualifying transactions as hedges for accounting purposes. It will replace Accounting Guideline AcG-13, Hedging Relationships, and build on Section 1650, Foreign Currency Translation, by specifying how hedge accounting is applied and what disclosures are necessary when it is applied.
          CICA Section 1530 Comprehensive Income introduces a new requirement to temporarily present certain gains and losses as part of a new earnings measurement called comprehensive income.
          All three standards are effective for annual and interim periods in fiscal years beginning on or after October 1, 2006. The Company is currently assessing the impact of these new standards on the Consolidated Financial Statements.

          Implicit Variable Interests
          The EIC issued EIC Abstract 157 Implicit Variable Interests, which is harmonized with the equivalent United States FASB Staff Position (FSP) FIN 46(R)-5 Implicit Variable Interests. Implicit variable interests are implied financial interests in an entity and act the same as an explicit variable interest except they involve the absorbing and or receiving of variability indirectly from the entity rather than directly. The Abstract is applicable to the first interim period or annual fiscal period beginning after October 17, 2005. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of the Abstract.

Conditional Asset Retirement Obligations
The EIC issued EIC Abstract 159 Accounting for Conditional Asset Retirement Obligations. The Abstract, which is harmonized with the equivalent United States FASB Interpretation (FIN) 47 Accounting for Conditional Asset Retirement Obligations, clarifies the accounting for conditional asset retirement obligations where the timing or method of settlement are conditional on a future event that may or may not be within the control of the entity. Although these uncertainties affect the fair value of the liability, they do not relieve an entity from the requirement to record a liability, if it can be reasonably determined. The Abstract is to be applied retroactively to all interim and annual reporting periods ending after March 31, 2006. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of the Abstract.

RISKS

The Company is exposed to a variety of business risks and uncertainties in the international petroleum industry including commodity prices, exploration success, production risk, foreign exchange, interest rates, government regulation, changes of laws affecting foreign ownership, political risk of operating in foreign jurisdictions, taxes, environmental preservation and safety concerns.
Many of these risks are not within the control of management, but the Company has adopted several strategies to reduce and
minimize the effects of these factors:

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

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

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

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

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

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

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

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

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2005, 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.

OUTLOOK

	*2006 Production Outlook*
		2006	2005	Change *
Barrels of oil equivalent per day		5,300 to 5,600	4,991	9%
* % growth based on mid point of guidance

	*2006 Cash Flow From Operations Outlook*
($000’s)		2006	2005	Change *
Cash flow from operations		43,000 to 45,000	38,077	16%
* Based on a dated Brent oil price of $55.00/Bbl and an AECO gas price of C$7.50/Mcf, from existing fields in Yemen and planned development

	*Sensitivity*
		2006 Cash Flow from
($000’s)		Operations Increase/Decrease
$1.00 per barrel change in dated Brent		560
C $1.00 per Mcf change in AECO		1,700

	*2006 Capital Budget*

($000’s)		2006
Canada		20,400
Yemen - Block S1		11,900
- Block 32		3,500
- Block 72		2,100
Egypt		7,400
Total		45,300

TransGlobe plans to continue increasing crude oil production in Yemen and natural gas production in Canada to deliver near term growth. Potential production growth could come from Block 72, Yemen, in the medium term and from Nuqra Block 1, Egypt, in the long term. For the near term growth, the Company expects to drill 16 wells in Yemen during 2006 of which six wells will be development wells and ten wells will be exploration wells. In Canada, the Company plans on drilling 25-30 wells during 2006 which are mainly development wells. The Company plans on drilling two exploratory wells in Egypt in late 2006. The Company attaches a significantly higher risk to the exploratory wells. The 2006 capital budget of $45.3 million is expected to be funded from cash flow and working capital. Equity and debt financing may be utilized in the future to accelerate existing projects or to finance new opportunities.

MANAGEMENT’S REPORT

         The consolidated financial statements of TransGlobe Energy Corporation were prepared by management within acceptable limits of materiality and are in accordance with Canadian generally accepted accounting principles. Management is responsible for ensuring that the financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements.
         The consolidated financial statements have been prepared by management in accordance with the accounting policies as described in the notes to the consolidated financial statements. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. When necessary, such estimates are based on informed judgements made by management.
         Management has designed and maintains an appropriate system of internal controls to provide reasonable assurance that all assets are safeguarded and financial records properly maintained to facilitate the preparation of consolidated financial statements for reporting purposes.
         Deloitte & Touche LLP, an independent firm of Chartered Accountants appointed by the shareholders, have conducted an examination of the corporate and accounting records in order to express their opinion on the consolidated financial statements. The Audit Committee, consisting of three independent directors, has met with representatives of Deloitte & Touche LLP and management in order to determine if management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The Board of Directors has approved the consolidated financial statements.

/s/ Ross G. Clarkson

Ross G. Clarkson
President &
Chief Executive Officer

March 8, 2006

/s/ David C. Ferguson

David C. Ferguson
Vice President, Finance &
Chief Financial Officer

	REPORT OF
	INDEPENDENT REGISTERED
	CHARTERED ACCOUNTANTS

To the Shareholders TransGlobe Energy Corporation:

We have audited the consolidated balance sheets of TransGlobe Energy Corporation as at December 31, 2005 and 2004 and the consolidated statements of income and retained earnings (deficit) 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. These standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of TransGlobe Energy Corporation as at December 31, 2005 and 2004 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly we express no such opinion.


	Independent Registered Chartered Accountants
	Calgary, Alberta, Canada
	February 24, 2006

CONSOLIDATED STATEMENTS OF INCOME
AND RETAINED EARNINGS ( DEFICIT )

(Expressed in thousands of U.S. Dollars)		Year Ended			Year Ended
		December 31, 2005			December 31, 2004

REVENUE
Oil and gas sales, net of royalties	$	58,911		$	31,630
Unrealized gain on commodity contracts (Note 13)		83			-
Other income		46			13
		59,040			31,643

EXPENSES
Operating		10,253			7,064
General and administrative		2,821			1,664
Stock-based compensation (Note 7e)		723			1,310
Foreign exchange loss		42			289
Interest		8			56
Depletion, depreciation and accretion		16,990			10,346
		30,837			20,729

Income before income taxes		28,203			10,914

Income taxes (Note 8)
- future		471			(285	)
- current		7,882			5,280
		8,353			4,995
NET INCOME		19,850			5,919

Deficit, beginning of year		(685	)		(6,604	)
RETAINED EARNINGS (DEFICIT), END OF YEAR	$	19,165		$	(685	)

Net income per share (Note 10)
Basic	$	0.34		$	0.11
Diluted	$	0.33		$	0.10

CONSOLIDATED BALANCE SHEETS

(Expressed in thousands of U.S. Dollars)		December 31, 2005		December 31, 2004

ASSETS
Current
Cash and cash equivalents	$	12,221	$	4,988
Accounts receivable		7,414		6,029
Oil inventory		436		389
Prepaid expenses		463		274
Unrealized commodity contracts (Note 13)		83		-
		20,617		11,680
Property and equipment
Republic of Yemen (Note 2)		30,898		26,054
Canada (Note 3)		30,261		19,111
Arab Republic of Egypt (Note 4)		2,512		992
		63,671		46,157
Future income tax asset (Note 8)		1,886		2,299
Deferred financing costs (Note 5)		112		386
	$	86,286	$	60,522

LIABILITIES
Current
Accounts payable and accrued liabilities	$	11,146	$	8,841

Asset retirement obligations (Note 6)		1,503		902

		12,649		9,743

Commitments and contingencies (Note 12)

SHAREHOLDERS’ EQUITY
Share capital (Note 7)		48,922		47,296
Contributed surplus (Note 7e)		1,908		1,593
Cumulative translation adjustment		3,642		2,575
Retained earnings (deficit)		19,165		(685	)
		73,637		50,779

	$	86,286	$	60,522

APPROVED BY THE BOARD

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

		Year Ended			Year Ended
(Expressed in thousands of U.S. Dollars)		December 31, 2005			December 31, 2004

CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:

OPERATING
Net income	$	19,850		$	5,919
Adjustments for:
Depletion, depreciation and accretion		16,990			10,346
Amortization of deferred financing costs		291			35
Future income taxes		471			(285	)
Stock-based compensation		723			1,310
Unrealized gain on commodity contracts		(83	)		-
Settlement of asset retirement obligations		(165	)		-
Changes in non-cash working capital (Note 9)		1,280			(4,259	)
		39,357			13,066

FINANCING
Issue of common shares for cash		1,218			10,006
Deferred financing costs		(17	)		(421	)
Changes in non-cash working capital (Note 9)		(24	)		24
		1,177			9,609

INVESTING
Exploration and development expenditures
Republic of Yemen		(17,939	)		(15,275	)
Canada		(13,189	)		(10,100	)
Arab Republic of Egypt		(1,526	)		(992	)
Changes in non-cash working capital (Note 9)		(509	)		4,678
		(33,163	)		(21,689	)

Effect of exchange rate changes on cash and cash equivalents		(138	)		(450	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		7,233			536

CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		4,988			4,452

CASH AND CASH EQUIVALENTS, END OF YEAR	$	12,221		$	4,988

	NOTES TO THE CONSOLIDATED
	FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 14). 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.

Nature of Business and Principles of Consolidation

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:

Block 32, Block S-1 and Block 72 within the Republic of Yemen.
the Western Canadian Sedimentary Basin within Canada.
Nuqra Block 1 within the Arab Republic of Egypt.

Joint Ventures

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.

Currency Translation

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 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 (Deficit).

Measurement Uncertainty

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.

Revenue Recognition

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.

Income Taxes

The Company records income taxes using the liability method. Under this method, 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.

Flow Through Shares

The Company has financed a portion of its exploration and development activities in Canada through the issue shares. Under the terms of these share issues, the tax attributes of the related expenditures are renounced to subscribers the foregone tax benefits, share capital is reduced and a future income tax liability is recorded for the income tax renounced deductions.

Per Share Amounts

Basic net income per share is calculated using the weighted average number of shares outstanding. Diluted net during the income per share is calculated by giving effect to the potential dilution that would occur if stock options were exercised per share is calculated using the treasury stock method. The treasury stock method assumes that the proceeds received of “in-the-money” stock options are used to repurchase common shares at the average market price.

Cash and Cash Equivalents

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

Inventories

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

Property and Equipment

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

Capitalized costs within each country are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves and determined by independent petroleum engineers. Oil and gas reserves and production are converted into equivalent units 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

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

Capitalization of Costs

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

Amortization of Deferred Financing Costs

Deferred financing costs are charged to expense over the term of the related loan facility.

Asset Retirement Obligations

The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when the incurred. Asset retirement obligations include those legal obligations where the Company will be required ible long-lived assets to retire tang such as producing well sites. The asset retirement cost, equal to the estimated fair value of the asset retirement obligation, part of the cost of the related long-lived asset. Asset retirement costs for natural gas and crude oil assets are amortized production method.

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

Stock-based Compensation

The Company records compensation expense in the Consolidated Financial Statements for stock options granted to and directors using the fair value method. Fair values are determined using the Black-Scholes option pricing model. Compensation are recognized over the vesting period.

Derivative Financial Instruments

Derivative financial instruments are used by the Company to manage its exposure to market risks relating to commodity 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 natural gas and crude oil revenues as the related sales 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.

2. PROPERTY AND EQUIPMENT - REPUBLIC OF YEMEN

(000’s)		2005			2004
Oil and gas properties - Block 32	$	25,790		$	21,651
- Block S-1		37,269			24,782
- Block 72		1,479			25
- Other		90			90
Accumulated depletion and depreciation		(33,730	)		(20,494	)
	$	30,898		$	26,054

The Company has working interests in three blocks in Yemen: Block 32, Block S-1 and Block 72. 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 ends in January 2008, at which time the Contractor can elect to proceed to the second exploration period.

During the year the Company capitalized overhead costs relating to exploration and development activities of $351,000 (2004 - $301,000). Unproven property costs in the amount of $1,479,000 in 2005 ($Nil in 2004) were excluded in the costs subject to depletion and depreciation representing the costs incurred at Block 72.

3. PROPERTY AND EQUIPMENT - CANADA

(000’s)		2005			2004
Oil and gas properties	$	38,144		$	23,444
Furniture and fixtures		867			366
Accumulated depletion and depreciation		(8,750	)		(4,699	)
	$	30,261		$	19,111

During the year the Company capitalized overhead costs relating to exploration and development activities of (2004 - $257,000).

4. PROPERTY AND EQUIPMENT - ARAB REPUBLIC OF EGYPT

(000’s)		2005			2004
Oil and gas properties	$	2,457		$	989
Furniture and fixtures		61			3
Accumulated depreciation		(6	)		-
	$	2,512		$	992

The Contractor is in the initial exploration period for two years of the Concession Agreement which expires in successive extensions to the initial exploration period, each three years, are available to the Contractor at its option.

The Company capitalized general and administrative costs relating to the start-up of TransGlobe Petroleum Egypt Inc. of $1,007,000 (2004 - $453,000). The remaining costs related to geological and geophysical activity. Unproven property costs associated with Nuqra Block 1 in the amount of $2,457,000 in 2005 (2004 - $989,000) were excluded from costs subject to depletion and depreciation.

5. LONG-TERM DEBT

The Company has a $7,000,000 loan facility which expires May 2006. The loan facility bears interest at the Eurodollar Rate plus four percent and is secured by a first floating charge debenture over all assets of the Company, a general assignment of book debts and certain covenants, among other things. At December 31, 2005 $Nil (2004 - $Nil) was drawn on these loan facilities.

During the year the Company spent $17,000 (2004 - $421,000) to secure the loan facility, of which $291,000 (2004 - $35,000) was amortized to the income statement and the remaining $112,000 was deferred and will be amortized to income over the term of the
loan facility.

6. ASSET RETIREMENT OBLIGATIONS

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:

(000’s)		2005			2004
Asset retirement obligations, beginning of year	$	1,902		$	467
Liabilities incurred		638			274
Liabilities settled		(165	)		-
Accretion		75			34
Foreign exchange loss		53			127
Asset retirement obligations, end of year	$	1,503		$	902

At December 31, 2005, the estimated total undiscounted amount required to settle the asset retirement obligations was $2,171,000 (2004 - $1,331,000). 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. SHARE CAPITAL

a) Authorized

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

b) Issued

Number

(000’s)

of shares

Amount

Balance, December 31, 2003

53,743

36,996

Stock options exercised (d)

523

164

Bought deal financing net of issue costs (c)

2,530

8,557

Bought deal financing over-allotment net of issue costs (c)

380

1,285

Future tax effect of bought deal financing costs (c)

294

Balance, December 31, 2004

57,176

47,296

Stock options exercised (d)

1,297

1,218

Transfer from contributed surplus related to stock options exercised (e)

408

Balance, December 31, 2005

58,473

48,922

c) Bought Deal Financing

In November 2004, the Company issued 2,530,000 common shares in a bought deal financing at C$4.35 per share for net proceeds of US$8,557,000. In December 2004, the Company issued an additional 379,500 shares as part of the over-allotment of the bought deal financing in November 2004 at C$4.35 per share for net proceeds of US$1,285,000. The issue costs were $848,686 for the bought deal financing and over-allotment. Share capital is increased and future income tax asset increased by the estimated future income taxes recoverable by the Company for the share issue expenses.

d) Stock Options

The Company adopted a new stock option plan in May 2004 (the “Plan”). The maximum number of common shares to be issued upon the exercise of options granted under the Plan is 5,847,300 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 and 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 will vest one-third on each of the first, second and third anniversaries of the grant date.

	2005			2004
	Number		Weighted-	Number		Weighted-
	of		Average	of		Average
(000’s except per share amounts)	Options		Exercise Price	Options		Exercise Price
Options outstanding at beginning of year	3,462		$1.15	2,760		$0.36
Granted	1,196		$5.31	1,225		$2.57
Exercised	(1,297	)	$0.83	(523	)	$0.28
Expired	-		-	-		-
Options outstanding at end of year	3,361		$2.76	3,462		$1.15
Options exercisable at end of year	2,165		$1.35	2,787		$0.79

The following table summarizes information about the stock options outstanding at December 31, 2005:

		Options Outstanding			Options Exercisable
		Weighted-			Weighted-
	Number	Average		Number	Average
	Outstanding	Remaining	Weighted-	Exercisable	Remaining	Weighted-
	at Dec. 31,	Contractual	Average	at Dec. 31,	Contractual	Average
Exercise	2005	Life	Exercise	2005	Life	Exercise
Prices	(000’s)	(Years)	Price	(000’s)	(Years)	Price
C$0.50	1,100	1.3	C$0.50	1,100	1.3	C$0.50
C$0.63	70	2.5	C$0.63	70	2.5	C$0.63
C$3.40	150	3.0	C$3.40	150	3.0	C$3.40
C$3.26	700	3.2	C$3.26	700	3.2	C$3.26
C$3.43	80	3.3	C$3.43	80	3.3	C$3.43
US$3.25	40	3.7	US$3.25	40	3.7	US$3.25
C$4.50	25	3.9	C$4.50	25	3.9	C$4.50
C$7.30	40	4.2	C$7.30	-	-	-
C$7.74	39	4.2	C$7.74	-	-	-
C$6.56	175	4.3	C$6.56	-	-	-
C$7.82	24	4.6	C$7.82	-	-	-
C$6.44	21	4.9	C$6.44	-	-	-
C$6.03	843	4.9	C$6.03	-	-	-
US$5.17	54	4.9	US$5.17	-	-	-
	3,361		US$2.76	2,165		US$1.35

e) Stock-based Compensation

Compensation expense of $723,000 has been recorded in the Consolidated Statements of Income and Retained Earnings (Deficit) in 2005 (2004 - $1,310,000). The fair value of all common share options granted is estimated on the date of grant using the Black-Scholes 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:

	2005	2004
Weighted average fair market value per option (C$)	3.38	1.84
Risk free interest rate (%)	3.86	5.17
Expected lives (years)	4.00	4.00
Expected volatility (%)	68.19	66.37
Dividend per share	0.00	0.00

During the year, employees exercised 1,297,000 stock options. In accordance with Canadian Generally Accepted Accounting Principles, the fair value related to these options was $408,000 at time of grant and has been transferred from contributed surplus to common shares.

		2005			2004
Contributed surplus, beginning of year	$	1,593		$	-
Stock-based compensation expense on adoption of
CICA section 3870		-			283
Stock-based compensation expense		723			1,310
Transfer of stock-based compensation expense to common
shares related to stock options exercised		(408	)		-
Contributed surplus, end of year	$	1,908		$	1,593

8. INCOME TAXES

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

		2005		2004
Temporary differences related to:
Oil and gas properties	$	1,555	$	2,154
Non-capital losses carried forward		118		457
Share issue expenses		213		287
Valuation allowance		-		(599	)
	$	1,886	$	2,299

The Company has deductible temporary differences of C$385,000 related to non-capital losses carried forward, C$722,000 related to share issuance expenses and C$5,243,000 related to income tax pools in excess of the carrying value of the Company’s Canadian property and equipment. The Company also has $12,700,000 of income tax losses in the United States of America. The Canadian losses carried forward expire between 2007 and 2009 and the United States of America losses carried forward expire between 2006 and 2020. In total, these temporary differences would generate a future income tax asset of C$2,193,000 on Canadian operations.

Current income taxes in the amount of $7,882,000 (2004 - $5,269,000) represents income taxes incurred and paid under the laws of the Republic of Yemen pursuant to the PSA on Block 32 and Block S-1 and $Nil (2004 - $11,000) paid in Canada.

The provision for income taxes has been computed as follows:

		2005			2004
Computed Canadian expected income tax
expense at 37.62% (2004 - 38.87%)	$	10,660		$	4,301
Non-deductible Crown charges (net of ARTC)		407			261
Resource allowance		(522	)		(180	)
Non-deductible stock-based compensation expense		272			509
Different tax rates in the Republic of Yemen		(1,751	)		945
Future income tax assets not previously recognized		(594	)		(1,083	)
Other differences		(119	)		242
	$	8,353		$	4,995

9. SUPPLEMENTAL CASH FLOW INFORMATION

(000’s)		2005			2004
Operating activities
Decrease (increase) in current assets
Accounts receivable	$	(591	)	$	(3,896	)
Prepaid expenses		(189	)		(113	)
Oil inventory		17			(180	)
Increase (decrease) in current liabilities
Accounts payable		2,043			(70	)
	$	1,280		$	(4,259	)
Investing activities
Decrease (increase) in current assets
Accounts receivable	$	(795	)	$	250

Increase (decrease) in current liabilities
Accounts payable		286			4,428
	$	(509	)	$	4,678
Financing activities
Increase (decrease) in current liabilities
Accounts payable	$	(24	)	$	24
	$	(24	)	$	24

Interest paid	$	8		$	56

Taxes paid	$	7,882		$	5,280

10. NET INCOME PER SHARE

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

	2005		2004
Weighted average number of shares outstanding	57,903		54,388
Shares issuable pursuant to stock options	3,251		3,445
Shares to be purchased from proceeds of stock options
under treasury stock method	(824	)	(1,114	)
Weighted average number of diluted shares outstanding	60,330		56,719

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, 2005, we excluded 63,000 options (2004 - 125,000) because their exercise price was greater than the annual average common share market price in this period.

11. SEGMENTED INFORMATION

In 2005 the Company had oil and natural gas production in two geographic segments, the Republic of Yemen and Canada, and start-up operations in a third geographic segment, the Arab Republic of Egypt. The property and equipment in each geographic segment are disclosed in Notes 2, 3 and 4.

The results of operations for the year ended December 31, 2005 are comprised of the following:

Republic

Arab Republic

(000’s)

of Yemen

Canada

of Egypt

Total

REVENUE

Oil and gas sales, net of royalties

47,384

11,527

58,911

EXPENSES

Operating

8,219

2,034

10,253

Depletion, depreciation and accretion

13,172

3,812

16,990

Segmented operations

25,993

5,681

)

31,668

Unrealized gain on commodity contracts

Other income

31,797

General and administrative

2,821

Stock-based compensation

723

Foreign exchange loss

Interest

Income taxes

8,353

NET INCOME

19,850

The results of operations for the year ended December 31, 2004 are comprised of the

		Republic
(000’s)		of Yemen		Canada		Total
REVENUE
Oil and gas sales, net of royalties	$	24,966	$	6,664	$	31,630
EXPENSES
Operating		5,449		1,615		7,064
Depletion, depreciation and accretion		8,162		2,184		10,346
Segmented operations	$	11,355	$	2,865		14,220
Other income						13
						14,233
General and administrative						1,664
Stock-based compensation						1,310
Foreign exchange loss						289
Interest						56
Income taxes						4,995
NET INCOME					$	5,919

2005 ANNUAL REPORT
53

12. COMMITMENTS AND CONTINGENCIES

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

2006	$ 270,000
2007	243,000
2008	339,000
2009	359,000
2010	353,000

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

Pursuant to the Company’s farm-in agreement on the Nuqra Concession in Egypt, the Company is committed to spend $6 million before July 1, 2009 to earn its 50% working interest. As at December 31, 2005, the Company has spent $2,065,000 of earning expense. As part of this commitment the Company issued a $2 million letter of credit on July 8, 2004 to a division of the Ministry of Oil (Ganoub El Wadi Holding Petroleum Company) which expires on February 14, 2007. This letter of credit is secured by a guarantee granted by Export Development Canada.

Pursuant to the PSA for Block 72, Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $4 million ($1.32 million to TransGlobe) during the first exploration period of 30 months for exploration work, including reprocessing of seismic data, acquisition of new seismic data and drilling two exploration wells.

13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Carrying Values and Estimated Fair Values of Financial Assets and Liabilities

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.

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 the Republic of Yemen, the Company sold all of its 2005 Block 32 production to one purchaser and all of its 2005 Block S-1 production to another single purchaser. In Canada, the Company sold primarily all of its 2005 gas production to one purchaser and primarily all of its 2005 oil production to another single purchaser.

Commodity Price Risk Management

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.

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

In March 2005, the Company entered into a physical contract to sell 2,000 gigajoules (GJ) per day (approximately 2,000 Mcfpd) of natural gas in Canada from April 1 to April 30, 2005 and from June 1 to October 31, 2005 for Cdn$6.95/GJ.

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 December 31, 2005 with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates.

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

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:

Consolidated Statements of Income and Retained Earnings (Deficit)

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

(000’s, except per share amounts)		2005			2004
Net income for the year under Canadian GAAP	$	19,850		$	5,919
Adjustments, before income taxes:
Stock-based compensation (b)		723			1,310
Net income for the year under U.S. GAAP		20,573			7,229
Deficit, beginning of year - U.S. GAAP		(1,203	)		(8,432	)
Retained earnings (deficit), end of year - U.S. GAAP	$	19,370		$	(1,203	)

Net income per share under U.S. - BasicGAAP	$	0.36		$	0.13
- Diluted	$	0.34		$	0.13

Statement of Other Comprehensive Income

(000’s)		2005		2004
Net income - U.S. GAAP	$	20,573	$	7,229
Currency translation adjustment (d)		1,067		734
Other comprehensive income	$	21,640	$	7,963

Consolidated Balance Sheets

Had the Company followed U.S. GAAP, asset and liability sections of the balance sheet would not have changed GAAP to U.S. GAAP, however the shareholders’ equity would have been reported as follows:

		2005				2004
		Cdn. GAAP		U.S. GAAP		Cdn. GAAP			U.S. GAAP
Share capital (b, c, e)	$	48,922	$	50,625	$	47,296		$	49,407
Contributed surplus (b)		1,908		-		1,593			-
Cumulative translation adjustment (d)		3,642		-		2,575			-
Accumulated other comprehensive income (d)		-		3,642		-			2,575
Retained earnings (deficit) (b, c, e)		19,165		19,370		(685	)		(1,203	)
	$	73,637	$	73,637	$	50,779		$	50,779

The reconciling items between share capital and retained earnings (deficit) for Canadian and U.S. GAAP are $833,000 related to escrowed shares, and $1,278,000 related to flow through shares. The reconciling items between contributed surplus and deficit for Canadian and U.S. GAAP are $283,000 for the adoption of stock-based compensation under Canadian GAAP and $2,033,000 for the 2005 and 2004 stock-based compensation expense under Canadian GAAP, which is not expensed 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 $408,000 for the transfer of compensation expense related to options exercised.

a) Full Cost Accounting

The full cost method 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 to determine whether impairment exists. However, in Canada, the impaired amount is measured using the fair value of reserves.

There are no impairment charges under Canadian GAAP or U.S. GAAP.

b) Stock-based Compensation

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 uses the intrinsic value method of accounting for stock options granted to employees and directors whereby no costs are recognized in the financial statements, per APB Opinion No. 25 as interpreted by FASB Interpretation No. 44.

The effect of applying this provision to the Company’s U.S. GAAP financial statements results in a decrease to stock-based compensation in 2005 by $723,000 (2004 - $1,310,000) and a corresponding decrease to the contributed surplus account. Also, the deficit would decrease by $283,000 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 $408,000 for options exercised since the compensation expense was transferred into common shares for Canadian GAAP, this is not required for U.S. GAAP.

Had compensation expense been determined based on fair value at the grant dates for the stock option grants consistent with the method under SFAS No. 123, the pro forma effect on the Company’s net income under U.S. GAAP would be as follows:

(000’s, except per share amounts)		2005		2004
Compensation costs	$	723	$	1,310

Net Income (U.S. GAAP)
As reported	$	20,573	$	7,229
Pro forma	$	19,850	$	5,919

Net Income per share (U.S. GAAP)
As reported - Basic	$	0.36	$	0.13
- Diluted	$	0.34	$	0.13

Pro forma - Basic	$	0.34	$	0.11
- Diluted	$	0.33	$	0.10

c) Future Income Taxes

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 2005, $Nil in 2004, $876,000 in 2003, $67,000 in 2002 and $335,000 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 2005, $Nil in 2004, $876,000 in 2003, $67,000 in 2002 and $335,000 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 $168,000 in 2005, $231,000 in 2004, $435,000 in 2003 and $Nil in 2002 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 $168,000 in 2005, $231,000 in 2004, $435,000 in 2003 and $Nil in 2002 to record an additional valuation allowance against the increased tax asset.

d) Foreign Currency Translation Adjustments and Other Comprehensive Income

U.S. GAAP requires gains or losses arising from the translation of self-sustaining operations to be included in other comprehensive income. Canadian GAAP requires these amounts to be recorded in a separate component of Shareholders’ Equity. Other comprehensive income arose from the translation adjustment resulting from the translation of Canadian currency financial statements into U.S. dollars under FAS 52. At December 31, 2005, accumulated other comprehensive income related to these items was a gain of $3,642,000 (2004 - $2,575,000 of which $1,841,000 represents the translation adjustment resulting from the Canadian operations becoming a self-sustaining operation effective October 1, 2004).

e) Escrowed Shares

For U.S. GAAP purposes, escrowed shares would be considered a separate compensatory arrangement between the Company and the holder of the shares. Accordingly, the fair market value of shares at the time the shares are released from escrow will be recognized as a charge to income in that year with a corresponding increase in share capital. The difference in share capital between Canadian GAAP and U.S. GAAP represents the effect of applying this provision in 1995 when 188,000 escrow shares were released resulting in an increase in share capital of $833,000 with the offset to deficit.

f) Derivative Instruments and Hedging

For U.S. GAAP, the Company adopted Statement of Financial Accounting Standards (“SFAS”) 133 effective January 1, 2001. SFAS 133 requires all derivatives to be recorded on the balance sheet as either assets or liabilities at their fair value. Changes in the derivative’s fair value are recognized in current period earnings unless specific hedge accounting criteria are met. To eliminate future GAAP reconciling items the Company has not designated any of its financial instruments, for the year ended December 31, 2005, as hedges for U.S. GAAP purposes under SFAS 133.

g) Recent Accounting Pronouncements

Inventory Costs

The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) 151, Inventory Costs. This statement amends Accounting Research Bulletin (ARB) 43 to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) should be recognized as current-period charges and requires the allocation of fixed production overhead to inventory based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect the adoption of this statement will have any material impact on our results of operations or financial position.

Share-based Payments

The FASB issued SFAS 123(R), Share-Based Payments, which replaces SFAS 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion 25, Accounting for Stock Issued to Employees. It requires compensation costs related to share-based payment transactions to be recognized as an expense at fair value with remeasurement to fair value each period. The compensation expense is recognized over the period that an employee provides service in exchange for the award with forfeitures estimated at each period end. This Statement is effective for interim or annual reporting periods beginning after December 15, 2005. Application is to be on a modifiedretrospective or modified-prospective basis of transition for new or modified awards and to unvested awards. Restatement of prior periods under the modified-retrospective approach is optional. The Company is currently assessing the impact of these new requirements on the Consolidated Financial Statements.

Exchanges of Nonmonetary Assets

The FASB issued SFAS 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29, Accounting for Nonmonetary Transactions. This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under Statement 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. This statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. The adoption of this statement will not have any material impact on our Consolidated Financial Statements.

Accounting for Changes and Error Corrections

The FASB issued SFAS 154, Accounting Changes and Error Corrections, which replaces APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements and changes the requirements for the accounting and reporting of a change in accounting principles. The Statement applies to all voluntary changes in accounting principles as well as changes required by an accounting pronouncement unless the pronouncement includes specific transition provisions. The Statement requires the retrospective application to prior periods’ financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Application is on a prospective basis and is effective for changes in accounting principles made in fiscal years beginning after December 15, 2005. The change, which harmonizes United States GAAP with Canadian GAAP, will affect the reporting of future changes in accounting principles under United States GAAP.

Purchase and Sales of Inventory with the Same Counterparty

The EITF issued EITF Abstract 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. The Abstract provides accounting guidance where an entity may sell inventory to another entity in the same line of business from which it also purchases inventory. It prescribes under what circumstances these exchanges with the same counterparty would be viewed as a single nonmonetary transaction and whether they would be accounted for at fair value or carrying value. The Abstract is applicable to transactions completed in reporting periods beginning after March 15, 2006, whether pursuant to arrangements that were in place at the date of initial application of the Abstract or arrangements executed subsequent to that date. The Company does not expect there to be any material impact on the Consolidated Financial Statements upon adoption of the Abstract.

*OFFICERS AND DIRECTORS*		*TRANSFER AGENT & REGISTRAR*

Robert A. Halpin^1,2,3		Computershare Trust Company of Canada
Director, Chairman of the Board		Calgary, Toronto, Vancouver

Ross G. Clarkson		*LEGAL COUNSEL*
Director, President & CEO
		Burnet, Duckworth & Palmer
Lloyd W. Herrick		Calgary, Alberta
Director, Vice President & COO
		*BANKER*
Erwin L. Noyes^2,3,4
Director		Standard Bank PLC
		London, England
Geoffrey C. Chase^1,2,4
Director		*AUDITOR*

Fred J. Dyment^1,3,4		Deloitte & Touche LLP
Director		Calgary, Alberta

David C. Ferguson		*EVALUATION ENGINEERS*
Vice President, Finance, CFO & Secretary
		DeGolyer and MacNaughton Canada Limited
Edward Bell		Calgary, Alberta
Vice President, Exploration
		*EXECUTIVE OFFICES*
1 Audit Committee
2 Reserves Committee		TransGlobe Energy Corporation
3 Compensation Committee		#2500, 605 - 5th Avenue S.W.
4 Governance and Nominating Committee		Calgary, Alberta, Canada, T2P 3H5
		Telephone: (403) 264-9888
*STOCK EXCHANGE LISTINGS*		Facsimile: (403) 264-9898
		Website: www.trans-globe.com
TSX: TGL		E-mail: trglobe@trans-globe.com
AMEX: TGA

A B B R E V I AT I O N S

Words

AMEX		American Stock Exchange
C		Canadian
CBM		Coal bed methane
CPF		Central Production Facility
Egypt		The Arab Republic of Egypt
GAAP		Generally Accepted Accounting Principles
G&A		General and Administrative
MD&A		Managements’ Discussion and Analysis
MOM		Ministry of Oil and Minerals, Republic of Yemen
NGL		natural gas liquids
PSA		Production Sharing Agreement
Q		quarter
the Company		TransGlobe Energy Corporation and/or its wholly owned subsidiaries
TransGlobe		TransGlobe Energy Corporation and/or its wholly owned subsidiaries
TSX		Toronto Stock Exchange
U.S.		United States
WTI		West Texas Intermediate
Yemen		The Republic of Yemen
YOC		Yemen Oil Company
yr		year

Metrics

Bbl		barrel
Bopd		barrels of oil per day
MBbls		thousand barrels
MMBbls		million barrels
Mcf		thousand cubic feet
Mcfpd		thousand cubic feet per day
MMcf		million cubic feet
MMcfpd		million cubic feet per day
GJ		gigajoule
Boe		*barrel of oil equivalent
Boepd		*barrel of oil equivalent per day
MBoe		*thousand barrels of oil equivalent
Km		kilometer
$MM		million dollars

Well Symbols

o		drilling location
•		oil well
		gas well
		abandoned well
		injection well

* A Boe conversion ratio of 6 Mcf = 1 Bbl has been used. Boe 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.