---



Management's Discussion and Analysis

---

March
  9, 2005

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

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

OVERVIEW

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

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

| | • | Cash Flow From Operations and Net Income items:
| | - | -----------------------------------------------
| |   | –                                              
| |   | –                                              
| |   | –                                              
| |   |                                                
| | • | Additional Net Income items:                   
| |   | –                                              
| |   | –                                              
| |   | –                                              

---

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

Operating
  Segments

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

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

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

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

Business
  Environment

Commodity
  Price and Foreign Exchange Benchmarks

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

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

In
  2004, TransGlobe sold approximately:

| | • | 5% of its crude oil at fixed prices;                                                         
| | - | ---------------------------------------------------------------------------------------------
| | • | 92% at dated Brent minus the Yemen government official selling
      price differentials; and
| | • | the remaining 3% at the Edmonton Par price less quality differentials.                       

---

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

In
  2004, TransGlobe sold approximately:

| | • | 29% of its natural gas at fixed prices; and   
| | - | ----------------------------------------------
| | • | the remaining 71% at AECO Index based pricing.

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

Management
  Strategy

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

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

SELECTED ANNUAL AND QUARTERLY INFORMATION

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

---

|                                    |   | **2004** | 
|----------------------------------- | - | -------- | 
|($000’s, except per share amounts)  |   | Q-4      | 
|Average sales volumes (Boepd)       |   | 5,384    | 
|Average price ($/Boe)               | $ | 37.45    | 
|                                    |   |          | 
|Oil and gas sales                   | $ | 18,548   | 
|                                    |   |          | 
|Oil and gas sales, net of royalties | $ | 11,756   | 
|                                    |   |          | 
|Cash flow from operations           | $ | 6,326    | 
|Cash flow from operations per share |   |          | 
|- Basic                             | $ | 0.12     | 
|- Diluted                           | $ | 0.11     | 
|                                    |   |          | 
|Net income                          | $ | 768      | 
|Net income per share                |   |          | 
|- Basic                             | $ | 0.01     | 
|- Diluted                           | $ | 0.01     | 

|                                    |   | 2003  | 
|----------------------------------- | - | ----- | 
|($000’s, except per share amounts)  |   | Q-4   | 
|Average sales volumes (Boepd)       |   | 2,819 | 
|Average price ($/Boe)               | $ | 28.90 | 
|                                    |   |       | 
|Oil and gas sales                   | $ | 7,496 | 
|                                    |   |       | 
|Oil and gas sales, net of royalties | $ | 4,489 | 
|                                    |   |       | 
|Cash flow from operations           | $ | 1,894 | 
|Cash flow from operations per share |   |       | 
|- Basic                             | $ | 0.04  | 
|-Diluted                            | $ | 0.03  | 
|                                    |   |       | 
|Net income                          | $ | 3,413 | 
|Net income per share                |   |       | 
|- Basic                             | $ | 0.06  | 
|- Diluted                           | $ | 0.06  | 

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

---

Discussion
  of Annual Information:

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

| | • | increased volumes from drilling success in both Yemen and
      Canada;                                      
| | - | -------------------------------------------------------------------------------------------------------------
| | • | increased commodity prices; and                                                                              
| | • | increased operating costs and current taxes due to higher
      volumes that offset the above cash increases.

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

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

Discussion
  of Quarterly Information:

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

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

OPERATING RESULTS

Daily
  Production, before royalties

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

Consolidated
  Net Operating Results

|                                | Consolidated
|------------------------------- | ------------
|                                | **2004**    
|(000’s, except per Boe amounts) | $           
|Oil and gas sales               | 49,495      
|Royalties                       | 17,865      
|Operating expenses              | 7,064       
|Net operating income*           | 24,566      

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

---

Segmented
  Net Operating Results

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

Republic
  of Yemen

|                                | **2004** | 2003 
|------------------------------- | -------- | -----
|(000’s, except per Boe amounts) | $        | $/Boe
|Oil sales                       | 41,472   | 36.33
|Royalties                       | 16,506   | 14.46
|Operating expenses              | 5,449    | 4.77 
|Net operating income*           | 19,517   | 17.10

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

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

| | • | Oil sales increased 70% mainly as a result of the following:                                                    
| | - | ----------------------------------------------------------------------------------------------------------------
|
| |   | 1.                                                                                                              
| |   | 2.                                                                                                              
|
| | • | Royalty costs increased 70%. Royalties as a percentage of revenue
      were consistent at 40% in 2004 and 2003.
|
| | • | Operating expenses on a Boe basis increased 37% mainly as a
      result of the following:                      
|
| |   | 1.                                                                                                              
| |   | 2.                                                                                                              

TransGlobe
  commenced production on Block 32 on November 4, 2000. Production from the block
  is shared between the Block 32 Joint Venture Group and MOM pursuant to a PSA.
  The PSA provides for MOM to receive a 3% royalty of gross production (10% over
  25,000 Bopd) with the remaining 97% of production split between cost recovery
  oil and production sharing oil. Cost recovery oil is up to a maximum of 60%
  of the production after deducting royalty. Cost recovery oil allows the Block
  32 Joint Venture Group to recover operating costs and exploration and development
  expenditures as outlined in the PSA. The remaining oil is allocated to production
  sharing oil shared 65% by MOM and 33.25% by the Block 32 Joint Venture Group
  and 1.75% to YOC. The Block 32 Joint Venture Group’s Yemen income taxes
  are paid out of the MOM’s share of production sharing oil. These terms
  remain in place until gross proved recoverable reserves exceed 30 million barrels
  of oil (assessed every two years) or until gross production exceeds 25,000 Bopd
  at which time the terms would revert to the original PSA terms in place prior
  to the 1999 PSA amendment. The original PSA terms provided for a 10% royalty
  on gross production with the remaining 90% of production split between cost
  recovery oil and production sharing oil. Cost recovery oil would be to a maximum
  of 25%, with the remaining oil allocated to production sharing oil shared 77%
  by MOM and 23 % by the Block 32 Joint Venture Group. The proved recoverable
  reserve determination is conducted every 2 years from the anniversary of first
  oil production (November 4, 2000). At November 4, 2004, the proved recoverable
  reserves recognized by the MOM approved independent third party audit was less
  than 10 million barrels. The next Block 32 MOM audit will be conducted effective
  November 4, 2006.

---

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

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

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

Canada

|                                | **2004** | 2003 
|------------------------------- | -------- | -----
|(000’s, except per Boe amounts) | $        | $/Boe
|Oil sales                       | 1,201    | 38.34
|Gas sales (6:1)                 | 5,675    | 31.14
|NGL sales                       | 1,070    | 31.37
|Other sales                     | 77       | -    
|                                | 8,023    | 32.40
|Royalties                       | 1,359    | 5.49 
|Operating expense               | 1,615    | 6.52 
|Net operating income            | 5,049    | 20.39

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

| | • | Sales increased 169% mainly as a result of the following:
| | - | ---------------------------------------------------------
|
| |   | 1.                                                       
| |   | 2.                                                       

---

| | • | Royalty costs increased 19% on a Boe basis. Royalties
      as a percentage of revenue increased to 17% in 2004 compared to 15% in 2003
      mainly as a result of the new wells that were placed on production in the
      second half of 2004, which have a higher royalty rate as a percentage of
      revenue than the previous wells on production.   
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                                                                                                                                                                                               
| | • | Operating costs decreased 10% on a Boe basis
      as a result of wells that were placed on production in 2004, which have
      a lower operating cost than the previous wells on production. This was offset
      by the strengthening of the Canadian dollar which increased Canada’s
      operating costs when converted to US dollars at a higher rate.

Egypt

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

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

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

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

GENERAL AND ADMINISTRATIVE EXPENSES

|                                | **2004** |   | 2003  |  
|------------------------------- | -------- | - | ----- | -
|(000’s, except per Boe amounts) | $        |   | $/Boe |  
|G&A (gross)                     | 2,862    |   | 2.06  |  
|Capitalized G&A                 | (1,011   | ) | (0.73 | )
|Overhead recoveries             | (187     | ) | (0.13 | )
|G&A (net)                       | 1,664    |   | 1.20  |  

---

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

| | • | Increases were experienced in personnel costs with additional
      employees and consultants, office overhead costs and insurance costs.                                       
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | Public company administration costs increased 16% in 2004
      and are anticipated to be higher in 2005 due to additional work associated
      with Sarbanes Oxley compliance.
| | • | Capitalized general and administrative expenses and overhead
      recoveries increased due to the increased capital activity in both 
      Yemen and Canada.                  
| | • | The strengthening of the Canadian dollar against the United
      States dollar increased net G&A costs by $0.10 per Boe through currency
      conversion.                     

STOCK-BASED COMPENSATION

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

DEPLETION, DEPRECIATION AND ACCRETION EXPENSE

|                                | **2004** | 2003 
|------------------------------- | -------- | -----
|(000’s, except per Boe amounts) | $        | $/Boe
|Republic of Yemen               | 8,162    | 7.15 
|Canada                          | 2,184    | 8.82 
|                                | 10,346   | 7.45 

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

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

INCOME TAXES

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

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

---

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

| | • | Increased volumes mainly as a result of production start up
      on Block S-1.                                                                                                                                                                         
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                                                                                         
| | • | Increase in oil prices.                                                                                                                                                                                                                                 
| |   |                                                                                                                                                                                                                                                         
| | • | An increase in the Yemen government’s share of production
      sharing oil on Block 32 as a result of recovery of all historical costs
      during Q2-2003. The Yemen government’s share of production sharing
      oil includes royalties and taxes.

CAPITAL EXPENDITURES/DISPOSITIONS

Capital
  Expenditures

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

Capital
  expenditures in 2004 are mainly comprised of the following:

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

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

| | • | Mainly costs associated with obtaining Block 72 in Yemen.
| | - | ---------------------------------------------------------

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

| | • | Costs mainly related to the drilling of fifteen wells (11.4 net wells)
      and related tie-in of seven of these wells (five gas, two oil) as part of
      the 2004 exploration and development program.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | Costs also related to the re-completion of four wells, of which three
      (two gas, one oil) came on production, and the tie-in of two wells (one
      gas, one oil) drilled in prior years.           
| | • | Other costs related to oil and gas lease acquisitions for future drilling
      associated with the 2004 and 2005 exploration and development programs.                                                   

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

---

FINDING AND DEVELOPMENT COSTS

Proved

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

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

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

RECYCLE RATIO

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

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

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

---

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

OUTSTANDING SHARE DATA

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

FOURTH QUARTER

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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

---

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

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

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

COMMITMENTS AND CONTINGENCIES

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

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

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

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

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

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

CRITICAL ACCOUNTING POLICIES

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

---

Oil
  and Gas Reserves

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

Full
  Cost Accounting for Oil and Gas Activities

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

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

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

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

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

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

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

---

CHANGES IN ACCOUNTING POLICIES AND PRACTICES

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

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

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

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

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

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

---

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

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

NEW ACCOUNTING STANDARDS

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

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

RISKS

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

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

| | • | The Company applies rigorous geological, geophysical and engineering
      analysis to each prospect.                                                                          
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                
| | • | The Company utilizes its in-house expertise for all international
      ventures and employs and contracts professionals to handle each aspect of
      the Company’s business.
| |   |                                                                                                                                                                                
| | • | The Company maintains U.S. dollar bank accounts which is its
      main operating currency.                                                                                    
| |   |                                                                                                                                                                                
| | • | The Company maintains a conservative approach to debt financing
      and currently has no long-term debt.                                                                     
| |   |                                                                                                                                                                                
| | • | The Company maintains insurance according to customary industry
      practice, but cannot fully insure against all risks.                                                     
| |   |                                                                                                                                                                                
| | • | The Company conducts its operations to ensure compliance with
      government regulations and guidelines.                                                                     
| |   |                                                                                                                                                                                
| | • | The Company retains independent petroleum engineering consultants
      to determine year-end Company reserves and estimated future net revenues.                              
| |   |                                                                                                                                                                                
| | • | The Company manages commodity prices by entering physical
      fixed price sales contracts when deemed appropriate.                                                           

---

OUTLOOK

2005
  Production Outlook

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

2005
  Cash Flow From Operations Outlook

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

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

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

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

---

Management’s Report

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

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

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

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

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

---