Management's Discussion and Analysis

March 20, 2007

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, 2006 and 2005, 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 16 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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TransGlobe Energy Corporation

	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
	($000’s, except per share, price and		%		%
	volume amounts and % change)	2006	Change	2005	Change	2004
	Average production volumes (Boepd)*	5,093	2	4,991	29	3,865
	Average sales volumes (Boepd)*	5,077	2	4,959	31	3,796
	Average price ($/Boe)	58.92	18	49.92	40	35.63
	Oil and gas sales	109,190	21	90,350	83	49,495
	Oil and gas sales, net of royalties and other	70,097	19	58,911	86	31,630
	Cash flow from operations**	46,763	23	38,077	120	17,325
	Cash flow from operations per share
	- Basic	0.80		0.66		0.32
	- Diluted	0.77		0.63		0.31
	Net income	26,195	32	19,850	235	5,919
	Net income per share
	- Basic	0.45		0.34		0.11
	- Diluted	0.43		0.33		0.10
	Total assets	116,473	35	86,286	43	60,522

* The differences in production and sales volumes result from inventory changes.
** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

Cash flow from operations increased by 23% in 2006 compared to 2005 mainly as a result of a 2% increase in sales volumes attributed to the pipeline completion and development drilling on Block S-1, Yemen, new wells in Canada and a 18% 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
	2005 Cash flow from operations**	38,077	0.63
	Volume variance	2,197	0.04	6
	Price variance	16,643	0.27	44
	Royalties	(7,654)	(0.13)	(20)
	Expenses:
	Operating	(854)	(0.01)	(2)
	Cash general and administrative	(797)	(0.01)	(2)
	Current income taxes	(1,247)	(0.02)	(3)
	Realized foreign exchange gain (loss)	54	-	-
	Settlement of asset retirement obligations	99	-	-
	Other	245	-	-
	Change in weighted average number of diluted shares outstanding	-	-	-
	2006 Cash flow from operations**	46,763	0.77	23

** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

Net income for 2006 increased 32% mainly as a result of the above increases in cash flow from operations.

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2006 Annual Report

Management Strategy and Business Environment

In 2007, the capital budget is focused on growing reserves and production in Yemen and in Canada. Also, a portion of the 2007 capital budget will be spent drilling two exploration wells on Nuqra Block 1 in Egypt.

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

• Exploratory success.
• 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.
• Foreign exchange and credit.
• Operational, safety and environmental.

Commodity Price and Foreign Exchange Benchmarks

			%		%
		2006	Change	2005	Change	2004
	Dated Brent average oil price ($ per barrel)	64.88	19	54.57	41	38.58
	WTI average oil price ($ per barrel)	66.09	17	56.46	36	41.42
	Edmonton Par average oil price (C$ per barrel)	73.30	6	69.29	31	52.91
	AECO average gas price (C$ per MMBtu)	6.51	(25)	8.73	33	6.54
	U.S./Canadian Dollar Year End Exchange Rate	1.1654	-	1.1630	(3)	1.2020
	U.S./Canadian Dollar Average Exchange Rate	1.1343	(6)	1.2114	(7)	1.3013
	World crude oil prices continued to increase significantly in 2006. Oil prices continued to be volatile during 2006 since global demand for oil remained very strong and outpaced supply increases. Also, supply uncertainties continued due to geopolitical concerns mainly in the Middle East, West Africa and South America. In 2006, TransGlobe sold approximately: 96% of its crude oil at dated Brent minus the selling price differentials. the remaining 4% at the Edmonton Par price less quality differentials. In 2005, natural gas 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/MMBtu in 2005, a 33% increase from 2004. In 2006 the weather in North America was extremely mild which reduced demand for natural gas. As a result, the 2006 average AECO natural gas price moderated to approximately C$6.51 per MMBtu. In 2006, TransGlobe sold all of its natural gas at AECO Index based pricing.

27

TransGlobe Energy Corporation

OPERATING RESULTS

Daily Volumes, Working Interest Before Royalties and Other

				2006	2005	% Change
		Yemen - Oil sales	Bopd	4,046	4,092	(1)
		Canada - Oil and liquids sales	Bopd	331	220	50
		- Gas sales	Mcfpd	4,204	3,880	8
		Canada	Boepd	1,031	867	19
		Total Company - daily sales volumes	Boepd	5,077	4,959	2
	Consolidated Net Operating Results
			Consolidated
			2006		2005
		(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
		Oil and gas sales	109,190	58.92	90,350	49.92
		Royalties and other	39,093	21.09	31,439	17.37
		Operating expenses	11,107	5.99	10,253	5.67
		Net operating income*	58,990	31.84	48,658	26.88
		* Net operating income amounts do not reflect Yemen income tax expense which is paid through oil allocations with MOM in Yemen (2006 - $9,129,000, $4.93/Boe, 2005 - $7,882,000, $4.36/Boe) .
	Segmented Net Operating Results
		In 2006 the Company had producing operations in two geographic areas, segmented as Yemen and Canada. Also, the Company had 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).
			2006		2005
		(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
		Oil sales	93,189	63.10	76,300	51.09
		Royalties and other	36,353	24.62	28,916	19.36
		Operating expenses	8,108	5.49	8,219	5.50
		Net operating income*	48,728	32.99	39,165	26.23
		* Net operating income amounts do not reflect Yemen income tax expense which is paid through oil allocations with MOM in Yemen (2006 - $9,129,000, $6.18/Boe, 2005 - $7,882,000, $5.28/Boe) .
		Net operating income in Yemen increased 24% in 2006 primarily as a result of the following:
		•   Oil sales increased 22% mainly as a result of the following:            1. Oil prices increased by 24%.            2. Sales volumes decreased 1% in 2006 primarily as a result of:                       - Block 32 sales volumes decreased by 26% from 1,926 Bopd in 2005 to 1,429 Bopd in 2006, due to natural declines in the Tasour field.                       - Block S-1 sales volumes increased 21% from 2,166 Bopd in 2005 to 2,617 Bopd in 2006.

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2006 Annual Report

Daily Volumes, Working Interest	12 Months Ended	12 Months Ended
Before Royalties	December 31, 2006	December 31, 2005
	Bopd	Bopd		% Change
Block S-1 - production	2,592	2,198		18
- inventory change	25	(32	)	-
Block S-1 - sales	2,617	2,166		21
Block 32 - sales	1,429	1,926		(26	)
Total sales	4,046	4,092		(1	)

Royalty costs increased 26%. Royalties as a percentage of revenue (royalty rate) increased to 39% in 2006 compared to 38% in 2005. 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:
	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 2006, the Company’s royalty rate was 41% compared to 42% in 2005.
	-	In 2007, the Company’s royalty rate is expected to average between 27% and 29% in the first quarter and increase to between 34% to 39% for the balance of the year depending upon production volumes, oil prices, operating costs and eligible capital expenditures.
	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.
	-	For the first three quarters 2005, 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 increased royalty rate of 46% for the fourth quarter. In 2006, the Company’s royalty rate was 38%.
	-	In 2007, the Company’s royalty rate is expected to average between 38% and 43% depending upon production volumes, oil prices, operating costs and eligible capital expenditures.
Operating expenses on a Boe basis were consistent at $5.49 in 2006 compared to $5.50 in 2005.

1.	Block 32 operating expenses decreased to $5.18 per barrel in 2006 compared to $5.80 per barrel in 2005 primarily due to decreased diesel costs. A diesel topping plant was constructed in 2005 to manufacture diesel from produced crude oil which reduced diesel costs significantly on a go forward basis. The plant became operational in December 2005.
2.	Block S-1 operating costs increased to $5.66 per barrel in 2006 compared to $5.17 per barrel in 2005.

Canada

		2006		2005
	(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
	Oil sales	3,178	58.45	1,886	52.04
	Gas sales ($ per Mcf)	9,478	6.18	10,292	7.27
	NGL sales	3,266	49.24	1,785	40.46
	Other sales	79	-	87	-
		16,001	42.51	14,050	44.41
	Royalties and other	2,740	7.28	2,523	7.97
	Operating expenses	2,999	7.97	2,034	6.43
	Net operating income	10,262	27.26	9,493	30.01
						29

TransGlobe Energy Corporation

Net operating income in Canada increased 8% in 2006 primarily as a result of the following:

Sales increased 14% mainly due to:
1.	Sales volumes increased 19% as a direct result of successful drilling.
2.	Offset by a commodity price decrease of 4% on a Boe basis.
Royalty costs decreased 9% on a Boe basis. Royalties as a percentage of revenue were consistent at 17% in 2006 compared to 18% in 2005. During the third quarter of 2006, the Alberta government announced it is discontinuing the Alberta Royalty Tax Credit program effective January 1, 2007. As a result, the Company’s royalties will be increased by C$500,000 in 2007.
Operating costs increased 24% on a Boe basis mainly as a result of five well workovers and overall general cost increases for all services resulting from a very active oil and gas industry in Canada.

UNREALIZED GAIN ON COMMODITY CONTRACTS

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). Through to the expiration of the contract, no realized gains or losses occurred.

GENERAL AND ADMINISTRATIVE EXPENSES

	2006				2005
(000’s, except per Boe amounts)	$		$/Boe		$		$/Boe
G&A (gross)	5,914		3.19		4,754		2.63
Stock based compensation	1,168		0.63		723		0.40
Capitalized G&A	(1,999	)	(1.08	)	(1,675	)	(0.93	)
Overhead recoveries	(409	)	(0.22	)	(258	)	(0.14	)
G&A (net)	4,674		2.52		3,544		1.96

General and administrative expenses (“G&A”) increased 32% in 2006 (29% increase on a Boe basis) compared to 2005 as a result of the following:

• Personnel and office overhead costs increased due to additional staff in both the Calgary and Cairo offices.
• Public company costs increased mainly due to the Company preparing for the new Sarbanes Oxley compliance requirements.
• Capitalized general and administrative expenses increased mainly as a result of expansion in the Eqypt operations and overhead recoveries increased due to the increased capital activity in Canada.

DEPLETION, DEPRECIATION AND ACCRETION EXPENSE (DD&A)

	2006		2005
(000’s, except per Boe amounts)	$	$/Boe	$	$/Boe
Republic of Yemen	11,623	7.87	13,172	8.82
Canada	7,281	19.34	3,812	12.05
Arab Republic of Egypt	37	-	6	-
	18,941	10.22	16,990	9.39

In Yemen, DD&A on a Boe basis decreased 11% in 2006 compared to 2005 primarily as a result of decreased finding and development costs in Yemen.

In Yemen (Block 72, Block 75 and Block 84) and Egypt (Nuqra Block 1) major development costs of $2,638,000 and $7,683,000 respectively, were excluded from costs subject to depletion and depreciation.

In Canada, DD&A on a Boe basis increased 60% in 2006 compared to 2005 primarily as a result of increased finding and development costs in Canada.

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2006 Annual Report

INCOME TAXES

($000’s)	2006	2005
Current income tax	9,129	7,882
Future income tax	263	471
	9,392	8,353

 

	Current income tax expense in 2006 of $9,129,000 (2005 - $7,882,000) represents income taxes incurred and paid under the laws of Yemen pursuant to the PSA’s on Block 32 and Block S-1. The increase in Yemen is primarily the result of increased revenue in Yemen. The income tax expense in Yemen as a percent of Yemen revenue was 10% in 2006 and 2005. No income tax was paid in Canada in 2006 or in 2005. At December 31, 2006, the Company has C$53 million in Canadian tax pools. It is estimated that C$24 million of these pools will be available to deduct against 2007 taxable Canadian income. The future income expense was $263,000 in 2006 (2005 - $471,000) which relates to a non-cash expense for taxes to be incurred in the future as Canadian tax pools reverse. CAPITAL EXPENDITURES/DISPOSITIONS
Capital Expenditures

 

			2006				2005
		Geological	Drilling	Facilities
	Land and	and	and	and
($000’s)	Acquisition	Geophysical	Completions	Pipelines	Other	Total	Total
Republic of Yemen
Block S-1	-	1,050	10,054	5,732	305	17,141	12,487
Block 32	-	791	5,943	1,430	114	8,278	3,999
Block 72	-	419	365	-	110	894	1,453
Block 75	250	-	-	-	-	250	-
Block 84	-	-	-	-	15	15	-
Other	-	-	-	-	7	7	-
	250	2,260	16,362	7,162	551	26,585	17,939
Canada	2,081	312	10,916	5,649	647	19,605	13,189
Arab Republic of Egypt	-	3,053	1,241	-	1,071	5,365	1,526
	2,331	5,625	28,519	12,811	2,269	51,555	32,654

On Block S-1 in Yemen, the Company drilled six wells (An Nagyah #19, #20, #21, #22, Wadi Bayhan #2 and Osaylan #2), continued working on CPF construction and expansion and began shooting a 3-D seismic acquisition (which was postponed). On Block 32, the Company drilled eight wells (Godah #1, #2, #3, #4, Tasour #21, #22, #23 and #24), began work on the Godah tie-in and began seismic acquisition. On Block 72, the Company continued to define drilling leads through seismic acquisition and processing and began access construction and the rig move for the first exploration well.

In Canada, the Company drilled 26 wells (20.8 net) mainly in the Nevis, Morningside and Thorsby areas. Also, the Company carried out completion and testing work on 27 wells, tied-in 18 wells and added compression equipment, mainly in the Nevis area.

In Egypt, the Company completed the field seismic acquisition on Nuqra Block 1 on April 5, 2006. The processing of seismic was completed in July. Interpretation and mapping of the seismic were completed and drilling locations selected. Drilling preparation began by starting access construction and purchasing drilling materials.

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TransGlobe Energy Corporation

FINDING AND DEVELOPMENT COSTS

Proved
	($000’s, except volumes and $/Boe amounts)	2006		2005	2004
	Total capital expenditure	51,555		32,654	26,367
	Net change from previous year’s future capital	(1,154	)	8,418	8,796
		50,401		41,072	35,163
	Reserve additions and revisions (MBoe)	3,371		2,987	4,332
	Average cost per Boe	14.95		13.75	8.12
	Three year average cost per Boe	11.85		9.57	7.42
Proved Plus Probable
	($000’s, except volumes and $/Boe amounts)	2006		2005	2004
	Total capital expenditure	51,555		32,654	26,367
	Net change from previous year’s future capital	3,943		9,449	597
		55,498		42,103	26,964
	Reserve additions and revisions (MBoe)	3,025		1,879	4,804
	Average cost per Boe	18.35		22.41	5.61
	Three year average cost per Boe	12.83		8.19	5.37

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.

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

Proved
			Three Year
			Average		2006		2005		2004
	Netback ($/Boe)	$	20.22	$	25.23	$	21.04	$	12.46
	Proved finding and development costs ($/Boe)	$	11.85	$	14.95	$	13.75	$	8.12
	Recycle ratio		1.71		1.69		1.53		1.53
Proved Plus Probable
			Three Year
			Average		2006		2005		2004
	Netback ($/Boe)	$	20.22	$	25.23	$	21.04	$	12.46
	Proved plus Probable finding and development costs ($/Boe)	$	12.83	$	18.35	$	22.41	$	5.61
	Recycle ratio		1.58		1.38		0.94		2.22

The 2006 proved recycle ratio increased to 1.69 compared to 1.53 in 2005 mainly as a result of an increase in commodity prices. The 2006 proved plus probable recycle ratio increased to 1.38 compared to 0.94 in 2005 mainly as a result of increased commodity prices and lower proved plus probable finding and development costs. 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.

32

2006 Annual Report

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)		2006			2005			2004
Net income		26,195			19,850			5,919
Adjustments for non-cash items:
Depletion, depreciation and accretion		18,941			16,990			10,346
Stock-based compensation		1,168			723			1,310
Future income taxes		263			471			(285	)
Amortization of deferred financing costs		179			291			35
Unrealized loss (gain) on commodity contracts		83			(83	)		-
Settlement of asset retirement obligations		(66	)		(165	)		-
Netback		46,763			38,077			17,325
Sales volumes		1,853,252			1,809,779			1,389,920
Netback per Boe	$	25.23		$	21.04		$	12.46

OUTSTANDING SHARE DATA

Common Shares issued and outstanding as at March 7, 2007 are 59,542,439.

SELECTED QUARTERLY INFORMATION

	2006				2005
($000’s, except per share,
price and volume amounts)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average production volumes (Boepd)*	5,475	4,952	4,915	5,026	5,132	5,285	4,658	4,887
Average sales volumes (Boepd)*	5,313	4,952	5,522	4,515	4,935	5,533	4,375	4,985
Average price ($/Boe)	55.30	61.88	62.17	55.93	54.58	56.57	44.99	42.04
Oil and gas sales	27,032	28,190	31,238	22,730	24,781	28,796	17,911	18,863
Oil and gas sales, net of royalties
and other	17,647	18,542	18,600	15,308	14,442	19,147	11,778	13,544
Cash flow from operations**	10,448	12,662	12,356	11,297	8,603	13,142	7,263	9,070
Cash flow from operations per share
- Basic	0.18	0.22	0.21	0.19	0.15	0.23	0.13	0.16
- Diluted	0.17	0.21	0.20	0.19	0.14	0.22	0.12	0.15
Net income	4,726	7,366	7,246	6,857	4,331	7,539	3,474	4,507
Net income per share
- Basic	0.08	0.13	0.12	0.12	0.07	0.13	0.06	0.08
- Diluted	0.08	0.12	0.12	0.11	0.07	0.13	0.06	0.08

* The differences in production and sales volumes result from inventory changes.
** Cash flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

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.

33

TransGlobe Energy Corporation

Oil and gas sales decreased 8% in Q1-2006 compared to Q4-2005; however, cash flow from operations and net income increased 31% to $11,297,000 and 58% to $6,857,000, respectively, in the same period mainly as a result of royalty and income tax costs decreasing at Block 32, Yemen in Q1-2006 due to the recovery of 50% of the 2005 capital costs from oil production as part of the Block 32 PSA, as discussed above. This was partially offset by an inventory build-up at Block S-1 since a portion of the March 2006 lifting was deferred to April 1, 2006.

Fourth Quarter 2006

Cash flow from operations decreased in Q4-2006 by $2,214,000 (17%) compared to Q3-2006 mainly as a result of the following:

• An 11% decrease in average commodity prices.
• Increased operating costs in Yemen due to technical charges from the partner for Block S-1.
• This is partially offset by an 7% increase in sales volumes.

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

The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2006 and 2005:

Sources and Uses of Cash

($000’s)	2006		2005
Cash sourced
Cash flow from operations*	46,763		38,077
Issue of common shares	297		1,218
	47,060		39,295
Cash used
Exploration and development expenditures	51,555		32,654
Other	545		155
	52,100		32,809
Net cash	(5,040	)	6,486
Increase in non-cash working capital	1,655		747
Change in cash and cash equivalents	(3,385	)	7,233
Cash and cash equivalents - beginning of year	12,221		4,988
Cash and cash equivalents - end of year	8,836		12,221

* 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 2006 was provided mainly by cash flow from operations and working capital.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2006 the Company had working capital of $4,361,000 (2005 - $9,471,000), zero debt and an unutilized loan facility of $55,000,000. Accounts receivable increased due primarily to higher revenue receivables as a result of volume increases in Yemen and Canada, oil price increases in Yemen offset by gas price decreases in Canada. This was offset by increased accounts payable due primarily to higher operating costs in Yemen and increased drilling activity at year end in Yemen.

The Company expects to fund its approved 2007 exploration and development program of $51 million through the use of working capital, cash flow and debt if necessary. The use of our credit facilities or equity financing during 2007 may also be utilized to accelerate existing projects or to finance new opportunities. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources.

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2006 Annual Report

COMMITMENTS AND CONTINGENCIES

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

($000’s)	2007	2008	2009	2010	2011
Office and equipment leases	284	386	409	402	101

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 Nuqra Concession Agreement in the Arab Republic of Egypt, the Company and its partners have entered into the first three year extension period which requires the completion of a two well drilling program with a minimum expenditure of $4.0 million over a period of three years. As part of this extension, the Company issued a $4.0 million letter of credit (expiring March 4, 2010) to guarantee the Company’s performance under the extension period. This letter of credit was reduced to $1,225,699 during 2006 and 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 (expiring January 12, 2008) for exploration work consisting of seismic acquisition (completed) and two exploration wells (planned completion in Q4-2007).

Pursuant to the bid awarded for Block 75, Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $7 million ($1.75 million to TransGlobe) for the signature bonus and first exploration period work program consisting of seismic acquisition and one exploration well. The first 36 month exploration period will commence when the PSA has been approved and ratified by the government of Yemen, anticipated to occur during 2007.

Pursuant to the bid awarded for Block 84, Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $20.1 million ($6.63 million to TransGlobe) for the signature bonus and first exploration period work program consisting of seismic acquisition and four exploration wells. The first 42 month exploration period will commence when the PSA has been approved and ratified by the government of Yemen, anticipated to occur in 2007.

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 reserve evaluators. 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.

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TransGlobe Energy Corporation

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 depleted, depreciated 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 depletion, depreciation and amortization. A downward revision in a reserve estimate could result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to be in excess of the calculated ceiling, which is based largely on reserve estimates (see asset impairment discussion below), the excess must be written off as an expense charged against earnings. In the event of a property disposition, proceeds are normally deducted from the full cost pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20% or greater.

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

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

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

Income Tax Accounting

The Company has recorded a future income tax asset in 2006 and 2005. 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 Income and Retained Earnings.

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2006 Annual Report

Derivative Financial Instruments

Derivative financial instruments are used by the Company to manage its exposure to market risks relating to commodity prices. The Company’s policy is not to utilize derivative financial instruments for speculative purposes.

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

Asset Retirement Obligations

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

NEW ACCOUNTING STANDARDS

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.

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TransGlobe Energy Corporation

Financial Instruments Disclosures

The ASB issued CICA 3862, Financial Instruments Disclosures, to enhance the disclosure requirements in CICA 3861, Financial Instruments and Disclosures. The main features of this section are to establish requirements for an entity to disclose the significance of financial instruments for its financial position and performance, revised from those of Section 3861. These requirements are less detailed than those of Section 3861 in certain areas and more so in others. There are also requirements for disclosures about fair value, revised but not substantially different from those of Section 3861. Lastly, there are requirements for an entity to disclose qualitative and quantitative information about exposure to risks arising from financial instruments, revised from, and more extensive than, those of Section 3861. The new requirements are effective for annual and interim periods beginning on or after October 1, 2007, or may be adopted earlier in place of Section 3861. As the Company is adopting Financial Instruments Standards 3855, 3865 and 1530 at January 1, 2007, Section 3862 will also be adopted at this time.

Financial Instruments Presentation

The ASB issued CICA 3863, Financial Instruments Presentation, which carries forward, unchanged from Section 3861, standards for presentation of financial instruments and non-financial derivatives. The new requirements are effective for annual and interim periods beginning on or after October 1, 2007, or may be adopted earlier in place on Section 3861. As the Company is adopting Financial Instruments Standards 3855, 3865, and 1530 at January 1, 2007, Section 3863 will also be adopted at this time.

Capital Disclosures

The Accounting Standards Board (AcSB) issued Canadian Institute of Chartered Accountants (CICA) Section 1535, Capital Disclosures. The main features of this section are to establish requirements for an entity to disclose qualitative information about its objectives, policies and processes for managing capital, quantitative data about what it regards as capital, and whether it has complied with any externally imposed capital requirements and, if not, the consequences of such non-compliance. The new requirements are effective for annual and interim periods beginning on or after October 1, 2007, and, upon adoption, are not expected to materially impact the Consolidated Financial Statements.

Variable Interest Entities

The EIC issued EIC 163, determining the variability to be considered in applying AcG-15 (Variable Interest Entities). The EIC provides guidance on those arrangements where application of either the cash flow method or the fair value method does not result in a clear determination as to whether those arrangements are variable interests or creators of variability. The Committee reached a consensus that variability to be considered should be based on the design of the entity as determined through analyzing the nature of the risks in the entity and the purpose for which the entity was created, as well as the variability (created by the risks) the entity is designed to create and pass along to its interest holders. The EIC is applicable to the first interim period or annual fiscal period beginning after January 1, 2007, and, upon adoption, is not expected to materially impact the Consolidated Financial Statements.

Equity

The ASB issued CICA 3251, Equity, which replaces CICA 3250, Surplus. This section establishes standards for the presentation of equity and changes in equity during the reporting period. The main feature of this section is a requirement for an entity to present separately each of the changes in equity during the period, including comprehensive income, as well as components of equity at the end of the period. The new requirements are effective for annual and interim periods beginning on or after October 1, 2007. This standard will have an effect on the Company’s Financial Statements due to adoption of the new financial instruments standards on January 1, 2007.

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 including the Kyoto Protocol, changes of laws affecting foreign ownership, political risk of operating in foreign jurisdictions, taxes, environmental preservation and safety concerns.

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2006 Annual Report

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 or employs and contracts professionals to handle each aspect of the Company’s business.
• 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, including the Kyoto Protocol. At this time, it is not possible to predict either the nature of the Kyoto Protocol requirements or impact on the Company.
• The Company retains independent reserve evaluators 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, 2006, 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.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Management has designed such internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian generally accepted accounting principles (GAAP), including a reconciliation to U.S. GAAP.

Because of its inherent limitations, the Company’s internal control over financial reporting may not prevent or detect all possible misstatements or frauds. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

To evaluate the effectiveness of the Company’s internal control over financial reporting, Management has used the Internal Control - Integrated Framework, which is a suitable, recognized control framework established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management has assessed the effectiveness of the Company’s internal control over financial reporting for fiscal year ended December 31, 2006 and concluded that such internal control over financial reporting is effective.

OUTLOOK

2007 Production Outlook
A number of projects are underway in Yemen and in Canada that are anticipated to increase oil and gas production during 2007. The majority of these projects will be completed during the first two quarters of 2007 and therefore will not have an impact on production until the second half of the year. Therefore a “Baseline” forecast is currently estimated using only the existing production and planned development in Canada. The Baseline forecast will be updated quarterly or when the facilities and development projects are completed.

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TransGlobe Energy Corporation

Baseline Production Forecast
		2007	2006	Change (*)
Barrels of oil equivalent per day	Boepd	5,300-5,400	5,093	5%
(*) % growth based on mid point of guidance

2007 Cash Flow From Operations Outlook
The 2007 Cash Flow From Operations Outlook was developed using the above Baseline Production Forecast, a dated Brent oil price of $55.00/Bbl and a gas price of C$7.50/Mcf. The prices used for the Outlook are 15% lower for oil and 6% higher for gas than the actual realized prices during 2006. The lower forecasted oil price has resulted in a decrease in the estimated 2007 Cash Flow From Operations. In addition, the Block S-1 Production Sharing Agreement has reached payout on the exploration expenditures and is quickly paying out the development expenditures which will result in a lower cost oil allocation during 2007, reducing 2007 Cash Flow From Operations.

2007 Cash Flow From Operations Outlook

($000’s)	2007(**)	2006	Change (*)
Cash flow from operations	39,000-41,000	46,763	(14)%
(*) % growth based on mid point of guidance (**) Based on a dated Brent oil price of $55.00/Bbl and a gas price of C$7.50/Mcf, from existing fields in Yemen and planned development in Canada.

Variations in production and commodity prices during 2007 could significantly change this Outlook. An estimate of the price sensitivity on the Baseline Production Forecast is shown below. During January and February 2007 the dated Brent oil price averaged $55.55 per barrel and the gas price averaged approximately C$7.50 per Mcf.

Sensitivity	2007
	Cash Flow from
	Operations
($000’s)	Increase/Decrease
$1.00 per barrel change in dated Brent	537
C$1.00 per Mcf change in AECO	1,633
2007 Capital Budget
($000’s)	2007
Canada	15,400
Yemen - Block S1	12,600
- Block 32	5,900
- Block 72	4,600
- Block 75	1,000
- Block 84	2,000
Egypt	4,700
Total	46,200

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, in Yemen, in the medium term. In the long term, production growth could come from Blocks 75 and 84 in Yemen and Nuqra Block 1 in Egypt. For the near term growth, the Company expects to drill 12 wells in Yemen during 2007 of which six wells will be development wells and six wells will be exploration wells. In Canada, the Company plans on drilling 10 to 12 wells during 2007 which are mainly development wells. The Company plans on drilling two exploratory wells in Egypt in 2007. The Company attaches a significantly higher risk to the exploratory wells. The 2007 capital budget of $46.2 million is expected to be funded from cash flow, working capital and debt as required. The use of our credit facilities or equity financing during 2007 may be utilized in the future to accelerate existing projects or to finance new opportunities.

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2006 Annual Report