Management's Discussion and Analysis
for 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.

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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		2002
	$	$/Boe	$	$/Boe
Oil and gas sales	27,335,841	28.43	15,386,359	24.34
Royalties	10,174,131	10.58	2,132,254	3.37
Operating expenses	3,706,096	3.85	1,843,273	2.92
Net operating income*	13,455,614	14.00	11,410,832	18.05

 

* 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).
 

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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	$	$/Boe
Oil sales	24,356,094	28.13	14,206,217	25.18
Royalties	9,731,206	11.24	1,967,506	3.49
Operating expenses	3,011,620	3.48	1,394,379	2.47
Net operating income*	11,613,268	13.41	10,844,332	19.22

 

* 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.	In 2002, TransGlobe had a cost oil reallocation between the Block 32 Joint Venture Group that decreased its royalty costs by $1,349,000.
	2.	In 2003, TransGlobe had a final cost oil reallocation between the Block 32 Joint Venture Group that increased its royalty costs by $1,245,000.
	3.	The Block 32 Joint Venture Group had recovered all of its historical cost pools by the second quarter of 2003, thereby reducing cost oil and increasing the production sharing oil which results in increased royalties and taxes to the Yemen government.
•	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

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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	$	$/Boe
Oil sales	344,630	27.00	210,827	22.01
Gas sales (6 : 1)	2,292,870	31.44	901,138	16.60
NGL sales	236,093	23.42	68,177	16.84
Other sales	106,154	-	-	-
	2,979,747	31.10	1,180,142	17.38
Royalties	442,925	4.62	164,748	2.43
Operating expense	694,476	7.25	448,894	6.61
Net operating income	1,842,346	19.23	566,500	8.34

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		$		$/Boe
G&A (gross)	1,568,401		1.63		1,234,921		1.95
Capitalized G&A	(278,257	)	(0.29	)	(392,403	)	(0.62	)
Overhead recoveries	(83,807	)	(0.09	)	(21,827	)	(0.03	)
G&A (net)	1,206,337		1.25		820,691		1.30

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.
   

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DEPLETION AND DEPRECIATION EXPENSE

	2003		2002
	$	$/Boe	$	$/Boe
Republic of Yemen	5,516,000	6.37	3,960,000	7.02
Canada	737,000	7.69	317,000	4.67
	6,253,000	6.50	4,277,000	6.77

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	)	$	(67,168	)
Current income tax		2,755,067			986,862
	$	306,982		$	919,694

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.

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CAPITAL EXPENDITURES/DISPOSITIONS

Capital Expenditures

	2003			2002
Republic of Yemen	$	9,012,022		$	5,435,398
Canada		5,217,084			1,041,146
		14,229,106			6,476,544
Proceeds on sale of property and equipment		(442,103	)		(133,587	)
Net capital expenditures	$	13,787,003		$	6,342,957

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.

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FINDING AND DEVELOPMENT COSTS

	2003				2002
			Proved +		Proved +
	Proved		Probable		Proved		Probable
Total capital expenditure	$	14,229,107	$	14,229,107	$	6,476,544	$	6,476,544
Net change from previous year’s future capital		2,158,637		11,303,354		634,524		465,967
	$	16,387,744	$	25,532,461	$	7,111,068	$	6,942,511
Reserve additions and revisions (MBoe)		2,360.7		4,872.5		1,209.7		1,390.2
Average cost per Boe	$	6.94	$	5.24	$	5.88	$	4.99
Three year average cost per Boe	$	6.40	$	5.47	$	6.75	$	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 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	$	11.69
Proved finding and development costs ($/Boe)	$	6.40	$	6.94	$	5.88	$	5.73
Recycle ratio		1.86		1.40		2.61		2.04

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

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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.

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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.

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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.

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QUARTERLY FINANCIAL SUMMARY

			2003
	Q-4		Q-3		Q-2		Q-1
Oil and gas sales, net of royalties	$	4,488,447	$	4,158,664	$	4,139,106	$	4,375,493
Cash flow from operations	$	1,894,490	$	2,192,540	$	2,368,713	$	2,891,258
Cash flow from operations per share
- Basic	$	0.04	$	0.04	$	0.05	$	0.06
- Diluted	$	0.04	$	0.04	$	0.05	$	0.06
Net income	$	3,413,717	$	290,540	$	775,713	$	1,425,258
Net income per share
- Basic	$	0.06	$	0.01	$	0.01	$	0.03
- Diluted	$	0.06	$	0.01	$	0.01	$	0.03
				2002
		Q-4		Q-3		Q-2		Q-1
Oil and gas sales, net of royalties	$	5,459,364	$	2,964,411	$	2,859,258	$	1,971,072
Cash flow from operations	$	4,380,792	$	2,111,302	$	1,951,125	$	1,266,633
Cash flow from operations per share
- Basic	$	0.09	$	0.04	$	0.04	$	0.02
-Diluted	$	0.09	$	0.04	$	0.04	$	0.02
Net income	$	3,197,791	$	1,040,470	$	873,125	$	315,003
Net income per share
- Basic	$	0.07	$	0.02	$	0.02	$	0.01
- Diluted	$	0.06	$	0.02	$	0.02	$	0.01

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.

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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
April 1, 2004

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