---





Management's Discussion and Analysisfor the fiscal year ended December 31, 2003



---

MANAGEMENT'S DISCUSSION AND ANALYSIS

April 1, 2004

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, 2003 and 2002, together with the notes related thereto.
  The consolidated financial statements have been prepared in accordance with
  accounting principles generally accepted in Canada. 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.

All dollar values are expressed in U.S. dollars, unless
  otherwise stated. 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.

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.

SELECTED FINANCIAL INFORMATION

|                                    | 2003       |  | %      |  | 2002       |  | %      |  | 2001       | 
|----------------------------------- | ---------- |  | ------ |  | ---------- |  | ------ |  | ---------- | 
|                                    | $          |  | Change |  | $          |  | Change |  | $          | 
|                                    |            |  |        |  |            |  |        |  |            | 
|Oil and gas sales, net of royalties | 17,161,710 |  | 29     |  | 13,254,105 |  | 55     |  | 8,554,085  | 
|                                    |            |  |        |  |            |  |        |  |            | 
|Cash flow from operations           | 9,347,001  |  | (4)    |  | 9,709,852  |  | 66     |  | 5,840,455  | 
|Cash flow from operations per share |            |  |        |  |            |  |        |  |            | 
|- Basic                             | 0.18       |  |        |  | 0.19       |  |        |  | 0.12       | 
|- Diluted                           | 0.17       |  |        |  | 0.19       |  |        |  | 0.11       | 
|                                    |            |  |        |  |            |  |        |  |            | 
|Net income                          | 5,905,228  |  | 9      |  | 5,426,389  |  | 77     |  | 3,062,237  | 
|Net income per share                |            |  |        |  |            |  |        |  |            | 
|- Basic                             | 0.11       |  |        |  | 0.11       |  |        |  | 0.06       | 
|- Diluted                           | 0.11       |  |        |  | 0.10       |  |        |  | 0.06       | 
|                                    |            |  |        |  |            |  |        |  |            | 
|Total assets                        | 35,214,816 |  | 44     |  | 24,386,147 |  | 29     |  | 18,847,489 | 

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.

1

---

RESULTS OF OPERATIONS

Net income for 2003 was $5,905,228 ($0.11 per share basic
  and $0.11 per share diluted) compared to a net income of $5,426,389 ($0.11 per
  share basic and $0.10 per share diluted) in 2002. Cash flow from operations
  for 2003 was $9,347,001 ($0.18 per share basic and $0.17 per share diluted)
  compared to $9,709,852 ($0.19 per share, basic and diluted) in 2002.

Although net income and cash flow from operations were only
  increased (decreased) by 9% and (4)% respectively, there are significant changes
  that impacted these items in 2003. The following is a brief summary of the primary
  changes that occurred during 2003 that will be discussed in more detail throughout
  this MD&A:

- Higher production volumes
- Higher commodity prices
- Payout of all historical costs on Block 32, Yemen
- Cost oil reallocation on Block 32, Yemen increased royalty costs between
    2003 and 2002 by approximately $2,594,000.
- Recognition of future income tax asset in Canada.

OPERATING RESULTS

Daily Production, before royalties

|                                  |                   |       |       | 2003  |       | 2002  |    | % Change | 
|--------------------------------- | ----------------- | ----- | ----- | ----- | ----- | ----- | -- | -------- | 
|                                  |                   |       |       |       |       |       |    |          | 
|Yemen                             | - Oil             | Bopd  |       | 2,372 |       | 1,545 |    | 54       | 
|Canada                            | - Oil and liquids | Bopd  |       | 63    |       | 37    |    | 70       | 
|                                  | - Gas             | Mcfpd |       | 1,200 |       | 892   |    | 35       | 
|Barrels of oil equivalent (6 : 1) | Boepd             |       | 2,635 |       | 1,731 |       | 52 |         

The Company has set a target of 3,400 Boepd for 2004 representing a 30% increase
  over 2003.

Consolidated Net Operating Results

|                      | Consolidated | 
|--------------------- | ------------ | 
|                      | 2003         | 
|                      |              | 
|                      | $            | 
|                      |              | 
|Oil and gas sales     | 27,335,841   | 
|Royalties             | 10,174,131   | 
|Operating expenses    | 3,706,096    | 
|                      |              | 
|Net operating income* | 13,455,614   | 

|* | Net operating income amounts do not reflect Yemen
        income tax expense which is paid through oil allocations with MOM in the
        Republic of Yemen(2003 - $2,755,067 $2.87/Boe; 2002 - $986,862, $1.56/Boe).
|- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

2

---

Segmented Net Operating Results

In 2003 the Company operated in two geographic areas, segmented as the Republic
  of Yemen and Canada. MD&A will follow under each of these segments.

Republic of Yemen

|                      | 2003       |  | 2002  | 
|--------------------- | ---------- |  | ----- | 
|                      |            |  |       | 
|                      | $          |  | $/Boe | 
|                      |            |  |       | 
|Oil sales             | 24,356,094 |  | 28.13 | 
|Royalties             | 9,731,206  |  | 11.24 | 
|Operating expenses    | 3,011,620  |  | 3.48  | 
|                      |            |  |       | 
|Net operating income* | 11,613,268 |  | 13.41 | 

|* | Net operating income amounts do not reflect Yemen income tax expense
        which is paid through oil allocations with MOM in the Republic of Yemen($2003 - $2,755,067, $3.18/Boe; ($2002 - $986,862, $1.75/Boe.)
|- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Net operating income in Yemen increased 7% in 2003 primarily as a result of
  the following:

| | Production volumes increased
        54%                                                                                                                                                                                                                                                                                                                                                                         
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Oil prices increased 12%                                                                                                                                                                                                                                                                                                                                                                                         
| | Royalty costs increased
        395% as a result of three events:                                                                                                                                                                                                                                                                                                                                                
|  | 1.                                                                                                                                                                                                                                                                                                                                                                                                               
|  | 2.                                                                                                                                                                                                                                                                                                                                                                                                               
|  | 3.                                                                                                                                                                                                                                                                                                                                                                                                               
| | Operating expenses increased
        41% on a Boe basis as a result of an increase in the cost of the Transportation
        and Facilities Usage Contract with the MOM which allowed for a $0.40 increase
        in the export pipeline tariff following recovery of all historical costs.
        Increases in workover expenses on the wells and additional fluid handling
        expenses also contributed.

TransGlobe commenced production on Block 32 on November 3,
  2000. Production from the block is shared between the Block 32 Joint Venture
  Group and MOM pursuant to a PSA. The PSA provides for MOM to receive a 3% royalty
  of gross production (10% over 25,000 Bopd) with the remaining 97% of revenue
  split between cost recovery oil and production sharing oil. Cost recovery oil
  is up to a maximum of 60% of the revenue after deducting 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 proven recoverable reserves exceed 30
  million barrels of oil or until gross production exceeds 25,000 Bopd.

The 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

3

---

of oil required to recover capital and operating costs will
  vary depending upon the prevailing oil prices. The Company expects to receive
  after tax between 65% to 70% share of production in the first quarter of 2004
  and then decrease to between 40% to 48% share of production in the balance of
  the year depending upon production volumes, oil prices, operating costs and
  eligible capital expenditures.

Canada

|                     | 2003      |  | 2002  | 
|-------------------- | --------- |  | ----- | 
|                     |           |  |       | 
|                     | $         |  | $/Boe | 
|                     |           |  |       | 
|Oil sales            | 344,630   |  | 27.00 | 
|Gas sales (6 : 1)    | 2,292,870 |  | 31.44 | 
|NGL sales            | 236,093   |  | 23.42 | 
|Other sales          | 106,154   |  | -     | 
|                     |           |  |       | 
|                     | 2,979,747 |  | 31.10 | 
|Royalties            | 442,925   |  | 4.62  | 
|Operating expense    | 694,476   |  | 7.25  | 
|                     |           |  |       | 
|Net operating income | 1,842,346 |  | 19.23 | 

Net operating income in Canada increased 225% in 2003 primarily as a result
  of the following:

- Production volumes increased 41% as a direct result of the 2003 drilling
    program.
- Gas prices increased 89% to average $5.24 per Mcf in
      2003 compared to $2.77 per Mcf in 2002 while oil and natural gas liquids
      prices increased 23% and 39%, respectively.
- Royalty costs increased 90% on a Boe basis as a result
      of higher commodity prices and an increase in royalties on freehold lands
      which are not Alberta royalty tax credit eligible.
- Operating expenses increased 10% ($0.64) on a Boe basis
      mainly as a result of the strengthening of the Canadian dollar which increased
      the operating costs in Canada by $0.78 per Boe through currency conversion.

GENERAL AND ADMINISTRATIVE EXPENSES

|                    | 2003      |   | 2002  |  
|------------------- | --------- | - | ----- | -
|                    |           |   |       |  
|                    | $         |   | $/Boe |  
|                    |           |   |       |  
|G&A (gross)         | 1,568,401 |   | 1.63  |  
|Capitalized G&A     | (278,257  | ) | (0.29 | )
|Overhead recoveries | (83,807   | ) | (0.09 | )
|                    |           |   |       |  
|G&A (net)           | 1,206,337 |   | 1.25  |  

General and administrative expenses increased 47% 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, insurance costs and public
      company administration costs.
- The strengthening of the Canadian dollar against the
      United States dollar increased G&A costs by $0.12 per Boe through currency
      conversion.

4

---

DEPLETION AND DEPRECIATION EXPENSE

|                  | 2003      |  | 2002  | 
|----------------- | --------- |  | ----- | 
|                  |           |  |       | 
|                  | $         |  | $/Boe | 
|                  |           |  |       | 
|Republic of Yemen | 5,516,000 |  | 6.37  | 
|Canada            | 737,000   |  | 7.69  | 
|                  |           |  |       | 
|                  | 6,253,000 |  | 6.50  | 

In Yemen unproven properties in the amount of $11,683,986
  were excluded from costs subject to depletion and depreciation. This represents
  a portion of the costs incurred in Block S-1. These costs will be included in
  the depletable base as Block S-1 is developed or as impairment is determined.

In Yemen, depletion and depreciation on a Boe basis decreased
  9% to $6.37 per Boe in 2003 from $7.02 in 2002 primarily as a result of the
  following:

Increase in the Yemen Proved reserves resulted in a lower depletion rate.


In Canada, depletion and depreciation on a Boe basis increased
  65% to $7.69 per Boe in 2003 from $4.67 in 2002 primarily as a result of the
  following:

Increase in the depletion rate occurred with the increase in production
      volumes.
    The strengthening of the Canadian dollar against the United States dollar
      increased the Canadian depletion and depreciation by $0.55 per Boe through
      currency conversion.


INCOME TAXES

|                   | 2003 |            | 2002 |  
|------------------ | ---- | ---------- | ---- | -
|                   |      |            |      |  
|Future income tax  | $    | (2,448,085 | )    | $
|Current income tax |      | 2,755,067  |      |  
|                   |      |            |      |  
|                   | $    | 306,982    |      | $

The future income tax recovery of $2,448,085 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 2003. The Company has unrecognized future tax
  benefits in Canada in the amount of $1,641,643 which may be recognized in the
  future with continued drilling successes in Canada.

Current income tax expense in 2003 of $2,755,067 (2002 - $986,862)
  represents income taxes incurred and paid under the laws of the Republic of
  Yemen pursuant to the PSA on Block 32. The increase is a result of increased
  oil prices and increased production volumes of which the Yemen governments
  share has increased due to recovery of all historical costs. The Yemen governments
  share of production sharing oil includes royalties and income taxes.

5

---

CAPITAL EXPENDITURES/DISPOSITIONS

Capital Expenditures

|                                           | 2003 |            | 2002 |  
|------------------------------------------ | ---- | ---------- | ---- | -
|                                           |      |            |      |  
|Republic of Yemen                          | $    | 9,012,022  |      | $
|Canada                                     |      | 5,217,084  |      |  
|                                           |      |            |      |  
|                                           |      | 14,229,106 |      |  
|Proceeds on sale of property and equipment |      | (442,103   | )    |  
|                                           |      |            |      |  
|Net capital expenditures                   | $    | 13,787,003 |      | $

Capital expenditures in Yemen in 2003 are primarily comprised of the following:

Block 32($4,347,955)

- Drilling, completion and tie ins of four wells at Tasour
      and drilling of one exploration well.
- High pressure water injection expenditures and production
      equipment.
- Final contingent payments on an additional working interest
      acquired in 2000, which consisted of $800,000 in 2003 (2002 - $160,000)
      (six $160,000 payments, one for each cumulative million barrels of gross
      oil production between 7 million barrels to a maximum of 12 million barrels).
      All obligations of this purchase were finalized in 2003.

Block S-1($4,633,929)

- Drilling and associated production testing of two wells
      at An Nagyah, completion of one well at An Naeem and costs associated with
      commercial development of An Nagyah.

Capital expenditures in Canada in 2003 are primarily comprised
  of the following:

Canada($5,217,084)

- Costs related to drilling, completing or recompleting
      and associated equipping and tie in costs for a nine well exploration and
      development program.
- Oil and gas lease acquisitions associated with the 2003
      and 2004 exploration and development program.

Dispositions($442,103)

- Proceeds on disposal of oil and gas properties represent
      dispositions in Canada of minor assets of $78,962 and disposition of seismic
      data in the United States of $363,141. 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.

6

---

FINDING AND DEVELOPMENT COSTS

|                                               | 2003   |            | 2002     |  
|---------------------------------------------- | ------ | ---------- | -------- | -
|                                               |        |            |          |  
|                                               |        |            | Proved + |  
|                                               | Proved |            | Probable |  
|                                               |        |            |          |  
|Total capital expenditure                      | $      | 14,229,107 |          | $
|Net change from previous years future capital |        | 2,158,637  |          |  
|                                               |        |            |          |  
|                                               | $      | 16,387,744 |          | $
|                                               |        |            |          |  
|Reserve additions and revisions (MBoe)         |        | 2,360.7    |          |  
|Average cost per Boe                           | $      | 6.94       |          | $
|Three year average cost per Boe                | $      | 6.40       |          | $

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 and the 2002 numbers have been
  restated to reflect the new Standards.

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 |       |      |   |      |  |      |      
|-------------------------------------------- | ---------- | ----- | ---- | - | ---- |  | ---- | -----
|                                             | Average    |       | 2003 |   | 2002 |  | 2001 |      
|                                             |            |       |      |   |      |  |      |      
|Netback ($/Boe)                              | $          | 11.89 |      | $ | 9.72 |  | $    | 15.36
|Proved finding and development costs ($/Boe) | $          | 6.40  |      | $ | 6.94 |  | $    | 5.88 
|                                             |            |       |      |   |      |  |      |      
|Recycle ratio                                |            | 1.86  |      |   | 1.40 |  |      | 2.61 

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 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,
  foreign exchange (gain) loss, interest and current income tax expense per Boe
  of production.

OUTSTANDING SHARE DATA

Common Shares issued and outstanding, as at April 1, 2004
  are 54,091,439.

LIQUIDITY AND CAPITAL RESOURCES

Funding for the Companys capital expenditures in 2003
  was provided by cash flow from operations and working capital.

At December 31, 2003 the Company had working capital of $2,537,369,
  zero debt and a revolving credit facility of Cdn$2,500,000 and an acquisition/development
  credit facility of Cdn$2,000,000. The Company expects to expand its available
  credit facilities during the second quarter of 2004.

The Company expects to fund its 2004 exploration and development
  program (budgeted at $20,000,000 firm and contingent) through the use of working
  capital, cash flow, debt and equity financing as required. The use of our credit
  facilities during 2004 is expected to remain within conservative guidelines
  of less than a debt to cash flow ratio of 1 : 1. The Company raised $2,053,005
  (net after costs) on a flow through financing in December 2003 to partially
  fund the Canadian exploration program. This amount is included in the

7

---

working capital at December 31, 2003. Should cash flow be
  negatively impacted by reduction in production volumes or commodity prices,
  the Company has some flexibility in decreasing its Canadian capital budget in
  excess of its flow through share commitments.

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

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:

|                            | 2004     |  | 2005     |  | 2006     |  | 2007    | 
|--------------------------- | -------- |  | -------- |  | -------- |  | ------- | 
|                            |          |  |          |  |          |  |         | 
|Office and equipment leases | $142,000 |  | $142,000 |  | $143,000 |  | $48,000 | 

Also, the Company entered into a contract to sell 1,500 gigajoules
  (GJ) per day (approximately 1500 Mcfpd) of natural gas in Canada from April
  1 to October 31, 2004 for Cdn$5.795/GJ.

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 Determination

The process of estimating reserves is complex. It requires
  significant judgements and decisions based on available geological, geophysical,
  engineering and economic data. These estimates may change substantially as additional
  data from ongoing development and production activities becomes available and
  as economic conditions impact oil and gas prices and costs. All of the Companys
  properties are evaluated by independent petroleum engineering consultants.

Full Cost Accounting for Oil and Gas Activities

Depletion and Depreciation Expense 
  The Company uses the full cost method of accounting for exploration and development
  activities. In accordance with this method of accounting, all costs associated
  with exploration and development are capitalized whether successful or not.
  The aggregate of net capitalized costs, estimated future development costs less
  estimated salvage values and estimated future site restoration costs is amortized
  using the unit of production method based on estimated proved oil and gas reserves.

An increase in estimated proved oil and gas reserves will
  result in a corresponding reduction in depletion and depreciation expense. A
  decrease in estimated future development costs will result in a corresponding
  reduction in depletion and depreciation expense.

8

---

Unproven 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.

Ceiling Test 
  The full cost method of accounting requires the calculation of a ceiling test
  which limits the net capital costs carried to an amount that is equal to the
  estimated future net revenues from the Companys oil and gas properties
  plus the cost (net of impairment) of unproved properties. The test is a cost
  recovery test and is not intended to represent an estimate of fair market value.
  The test is performed quarterly. If the net carrying cost of the oil and gas
  properties exceeds the indicated limit then the difference is charged to earnings.

Income Tax Accounting 
  The Company has recorded a future income tax asset in 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.

NEW ACCOUNTING STANDARDS

Asset Retirement Obligations 
  Effective January 1, 2004 the Company will change its accounting policy with
  respect to accounting for asset retirement obligations. CICA section 3110, essentially
  the same as FASBs Statement No. 143, Accounting for Asset Retirement
  Obligations (FAS 143), requires an entity to record the fair
  value of a liability for an asset retirement obligation in the period in which
  it is incurred. When initially recorded, the liability is added to the related
  property, plant and equipment, subsequently increasing depletion and depreciation
  expense. In addition, the liability is accreted for the change in present value
  in each period. Upon adoption of CICA section 3110, the Company will adjust
  its existing provision for site restoration and abandonment liability retroactively
  with restatement of prior years financial statements.

The Company has estimated that the cumulative effect will
  be to recognize an asset retirement liability of $467,399, eliminate the provision
  for site restoration and abandonment liability of $153,209, increase property
  and equipment by $386,353 and increase deficit by $72,163.

Stock-Based Compensation Plans 
  Effective January 1, 2004, CICA section 3870, Stock-based Compensation
  and Other Stock-based Payments, will require all public companies to expense
  all stock-based compensation. This standard provides for the retroactive adoption
  of fair value accounting effective January 1, 2004 which results in an increase
  in deficit and contributed surplus of $283,000. After January 1, 2004 the fair
  value of stock-based compensation will be recognized as an expense in the financial
  statements.

The Company uses stock-based compensation as a significant
  part of the Companys overall compensation package to its directors, officers
  and employees and therefore the Company expects this Standard may materially
  impact earnings with no effect on cash flows from operations. Based on stock
  option grants in prior years that will affect 2004 and stock option grants to
  date in 2004, it is expected that the effect on 2004 earnings will be approximately
  $1.1 million with no effect on cash flow from operations. The full effect on
  this Standard cannot be determined accurately at this time, as it will depend
  on future events such as number of options granted, volatility of the Companys
  stock price and other relevant factors.

9

---

Oil and Gas Full Cost Accounting 
  In July 2003 the AcSB issued Accounting Guideline 16, Oil and Gas Accounting
  - Full Cost (AcG-16), replacing AcG-5 which is effective January
  1, 2004, AcG-16 provides for methodology consistent with CICA section 3063,
  Impairment of Long-lived Assets, CICA section 3475, Disposal
  of Long-lived Assets and Discontinued Operations and FASB Statement No.
  144, Accounting for the Impairment and Disposal of Long-lived Assets.

The new standards prescribe the recognition of impairment
  only if the carrying amount of a long-lived asset is not recoverable from its
  undiscounted cash flows and measure the impairment amount as the difference
  between the carrying amount and the fair value. In addition, discontinued operations
  disclosure will be required upon the disposition of a cost centre of the entity
  rather than an entire business segment.

This Guideline is not expected to have a material effect on
  the Company.

Accounting for Derivative Instruments and Hedging Activities
  
  Effective January 1, 2004 the Company will adopt 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 Guideline is not expected to have a material effect on
  the Company.

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.                                                             

10

---

QUARTERLY FINANCIAL SUMMARY

|                                    |     |           | 2003 |   |           | 
|----------------------------------- | --- | --------- | ---- | - | --------- | 
|                                    |     |           |      |   |           | 
|                                    | Q-4 |           | Q-3  |   | Q-2       | 
|                                    |     |           |      |   |           | 
|Oil and gas sales, net of royalties | $   | 4,488,447 |      | $ | 4,158,664 | 
|                                    |     |           |      |   |           | 
|Cash flow from operations           | $   | 1,894,490 |      | $ | 2,192,540 | 
|Cash flow from operations per share |     |           |      |   |           | 
|- Basic                             | $   | 0.04      |      | $ | 0.04      | 
|- Diluted                           | $   | 0.04      |      | $ | 0.04      | 
|                                    |     |           |      |   |           | 
|Net income                          | $   | 3,413,717 |      | $ | 290,540   | 
|Net income per share                |     |           |      |   |           | 
|- Basic                             | $   | 0.06      |      | $ | 0.01      | 
|- Diluted                           | $   | 0.06      |      | $ | 0.01      | 
|                                    |     |           |      |   |           | 
|                                    |     |           |      |   |           | 
|                                    |     |           |      |   | 2002      | 
|                                    |     |           |      |   |           | 
|                                    |     | Q-4       |      |   | Q-3       | 
|                                    |     |           |      |   |           | 
|Oil and gas sales, net of royalties | $   | 5,459,364 |      | $ | 2,964,411 | 
|                                    |     |           |      |   |           | 
|Cash flow from operations           | $   | 4,380,792 |      | $ | 2,111,302 | 
|Cash flow from operations per share |     |           |      |   |           | 
|- Basic                             | $   | 0.09      |      | $ | 0.04      | 
|-Diluted                            | $   | 0.09      |      | $ | 0.04      | 
|                                    |     |           |      |   |           | 
|Net income                          | $   | 3,197,791 |      | $ | 1,040,470 | 
|Net income per share                |     |           |      |   |           | 
|- Basic                             | $   | 0.07      |      | $ | 0.02      | 
|- Diluted                           | $   | 0.06      |      | $ | 0.02      | 

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.

Significant variations between quarters are as follows:

- Q4, 2003 increase in net income to $3,413,717 is mainly
      a result of recognizing future tax benefits in Canada of $2,448,085 and
      recording a gain on disposal of seismic data in the United States of $363,141.
- Q4, 2002 increases in oil and gas sales, net of royalties,
      cash flow from operations and net income were impacted by historical cost
      oil reallocation of $1,496,000 between partners on Block 32 in Yemen which
      resulted in lower royalties in that quarter.

11

---

MANAGEMENTSREPORT

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  
|                        |                          
|April 1, 2004           |                          

12

---