Calgary, Alberta, November 4, 2010 - TransGlobe Energy Corporation (“TransGlobe” or the “Company”) is pleased to announce its financial and operating results for the three and nine month periods ended September 30, 2010. All dollar values are expressed in United States dollars unless otherwise stated.

HIGHLIGHTS

• Record third quarter production of 10,138 Bopd, (Egypt 7,601 Bopd, Yemen 2,537 Bopd); October production 10,589 Bopd;

• Record third quarter funds flow of $19.5 million ($0.28/share), a 55% increase over third quarter 2009;

• Third quarter net income of $8.8 million ($0.13/share), compared to a $1.6 million loss in the third quarter of 2009;

• Drilled 12 wells in third quarter resulting in nine oil wells (five at West Gharib, three at Block S-1 and one at Block 32);

• Nukhul pools at West Gharib continue to grow with appraisal drilling; new Nukhul pool oil discovery at East Arta #4, initial rate 500 Bopd;

• Successful development drilling program in Block S-1, Yemen; An Nagyah #29 initial rate over 2,000 Bopd;

• Sabbar #1 appraisal well on Safwa pool tested at 500 Bopd at East Ghazalat; PIIP estimates for Safwa increased by 280%;

• Added to S&P/TSX Small Cap Index.

CORPORATE SUMMARY

The total production from all Nukhul wells in West Gharib increased to 1,900 Bopd during the quarter from 130 Bopd just nine months ago. The Company has yet to define the areal extent of the Nukhul pools. This will be the focus of the fourth quarter drilling program. Full development of the fields is expected to continue through 2011 and 2012 with the potential to more than quadruple current Nukhul production. The West Gharib project area is now the primary producing asset in the Company’s portfolio and continues to be the growth engine for the future.

In the Western Desert area, the third well in the Safwa field encountered better reservoir rock and tested at the highest rate to date. The result has increased the internally estimated P-mean case gross petroleum initially in place (“PIIP”) by 280% to 58 million barrels after incorporating the Sabbar well results and remapping the 3-D seismic. Two additional wells are planned for the remainder of the year. Plans are underway to bring the discovery into production in 2011.

In the Nuqra Block in Egypt, the Company has firmed up its drilling plans and anticipates it will drill two exploratory wells starting in January 2011.

The drilling program in the Republic of Yemen (“Yemen”) has increased production in the third quarter. Two high impact Basement exploration wells are expected to spud in Yemen within the next few weeks.

The successful 2010 drilling program is setting the stage for continued growth in 2011. The drilling plans and budget for 2011 will be released in early December.

A conference call to discuss TransGlobe’s third quarter results presented in this report will be held on Thursday, November 4, 2010 at 2:30 p.m. Mountain Time (4:30 p.m. Eastern Time) and is accessible to all interested parties by dialing (416) 340-8018 or toll-free 1-866-223-7781 (see also TransGlobe’s news release dated October 28, 2010). Online, the web cast may be accessed at http://events.digitalmedia.telus.com/transglobe/110410/index.php.

CONTENTS

FINANCIAL AND OPERATING RESULTS	Page 2
OPERATIONS UPDATE	Page 3
MANAGEMENT’S DISCUSSION AND ANALYSIS	Page 6
CONSOLIDATED FINANCIAL STATEMENTS	Page 16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	Page 19

FINANCIAL AND OPERATING RESULTS

(US$000s, except per share, price, volume amounts and % change)

	Three Months Ended September 30						Nine Months Ended September 30
Financial	2010		2009		% Change		2010	2009		% Change
Oil revenue	66,470		46,818		42		189,661	117,754		61
Oil revenue, net of royalties and other	38,980		28,495		37		112,022	74,017		51
Derivative gain (loss) on commodity contracts	(221	)	152		(245	)	68	(3,529	)	102
Operating expense	6,708		6,971		(4	)	18,742	17,378		8
General and administrative expense	2,999		2,636		14		9,418	7,505		25
Depletion, depreciation and accretion expense	9,440		14,192		(33	)	24,121	40,624		(41	)
Income taxes	9,785		6,161		59		27,619	14,966		85
Funds flow from operations*	19,535		12,603		55		55,635	35,361		57
Basic per share	0.29		0.19				0.84	0.55
Diluted per share	0.28		0.19				0.82	0.55
Net income (loss)	8,805		(1,618	)			29,841	(10,933	)
Basic per share	0.13		(0.02	)			0.45	(0.17	)
Diluted per share	0.13		(0.02	)			0.44	(0.17	)
Capital expenditures	19,453		10,599		84		47,386	28,005		69
Long-term debt, including current portion	46,045		52,686		(13	)	46,045	52,686		(13	)
Common shares outstanding
Basic (weighted-average)	66,775		65,328		2		66,085	64,135		3
Diluted (weighted-average)	69,309		65,328		6		68,402	64,135		7
Total assets	275,885		228,964		20		275,885	228,964		20
* Funds flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.
Operating
Average production volumes (Bopd)	10,138		8,864		14		9,681	9,090		6
Average price ($ per Bbl)	71.27		57.41		24		71.76	47.45		51
Operating expense ($ per Bbl)	7.19		8.55		(16	)	7.09	7.00		1

2 Q3 2010

OPERATIONS UPDATE

OPERATIONS UPDATE

ARAB REPUBLIC OF EGYPT

West Gharib, Arab Republic of Egypt (100% working interest, TransGlobe operated)

Operations and Exploration

Drilling
Delineation drilling of the Nukhul formation continues to be the primary focus of the expanded 2010 drilling program. During the third quarter, the Company drilled four oil wells (East Arta #3, East Arta #4, Arta #21 and Hana #23), one potential oil well (North Hoshia #3) and two dry holes (Hoshia #9 and West Hoshia #5). Subsequent to the quarter, four additional oil wells were drilled (Arta #22, Arta #23, East Arta #5 and East Arta #7).

Arta/East Arta
At present it appears that the Nukhul formation at Arta and East Arta is part of a large sandstone and conglomerate fan sequence. The recent drilling indicates the reservoir may comprise one large oil pool. The total potential productive area covers approximately 8,500 acres extending 14 kilometers north to south by 4 kilometers west to east. At Arta, the internally estimated PIIP has increased to 54 million barrels of oil (“MMBbl”) and the East Arta pool has a PIIP of 32 MMBbls, using a deterministic P50 case. The undrilled area between the pools has a potential PIIP of 88 MMBbls using the same reservoir parameters. The net pay varies between the wells depending on where they are located on the structure and on the Nukhul fan deposit. The crestal wells have encountered thinner sands with 30 to 50 feet of net pay or carbonate wells with zero to 10 feet of net pay. Wells on the flank of the structure have much thicker sands and better reservoir quality. For example, the most recent well, East Arta #7, encountered more than 80 feet of net pay in high porosity and high permeability sands. There is also a significant amount of structural relief across the deposit. The oil column is greater than 1,650 feet from the crest of the pool (Arta #13) to the base of the reservoir at East Arta #7. The oil/water contact has not been found yet so additional drilling is planned to define the down dip extent of the pool. Future drill locations will be focused on the thicker, more productive, flank locations as the reservoir facies becomes better delineated.

Hana
The Hana #23 well was drilled, cased and completed as a producing Kareem oil well at an initial rate of 100 Bopd.

North Hoshia
The North Hoshia #3 was drilled, cased and completed as a potential Nukhul oil well. The well came in structurally low to the North Hoshia field and has tested water in the lower Nukhul formation. The well may be recompleted in the Upper Nukhul.

Hoshia
The Nukhul formation discovered in Hoshia #8 was frac’d during September and is producing at a post-frac rate of 150 Bopd.

West Gharib Forward Drilling Plans
The rigs are currently moving to East Arta #6 (a 1.1 km appraisal to East Arta #4) and Arta #19 on the south end of Arta, to be followed by wells at East Arta #8, #9 and #10.

The recent drilling has started to define a potentially large oil pool on TransGlobe’s lands at Arta/East Arta. The development drilling plan for this pool will initially focus on drilling widely spaced delineation wells with approximately 640 acre spacing. The north portion of the Arta field is now largely delineated at 640 acre spacing. The East Arta area requires an additional six to eight delineation wells. The Arta/East Arta pool could require over 200 wells if developed on an initial well spacing of 40 acres. Down-spacing to 20 acre well spacing may be required in the future to increase oil recovery.

The Nukhul oil discovery at Hoshia #8 also requires five to eight development wells. A Nukhul test is also planned in the fourth quarter at South Rahmi #8 which may lead to additional development drilling.

In light of the expanding drilling inventory, the Nukhul development is being accelerated in 2011 with the addition of a third drilling rig.

Production
Production from West Gharib averaged 7,601 Bopd to TransGlobe during the third quarter, a 15% (970 Bopd) increase from the previous quarter. Production increases were attributable to increased Nukhul production from Arta and East Arta during the quarter. Production averaged 7,610 Bopd to TransGlobe during October.

Total Nukhul production has increased from an average of 130 Bopd in January 2010 to approximately 760 Bopd in the second quarter, 1,448 Bopd in the third quarter and 1,901 Bopd in October.

The Company has successfully fracture stimulated the Nukhul formation in 13 vertical wells and one horizontal well in the West Gharib area. The initial, pre-frac production from these wells was between 0 and 80 Bopd. The post-frac initial rates have ranged between 100 Bopd on the crest of the Arta pool and as high as 800 to 1,000 Bopd on the thicker wells drilled on the flank. The wide range in post-frac performance makes it challenging to type curve the post-frac performance, however three trends are emerging. The low productivity carbonate wells had an average post frac rate of 40 Bopd/well and are producing 0 to 35 Bopd/well. The crestal wells had an average post frac rate of 223 Bopd/well and are producing in the 80 to 170 Bopd/well range. The flank wells (excluding East Arta #7) had an average post frac rate of 535 Bopd/well and are producing in the 320 to 500 Bopd/well range. East Arta #7 is also a flank well with a better quality thick reservoir. It is expected to be placed on production in the next two weeks at an initial rate of greater than 500 Bopd (without a frac).

Q3 2010 3

OPERATIONS UPDATE

Quarterly West Gharib Production (Bopd)

		2010		2009
	Q-3	Q-2	Q-1	Q-4
Gross production rate	7,601	6,631	6,848	5,815
TransGlobe working interest	7,601	6,631	6,848	5,815
TransGlobe net (after royalties)	4,626	4,040	4,250	3,775
TransGlobe net (after royalties and tax)*	3,460	3,009	3,222	2,951
* Under the terms of the West Gharib Production Sharing Concession, royalties and taxes are paid out of the Government’s share of production sharing oil.

East Ghazalat Block, Arab Republic of Egypt (50% working interest)

Operations and Exploration

A three well drilling program commenced on September 13 at the Sabbar #1 location. The Sabbar #1 well is the first of two planned appraisal wells on the Safwa structure.

The Sabbar #1 was drilled to a total depth of 4,600 feet, cased and completed as a Bahariya oil well. Sabbar #1 encountered 40+ feet of net pay in the Bahariya sandstones, 27 feet structurally higher than the Safwa discovery wells. A 45 foot interval was perforated and flowed naturally at a rate of 500 Bopd on a short test. Sabbar #1 is located approximately 1.7 kilometres northeast of Safwa NW-1 which tested 250 Bopd and Safwa #1 which tested 300 Bopd from the Upper Bahariya (un-stimulated). The positive results at Sabbar #1 have increased the internally estimated gross PIIP to 58 million barrels of oil (“MMBbl”), up from the initial estimate of 20.6 MMBbl of oil using the respective probabilistic P-mean cases.

Drilling commenced on Safwa #2 on October 25th. Safwa #2 is a step-out appraisal well located approximately 350 meters east of Safwa #1.

Following Safwa #2 the drilling rig will move to Nakhil #1 targeting a prospect which has an internally estimated gross PIIP of 10.4 MMBbl using the P-mean case. The Nakhil prospect is located approximately eight kilometres southwest of Safwa #1.

TransGlobe and the operator are evaluating early development options for the Safwa discovery including the commencement of production by mid-2011.

Nuqra Block 1, Arab Republic of Egypt (71.43% working interest, TransGlobe operated)

Operations and Exploration

TransGlobe has contracted the drilling rig currently working on East Ghazalat for a one-year period. Initially it will drill two exploration wells in Nuqra commencing in late December/early January. The rig will be available for Nukhul development drilling at West Gharib following the Nuqra program. The two exploration wells (Selsella #1 and Diwan #1) are targeting prospects with gross PIIP of 13.6 MMBbl and 46 MMBbl respectively, based on internally generated estimates using the respective probabilistic P-mean cases.

YEMEN EAST- Masila Basin

Block 32, Republic of Yemen (13.81% working interest)

Operations and Exploration

During the third quarter, the Safa #1 exploration well was drilled and abandoned.

Subsequent to the quarter, the Godah #12 development well was drilled and completed as a Qishn oil well. The drilling rig will be moved to Block 72 to drill the Gabdain #1 exploration well.

Production
Production from Block 32 averaged 4,232 Bopd (585 Bopd to TransGlobe) during the quarter, representing a 5% decrease from the previous quarter primarily due to natural declines.

Production averaged approximately 3,986 Bopd (550 Bopd to TransGlobe) during October.

Quarterly Block 32 Production (Bopd)

	2010		2009
	Q-3	Q-2	Q-1	Q-4
Gross production rate	4,232	4,464	4,948	5,174
TransGlobe working interest	585	616	683	715
TransGlobe net (after royalties)	332	315	472	437
TransGlobe net (after royalties and tax)*	248	215	400	346
* Under the terms of the Block 32 Production Sharing Agreement (“PSA”), royalties and taxes are paid out of the government’s share of production sharing oil.

4 Q3 2010

OPERATIONS UPDATE

Block 72, Republic of Yemen (20% working interest)

Operations and Exploration

The Block 72 joint venture partnership entered the second, 30-month exploration period in January 2009 which carries a commitment of one exploration well.

The Block 72 joint venture partnership entered into a farm-out agreement with TOTAL E&P Yemen who is the Operator of Block 10 in the Masila Basin. Under the terms of the agreement, the Company reduced its working interest from 33% to 20%.

An exploration well (Gabdain #1) is planned for November/December of 2010. The operator (DNO) is currently moving the drilling rig from Block 32 to the Gabdain well site and it is expected that drilling will commence in the next two to three weeks. Gabdain #1 is targeting a fractured basement prospect identified on 3-D seismic on the northern portion of Block 72. The Gabdain fractured Basement prospect has an internally estimated gross PIIP of 185 MMBbl, using the probabilistic P-mean case.

YEMEN WEST- Marib Basin

Block S-1, Republic of Yemen (25% working interest)

Operations and Exploration

During the quarter, three horizontal wells were drilled and completed as Lam ‘A’ oil producers in the An Nagyah pool. The wells were comprised of two re-entries (An Nagyah #4 and #25) and a new horizontal development well at An Nagyah #29. The An Nagyah #2 vertical well was re-entered and completed as a horizontal producing Lam ‘A’ oil well in late October.

The drilling rig is currently mobilizing to An Nagyah #31 to drill a dual target exploration well. The An Nagyah #31 exploration well is targeting a separate Lam terrace adjacent to the producing An Nagyah field and a fractured Basement prospect under the main field. The well will be drilled vertically through the Lam formation and then directionally drilled at a high angle into the Basement structure. The well is targeting a gross PIIP of 21.2 MMBbl in the Lam prospect and 73.1 MMBbl in the fractured Basement prospect, based on internally generated estimates using the respective probabilistic P-mean case.

Production

Production from Block S-1 averaged 7,812 Bopd (1,952 Bopd to TransGlobe) during the third quarter, unchanged from the previous quarter. Curtailed production during July due to compressor overhauls was offset by new producers in August and September. Concurrent with the horizontal development drilling program, the operator is installing additional compression to increase gas injection capacity in December 2010 and in the second quarter of 2011.

Production averaged approximately 9,715 Bopd (2,429 Bopd to TransGlobe) during October, representing a 24% increase (477 Bopd increase to TransGlobe) from the third quarter, primarily due to the new producers at An Nagyah. The An Nagyah #29 horizontal is currently producing in excess of 2,000 Bopd.

Quarterly Block S-1 Production (Bopd)

		2010		2009
	Q-3	Q-2	Q-1	Q-4
Gross field production rate	7,812	7,836	8,652	8,504
TransGlobe working interest	1,952	1,959	2,163	2,126
TransGlobe net (after royalties)	1,003	995	1,169	867
TransGlobe net (after royalties and tax)*	756	744	906	585
* Under the terms of the Block S-1 PSA royalties and taxes are paid out of the government’s share of production sharing oil.

Block 75, Republic of Yemen (25% working interest)

Operations and Exploration

The PSA for Block 75 was ratified and signed into law effective March 8, 2008. The first, three-year exploration phase has a work commitment of 3-D seismic and one exploration well. The 3-D seismic was acquired in 2009. One exploration well is planned as part of the Block S-1/75 drilling program.

The Block 75 exploration well (Osaylan SW) is currently scheduled for the first quarter of 2011. The Osaylan SW exploration well is targeting a Lam formation exploration prospect which has an internally estimated gross PIIP of 184 MMBbl using the probabilistic P-mean case.

Q3 2010 5

MANAGEMENT’S DISCUSSION AND ANALYSIS

November 4, 2010

Management’s discussion and analysis (“MD&A”) should be read in conjunction with the unaudited interim financial statements for the three months and nine months ended September 30, 2010 and 2009 and the audited financial statements and MD&A for the year ended December 31, 2009 included in the Company’s annual report. 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 otherwise noted). Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The Company’s annual report and Form 40-F may be found on EDGAR at www.sec.gov.

READER ADVISORIES

Forward-Looking Statements

This 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. Such statements relate to possible future events. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Although TransGlobe’s forward-looking statements are based on the beliefs, expectations, opinions and assumptions of the Company’s management on the date the statements are made, such statements are inherently uncertain and provide no guarantee of future performance. Actual results may differ materially from TransGlobe’s expectations as reflected in such forward-looking statements as a result of various factors, many of which are beyond the control of the Company. These factors include, but are not limited to, unforeseen changes in the rate of production from TransGlobe’s oil and gas properties, changes in price of crude oil and natural gas, adverse technical factors associated with exploration, development, production or transportation of TransGlobe’s crude oil and natural gas reserves, changes or disruptions in the political or fiscal regimes in TransGlobe’s areas of activity, changes in tax, energy or other laws or regulations, changes in significant capital expenditures, delays or disruptions in production due to shortages of skilled manpower, equipment or materials, economic fluctuations, and other factors beyond the Company’s control. TransGlobe does not assume any obligation to update forward-looking statements, other than as required by law, if circumstances or management’s beliefs, expectations or opinions should change and investors should not attribute undue certainty to, or place undue reliance on, any forward-looking statements. Please consult TransGlobe’s public filings at www.sedar.com and www.sec.gov for further, more detailed information concerning these matters.

Non-GAAP Measures

           Funds Flow from Operations

This document contains the term “funds flow from operations”, which should not be considered an alternative to or more meaningful than “cash flow from operating activities” as determined in accordance with Generally Accepted Accounting Principles (“GAAP”). Funds flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital. Management considers this a key measure as it demonstrates TransGlobe’s ability to generate the cash flow necessary to fund future growth through capital investment. Funds flow from operations may not be comparable to similar measures used by other companies.

           Reconciliation of Funds Flow from Operations

	Three Months Ended September 30		Nine Months Ended September 30
($000s)	2010	2009	2010	2009
Cash flow from operating activities	12,297	1,264	32,178	24,205
Changes in non-cash working capital	7,238	11,339	23,457	11,156
Funds flow from operations	19,535	12,603	55,635	35,361

            Debt-to-funds flow ratio
Debt-to-funds flow is a non-GAAP measure that is used to set the amount of capital in proportion to risk. The Company’s debt-to-funds flow ratio is computed as long-term debt, including the current portion, over funds flow from operations for the trailing twelve months. Debt-to-funds flow may not be comparable to similar measures used by other companies.

            Netback
Netback is a non-GAAP measure that represents sales net of royalties (all government interests, net of income taxes), operating expenses and current taxes. Management believes that netback is a useful supplemental measure to analyze 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. Netback may not be comparable to similar measures used by other companies.

TRANSGLOBE’S BUSINESS

TransGlobe is a Canadian-based, publicly traded, oil exploration and production company whose activities are concentrated in two main geographic areas, the Arab Republic of Egypt (“Egypt”) and the Republic of Yemen (“Yemen”). Egypt and Yemen include the Company’s exploration, development and production of crude oil. TransGlobe disposed of its Canadian oil and gas operations in 2008 to reposition itself as a 100% oil, Middle East/North Africa growth company.

6 Q3 2010

MANAGEMENT’S DISCUSSION AND ANALYSIS

SELECTED QUARTERLY FINANCIAL INFORMATION

	2010			2009							2008
($000s, except per share, price and	Q-3	Q-2	Q-1	Q-4	Q-3		Q-2		Q-1		Q-4
volume amounts)
Average sales volumes (Bopd)	10,138	9,206	9,694	8,656	8,864		9,619		8,788		6,893
Average price ($/Bbl)	71.27	73.46	70.66	62.84	57.41		48.62		35.88		46.18
Oil sales	66,470	61,540	61,651	50,044	46,818		42,557		28,379		29,285
Oil sales, net of royalties and other	38,980	35,638	37,404	28,788	28,495		26,462		19,060		18,272
Cash flow from operating activities	12,297	15,627	4,254	12,594	1,264		15,052		7,889		11,252
Funds flow from operations*	19,535	17,027	19,073	9,703	12,603		14,117		8,641		6,134
Funds flow from operations per share
- Basic	0.29	0.26	0.29	0.15	0.19		0.22		0.14		0.10
- Diluted	0.28	0.25	0.29	0.15	0.19		0.22		0.14		0.10
Net income (loss)	8,805	9,438	11,598	2,516	(1,618	)	(4,361	)	(4,954	)	7,640
Net income (loss) per share
- Basic	0.13	0.14	0.18	0.04	(0.02	)	(0.07	)	(0.08	)	0.14
- Diluted	0.13	0.14	0.17	0.04	(0.02	)	(0.07	)	(0.08	)	0.13
Total assets	275,885	263,345	248,446	228,882	228,964		229,658		238,145		228,238
Cash and cash equivalents	15,412	21,437	18,845	16,177	14,804		23,952		22,041		7,634
Total long-term debt, including current portion	46,045	49,977	49,888	49,799	52,686		52,551		57,347		57,230
Debt-to-funds flow ratio**	0.7	0.9	0.9	1.1	1.3		1.2		1.1		1.0

*	Funds flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.
**	Debt-to-funds flow ratio is a non-GAAP measure that represents total current and long-term debt over funds flow from operations for the trailing 12 months.

During the third quarter of 2010, TransGlobe has:

• Maintained a strong financial position, reporting a debt-to-funds flow ratio of 0.7 at September 30, 2010 (September 30, 2009 - 1.3);
• Funded capital programs entirely with funds flow from operations;
• Reported a 55% increase in funds flow from operations due to a 24% increase in commodity prices along with a 14% increase in sales volumes compared to Q3-2009; and
• Reported net income in Q3-2010 of $8.8 million (Q3-2009 – $1.6 million net loss) mainly due to higher commodity prices and production volumes in the quarter compared with the same period in 2009, along with lower depletion and depreciation expense.

2010 VARIANCES

	$000s		$	Per Share Diluted		% Variance
Q3-2009 net loss	(1,618	)		(0.02	)
Cash items
Volume variance	8,400			0.11		519
Price variance	11,252			0.16		695
Royalties	(9,168	)		(0.13	)	(567	)
Expenses:
Operating	263			-		16
Realized derivative loss	442			0.01		27
Cash general and administrative	(127	)		-		(8	)
Current income taxes	(3,624	)		(0.05	)	(224	)
Realized foreign exchange gain	(208	)		-		(13	)
Interest on long-term debt	(324	)		-		(20	)
Other income	27			-		2
Total cash items variance	6,933			0.10		427
Non-cash items
Unrealized derivative gain	(815	)		(0.01	)	(49	)
Depletion and depreciation	4,752			0.06		294
Stock-based compensation	(236	)		-		(15	)
Amortization of deferred financing costs	(211	)		-		(13	)
Total non-cash items variance	3,490			0.05		217
Q3-2010 net income	8,805			0.13		644

Net income increased to $8.8 million in Q3-2010 compared to a loss of $1.6 million in Q3-2009, which was mostly due to significant increases in commodity prices and production volumes along with a decrease in depletion and depreciation, which was partially offset by higher royalties and income taxes.

Q3 2010 7

MANAGEMENT’S DISCUSSION AND ANALYSIS

BUSINESS ENVIRONMENT

The Company’s financial results are significantly influenced by fluctuations in commodity prices, including price differentials. The following table shows select market benchmark prices and foreign exchange rates:

	2010			2009
	Q-3	Q-2	Q-1	Q-4	Q-3
Dated Brent average oil price ($/Bbl)	76.86	78.30	76.10	74.56	68.27
U.S./Canadian Dollar average exchange rate	1.039	1.028	1.016	1.056	1.098

The price of Dated Brent oil averaged 13% higher in Q3-2010 compared with Q3-2009. Global markets are currently in a period of economic recovery with improved liquidity and access to capital, in addition to strengthening oil prices. TransGlobe’s management believes the Company is well positioned to take advantage of the improving economy due to its increasing production, manageable debt levels, positive cash generation from operations and the availability of cash and cash equivalents.

The Company designed its 2010 budget to be flexible, allowing spending to be adjusted as commodity prices change and forecasts are reviewed.

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest Before Royalties and Other (Bopd)

	Three Months Ended		Nine Months Ended
	September 30		September 30
	2010	2009	2010	2009
Egypt - Oil sales	7,601	5,747	7,029	5,833
Yemen - Oil sales	2,537	3,117	2,652	3,257
Total Company - daily sales volumes	10,138	8,864	9,681	9,090

Netback

Consolidated

	Nine Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	189,661	71.76	117,754	47.45
Royalties and other	77,639	29.38	43,737	17.62
Current taxes	27,619	10.45	14,966	6.03
Operating expenses	18,742	7.09	17,378	7.00
Netback	65,661	24.84	41,673	16.80

	Three Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	66,470	71.27	46,818	57.41
Royalties and other	27,490	29.47	18,323	22.47
Current taxes	9,785	10.49	6,161	7.56
Operating expenses	6,708	7.19	6,971	8.55
Netback	22,487	24.12	15,363	18.83

Egypt

	Nine Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	133,676	69.66	68,265	42.87
Royalties and other	51,782	26.99	23,969	15.05
Current taxes	20,461	10.66	9,658	6.07
Operating expenses	11,800	6.15	9,695	6.09
Netback	49,633	25.86	24,943	15.66

8 Q3 2010

MANAGEMENT’S DISCUSSION AND ANALYSIS

Egypt (continued)

	Three Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	48,551	69.43	27,339	51.71
Royalties and other	18,999	27.17	9,584	18.13
Current taxes	7,447	10.65	3,874	7.33
Operating expenses	4,313	6.17	4,241	8.02
Netback	17,792	25.44	9,640	18.23

The netback per Bbl in Egypt increased 40% and 65% in the three and nine months ended September 30, 2010, respectively, compared with the same periods of 2009, mainly as a result of oil prices increasing by 34% and 62%, respectively, partially offset by higher royalty and tax rates. The average selling price during the three months ended September 30, 2010 was $69.43/Bbl, which represents a gravity/quality adjustment of approximately $7.43/Bbl to the average Dated Brent oil price for the period of $76.86/Bbl.

Royalties and taxes as a percentage of revenue increased to 54% in the three and nine months ended September 30, 2010, compared with 49% in the same period of 2009. Royalty and tax rates fluctuate in Egypt due to changes in the cost oil whereby the Production Sharing Contract (“PSC”) allows for recovery of operating and capital costs through a reduction in government take.

Operating expenses on a per Bbl basis for the three and nine months ended September 30, 2010 decreased 23% and increased 1%, respectively, compared with the same periods of 2009. This is mainly due to a significant increase in production in Egypt during the three and nine month periods ended September 30, 2010 compared with the same periods in 2009, along with more workovers performed in the third quarter of 2009 compared to the third quarter of 2010.

Yemen

	Nine Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	55,985	77.33	49,489	55.66
Royalties and other	25,857	35.71	19,768	22.23
Current taxes	7,158	9.89	5,308	5.97
Operating expenses	6,942	9.59	7,683	8.64
Netback	16,028	22.14	16,730	18.82

		Three Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	17,919	76.77	19,479	67.92
Royalties and other	8,491	36.38	8,739	30.47
Current taxes	2,338	10.02	2,287	7.97
Operating expenses	2,395	10.26	2,730	9.52
Netback	4,695	20.11	5,723	19.96

In Yemen, the netback per Bbl increased 1% and 18% in the three and nine months ended September 30, 2010, respectively, compared with the same periods in 2009 primarily as a result of oil prices increasing by 13% and 39%, respectively, partially offset by higher royalty and tax rates.

Royalties and taxes as a percentage of revenue increased to 60% and 59% in the three and nine months ended September 30, 2010, respectively, compared with 57% and 51%, respectively, in 2009. Royalty and tax rates fluctuate in Yemen due to changes in the amount of cost sharing oil, whereby the Block 32 and Block S-1 Production Sharing Agreements (“PSAs”) allow for the recovery of operating and capital costs through a reduction in Ministry of Oil and Minerals’ take of oil production.

Operating expenses on a per Bbl basis for the three and nine months ended September 30, 2010 increased 8% and 11%, respectively, mostly due to lower volumes compared to the same periods in 2009.

DERIVATIVE COMMODITY CONTRACTS

TransGlobe uses hedging arrangements as part of its risk management strategy to manage commodity price fluctuations and stabilize cash flows for future exploration and development programs. In July 2010 the Company bought out two financial collar contracts that had been set to expire on August 31, 2010. Furthermore, in the first week of October 2010 the Company purchased two new financial floor contracts, which both carry volumes of 10,000 Bbl/month, that are effective from January 1, 2011 to December 31, 2011.

The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheets, with any change in the unrealized positions recorded to income. The fair values of these transactions are based on an approximation of the amounts that would have been paid to, or received from, counter-parties to settle the transactions outstanding as at the Consolidated Balance Sheet date with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates. The realized loss on commodity contracts in the first nine months of 2010 relates mostly

Q3 2010 9

MANAGEMENT’S DISCUSSION AND ANALYSIS

to the purchase of a new financial floor derivative commodity contract for $0.4 million, compared with $0.2 million in realized gains for the same period in 2009 as a result of depressed oil prices in the first nine months of last year. The mark-to-market valuation of TransGlobe’s future derivative commodity contracts increased in value by $0.5 million between December 31, 2009 and September 30, 2010, moving from a $0.5 million liability at December 31, 2009 to an almost even position at September 30, 2010, thus resulting in a $0.5 million unrealized gain on future derivative commodity contracts being recorded in the period.

	Three Months Ended				Nine Months Ended
	September 30				September 30
($000s)	2010		2009		2010		2009
Realized cash (loss) gain on commodity contracts*	(35	)	(477	)	(452	)	191
Unrealized gain (loss) on commodity contracts**	(186	)	629		520		(3,720	)
Total derivative gain (loss) on commodity contracts	(221	)	152		68		(3,529	)

*	Realized cash gain (loss) represents actual cash settlements, receipts and premiums paid under the respective contracts.
**	The unrealized loss on derivative commodity contracts represents the change in fair value of the contracts during the period.

If the Dated Brent oil price remains at the level experienced at the end of Q3-2010, the derivative asset will be realized over the next year. However, a 10% decrease in Dated Brent oil prices would result in a $0.2 million increase in the derivative commodity contract asset, thus increasing the unrealized gain by the same amount. Conversely, a 10% increase in Dated Brent oil prices would not have a material effect on the unrealized gain on commodity contracts. The following commodity contracts are outstanding immediately following September 30, 2010:

			Dated Brent
Period	Volume	Type	Pricing Put
Crude Oil
July 1, 2010-December 31, 2010	10,000 Bbl/month	Financial Floor	$60.00
July 1, 2010-December 31, 2010	20,000 Bbl/month	Financial Floor	$65.00
January 1, 2011-December 31, 2011*	20,000 Bbl/month	Financial Floor	$65.00
* Contract was purchased in October 2010.

Including the contracts purchased in October 2010, the total volumes hedged for the balance of 2010 and following years are:

	Three Months
	2010	2011
Bbls	90,000	240,000
Bopd	978	658

At September 30, 2010, all of the derivative commodity contracts were classified as current assets.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	Nine Months Ended September 30
	2010				2009
(000s, except per Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	9,739		3.68		8,259		3.33
Stock-based compensation	1,670		0.63		1,493		0.60
Capitalized G&A and overhead recoveries	(1,991	)	(0.75	)	(2,247	)	(0.90	)
G&A (net)	9,418		3.56		7,505		3.03

			Three Months Ended September 30
	2010				2009
(000s, except per Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	3,006		3.22		2,844		3.49
Stock-based compensation	759		0.81		523		0.64
Capitalized G&A and overhead recoveries	(766	)	(0.82	)	(731	)	(0.90	)
G&A (net)	2,999		3.21		2,636		3.23

G&A expenses (net) increased 14% (1% decrease on a per Bbl basis) and 25% (17% on a per Bbl basis) in the three and nine months ended September 30, 2010, respectively, compared with the same periods in 2009 partly due to a strengthening Canadian dollar which accounted for approximately 41% and 51% of the increases, respectively, as the majority of TransGlobe’s G&A costs are incurred in Canadian dollars. The remainder of the increase was due to increased insurance, staffing and office costs.

INTEREST ON LONG-TERM DEBT

Interest expense for the three and nine months ended September 30, 2010 increased to $1.1 million and $2.1 million, respectively (2009 - $0.6 million and $1.9 million, respectively). Interest expense includes interest on long-term debt and amortization of transaction costs associated with long-term debt. In the three and nine months ended September 30, 2010, the Company expensed $0.3 million and $0.5 million, respectively, of transaction costs (2009 - $0.1 million and $0.5 million, respectively). The Company had $50.0 million of debt outstanding at September 30, 2010 (September 30, 2009 - $53.0 million). The long-term debt that was outstanding at September 30, 2010 bore interest at LIBOR plus an applicable margin that varies from 3.75% to 4.75% depending on the amount drawn under the facility. In previous quarters long-term debt bore interest at the Eurodollar rate plus three percent under the terms of the previous credit facility that was terminated in July 2010 and replaced with a new Borrowing Base Facility.

10 Q3 2010

MANAGEMENT’S DISCUSSION AND ANALYSIS

DEPLETION AND DEPRECIATION (“DD&A”)

	Nine Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	18,186	9.48	33,150	20.82
Yemen	5,752	7.94	7,331	8.24
Corporate	183	-	143	-
	24,121	9.13	40,624	16.37

	Three Months Ended September 30
	2010		2009
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	7,468	10.68	11,747	22.22
Yemen	1,893	8.11	2,394	8.35
Corporate	79	-	51	-
	9,440	10.12	14,192	17.40

In Egypt, DD&A decreased 52% and 54% on a per Bbl basis for the three and nine month periods ended September 30, 2010, respectively, due to significant increases to Proved reserves at year-end 2009.

In Yemen, DD&A decreased 3% and 4% on a per Bbl basis for the three and nine months ended September 30, 2010, respectively, due to Proved reserve additions at year-end 2009.

In Egypt, unproven properties of $13.9 million (2009 - $9.9 million) relating to Nuqra ($8.0 million), West Gharib ($1.8 million) and East Ghazalat ($4.1 million) were excluded from the costs subject to DD&A in the quarter. In Yemen, unproven property costs of $11.0 million (2009 - $10.6 million) relating to Block 72 and Block 75 were excluded from the costs, subject to DD&A in the quarter.

CAPITAL EXPENDITURES

	Nine Months Ended September 30
($000s)	2010	2009
Egypt	42,484	21,491
Yemen	4,636	6,345
Corporate	266	169
Total	47,386	28,005

In Egypt, total capital expenditures in the first nine months of 2010 were $42.5 million (2009 - $21.5 million). The Company drilled 20 wells, resulting in 16 oil wells (four at Hana, three at Arta, three at East Arta, two at North Hoshia, one at each of Hana West and Hoshia, and two at East Ghazalat), in addition to two dry holes at East Ghazalat, one at Hoshia and one at West Hoshia.

In Yemen, total capital expenditures in 2010 were $4.6 million (2009 - $6.3 million). Three oil development wells were drilled in the first nine months of 2010 at Block S-1, along with one oil development well and one dry hole at Block 32.

OUTSTANDING SHARE DATA

As at September 30, 2010, the Company had 66,917,172 common shares issued and outstanding.

The Company received regulatory approval to purchase, from time-to-time, as it considers advisable, up to 6,116,905 common shares under a Normal Course Issuer Bid which commenced September 7, 2009 and expired September 6, 2010. During the nine months ended September 30, 2010 and during the year ended December 31, 2009, the Company did not repurchase any common shares.

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 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. A key measure that TransGlobe uses to evaluate the Company’s overall financial strength is debt-to-funds flow from operating activities (calculated on a 12-month trailing basis). TransGlobe’s debt-to-funds flow from operating activities ratio, a key short-term leverage measure, remained strong at 0.7 times at September 30, 2010. This was within the Company’s target range of no more than 2.0 times.

Q3 2010 11

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following table illustrates TransGlobe’s sources and uses of cash during the periods ended September 30, 2010 and 2009:

Sources and Uses of Cash

	Nine Months Ended September 30
($000s)	2010		2009
Cash sourced
Funds flow from operations*	55,635		35,361
Exercise of options	7,406		80
Increase in long-term debt	55,916
Issuance of common shares, net of share issuance costs	-		15,109
	118,957		50,550
Cash used
Capital expenditures	47,386		28,005
Deferred financing costs	4,277		-
Transfer to restricted cash	1,890
Repayment of long-term debt	55,916		5,000
Options surrendered for cash payments	-		13
	109,469		33,018
Net cash from operations	9,488		17,532
Changes in non-cash working capital	(10,253	)	(10,362	)
Increase in cash and cash equivalents	(765	)	7,170
Cash and cash equivalents – beginning of period	16,177		7,634
Cash and cash equivalents – end of period	15,412		14,804
* Funds 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 was provided by funds flow from operations. The Company expects to fund its 2010 exploration and development program of $71.0 million ($24.0 million remaining) and contractual commitments through the use of working capital and cash generated by operating activities. The use of new financing during 2010 may also be utilized to finance new opportunities. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources.

Working capital is the amount by which current assets exceed current liabilities. At September 30, 2010, the Company had working capital of $47.9 million (December 31, 2009 – deficiency of $11.8 million). The working capital deficiency as at December 31, 2009 was primarily the result of the reclassification of long-term debt as a current liability. On July 22, 2010, the Company entered into a new Borrowing Base Facility. Therefore, as at September 30, 2010 the credit facility was classified as long-term which eliminated the working capital deficiency. While the reclassification of bank debt accounts for the majority of the increase in working capital, other increases to working capital in 2010 are the result of increased accounts receivable due to higher oil prices and higher sales volumes. These receivables are not considered to be impaired; however, to mitigate this risk, the Company entered into an insurance program on a portion of the receivable balance.

At June 30, 2010, TransGlobe had a $60.0 million Revolving Credit Agreement of which $50.0 million was drawn. Amounts drawn under the Revolving Credit Agreement were set to become due September 25, 2010. On July 22, 2010, the Company entered into a new five-year $100.0 million Borrowing Base Facility and paid out the original Revolving Credit Agreement. As repayments on the new Borrowing Base Facility are not expected to commence until 2012, the entire balance is presented as a long-term liability on the consolidated balance sheets. Repayments will be made on a semi-annual basis according to the scheduled reduction of the facility. As of September 30, 2010, the Company has incurred financing costs related to the new Borrowing Base Facility in the amount of $4.3 million.

($000s)	September 30, 2010		December 31, 2009
Bank debt	50,000		50,000
Deferred financing costs	(3,955	)	(201	)
	46,045		49,799
Current portion of long-term debt (net of deferred financing costs)	-		49,799
Long-term debt (net of deferred financing costs)	46,045		-

12 Q3 2010

MANAGEMENT’S DISCUSSION AND ANALYSIS

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:

($000s)	Payment Due by Period1,2
	Recognized										More
	in Financial		Contractual		Less than						than
	Statements		Cash Flows		1 year		1-3 years		4-5 years		5 years
Accounts payable and accrued liabilities	Yes-Liability	$	27,364	$	27,364	$	-	$	-	$	-
Long-term debt:
Borrowing Base Facility	Yes-Liability		50,000		-		29,557		20,443		-
Office and equipment leases	No		11,051		1,567		3,034		1,916		4,534
Minimum work commitments3	No		4,953		-		4,953		-		-
Total		$	93,368	$	28,931	$	37,544	$	22,359	$	4,534

1	Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivatives.
2	Payments denominated in foreign currencies have been translated at September 30, 2010 exchange rates.
3	Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

Pursuant to the Concession agreement for Nuqra Block 1 in Egypt, the Contractor (Joint Venture Partners) has a minimum financial commitment of $5.0 million ($4.4 million to TransGlobe) and a work commitment for two exploration wells in the second exploration extension. The second, 36-month extension period commenced on July 18, 2009. The Contractor has met the second extension financial commitment of $5.0 million in the prior periods. At the request of the Government, the Company provided a $4.0 million production guarantee from the West Gharib Concession prior to entering the second extension period.

Pursuant to the PSA for Block 72 in Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $2.0 million ($0.1 million to TransGlobe) to drill one exploration well during the second exploration period. The second, 30-month exploration period commenced on January 12, 2009. The Contractor has entered into a farm-in agreement with TOTAL E&P Yemen which has reduced TransGlobe’s interest in the concession to 20%.

Pursuant to the PSA for Block 75 in Yemen, the Contractor (Joint Venture Partners) has a remaining minimum financial commitment of $3.0 million ($0.8 million to TransGlobe) for one exploration well. The first, 36-month exploration period commenced March 8, 2008. The Company issued a $1.5 million letter of credit (expiring November 15, 2011) to guarantee the Company’s performance under the first exploration period. The letter is secured by a guarantee granted by Export Development Canada.

Pursuant to the August 18, 2008 asset purchase agreement for a 25% financial interest in eight development leases on the West Gharib Concession in Egypt, the Company has committed to paying the vendor a success fee to a maximum of $7.0 million if incremental reserve thresholds are reached in the East Hoshia (up to $5.0 million) and South Rahmi (up to $2.0 million) development leases, to be evaluated annually. As at December 31, 2009, no additional fees are due in 2010.

In the normal course of its operations, the Company may be subject to litigations and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.

MANAGEMENT STRATEGY AND OUTLOOK FOR 2010

The 2010 outlook provides information as to management’s expectation for results of operations for 2010. Readers are cautioned that the 2010 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to fluctuations in the business environment and may vary accordingly. This outlook contains forward-looking statements that should be read in conjunction with the Company’s disclosure under “Forward-Looking Statements”, outlined on the first page of this MD&A.

2010 Outlook Highlights

• Production is expected to average approximately 10,000 Bopd, an 11% increase over the 2009 average production;
• Exploration and development capital budget increased during the third quarter to $71.0 million from $63.0 million (allocated 84% to Egypt, 14% to Yemen and 2% to other) funded from funds flow from operations and cash on hand; and
• Using the 10,000 Bopd production forecast and an average oil price assumption for the remainder of the year of $75.00/Bbl, funds flow from operations is expected to be $75.0 million for the year.

2010 Production Outlook

TransGlobe’s production guidance for 2010 is expected to average approximately 10,000 Bopd, representing an 11% increase over the 2009 average production of 8,980 Bopd. This target includes increased production from Hana, Hana West, Hoshia, Arta and East Arta in Egypt, and production from the development drilling program on Block S-1 in Yemen. Production from Egypt is expected to average approximately 7,300 Bopd during 2010, with the balance of approximately 2,700 Bopd coming from the Yemen properties. TransGlobe’s target exit rate for 2010 is 11,000 Bopd.

Production Forecast

	2010 Guidance	2009 Actual	% Change*
Barrels of oil per day	10,000	8,980	11

Q3 2010 13

MANAGEMENT’S DISCUSSION AND ANALYSIS

2010 Funds Flow From Operations Outlook

This outlook was developed using the above production forecast and an average Dated Brent oil price of $75.00/Bbl for the remainder of the year.

2010 Funds Flow From Operations Outlook
($ million, except % change)	2010 Guidance	2009 Actual	% Change
Funds flow from operations*	75.0	45.1	66
* Funds flow from operations is a non-GAAP measure that represents cash generated from operating activities before changes in non-cash working capital.

Due in part to higher expected prices and higher production, funds flow from operations is expected to increase by 66% in 2010. One of the key factors in the increased funds flow in 2010 is due to a better oil price differential to average Dated Brent benchmark price in Egypt. Price differentials to average Dated Brent in Egypt narrowed from 24% in 2009 to 10% in 2010. Variations in production and commodity prices during 2010 could significantly change this outlook. An increase in the Dated Brent oil price of $10.00/Bbl for the remainder of the year would increase anticipated funds flow by approximately $3.0 million to $78.0 million for the year, while a $10.00/Bbl decrease in the Dated Brent oil price would result in anticipated funds flow decreasing by approximately $3.0 million to $72.0 million for the year.

2010 Capital Budget	Nine Months Ended
	September 30, 2010	2010
($ million)	Actual	Annual Budget
Egypt	42.5	60.0
Yemen	4.6	10.0
Corporate	0.3	1.0
Total	47.4	71.0

The 2010 capital program is split 64:36 between development and exploration, respectively. The Company plans to participate in 40 wells in 2010. The Company will fund its entire 2010 capital budget from funds flow and working capital. The Company designed its 2010 budget to be flexible, allowing spending to be adjusted as commodity prices change and forecasts are reviewed.

CHANGES IN ACCOUNTING POLICIES

New Accounting Policies

The Company adopted a share appreciation rights plan in March 2010. Under the share appreciation rights plan, all liabilities must be settled in cash and, consequently, are classified as liability instruments and measured at their intrinsic value less any unvested portion. Unvested share appreciation rights accrue evenly over the vesting period. The intrinsic value is determined as the difference between the market value of the Company’s common shares and the exercise price of the share appreciation rights. This obligation is revalued each reporting period and the change in the obligation is recognized as stock-based compensation expense (recovery).

New Accounting Standards

a) Business Combinations

In December 2008, the CICA issued Section 1582, Business Combinations, which will replace CICA Section 1581 of the same name. Section 1582 establishes principles and requirements of the acquisition method for business combinations and related disclosures. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. The Company is currently evaluating the impact of this change on its Consolidated Financial Statements.

b) Non-Controlling Interests

In December 2008, the CICA issued Sections 1601, Consolidated Financial Statements, and 1602, Non-Controlling Interests. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards are effective on or after the beginning of the first annual reporting period beginning on or after January 2011 with earlier application permitted. These standards currently do not impact the Company as it has full controlling interest of all of its subsidiaries.

c) International Financial Reporting Standards (“IFRS”)

On February 13, 2008 the Canadian Accounting Standards Board confirmed that effective for interim and annual financial statements related to fiscal years beginning on or after January 1, 2011, IFRS will replace Canada’s current GAAP for all publicly accountable profit-oriented enterprises.

The Company commenced its IFRS transition project in 2008 and has completed the project awareness and engagement phase of the IFRS transition project. Corporate governance over the project was established and a steering committee and project team formed. The steering committee is comprised of members of management and executive and is responsible for final approval of project recommendations and deliverables to the Audit Committee and Board of Directors. Communication, training and education are an important aspect of the Company’s IFRS conversion project. Internal and external training and education sessions have been carried out and will continue throughout each phase of the project.

14 Q3 2010

MANAGEMENT’S DISCUSSION AND ANALYSIS

The Company completed the diagnostic assessment phase by performing comparisons of the differences between Canadian GAAP and IFRS and has assessed the effects of adoption. The Company determined that the most significant impact of IFRS conversion is to property and equipment. IFRS does not prescribe specific oil and gas accounting guidance other than for costs associated with the exploration and evaluation phase. The Company currently follows full cost accounting as prescribed in Accounting Guideline 16, Oil and Gas Accounting – Full Cost. Conversion to IFRS will have a significant impact on how the Company accounts for costs pertaining to oil and gas activities, in particular those related to the pre-exploration and development phases. In addition, the level at which impairment tests are performed and the impairment testing methodology will differ under IFRS, although the Company does not expect to experience an impairment loss on oil and gas assets on transition to IFRS. IFRS conversion will also result in other impacts, including but not limited to the calculation of share-based payments expense and depletion expense on oil and gas assets, which may be significant in nature. The Company continues to focus on analyzing and developing implementation strategies and processes for the key IFRS transition issues identified. Where applicable, key IFRS transition alternatives are being considered and evaluated. The Company continues to perform accounting assessments on less critical IFRS transition issues and has commenced analysis of IFRS financial statement presentation and disclosure requirements. These assessments will need to be further analyzed and evaluated throughout the implementation phase of the Company’s project as new transactions may have different GAAP versus IFRS treatment, and ongoing changes to IFRS may have an impact on the conversion.

In July 2009, the International Accounting Standards Board (“IASB”) approved additional exemptions that will allow entities to allocate their oil and gas asset balance as determined under full cost accounting to the IFRS categories of exploration and evaluation assets and development and producing properties. Under the exemption, exploration and evaluation assets are measured at the amount determined under an entity’s previous GAAP. For assets in the development or production phases, the amount is also measured at the amount determined under an entity’s previous GAAP; however, such values must be allocated to the underlying IFRS transitional assets on a pro-rata basis using either reserve values or reserve volumes as of the entity’s IFRS transition date. This exemption will relieve entities from significant adjustments resulting from retrospective adoption of IFRS. The Company will utilize this exemption.

Concurrently, the project team is working on the design, planning and solution development phase. In this phase, the focus is on determining the specific qualitative and quantitative impact the application of IFRS requirements has on the Company. The project team members continue to work with representatives from the various operational areas to develop recommendations including first-time adoption exemptions available upon initial transition to IFRS. The results from the consultations with the various operational areas are used to draft accounting policies. One of the sections in each of the draft accounting policies is the disclosure section which includes the financial statement disclosure as required by IFRS. The project team has analyzed first-time adoption exemptions and documented which exemptions it intends to utilize, pending approval from the steering committee. These exemptions include the oil and gas asset exemption described above, along with the cumulative translation differences exemption which allows the cumulative translation differences for all foreign operations to be deemed to be zero at the date of transition, and the share-based payments exemption which allows for IFRS requirements to apply only to those options that were unvested at the date of transition. A detailed implementation plan and timeline has been developed, which also includes the development of a training plan. Furthermore, in the last quarter of 2010 the Company will continue to work on the development of processes and systems to ensure that IFRS comparative data is captured, and to position it for reporting under IFRS in 2011.

During the third quarter of 2010 the Company completed its draft opening balance sheet under IFRS, which is as at January 1, 2010. Transition to IFRS on the opening balance sheet date does not result in a material adjustment to the Company’s property and equipment. The valuation and expensing of share-based payments will be done using a tranche method under IFRS whereas under previous GAAP entire stock option issuances were valued as a whole and expensed on a straight line over the lives of the options. This results in an accelerated expensing of the share-based payments as the fair value is weighted more heavily toward the periods closer to the date of issuance of the stock options. The adjustment for the change in treatment of share-based payments results in an increase in contributed surplus with a corresponding decrease in retained earnings. Furthermore, cumulative translation adjustments have been deemed to be zero on transition, resulting in a decrease in accumulated other comprehensive income along with a corresponding increase in retained earnings. The Company also continues to work on calculating adjustments for the first three quarters of 2010. While quantification of the impact is in progress but cannot currently be estimated accurately, the Company expects depletion and depreciation expense to decrease under IFRS as compared to Canadian GAAP as a result of the depletion rate being calculated based on proved and probable reserves under IFRS compared to proved reserves only under previous GAAP. At this time, any other potential adjustments to the Company’s financial position and results of operations for the first three quarters in 2010 cannot be reliably determined or estimated.

Additionally, the Company is monitoring the IASB’s active projects and all changes to IFRS prior to January 1, 2011 and will be incorporated as required.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

TransGlobe’s management designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, of the Canadian Securities Administrators. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel 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, including a reconciliation to U.S. generally accepted accounting principles, focusing in particular on controls over information contained in the annual and interim financial statements. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

As at the date of this report, management is not aware of any change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Q3 2010 15

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statements of Income (Loss) and Retained Earnings

(Unaudited - Expressed in thousands of U.S. Dollars, except per share amounts)

		Three Months Ended						Nine Months Ended
		September 30						September 30
		2010			2009			2010		2009
REVENUE
Oil sales, net of royalties and other	$	38,980		$	28,495		$	112,022	$	74,017
Derivative gain (loss) on commodity contracts (Note 13)		(221	)		152			68		(3,529	)
Other income (loss)		11			(16	)		18		16
		38,770			28,631			112,108		70,504
EXPENSES
Operating		6,708			6,971			18,742		17,378
General and administrative		2,999			2,636			9,418		7,505
Foreign exchange loss (gain)		(78	)		(286	)		253		(940	)
Interest on long-term debt		1,111			575			2,114		1,904
Depletion and depreciation (Note 4)		9,440			14,192			24,121		40,624
		20,180			24,088			54,648		66,471
Income before income taxes		18,590			4,543			57,460		4,033
Income taxes – current		9,785			6,161			27,619		14,966
NET INCOME (LOSS)		8,805			(1,618	)		29,841		(10,933	)
Retained earnings, beginning of period		101,049			79,115			80,013		88,430
RETAINED EARNINGS, END OF PERIOD	$	109,854		$	77,497		$	109,854	$	77,497
Net income (loss) per share (Note 11)
Basic	$	0.13		$	(0.02	)	$	0.45	$	(0.17	)
Diluted	$	0.13		$	(0.02	)	$	0.44	$	(0.17	)
See accompanying notes to the consolidated financial statements.

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited - Expressed in thousands of U.S. Dollars)

		Three Months Ended					Nine Months Ended
		September 30					September 30
		2010		2009			2010		2009
Net income (loss)	$	8,805	$	(1,618	)	$	29,841	$	(10,933	)
Other comprehensive income		-		-			-		-
COMPREHENSIVE INCOME (LOSS)	$	8,805	$	(1,618	)	$	29,841	$	(10,933	)
See accompanying notes to the consolidated financial statements.

16 Q3 2010

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Balance Sheets

(Unaudited - Expressed in thousands of U.S. Dollars)

		As at		As at
		September 30, 2010		December 31, 2009
ASSETS
Current
Cash and cash equivalents	$	15,412	$	16,177
Accounts receivable		57,307		35,319
Derivative commodity contracts (Note 13)		6		-
Prepaids and other		2,529		1,909
		75,254		53,405
Restricted cash (Note 3)		1,890		-
Goodwill (Note 5)		8,180		8,180
Property and equipment (Note 4)		190,561		167,297
	$	275,885	$	228,882
LIABILITIES
Current
Accounts payable and accrued liabilities	$	27,364	$	14,879
Derivative commodity contracts (Note 13)		-		514
Current portion of long-term debt (Note 6)		-		49,799
		27,364		65,192
Long-term debt (Note 6)		46,045		-
		73,409		65,192
Commitments and contingencies (Note 14)
SHAREHOLDERS’ EQUITY
Share capital (Note 7)		76,639		66,106
Contributed surplus (Note 9)		5,103		6,691
Accumulated other comprehensive income (Note 10)		10,880		10,880
Retained earnings		109,854		80,013
		202,476		163,690
	$	275,885	$	228,882
See accompanying notes to the consolidated financial statements.

Approved on behalf of the Board:
Signed by:
“Ross G. Clarkson”	“Fred J. Dyment”
Ross G. Clarkson, Director	Fred J. Dyment, Director

Q3 2010 17

CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Statements of Cash Flows

(Unaudited - Expressed in thousands of U.S. Dollars)

		Three Months Ended						Nine Months Ended
		September 30						September 30
		2010			2009			2010			2009
CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:
OPERATING
Net income (loss)	$	8,805		$	(1,618	)	$	29,841		$	(10,933	)
Adjustments for:
Depletion and depreciation		9,440			14,192			24,121			40,624
Amortization of deferred financing costs		345			135			523			457
Stock-based compensation (Note 8)		759			523			1,670			1,493
Unrealized (gain) loss on commodity contracts		186			(629	)		(520	)		3,720
Changes in non-cash working capital		(7,238	)		(11,339	)		(23,457	)		(11,156	)
		12,297			1,264			32,178			24,205
FINANCING
Increase in long-term debt		55,916			-			55,916			-
Repayments of long-term debt		(55,916	)		-			(55,916	)		(5,000	)
Options surrendered for cash payments (Note 7)		-			(13	)		-			(13	)
Issue of common shares for cash (Note 7)		1,662			-			7,406			16,392
Issue costs for common shares (Note 7)		-			(18	)		-			(1,203	)
Deferred financing costs		(3,578	)		-			(4,277	)		-
Changes in non-cash working capital		-			4			-			(875	)
		(1,916	)		(27	)		3,129			9,301
INVESTING
Exploration and development expenditures		(19,453	)		(10,599	)		(47,386	)		(28,005	)
Changes in restricted cash		(1,890	)		-			(1,890	)		-
Changes in non-cash working capital		4,937			214			13,204			1,669
		(16,406	)		(10,385	)		(36,072	)		(26,336	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(6,025	)		(9,148	)		(765	)		7,170
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		21,437			23,952			16,177			7,634
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	15,412		$	14,804		$	15,412		$	14,804
Supplemental Disclosure of Cash Flow Information
Cash interest paid	$	766		$	440		$	1,591		$	1,447
Cash taxes paid		9,785			6,161			27,619			14,966
Cash is comprised of cash on hand and balances with banks		15,412			14,804			15,412			14,804
Cash equivalents		-			-			-			-
See accompanying notes to the consolidated financial statements.

18 Q3 2010

CONSOLIDATED FINANCIAL STATEMENTS

As at September 30, 2010 and December 31, 2009 and for the periods ended September 30, 2010 and 2009
(Unaudited - Expressed in U.S. Dollars)

1. BASIS OF PRESENTATION

The interim consolidated financial statements include the accounts of TransGlobe Energy Corporation and its subsidiaries (“TransGlobe” or the “Company”), as at September 30, 2010 and December 31, 2009 and for the three and nine month periods ended September 30, 2010 and 2009, are presented in accordance with Canadian generally accepted accounting principles (“Canadian GAAP” or “Cdn. GAAP”) on the same basis as the audited consolidated financial statements as at and for the year ended December 31, 2009 except as outlined in Note 2. These interim consolidated financial statements do not contain all the disclosures required for annual financial statements. Accordingly, these interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in TransGlobe’s annual report for the year-ended December 31, 2009. In these interim consolidated financial statements, unless otherwise indicated, all dollars are in United States (U.S.) dollars. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.

2. CHANGES IN ACCOUNTING POLICIES

New Accounting Policies

The Company adopted a share appreciation rights plan in March 2010, which is described in Note 8. Under the share appreciation rights plan, all liabilities must be settled in cash and, consequently, are classified as liability instruments and measured at their intrinsic value less any unvested portion. Unvested share appreciation rights accrue evenly over the vesting period. The intrinsic value is determined as the difference between the market value of the Company’s common shares and the exercise price of the share appreciation rights. This obligation is revalued each reporting period and the change in the obligation is recognized as stock-based compensation expense (recovery).

3. RESTRICTED CASH

As at September 30, 2010 the Company had restricted cash of $1.9 million (2009 - $nil), as required by the Borrowing Base Facility (Note 6), and represents the aggregate amount of interest for six months on the loan balance outstanding.

4. PROPERTY AND EQUIPMENT

The Company capitalized general and administrative costs relating to exploration and development activities during the three and nine months ended September 30, 2010 of $0.7 million and $1.7 million, respectively, in Egypt (2009 - $0.5 million and $1.7 million, respectively) and $0.1 million and $0.2 million, respectively, in Yemen (2009 - $0.02 million and $0.2 million, respectively).

Unproven property costs for the three months ended September 30, 2010 in the amount of $13.9 million in Egypt (2009 - $9.9 million) and $11.0 million in Yemen (2009 - $10.6 million) were excluded from costs subject to depletion and depreciation.

Future development costs for Proved reserves included in the depletion and depreciation calculations for the three months ended September 30, 2010 totaled $11.9 million in Egypt (2009 – $1.9 million) and $9.0 million in Yemen (2009 – $10.9 million).

5. GOODWILL

Changes in the carrying amount of the Company’s goodwill, arising from acquisitions, are as follows:

		Nine Months Ended		Year Ended
(000s)		September 30, 2010		December 31, 2009
Balance, beginning of period	$	8,180	$	8,180
Changes during the period		-		-
Balance, end of period	$	8,180	$	8,180

6. LONG-TERM DEBT

		As at			As at
(000s)		September 30, 2010			December 31, 2009
Bank debt	$	50,000		$	50,000
Deferred financing costs		(3,955	)		(201	)
		46,045			49,799
Current portion of long-term debt (net of deferred financing costs)		-			49,799
	$	46,045		$	-

As at June 30, 2010, the Company had a $60.0 million Revolving Credit Agreement of which $50.0 million was drawn. The Revolving Credit Agreement was set to expire on September 25, 2010 and was secured by a first floating charge debenture over all assets of the Company, a general assignment of book debts, security pledge of the Company’s subsidiaries and certain covenants. The Revolving Credit Agreement bore interest at the Eurodollar Rate plus three percent.

Q3 2010 19

CONSOLIDATED FINANCIAL STATEMENTS

On July 22, 2010, the Company entered into a new five-year $100.0 million Borrowing Base Facility and paid out the original Revolving Credit Agreement. The new Borrowing Base Facility is secured by a pledge over certain bank accounts, a pledge over the Company’s subsidiaries, and a fixed and floating charge over certain assets. The new credit facility bears interest at the LIBOR rate plus an applicable margin, which ranges from 3.75% to 4.75% and is dependent on the amount drawn. As repayments on the new Borrowing Base Facility are not expected to commence until 2012, the entire balance has been presented as a long-term liability on the consolidated balance sheets. Repayments will be made on a semi-annual basis in order to reduce the amount borrowed to an amount no greater than the Borrowing Base. The amount of the Borrowing Base may fluctuate over time and is determined principally by the net present value of the Company’s proved and probable reserves over the term of the facility, up to a pre-defined commitment amount which is subject to pre-determined semi-annual reductions. Accordingly, for each balance sheet date, the timing of repayment is estimated based on the most recent redetermination of the Borrowing Base and repayment schedules may change in future periods.

The estimated future debt payments on long-term debt, as of September 30, 2010, are as follows:

(000s)
2010		-
2011		-
2012	$	10,876
2013		18,681
2014		14,626
Thereafter		5,817

7. SHARE CAPITAL

Authorized

The Company is authorized to issue an unlimited number of common shares with no par value.

Issued

	Nine Months Ended			Year Ended
	September 30, 2010			December 31, 2009
(000s)	Shares		Amount	Shares		Amount
Balance, beginning of period	65,399	$	66,106	59,500	$	50,532
Share issuance	-		-	5,798		16,312
Stock options exercised	1,518		7,406	101		266
Stock options surrendered for cash payments	-		-	-		(13	)
Stock-based compensation on exercise	-		3,127	-		213
Share issue costs	-		-	-		(1,204	)
Balance, end of period	66,917	$	76,639	65,399	$	66,106

The Company has received regulatory approval to purchase, from time to time, as it considers advisable, up to 6,116,905 common shares under a Normal Course Issuer Bid which commenced September 7, 2009 and expired September 6, 2010. During the three and nine month period ended September 30, 2010, the Company did not repurchase any common shares. During the year-ended December 31, 2009, the Company did not repurchase and cancel any common shares.

8. STOCK OPTION PLAN

Stock option plan

The Company adopted a stock option plan in May 2007 (the “Plan”) and reapproved unallocated options issuable pursuant to the Plan in May 2010. The number of Common Shares that may be issued pursuant to the exercise of options awarded under the Plan and all other Security Based Compensation Arrangements of the Company is 10% of the common shares outstanding from time to time. All incentive stock options granted under the Plan have a per-share exercise price not less than the trading market value of the common shares at the date of grant. Stock options vest one-third on each of the first, second and third anniversaries of the grant date. Options granted expire five years after the grant date.

The following table summarizes information about the stock options outstanding and exercisable at the dates indicated:

	Nine Months Ended			Year Ended
	September 30, 2010			December 31, 2009
			Weighted-			Weighted-
	Number		Average	Number		Average
	of		Exercise	of		Exercise
(000s, except per share amounts)	Options		Price (C$)	Options		Price (C$)
Options outstanding, beginning of period	5,478		4.12	5,600		4.20
Granted	1,370		6.89	815		3.45
Exercised	(1,518	)	5.01	(101	)	2.92
Exercised for cash	-		-	(80	)	3.26
Forfeited	(575	)	4.04	(756	)	3.91
Options outstanding, end of period	4,755		4.64	5,478		4.12
Options exercisable, end of period	1,385		4.18	2,335		4.72

20 Q3 2010

CONSOLIDATED FINANCIAL STATEMENTS

Stock–based compensation

Compensation expense of $0.7 million and $1.5 million has been recorded in general and administrative expenses in the Consolidated Statements of Income (Loss) and Retained Earnings for the three and nine months ended September 30, 2010 (September 30, 2009 - $0.5 million and $1.5 million, respectively). The fair value of all common stock options granted is estimated on the date of grant using the lattice-based binomial option pricing model. The weighted-average fair value of options granted during 2010 and the assumptions used in their determination are as follows:

	2010
Weighted-average fair market value per option (C$)	2.68
Risk free interest rate (%)	2.71
Expected life (years)	5
Expected volatility (%)	49.07
Dividend per share	0.00
Expected forfeiture rate (non-executive employees) (%)	12
Early exercise (Year 1/Year 2/Year 3/Year 4/Year 5)	0%/10%/20%/30%/40%

Share appreciation rights plan

In addition to the Company’s stock option plan, the Company also issues share appreciation rights under the share appreciation rights plan, which was adopted in March 2010. Share appreciation rights are similar to stock options except that the holder does not have the right to purchase the underlying share of the Company and instead the units are settled in cash. Units granted under the share appreciation rights plan vest one-third on each of the first, second and third anniversaries of the grant date. Share appreciation rights granted expire five years after the grant date.

	Nine Months Ended
	September 30, 2010
		Weighted-
	Number	Average
	of	Exercise
(000s, except per share amounts)	Units	Price (C$)
Outstanding, beginning of period	-	-
Granted	150	6.61
Exercised	-	-
Forfeited	-	-
Outstanding, end of period	150	6.61
Exercisable, end of period	-	-

The mark-to-market liability for the share appreciation rights plan as at September 30, 2010 amounted to $0.1 million and was included in accounts payable and accrued liabilities on the Consolidated Balance Sheets.

9. CONTRIBUTED SURPLUS

		Nine Months Ended			Year Ended
(000s)		September 30, 2010			December 31, 2009
Contributed surplus, beginning of period	$	6,691		$	4,893
Stock-based compensation expense		1,539			2,011
Transfer to common shares on exercise of options		(3,127	)		(213	)
Contributed surplus, end of period	$	5,103		$	6,691

10. ACCUMULATED OTHER COMPREHENSIVE INCOME

The balance of accumulated other comprehensive income consists of the following:

		Nine Months Ended		Year Ended
(000s)		September 30, 2010		December 31, 2009
Accumulated other comprehensive income, beginning of period	$	10,880	$	10,880
Other comprehensive income		-		-
Accumulated other comprehensive income, end of period	$	10,880	$	10,880

Q3 2010 21

CONSOLIDATED FINANCIAL STATEMENTS

11. PER SHARE AMOUNTS

In calculating the net income (loss) per share, basic and diluted, the following weighted-average shares were used:

	Three Months Ended		Nine Months Ended
	September 30		September 30
(000s)	2010	2009	2010	2009
Weighted-average number of shares outstanding	66,775	65,328	66,085	64,135
Dilutive effect of stock options	2,534	-	2,317	-
Weighted-average number of diluted shares outstanding	69,309	65,328	68,402	64,135

The treasury stock method assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the three and nine month periods ended September 30, 2010, the Company excluded 234,000 and 1,061,400 options, respectively, as their exercise price was greater than the average common share market price in this period. In calculating the weighted-average number of diluted common shares outstanding for the three and nine month periods ended September 30, 2009, the Company excluded all stock options outstanding because there was a net loss in these periods.

12. CAPITAL DISCLOSURES

The Company’s objectives when managing capital are to ensure the Company will have the financial capacity, liquidity and flexibility to fund the ongoing exploration and development of its oil and gas assets. The Company relies on cash flow to fund its capital investments. However, due to long lead cycles of some of its developments and corporate acquisitions, the Company’s capital requirements may exceed its cash flow generated in any one period. This requires the Company to maintain financial flexibility and liquidity. The Company sets the amount of capital in proportion to risk and manages to ensure that the total of the long-term debt is not greater than two times the Company’s funds flow from operations for the trailing twelve months. For the purposes of measuring the Company’s ability to meet the above-stated criteria, funds flow from operations is defined as the net income or loss before any deduction for depletion, depreciation and accretion, amortization of deferred financing charges, non-cash stock-based compensation, and non-cash derivative (gain) loss on commodity contracts. Funds flow from operations is a non-GAAP measure and may not be comparable to similar measures used by other companies.

The Company defines and computes its capital as follows:

		As at			As at
(000s)		September 30, 2010			December 31, 2009
Shareholders’ equity	$	202,476		$	163,690
Long-term debt, including the current portion (net of unamortized transaction costs)		46,045			49,799
Cash and cash equivalents		(15,412	)		(16,177	)
Total capital	$	233,109		$	197,312

The Company’s debt-to-funds flow ratio is computed as follows:

		12 Months Trailing
(000s)		September 30, 2010		December 31, 2009
Long-term debt, including the current portion (net of unamortized transaction costs)	$	46,045	$	49,799
Cash flow from operating activities	$	44,772	$	36,799
Changes in non-cash working capital		20,566		8,265
Funds flow from operations	$	65,338	$	45,064
Ratio		0.7		1.1

The Company’s financial objectives and strategy as described above have remained substantially unchanged over the last two completed fiscal years. These objectives and strategy are reviewed on an annual basis. The Company believes that its ratios are within reasonable limits, in light of the relative size of the Company and its capital management objectives.

The Company is also subject to financial covenants in the Borrowing Base Facility that existed as at September 30, 2010. The key financial covenants are as follows:

• Consolidated Financial Indebtedness to EBITDAX will not exceed 3.0 to 1.0. For the purposes of this calculation, Consolidated Financial Indebtedness shall mean the aggregate of all Financial Indebtedness of the Company. EBITDAX shall be defined as Consolidated Net Income before interest, income taxes, depreciation, depletion, amortization, accretion of abandonment liability, unrealized hedging losses and other similar non-cash charges (including expenses related to stock options), minus unrealized hedging gains and all non-cash income added to Consolidated Net Income.
• Current ratio (current assets to current liabilities, excluding the current portion of long-term debt) of greater than 1.0 to 1.0.

The Company is in compliance with all financial covenants at September 30, 2010.

22 Q3 2010

CONSOLIDATED FINANCIAL STATEMENTS

13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Carrying Values and Estimated Fair Values of Financial Assets and Liabilities

The Company has classified its cash and cash equivalents and restricted cash as assets held for trading and its derivative commodity contracts as financial assets or liabilities held for trading, which are both measured at fair value with changes being recognized in net income. Accounts receivable are classified as loans and receivables; accounts payable and accrued liabilities, and long-term debt are classified as other liabilities, all of which are measured at amortized cost.

Carrying value and fair value of financial assets and liabilities are summarized as follows:

(000s)		September 30, 2010
Classification		Carrying Value		Fair Value
Financial assets held-for-trading	$	17,308	$	17,308
Loans and receivables		57,307		57,307
Other liabilities		73,409		77,364

Assets and liabilities at September 30, 2010 that are measured at fair value are classified into levels reflecting the method used to make the measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement.

The Company’s cash and cash equivalents and risk management contracts are assessed on the fair value hierarchy described above. TransGlobe’s cash and cash equivalents are classified as Level 1 and risk management contracts as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level.

Credit Risk
Credit risk is the risk of loss if the counter parties do not fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to accounts receivable, the majority of which are in respect of oil operations, and derivative commodity contracts. The Company generally extends unsecured credit to these parties and therefore the collection of these amounts may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit and an insurance program on a portion of the receivable balance. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

Trade and other receivables are analyzed in the table below. With respect to the trade and other receivables that are not impaired and past due, there are no indications as of the reporting date that the debtors will not meet their payment obligations.

(000s)
Trade and other receivables at September 30, 2010
Neither impaired nor past due	$	23,689
Impaired (net of valuation allowance)		-
Not impaired and past due in the following period:
Within 30 days		7,725
31-60 days		6,534
61-90 days		7,630
Over 90 days		11,729

In Egypt, the Company sold all of its 2010 production to one purchaser. In Yemen, the Company sold all of its 2010 Block 32 production to one purchaser and all of its 2010 Block S-1 production to one purchaser. Management considers such transactions normal for the Company and the international oil industry in which it operates.

Market Risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The market price movements that the Company is exposed to include oil prices (commodity price risk), foreign currency exchange rates and interest rates, all of which could adversely affect the value of the Company’s financial assets, liabilities and financial results.

a) Commodity Price Risk
The Company’s operational results and financial condition are partially dependent on the commodity prices received for its oil production. Commodity prices have fluctuated significantly during recent years.

Any movement in commodity prices would have an effect on the Company’s financial condition. Therefore, the Company has entered into various financial derivative contracts to manage fluctuations in commodity prices in the normal course of operations. The following contracts are outstanding immediately following September 30, 2010:

			Dated Brent Pricing
Period	Volume	Type	Put
Crude Oil
July 1, 2010-December 31, 2010	10,000 Bbl/month	Financial Floor	$60.00
July 1, 2010-December 31, 2010	20,000 Bbl/month	Financial Floor	$65.00
January 1, 2011-December 31, 2011*	20,000 Bbl/month	Financial Floor	$65.00
* Contract was purchased in October 2010.

Q3 2010 23

CONSOLIDATED FINANCIAL STATEMENTS

The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheets, with any change in the unrealized positions recorded to income. The Company assessed these instruments on the fair value hierarchy and has classified the determination of fair value of these instruments as Level 2, as the fair values of these transactions are based on an approximation of the amounts that would have been received from counter-parties to settle the transactions outstanding as at the Consolidated Balance Sheet date with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates.

When assessing the potential impact of commodity price changes on its financial derivative commodity contracts, the Company believes 10% volatility is a reasonable measure. A 10% increase in commodity prices on the derivative commodity contracts would not have a material effect on net income for the three and nine months ended September 30, 2010. The effect of a 10% decrease in commodity prices on the derivative commodity contracts would increase the net income, for the three and nine months ended September 30, 2010, by $0.2 million.

b) Foreign Currency Exchange Risk
As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates to certain cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would result in an increase in the net income for the three and nine months ended September 30, 2010 of approximately $0.2 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the net income by said amount for the same periods. The Company does not utilize derivative instruments to manage this risk.

c) Interest Rate Risk
Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable-interest, U.S.-dollar-denominated debt. No derivative contracts were entered into during 2010 to mitigate this risk. When assessing interest rate risk applicable to the Company’s variable-interest, U.S.-dollar-denominated debt the Company believes 1% volatility is a reasonable measure. The effect of interest rates increasing by 1% would decrease the Company’s net income, for the three and nine months ended September 30, 2010, by $0.1 million and $0.4 million, respectively. The effect of interest rates decreasing by 1% would increase the Company’s net income, for the three and nine months ended September 30, 2010, by $0.1 million and $0.4 million, respectively.

Liquidity Risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. 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.

The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. The following are the contractual maturities of financial liabilities at September 30, 2010:

(000s)	Payment Due by Period1,2
	Recognized										More
	in Financial		Contractual		Less than						than
	Statements		Cash Flows		1 year		1-3 years		4-5 years		5 years
Accounts payable and accrued liabilities	Yes-Liability	$	27,364	$	27,364	$	-	$	-	$	-
Long-term debt:
Borrowing Base Facility	Yes-Liability		50,000		-		29,557		20,443		-
Office and equipment leases	No		11,051		1,567		3,034		1,916		4,534
Minimum work commitments3	No		4,953		-		4,953		-		-
Total		$	93,368	$	28,931	$	37,544	$	22,359	$	4,534

1.	Payments exclude ongoing operating costs related to certain leases, interest on long-term debt and payments made to settle derivatives.
2.	Payments denominated in foreign currencies have been translated at September 30, 2010 exchange rates.
3.	Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

The Company actively monitors its liquidity to ensure that its cash flows, credit facilities and working capital are adequate to support these financial liabilities, in addition to the Company’s capital programs.

The existing banking arrangement at September 30, 2010 consists of a Revolving Credit Facility of $100.0 million of which $50.0 million was drawn.

14. COMMITMENTS AND CONTINGENCIES

The Company is subject to certain office and equipment leases (Note 13).

Pursuant to the Concession agreement for Nuqra Block 1 in Egypt, the Contractor (Joint Venture Partners) has a minimum financial commitment of $5.0 million ($4.4 million to TransGlobe) and a work commitment for two exploration wells in the second exploration extension. The second, 36-month extension period commenced on July 18, 2009. The Contractor has met the second extension financial commitment of $5.0 million in the prior periods. At the request of the Government, the Company provided a $4.0 million production guarantee from the West Gharib Concession prior to entering the second extension period.

Pursuant to the PSA for Block 72 in Yemen, the Contractor (Joint Venture Partners) has a minimum financial commitment of $2.0 million ($0.1 million to TransGlobe) to drill one exploration well during the second exploration period. The second, 30-month exploration period commenced on January 12, 2009. The Contractor has entered into a farm-in agreement with TOTAL E&P Yemen which has reduced TransGlobe’s interest in the concession to 20%.

24 Q3 2010

CONSOLIDATED FINANCIAL STATEMENTS

Pursuant to the PSA for Block 75 in Yemen, the Contractor (Joint Venture Partners) has a remaining minimum financial commitment of $3.0 million ($0.8 million to TransGlobe) for one exploration well. The first, 36-month exploration period commenced March 8, 2008. The Company issued a $1.5 million letter of credit (expiring November 15, 2011) to guarantee the Company’s performance under the first exploration period. The letter is secured by a guarantee granted by Export Development Canada.

Pursuant to the August 18, 2008 asset purchase agreement for a 25% financial interest in eight development leases on the West Gharib Concession in Egypt, the Company has committed to paying the vendor a success fee to a maximum of $7.0 million if incremental reserve thresholds are reached in the East Hoshia (up to $5.0 million) and South Rahmi (up to $2.0 million) development leases, to be evaluated annually. As at December 31, 2009, no additional fees are due in 2010.

In the normal course of its operations, the Company may be subject to litigations and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.

Q3 2010 25

CONSOLIDATED FINANCIAL STATEMENTS

SEGMENTED INFORMATION

		Egypt					Yemen				Total
				Nine Months Ended September 30
(000s)		2010		2009			2010		2009		2010			2009
Revenue
Oil sales, net of royalties and other	$	81,894	$	44,296		$	30,128	$	29,721	$	112,022		$	74,017
Segmented expenses
Operating		11,800		9,695			6,942		7,683		18,742			17,378
Depletion and depreciation		18,186		33,150			5,752		7,331		23,938			40,481
Income taxes		20,461		9,658			7,158		5,308		27,619			14,966
Total segmented expenses		50,447		52,503			19,852		20,322		70,299			72,825
Segmented income (loss)	$	31,447	$	(8,207	)	$	10,276	$	9,399		41,723			1,192
Non-segmented expenses
Derivative loss (gain) on commodity contracts (Note 13a)											(68	)		3,529
General and administrative											9,418			7,505
Interest on long-term debt											2,114			1,904
Depreciation											183			143
Foreign exchange loss (gain)											253			(940	)
Other income											(18	)		(16	)
Total non-segmented expenses											11,882			12,125
Net income (loss)										$	29,841		$	(10,933	)
Capital expenditures
Exploration and development	$	42,484	$	21,491		$	4,636	$	6,345	$	47,120		$	27,836
Corporate											266			169
Total capital expenditures										$	47,386		$	28,005

26 Q3 2010

CONSOLIDATED FINANCIAL STATEMENTS

		Egypt					Yemen				Total
				Three Months Ended September 30
(000s)		2010		2009			2010		2009		2010			2009
Revenue
Oil sales, net of royalties and other	$	29,552	$	17,755		$	9,428	$	10,740	$	38,980		$	28,495
Segmented expenses
Operating		4,313		4,241			2,395		2,730		6,708			6,971
Depletion and depreciation		7,468		11,747			1,893		2,394		9,361			14,141
Income taxes		7,447		3,874			2,338		2,287		9,785			6,161
Total segmented expenses		19,228		19,862			6,626		7,411		25,854			27,273
Segmented income (loss)	$	10,324	$	(2,107	)	$	2,802	$	3,329	$	13,126		$	1,222
Non-segmented expenses
Derivative loss (gain) on commodity contracts (Note 13a)											221			(152	)
General and administrative											2,999			2,636
Interest on long-term debt											1,111			575
Depreciation											79			51
Foreign exchange loss (gain)											(78	)		(286	)
Other income (loss)											(11	)		16
Total non-segmented expenses											4,321			2,840
Net income (loss)										$	8,805		$	(1,618	)
Capital expenditures
Exploration and development	$	16,297	$	8,559		$	2,964	$	2,029	$	19,261		$	10,588
Corporate											192			11
Total capital expenditures										$	19,453		$	10,599
		Sept. 30		Dec. 31			Sept. 30		Dec. 31		Sept. 30			Dec. 31
		2010		2009			2010		2009		2010			2009
Property and equipment	$	143,376	$	119,079		$	46,370	$	47,486	$	189,746		$	166,565
Goodwill		8,180		8,180			-		-		8,180			8,180
Other		58,982		41,347			8,314		5,877		67,296			47,224
Segmented assets	$	210,538	$	168,606		$	54,684	$	53,363		265,222			221,969
Non-segmented assets											10,663			6,913
Total assets										$	275,885		$	228,882

Q3 2010 27

CORPORATE INFORMATION

DIRECTORS AND OFFICERS	TRANSFER AGENT AND REGISTRAR
Robert A. Halpin1,2,4	Olympia Trust Company
Director, Chairman of the Board	Calgary, Alberta
Ross G. Clarkson
Director, President & CEO	LEGAL COUNSEL
Lloyd W. Herrick	Burnet, Duckworth & Palmer LLP
Director, Vice President & COO	Calgary, Alberta
Geoffrey Chase1,2,4
Director	BANK
Fred J. Dyment1,3,4	Sumitomo Mitsui Banking Corporation Europe Limited
Director	London, United Kingdom
Gary S. Guidry1,2,3
Director	AUDITOR
Erwin L. Noyes2,3,4	Deloitte & Touche LLP
Director	Calgary, Alberta
David C. Ferguson
Vice President, Finance, CFO & Corporate Secretary	EVALUATION ENGINEERS
1.   Audit Committee	DeGolyer and MacNaughton Canada Limited
2.   Reserves Committee	Calgary, Alberta
3.   Compensation Committee
4.   Governance and Nominating Committee	HEAD OFFICE
	2500, 605 – 5th Avenue S.W.
INVESTOR RELATIONS	Calgary, Alberta, Canada T2P 3H5
	Telephone: (403) 264-9888
Scott Koyich	Facsimile: (403) 264-9898
Telephone: (403) 264-9888
Email: investor.relations@trans-globe.com	EGYPT OFFICE
	6 Badr Towers, 3rd Floor
Website: www.trans-globe.com	Ring Road
	New Maadi, Cairo, Egypt

	Nine Months Ended		Three Months Ended
SHARE INFORMATION	September 30		September 30
	2010	2009	2010	2009
TSX: Price per share – TSX (C$)
High	9.99	4.10	9.99	4.10
Low	3.52	2.60	6.74	2.60
Close	9.76	3.81	9.76	3.81
Average daily trading volume	188,414	67,248	180,186	68,642
NASDAQ: Price per share – NASDAQ (US$)
High	9.70	3.78	9.70	3.78
Low	3.33	2.20	6.80	2.21
Close	9.46	3.57	9.46	3.57
Average daily trading volume	193,856	150,192	150,740	147,500