MANAGEMENT’S DISCUSSION AND ANALYSIS

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

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

          Non-GAAP Measures
          This document contains the term “cash flow from operations”, which should not be considered an alternative to, or more meaningful than “cash flow from operation activities” as determined in accordance with Generally Accepted Accounting Principles (GAAP). Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital. We consider this a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment. Cash flow from operations may not be comparable to similar measures used by other companies.
          Net operating income is a non-GAAP measure that represents revenue net of royalties and operating expenses. Management believes that net operating income is a useful supplemental measure to analyse operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Net operating income may not be comparable to similar measures used by other companies.

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

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OVERVIEW

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

Selected Annual Information
($000’s, except per share amounts,			%		%
volumes and % change)		2005	Change	2004	Change	2003
Average production volumes (Boepd)*		4,991	29	3,865	47	2,635
Average sales volumes (Boepd)*		4,959	31	3,796	44	2,635
Average price ($/Boe)		49.92	40	35.63	25	28.43
Oil and gas sales		90,350	83	49,495	81	27,336
Oil and gas sales, net of royalties		58,911	86	31,630	84	17,162
Cash flow from operations**		38,077	120	17,325	85	9,347
Cash flow from operations per share
	- Basic	0.66		0.32		0.18
	- Diluted	0.63		0.31		0.17
Net income		19,850	235	5,919	-	5,905
Net income per share
	- Basic	0.34		0.11		0.11
	- Diluted	0.33		0.10		0.11
Total assets		86,286	43	60,522	70	35,601
* The differences in production and sales volumes result from inventory changes at Block S-1, Yemen. ** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

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          Cash flow from operations increased by 120% in 2005 compared to 2004 mainly as a result of a 31% increase in sales volumes attributed to the pipeline completion and development drilling on Block S-1, Yemen, new wells in Canada and a 40% increase in commodity prices, which were offset in part by increases in royalties, operating costs and taxes associated with the increased volumes and prices, as displayed below:

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

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

          Management Strategy
          In 2006, the capital budget is focused on growing reserves and production in Yemen and in Canada. Also, a portion of the 2006 capital budget will be spent defining leads and drilling two exploration wells on Nuqra Block 1 in Egypt.
          
           The success of these strategies is subject to numerous risk factors such as (including but not limited to) exploration success, fluctuations in commodity prices and foreign exchange rates, in addition to credit, operational and safety and environmental risks.

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

• Crude oil and natural gas prices.

• The price differential and demand related to various crude oil qualities.

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

• Availability of equipment and labour to conduct field activities.

• Availability of pipeline capacity.

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Commodity Price and Foreign Exchange Benchmarks

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

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

          In 2005, TransGlobe sold approximately:

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

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

          In 2005, TransGlobe sold approximately:

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

OPERATING RESULTS

          Daily Volumes, Working Interest Before Royalties

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

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          Consolidated Net Operating Results

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

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

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

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

* Net operating income amounts do not reflect Yemen income tax expense which is paid through oil allocations with MOM in $5.28/Boe, 2004 - $5,269,000, $4.62/Boe.)
	Net operating income in Yemen increased 101% in 2005 primarily as a result of the following:
	•	Oil sales increased 84% mainly as a result of the following:
		1.	Sales volumes increased 31% in 2005 primarily as a result of:
			-	Block S-1 sales volumes increased 225% from 666 Bopd in 2004 to 2,166 Bopd in 2005 as a resultof drilling success and pipeline completion in June 2005.
			-	offset by natural declines at Block 32 which decreased sales volumes by 21% from 2,453 Bopd in 2004 to 1,926 Bopd in 2005.
		2.	Oil prices increased by 41%.
	•	Royalty costs increased 75% as a result of increased volumes and prices. Royalties as a percentage of revenue (royalty rate) decreased to 38% in 2005 compared to 40% in 2004. This was a result of a significant increase in Block S-1 production which has a lower royalty rate than Block 32. Royalty rates fluctuate in Yemen due to changes in the amount of cost sharing oil, whereby the Block 32 and Block S-1 PSA’s allow for the recovery of operating and capital costs through a reduction in MOM take of oil production as discussed below:

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	1.	Block 32:
		-	Operating costs are recovered in the quarter expended.
		-	The capital costs are amortized over two years with 50% recovered in the quarter expended and the remaining 50% recovered in the first quarter of the following calendar year. As a result, the Company will receive a larger share of production in the first quarter of each year as 50% of the previous year’s historical costs are recovered.
		-	In 2005, the Company’s royalty rate was 42% compared to 43% in 2004.
		-	In 2006, the Company’s royalty rate is expected to average between 25% and 28% in the first quarter and increase to between 41% to 45% for the balance of the year depending upon production volumes, oil prices, operating costs and eligible capital expenditures.
	2.	Block S-1:
		-	Operating costs are recovered in the quarter expended.
		-	New capital costs are amortized over eight quarters with one eighth (12.5%) recovered each quarter.
		-	Historical exploration costs, which consist of the costs expended before the Contractor declared commerciality of the Block, are recovered on a “last in, first out” basis.
		-	For the first three quarters of 2005 and all of 2004, the Company’s royalty rate was 30%. At the end of the third quarter, the Company had recovered its historical exploration cost pools which resulted in an increase to royalty rate of 46% for the fourth quarter.
		-	In 2006, the Company’s royalty rate is expected to average between 38% and 46% depending upon production volumes, oil prices, operating costs and eligible capital expenditures.
		-	The Company anticipates recovery of the majority of historical development cost pools to occur in 2006.
•	Operating expenses on a Boe basis increased 15% mainly as a result of the following:
	1.	Block 32 operating expenses averaged $5.80 per barrel in 2005 compared to $4.11 per barrel in 2004 primarily due to increased diesel costs. A diesel topping plant was constructed in 2005 to manufacture diesel from produced crude oil which will reduce diesel costs significantly on a go forward basis. The plant became operational in December 2005.
	2.	An increased percentage of the Yemen production was from Block S-1 in 2005 (53% in 2005 compared 21% in 2004) which had a higher operating cost per Boe than Block 32. Block S-1 operating costs averaged $5.17 per barrel in 2005 compared to $7.96 per barrel in 2004 (first half of 2005 was $5.90 per barrel with the second half of 2005 at $4.56 per barrel). This reduction is a reflection of increased volumes and commissioning of the pipeline in June 2005.

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

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

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

GENERAL AND ADMINISTRATIVE EXPENSES

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

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

• Personnel and office overhead costs increased due to additional staff.

• Public company costs increased mainly due to the Company preparing for the new Sarbanes Oxley compliance requirements.

• Deferred financing cost amortization commenced in Q4-2004.

• Capitalized general and administrative expenses increased mainly as a result of expansion in the Egypt operations and overhead recoveries increased due to the increased capital activity in Canada.

• The strengthening of the Canadian dollar against the United States dollar increased net G&A costs by $0.08 per Boe through currency conversion.

STOCK-BASED COMPENSATION

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

DEPLETION, DEPRECIATION AND ACCRETION EXPENSE (DD&A)

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

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

INCOME TAXES

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

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

CAPITAL EXPENDITURES/DISPOSITIONS

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

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

FINDING AND DEVELOPMENT COSTS

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

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

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

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RECYCLE RATIO

	Three Year
Proved	Average	2005	2004	2003
Netback ($/Boe)	$ 15.56	$ 21.04	$ 12.46	$ 9.72
Proved finding and development costs ($/Boe)	$ 9.57	$ 13.75	$ 8.12	$ 6.94
Recycle ratio	1.63	1.53	1.53	1.40
	Three Year
Proved Plus Probable	Average	2005	2004	2003
Netback ($/Boe)	$ 15.56	$ 21.04	$ 12.46	$ 9.72
Proved plus Probable finding and development
costs ($/Boe)	$ 8.19	$ 22.41	$ 5.61	$ 5.24
Recycle ratio	1.90	0.94	2.22	1.85

          The 2005 proved recycle ratio was consistent with 2004. The decrease in the 2005 proved plus probable recycle ratio to 0.94 compared to 2004 of 2.22 mainly relates to a higher finding and development cost.
          The recycle ratio measures the efficiency of TransGlobe’s capital program by comparing the cost of finding and developing proved reserves with the netback from production. The ratio is calculated by dividing the netback by the proved finding and development cost on a Boe basis. Netback is defined as net sales less operating, general and administrative (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Boe of production.

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

OUTSTANDING SHARE DATA

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

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SELECTED QUARTERLY INFORMATION

	2005				2004
($000’s, except per share amounts and volumes)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average production volumes (Boepd)*	5,132	5,285	4,658	4,887	4,979	4,303	3,389	2,765
Average sales volumes (Boepd)*	4,935	5,533	4,375	4,985	5,384	3,918	3,103	2,760
Average price ($/Boe)	54.58	56.57	44.99	42.04	37.45	37.12	34.25	31.44
Oil and gas sales	24,781	28,796	17,911	18,863	18,548	13,380	9,670	7,897
Oil and gas sales, net of royalties	14,442	19,147	11,778	13,544	11,756	8,227	5,779	5,868
Cash flow from operations**	8,603	13,142	7,263	9,070	6,326	4,363	2,749	3,887
Cash flow from operations per share
- Basic	0.15	0.23	0.13	0.16	0.12	0.08	0.05	0.07
- Diluted	0.14	0.22	0.12	0.15	0.11	0.08	0.05	0.07
Net income	4,331	7,539	3,474	4,507	768	2,541	447	2,163
Net income per share
- Basic	0.07	0.13	0.06	0.08	0.01	0.05	0.01	0.04
- Diluted	0.07	0.13	0.06	0.08	0.01	0.04	0.01	0.04
* The differences in production and sales volumes result from inventory changes at Block S-1, Yemen.
** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working

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

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

• A 4% decrease in average commodity prices.

• An 11% decrease in sales volumes (mainly a result of inventory draw in Q-3 and inventory build in Q-4).

• TransGlobe’s percentage of the cost oil on Block S-1 Yemen in Q-4 2005 was reduced as a result of recovering its historical exploration cost pools. This resulted in an approximately $2.0 million reduction in cash flows from operations.

          LIQUIDITY AND CAPITAL RESOURCES

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

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

Sources and Uses of Cash
($000’s)	2005	2004
Cash sourced
Cash flow from operations*	38,077	17,325
Issue of common shares	1,218	10,006
	39,295	27,331
Cash used
Exploration and development expenditures	32,654	26,367
Other	155	871
	32,809	27,238
Net cash	6,486	93
Increase in non-cash working capital	747	443
Increase in cash and cash equivalents	7,233	536
Cash and cash equivalents - beginning of year	4,988	4,452
Cash and cash equivalents - end of year	12,221	4,988
* Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital

          Funding for the Company’s capital expenditures in 2005 was provided by cash flow from operations, working equity financing in 2004.
          Working capital is the amount by which current assets exceed current liabilities. At December 31, 2005 working capital of $9,471,000 (2004 - $2,839,000), zero debt and an unutilized loan facility of $7,000,000. Accounts due primarily to higher revenue receivables as a result of volume and his was offset by. price increases T increased accounts payable primarily to increased capital expenditures in late 2005 related to the Canadian drilling program, increased operating and Yemen due to higher volumes, offset by reduced Yemen capital payables compared to 2004 mainly due to construction on Block S-1 which was completed in June 2005.
           The Company expects to fund its approved 2006 exploration and development program of $45.3 million flowuse of our credit facilities or equity financing during 2006 are expected to be utilized only to accelerate working capital and cash existing projects or to finance new opportunities. Fluctuations in commodity prices, product demand, foreign exchange and various other risks may impact capital resources.

COMMITMENTS AND CONTINGENCIES

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

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

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

CRITICAL ACCOUNTING POLICIES

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

          Oil and Gas Reserves

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

          Full Cost Accounting for Oil and Gas Activities

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

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

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

          Income Tax Accounting
          The Company has recorded a future income tax asset in 2005, 2004 and 2003. This future income tax asset is an estimate of the expected benefit that will be realized by the use of deductible temporary differences in excess of carrying value of the Company’s Canadian property and equipment against future estimated taxable income. These estimates may change substantially as additional information from future production and other economic conditions such as oil and gas prices and costs become available.
          The determination of the Company’s income tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

          Currency Translation
          The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at year-end exchange rates and revenues and expenses are translated using average annual exchange rates. Translation gains and losses relating to the self-sustaining operations are included as a separate component of shareholders’ equity.
          Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings.

          Derivative Financial Instruments
          Derivative financial instruments are used by the Company to manage its exposure to market risks relating to commodity prices. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.
          Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded at fair values where instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net income. Realized gains or losses from financial derivatives related to commodity prices are recognized in natural gas and crude oil revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimation of the fair value of certain derivative financial instruments requires considerable judgement. The estimation of the fair value of commodity price instruments requires sophisticated financial models that incorporate forward price and volatility data. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

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

NEW ACCOUNTING STANDARDS

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

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

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

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

RISKS

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

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

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

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

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

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

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

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

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

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2005, an evaluation was carried out under the supervision, and with the participation, of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

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OUTLOOK

	2006 Production Outlook
		2006	2005	Change *
Barrels of oil equivalent per day		5,300 to 5,600	4,991	9%
* % growth based on mid point of guidance
	2006 Cash Flow From Operations Outlook
($000’s)		2006	2005	Change *
Cash flow from operations		43,000 to 45,000	38,077	16%
* Based on a dated Brent oil price of $55.00/Bbl and an AECO gas price of C$7.50/Mcf, from existing fields in Yemen and planned development
	Sensitivity
		2006 Cash Flow from
($000’s)		Operations Increase/Decrease
$1.00 per barrel change in dated Brent		560
C $1.00 per Mcf change in AECO		1,700
	2006 Capital Budget
($000’s)		2006
Canada		20,400
Yemen  - Block S1		11,900
- Block 32		3,500
- Block 72		2,100
Egypt		7,400
Total		45,300

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

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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.

/s/ Ross G. Clarkson Ross G. Clarkson
President &
Chief Executive Officer March 8, 2006 /s/ David C. Ferguson David C. Ferguson
Vice President, Finance &
Chief Financial Officer

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