TransGlobe Energy Corporation - Exhibit 99.2

The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2011 and 2010, together with the notes related thereto. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) 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 on Form 40-F may be found on EDGAR at www.sec.gov.

Certain statements or information contained herein may constitute forward-looking statements or information under applicable securities laws, including management’s assessment of future plans and operations, drilling plans and the timing thereof, commodity price risk management strategies, adapting to the current political situations in Egypt and Yemen, reserve estimates, the resolution of potential litigation and claims and impact on the Company of the costs of resolutions, completion of the acquisition of the 50% working interest in the South Alamein Concession agreement in the Arab Republic of Egypt, management’s expectation for results of operations for 2012, including expected 2012 average production, funds flow from operations, the 2012 capital program for exploration and development, the timing and method of financing thereof, method of funding drilling commitments, commodity prices and expected volatility thereof and use of proceeds from recent financings.

Forward-looking statements or information relate to the Company’s future events or performance. All statements other than statements of historical fact may be forward-looking statements or information. Such statements or information 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.

Forward-looking statements or information necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, economic and political instability, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. The recovery and reserve estimates of the Company's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company.

In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on the Company's future operations. Such statements and information may prove to be incorrect and readers are cautioned that such statements and information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements or information because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market and receive payment for its oil and natural gas products.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) and at the Company's website (www.trans-globe.com). Furthermore, the forward-looking statements or information contained herein are made as at the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

The reader is further cautioned that the preparation of financial statements in accordance with IFRS requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

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 IFRS. Funds flow from operations is a 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.

Debt-to-funds flow ratio
Debt-to-funds flow is a 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 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 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.

On December 29, 2011, the Company completed the acquisition of a 100% working interest in the West Bakr Concession agreement in the Arab Republic of Egypt from the Egyptian Petroleum Development Co. Ltd. (of Japan) (“EPEDECO”). The transaction provided for operatorship of three fields with 28 producing wells, located immediately adjacent to the Company’s West Gharib development leases. West Bakr is producing approximately 4,350 Bopd and had Proved reserves of 7.4 million barrels and Proved plus Probable reserves of 11.6 million barrels as of January 1, 2012. The transaction was structured as an all-cash deal, effective July 1, 2010, to acquire all the Egyptian assets of EPEDECO, funded through working capital and the Borrowing Base Facility. Total consideration for the transaction was $74.5 million, comprised of $52.6 million cash and $21.9 million payable to EPEDECO ($10.0 million due by May 31, 2012, with the balance due by June 29, 2012). Total consideration represents an initial $60 million base purchase price plus $14.5 million in working capital and other closing adjustments between the effective date and the acquisition closing date.

($000s, except per share, price and volume
amounts)	2011	% Change		2010	% Change	2009***
Operations
Average sales volumes (Bopd)	12,132	22		9,960	11	8,980
Average price ($/Bbl)	101.58	37		73.97	45	51.19
Oil and gas sales	449,794	67		268,901	60	167,798
Oil and gas sales, net of royalties and other	247,754	58		157,220	53	102,805
Cash flow from operating activities	63,630	12		56,969	55	36,799
Funds flow from operations*	119,976	59		75,460	67	45,064
Funds flow from operations per share
- Basic	1.65			1.14		0.70
- Diluted	1.60			1.10		0.70

Net earnings (loss)	81,392	101		40,565	-	(8,417	)
Net earnings (loss) per share
- Basic	1.12			0.61		(0.13	)
- Diluted	1.09			0.59		(0.13	)


Total assets	525,806	52		345,625	51	228,882
Cash and cash equivalents	43,884	(24	)	57,782	257	16,177
Total long-term debt, including current portion	57,609	(33	)	86,420	74	49,799
Debt-to-funds flow ratio**	0.5			1.1		1.1

Reserves
Total Proved (MMBbl)	28.1	37		20.5	7	19.2
Total Proved plus Probable (MMBbl)	44.2	45		30.4	26	24.2

Net earnings increased to $81.4 million in 2011 compared to $40.6 million in 2010, which was mostly due to significant increases in commodity prices and production volumes, which was partially offset by higher royalties and income taxes, and increases in depletion and depreciation and operating costs. Also significantly impacting net earnings was a purchase gain recognized on the acquisition of the West Bakr assets, which was partially offset by an impairment loss on the Company’s Nuqra assets.

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:

The price of Dated Brent oil averaged 40% higher in 2011 compared with 2010. All of the Company’s production is priced based on Dated Brent and shared with the respective governments through Production Sharing Agreements. When the price of oil goes up, it takes fewer barrels to recover costs (cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total revenue. Typically maximum cost recovery ranges from 25% to 60% of production depending on the country and the contract. Generally the balance of the production is shared with the respective government (production sharing oil). Depending on the contract, the government receives 70% to 85% of the production sharing oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of production sharing oil increases when production exceeds pre-set production levels in the respective contracts. During times of increased oil prices, the Company receives less cost oil and may receive more production sharing oil. For reporting purposes, the Company records the respective government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production).

The recent political instability in Egypt and Yemen could present challenges to the Company if the issues persist over an extended period of time. TransGlobe’s management believes the Company is well positioned to adapt to the current political situations in Egypt and Yemen due to its increasing production, manageable debt levels, positive cash generation from operations and the availability of cash and cash equivalents.

	2011				2010
($000s, except per share,
price and volume amounts)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Total Operations
Average sales volumes (Bopd)	12,054	13,406	11,826	11,218	10,789	10,138	9,206	9,694
Average price ($/Bbl)	99.12	104.00	105.57	97.06	79.83	71.27	73.46	70.66
Oil sales	109,919	128,265	113,615	97,995	79,240	66,470	61,540	61,651
Oil sales, net of royalties and other	60,609	71,769	62,513	52,863	45,198	38,980	35,638	37,404
Cash flow from operating activities	2,330	3,575	54,235	3,490	17,010	15,024	13,283	11,652
Funds flow from operations*	26,469	38,099	30,478	24,930	19,355	19,849	17,007	19,249
Funds flow from operations per share
Basic	0.36	0.52	0.42	0.35	0.29	0.30	0.26	0.29
Diluted	0.35	0.51	0.40	0.34	0.28	0.29	0.25	0.29
Net earnings	30,519	26,110	21,874	2,889	8,932	9,321	9,711	12,601
Net earnings per share
Basic	0.42	0.36	0.30	0.04	0.13	0.14	0.15	0.19
Diluted	0.41	0.35	0.29	0.04	0.13	0.13	0.14	0.19
Total assets	525,806	465,262	420,956	404,184	345,625	278,426	264,490	248,837
Cash and cash equivalents	43,884	105,007	122,659	86,353	57,782	15,412	21,437	18,845
Total long-term debt, including current portion	57,609	57,303	56,998	56,731	86,420	46,045	49,977	49,888
Debt-to-funds flow ratio**	0.5	0.5	0.6	0.7	1.1	0.7	0.9	0.9

The netback per Bbl in Egypt increased 20% in 2011 compared with 2010, mainly as a result of oil prices increasing by 40% which was partially offset by higher royalty and tax rates. In 2011, the average selling price was $100.61/Bbl, which represents a quality adjustment of approximately 10% relative to the average Dated Brent oil price of $111.27/Bbl for West Gharib sales. This adjustment is consistent with the discount applied in 2010.

Royalties and taxes as a percentage of revenue increased to 62% in 2011, compared with 55% in 2010. 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. Cost recovery for the purposes of calculating cost oil is based on expenses incurred and paid in the period plus capital costs which are amortized over four years in West Gharib.

Operating expenses on a per Bbl basis increased 13% in 2011 compared with 2010. This is mainly due to increases in oil treatment fees, fuel costs and workovers during 2011.

In Yemen, the netback per Bbl increased 29% in 2011 compared with 2010, primarily due to the 36% increase in oil prices in 2011.

Royalties and taxes as a percentage of revenue decreased to 58% in 2011, compared with 59% 2010. 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 increased by 65% in 2011. This was mostly due to a decrease in production volumes of 46% and cost increases associated with the unstable political situation in Yemen. This decrease in production volumes is mainly the result of production being shut-in on Block S-1 for approximately seven months (from March 17, 2011 through to July 16, 2011, and from October 8, 2011 to the end of the calendar year). While production volumes were down, the Company continued to incur the majority of the operating costs on Block S-1 which significantly impacted operating expenses per Bbl.

Production from Block S-1 remains shut-in following an attack on the oil export pipeline on October 8, 2011, and production will not commence until repairs to the export pipeline can be completed. It is difficult to predict when production will resume as local tribal groups are currently preventing access to the pipeline.

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. The hedging program is actively monitored and adjusted as deemed necessary to protect the cash flows from the risk of commodity price exposure.

The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheets, with any change in the unrealized positions recorded to earnings. 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 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 losses on commodity contracts in 2011 and 2010 relate to the purchase of new financial floor derivative commodity contracts. The mark-to-market valuation of TransGlobe’s future derivative commodity contracts decreased from a $0.3 million asset at December 31, 2010 to a $0.1 million asset at December 31, 2011, thus resulting in a $0.2 million unrealized loss on future derivative commodity contracts being recorded in the year.

If the Dated Brent oil price remains at the level experienced in 2011, the derivative asset will be realized over the balance of the year. A 10% increase or decrease in Dated Brent oil prices would not result in a material adjustment to the derivative commodity contract asset. The following commodity contracts are outstanding as at December 31, 2011:

At December 31, 2011, all of the derivative commodity contracts were classified as current assets.

G&A expenses (net) increased 22% (no change on a per Bbl basis) in 2011, compared with 2010. This is mostly due to increased staffing and associated costs and increased professional fees. The increase in stock-based compensation is due to an increase in the total value of new options awarded during the second quarter of 2011 as compared to those issued during 2010, which was partially offset by expense recoveries on share appreciation rights in 2011 which were caused by a lower share price in 2011 compared to 2010.

Finance costs for 2011 increased to $5.0 million compared to $3.3 million in 2010. Finance costs include interest on long-term debt and amortization of transaction costs associated with long-term debt. The Company expensed $1.2 million of transaction costs in 2011 (2010 - $0.8 million). The Company had $60.0 million of debt outstanding at December 31, 2011 (December 31, 2010 - $90.0 million). The long-term debt that was outstanding at December 30, 2011 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 February 2012, the Company closed an agreement to issue convertible unsecured subordinated debentures with an aggregate principal amount of C$97.8 million. The debentures have a maturity date of March 31, 2017, and are convertible into common shares of the Company at a price of C$15.10 per common share. The debentures will not be redeemable by the Company on or before March 31, 2015. After March 31, 2015 and prior to March 31, 2017, the debentures may be redeemed by the Company at a redemption price equal to the principal amount plus accrued and unpaid interest, provided that the weighted average trading price of the common shares for the 20 consecutive trading days ending five trading days prior to the date on which notice of redemption is provided is not less than 125 percent of the conversion price. Interest of 6% will be payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2012. The Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations.

In Egypt and Yemen, DD&A on a per Bbl basis remained consistent in 2011. DD&A expense in Egypt increased 45% in 2011 due to production volume increases of 47%. DD&A expense in Yemen decreased 45% due to production volume decreases of 46%. The volume decreases in Yemen were caused by the shut-in of Block S-1 for approximately seven months during 2011, which was the result of damage to the oil export pipeline from Marib to the Ras Eisa port on the Red Sea. The pipeline was the target of a number of attacks during 2011, and completing the necessary repairs is difficult due to local tribal groups preventing access to the pipeline.

On the Nuqra Block, the Company drilled two exploration wells during 2011, both of which were dry. The 3.65 million acre Nuqra Block exploration concession is in the second and final extension period which is scheduled to expire in July 2012. The Company has met all the work commitments of the second extension period and has no plans for further exploration in the Nuqra Block at this time. As a result, the Company recorded an impairment loss on these exploration and evaluation assets in the amount of $12.1 million ($0.16/share) during 2011. All exploration and evaluation expenditures incurred at Nuqra up to December 31, 2011 have been written off as an impairment loss.

In Egypt, total capital expenditures in 2011 were $63.2 million (2010 - $56.9 million). The Company drilled 44 wells in West Gharib, resulting in 36 oil wells (nineteen at Arta, twelve at East Arta, four at Hoshia and one at Hana West), three water injector wells at East Arta, one water source well at East Arta, one water source well at Hoshia, one dry hole at West Hoshia, one dry hole at North Hoshia and one dry hole at East Arta. Outside of West Gharib, the Company drilled three dry holes (one at East Ghazalat and two at Nuqra).

In Yemen, total capital expenditures in 2011 were $5.5 million (2010 - $7.6 million). Two oil development wells were drilled in 2011 at Block S-1, along with one oil exploration discovery well and one dry hole at Block 72.

On December 29, 2011, the Company completed the acquisition of a 100% working interest in the West Bakr Concession agreement in Egypt from the Egyptian Petroleum Development Co. Ltd. (of Japan) (“EPEDECO”). The property and equipment acquired in the transaction was valued at $74.8 million at closing.

Corporate expenditures in 2011 were primarily due to costs incurred for the new head office in Calgary.

FINDING AND DEVELOPMENT COSTS/FINDING, DEVELOPMENT AND NET ACQUISITION COSTS

Canadian National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), specifies how finding and development (“F&D”) costs should be calculated. NI 51-101 requires that exploration and development costs incurred in the year along with the change in estimated future development costs be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions and dispositions on both reserves and costs. TransGlobe believes that the provisions of NI 51-101 do not fully reflect TransGlobe’s on-going reserve replacement costs. Since acquisitions can have a significant impact on TransGlobe’s annual reserves replacement cost, to not include these amounts could result in an inaccurate portrayal of TransGlobe’s cost structure. Accordingly, TransGlobe has also reported finding, development and acquisition (“FD&A”) costs that will incorporate acquisitions, net of any dispositions during the year.

The 2011 Proved and Proved plus Probable recycle ratios increased from 2010, which is the result of higher netbacks due to stronger oil prices in the year, combined with reduced finding and development costs. In particular, the acquisition cost per Bbl of reserves in West Bakr was $5.47/Bbl on a Proved basis and $4.20/Bbl on a Proved plus Probable basis including future capital costs. The increased ratios were also impacted by reduced future capital associated with both Proved and Proved plus Probable reserves in 2011.

Due to the nature of international projects, the Company considers the three-year weighted average recycle ratios to provide the most useful information. The three-year weighted average ratios are consistent with Company expectations and with prior periods.

The recycle ratio measures the efficiency of TransGlobe’s capital program by comparing the cost of finding and developing both proved reserves and proved plus probable reserves with the netback from production. The ratio is calculated by dividing the netback by the proved and proved plus probable finding and development cost on a per Bbl basis.

As at December 31, 2011, the Company had 73,054,138 common shares issued and outstanding. On February 1, 2011, the Company closed an equity offering of 5,000,000 common shares at C$15.00 per common share for gross proceeds of C$75.0 million (US$75.6 million).

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 0.5 times at December 31, 2011. This was within the Company’s target range of no more than 2.0 times.

The following table illustrates TransGlobe’s sources and uses of cash during the year ended December 31, 2011 and 2010:

Funding for the Company’s capital expenditures was provided by funds flow from operations. The Company funded its 2011 exploration and development program of $68.7 million and contractual commitments through the use of working capital and cash generated by operating activities. The use of new financing during 2011 was utilized to finance the acquisition of a 100% working interest in the West Bakr Concession agreement in Egypt. 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 December 31, 2011, the Company had working capital of $140.0 million (December 31, 2010 - $88.2 million). The increase to working capital in 2011 is due almost entirely to higher accounts receivable than 2010, which was partially offset by a decrease in cash and increased accounts payable. Cash has decreased by $13.9 million from December 31, 2010, which is due mostly to the acquisition of the West Bakr assets along with the repayment of long-term debt, which was partially offset by cash flows generated from operations and the issuance of common shares in the first quarter of 2011. Accounts receivable have increased by $93.1 million from December 31, 2010, which is due to increased production and higher commodity prices resulting in significantly larger monthly billings combined with the acquisition of the West Bakr assets which added $34.5 million of accounts receivable. The majority of these receivables are due from the Egyptian Government, and the recent political unrest in the country has increased the Company’s credit risk. Despite these factors the Company still expects to collect in full all outstanding receivables.

At December 31, 2011, TransGlobe had a $100.0 million Borrowing Base Facility of which $60.0 million was drawn. As repayments on the Borrowing Base Facility are not expected to commence until 2013, 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 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 Period ¹2
	Recognized
	in Financial	Contractual	Less than			More than
	Statements	Cash Flows	1 year	1-3 years	4-5 years	5 years
Accounts payable and accrued liabilities	Yes - Liability	73,692	73,692	-	-	-
Long-term debt	Yes - Liability	60,000	-	60,000	-	-
Office and equipment leases	No	17,300	8,368	3,465	2,028	3,439
Minimum work commitments³	No	750	750	-	-	-
Total		151,742	82,810	63,465	2,028	3,439

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. Drilling has been suspended in Yemen due to security and logistics concerns.

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 $2.0 million if incremental reserve thresholds are reached in the South Rahmi development lease, to be evaluated annually. As at December 31, 2011, no additional fees are due in 2012.

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.

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2011.

On June 29, 2011, the Company entered into an agreement to acquire a 50% working interest in the South Alamein Concession agreement in the Arab Republic of Egypt from Cepsa Egypt SA B.V. (“Cepsa Egypt”), a wholly-owned subsidiary of Compania Espanola De Petroleos, S.A. (of Spain), subject to the approval of the Egyptian Government and customary closing conditions. The proposed transaction provides for the operatorship of the concession and near-term appraisal/development of one oil discovery well and of a significant number of ready to drill exploration projects, located in Egypt’s Western Desert. The Company has structured the transaction as an all-cash deal effective on and subject to approval from the Egyptian Government. Consideration for the transaction is $3.0 million plus an inventory adjustment to be determined based on customary due diligence and other closing conditions. Because of uncertainty related to the successful approval of the transaction by the Egyptian Government, management is not able to provide any assurances that it will successfully close the subject transaction. Accordingly, no amount has been accrued in the Consolidated Financial Statements for the year ended December 31, 2011 related to the contingency.

The Company has certain lease arrangements, all of which are reflected in the Commitments and Contingencies table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the balance sheet as of December 31, 2011.

The 2012 outlook provides information as to management’s expectation for results of operations for 2012. Readers are cautioned that the 2012 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.

Production for 2012 is expected to average between 16,000 and 20,000 Bopd, representing a 32% to 65% increase over the 2011 average production of 12,132 Bopd. The large spread in the estimated production is due to a number of variables outside of the Company’s control such as government approvals, the start of production at East Ghazalat and South Alamein and the repair of the export pipeline for Block S-1 in Yemen.

Funds flow from operations is estimated at $133.0 million ($1.76/share) based on an annual average Dated Brent oil price of $90/Bbl and using the mid-point of the production guidance. Variations in production and commodity prices during 2012 could significantly change this outlook. An increase or decrease in the average Dated Brent oil price of $10/Bbl for the year would result in a corresponding change in anticipated 2012 funds flow by approximately $14.0 million or $0.19/share.

The Company entered into an agreement to acquire a 50% working interest in the South Alamein Concession agreement. Closing is subject to the approval of the Egyptian Government and customary closing conditions. TransGlobe cannot make assurances that it will successfully close the subject transaction.

The 2012 capital program is split 77:23 between development and exploration, respectively. The Company plans to participate in 38 wells in 2012. It is anticipated that the Company will fund its 2012 capital budget from funds flow from operations and working capital.

TransGlobe’s results are affected by a variety of business risks and uncertainties in the international petroleum industry including but not limited to:

Many of these risks are not within the control of management, but the Company has adopted several strategies to reduce and minimize the effects of these risks:

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on TransGlobe.

To mitigate these risks, the Company raised C$75.0 million (US$75.6 million), before fees and expenses, in a public offering of common shares that closed on February 1, 2011. The Company also raised C$97.8 million (US$97.8 million), before fees and expenses, through a public sale of convertible debentures. The amount raised was comprised of an original issuance in the amount of C$85.0 million (US$85.0 million) that closed on February 22, 2012, along with an overallotment option in the amount of C$12.8 million (US$12.9 million) that was exercised by the underwriters and closed on February 29, 2012. The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flows from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs.

The recent political instability in Egypt and Yemen could present challenges to the Company if the issues persist over an extended period of time. Continued instability could reduce the Company’s ability to access debt, capital and banking markets. To mitigate potential financial risk factors, management regularly evaluates operational and financial risk strategies and continues to monitor the 2012 capital budget and the Company’s long-term plans. The Company has designed its 2012 budget to be flexible allowing spending to be adjusted for any unforeseen events and changes in commodity prices.

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.

Commodity price risk
The Company’s operational results and financial condition are dependent on the commodity prices received for its oil production. Commodity prices have fluctuated significantly this year.

Any movement in commodity prices would have an effect on the Company’s financial condition which could result in the delay or cancellation of drilling, development or construction programs, all of which could have a material adverse impact on the Company. Therefore, the Company has entered into various financial derivative contracts to manage fluctuations in commodity prices in the normal course of operations. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

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 and Egyptian pounds. Periodically, the Company utilizes derivatives to manage this risk, however, there are no outstanding derivative foreign currency exchange contracts as at December 31, 2011. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The effect of a 10% increase or decrease in the value of the Canadian dollar against the U.S. dollar would not have a material impact on net earnings for the year ended December 31, 2011. The Company maintains Egyptian pound cash balances to offset the Egyptian pound liabilities, and therefore, the Company believes its exposure to Egyptian pound fluctuations is not significant.

Interest rate risk
Fluctuations in interest rates could result in a change in the amount the Company pays to service variable-interest, U.S.-dollar-denominated debt. No derivative contracts were entered into during 2011 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 earnings by $0.6 million for the year ended December 31, 2011. The effect of interest rates decreasing by 1% would increase the Company’s net earnings by $0.6 million for year ended December 31, 2011.

Credit risk is the risk of loss if counterparties 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 is and may in the future be exposed to third-party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum production and other parties, including the governments of Egypt and Yemen. Significant changes in the oil industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect the Company’s ability to realize the full value of its accounts receivable. The Company currently has, and historically has had, a significant account receivable outstanding from the Government of Egypt. While the Government of Egypt does make payments on these amounts owing, the timing of these payments has historically been longer than normal industry standard. The recent political unrest in Egypt has increased the delay in payments. Despite these factors, the Company still expects to collect this account receivable in full, although there can be no assurance that this will occur. In the event the Government of Egypt fails to meet its obligations, or other third-party creditors fail to meet their obligations to the Company, such failures could individually or in the aggregate have a material adverse effect on the Company, its cash flow from operating activities and its ability to conduct its ongoing capital expenditure program. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

In Egypt, the Company sold all of its 2011 and 2010 production to one purchaser. In Yemen, the Company sold all of its 2011 and 2010 Block 32 production to one purchaser and all of its 2011 and 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.

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.

To mitigate these risks, the Company raised C$75.0 million (US$75.6 million), before fees and expenses, in a public offering that closed on February 1, 2011. The Company also raised C$97.8 million (US$97.9 million), before fees and expenses, through a public sale of convertible debentures. The amount raised was comprised of an original issuance in the amount of C$85.0 million (US$85.0 million) that closed on February 22, 2012, along with an overallotment option in the amount of C$12.8 million (US$12.9 million) that was exercised by the underwriters and closed on February 29, 2012. The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flows from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs.

Exchange controls may prevent the Company from transferring funds abroad. In Egypt, the Government have imposed monetary and currency exchange control measures that include restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad, with certain exceptions for transfers related to foreign trade and other authorized transactions approved by the country's central bank. The Egyptian central bank may require prior authorization and may or may not grant such authorization for the Company's foreign subsidiaries to make dividend payments to it and there may be a tax imposed with respect to the expatriation of the proceeds from the Company's foreign subsidiaries.

To date, the Company has experienced no difficulties with transferring funds abroad.

The Company’s future success largely depends on its ability to exploit its current reserve base and to find, develop or acquire additional oil reserves that are economically recoverable. Failure to acquire, discover or develop these additional reserves will have an impact on cash flows of the Company.

Third parties operate some of the assets in which TransGlobe has interests. As a result, TransGlobe may have limited ability to exercise influence over the operations of these assets and their associated costs. The success and timing of these activities may be outside of the Company’s control.

To mitigate these operational risks, as part of its capital approval process, the Company applies rigorous geological, geophysical and engineering analysis to each prospect. The Company utilizes its in-house expertise for all international ventures or employs and contracts professionals to handle each aspect of the Company’s business. The Company retains independent reserve evaluators to determine year-end Company reserves and estimated future net revenues.

The Company also mitigates operational risks by maintaining a comprehensive insurance program according to customary industry practice, but cannot fully insure against all risks.

To mitigate environmental risks, the Company conducts its operations to ensure compliance with government regulations and guidelines. Monitoring and reporting programs for environmental health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Security risks are managed through security procedures designed to protect TransGlobe’s personnel and assets. The Company has a “Whistleblower” Protection Policy which protects employees if they raise any concerns regarding TransGlobe’s operations, accounting or internal control matters.

Regulatory and legal risks are identified and monitored by TransGlobe’s corporate team and external legal professionals to ensure that the Company continues to comply with laws and regulations.

TransGlobe operates in countries with political, economic and social systems which subject the Company to a number of risks that are not within the control of the Company. These risks may include, among others, currency restrictions and exchange rate fluctuations, loss of revenue and property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks, increases in taxes and governmental royalties, changes in laws and policies governing operations of foreign-based companies, and economic and legal sanctions and other uncertainties arising from foreign governments.

While the recent civil unrest in Egypt and Yemen has created uncertainty regarding the Company’s political risk, management believes that the Company is well positioned to adapt to this situation due to its increasing production, manageable debt levels, positive cash generation from operations and the availability of cash and cash equivalents. However, if the political issues in Egypt and Yemen continue for an extended period of time, the Company may be forced to reduce its capital spending and participate in fewer wells than anticipated, which will have a negative effect on production volumes and cash flows.

The preparation of financial statements in accordance with IFRS requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. The following is included in the MD&A to aid the reader in assessing the critical accounting policies and practices of the Company. The information will also aid in assessing the likelihood of materially different results being reported depending on management’s assumptions and changes in prevailing conditions which affect the application of these policies and practices. Significant accounting policies are disclosed in Note 3 of the Consolidated Financial Statements.

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

The Company accounts for exploration and evaluation (“E&E”) costs, in accordance with the requirements of IFRS 6: “Exploration for and Evaluation of Mineral Resources.” E&E costs related to each license/prospect are initially capitalized within “intangible exploration and evaluation assets.” Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable expenses, including remuneration of production personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not include pre-licensing costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to earnings as they are incurred.

Tangible assets acquired for use in E&E activities are classified as other assets; however, to the extent that such a tangible asset is consumed in developing an intangible exploration asset, the amount reflecting that consumption is recorded as part of the cost of the intangible exploration and evaluation asset.

Intangible exploration and evaluation assets are not depleted. They are carried forward until technical feasibility and commercial viability of extracting a mineral resource is considered to be determined. The technical feasibility and commercial viability is considered to be determined when proved and/or probable reserves are determined to exist or they can be empirically supported with actual production data or conclusive formation tests. A review of each concession agreement is carried out at least annually. Intangible exploration and evaluation assets are transferred to petroleum properties as development and production (“D&P”) assets upon determination of technical feasibility and commercial viability.

Petroleum properties and other assets are measured at cost less accumulated depletion, depreciation, and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, including qualifying E&E costs on reclassification from intangible exploration and evaluation assets, and for qualifying assets, where applicable, borrowing costs. When significant parts of an item of property and equipment have different useful lives, they are accounted for as separate items.

As at January 1, 2010, the date of transition to IFRS, the cost of petroleum properties and other assets was determined by reference to IFRS 1: “First-time Adoption of International Financial Reporting Standards”. The methodology adopted for initial recognition of these costs at transition was the cost model, whereby all non-petroleum assets and all E&E assets were measured at the amount recognized under the Company’s previous accounting framework, Canadian GAAP, and assets in the development and production phases were measured at the amount determined for the cost centre to which they relate. The adopted process allocated the development and production asset amounts to the underlying assets pro rata based on reserve values as at the date of transition.

Gains and losses on disposal of items of property and equipment are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in earnings immediately.

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum properties or other assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in earnings as incurred. Such capitalized property and equipment generally represent costs incurred in developing Proved and/or Probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis.

The depletion, depreciation and amortization of petroleum properties and other assets, and any eventual reversal thereof, are recognized in earnings.

The net carrying value of D&P assets included in petroleum properties is depleted using the unit of production method by reference to the ratio of production in the year to the related proved and probable reserves using estimated future prices and costs. Costs subject to depletion include estimated future development costs necessary to bring those reserves into production. These estimates are reviewed by independent reserve engineers at least annually.

Proved and probable reserves are estimated using independent reserve evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially viable. The specified degree of certainty must be a minimum 90% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and a minimum 50% statistical probability for proved and probable reserves to be considered commercially viable.

Furniture and fixtures are depreciated at declining balance rates of 20% to 30%, whereas vehicles and leasehold improvements are depreciated on a straight-line basis over their estimated useful lives.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

International operations conducted pursuant to PSAs are reflected in the Consolidated Financial Statements based on the Company’s working interest in such operations. Under the PSAs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSA establishes specific terms for the Company to recover these costs (Cost Recovery Oil) and to share in the production sharing oil. Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each fiscal year. Production sharing oil is that portion of production remaining after Cost Recovery Oil and is shared between the joint venture partners and the government of each country, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company’s share and is recorded net of royalty payments to government and other mineral interest owners. For the Company’s international operations, all government interests, except for income taxes, are considered royalty payments. The Company’s revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.

Non-derivative financial instruments comprise investment in accounts receivable, cash and cash equivalents, restricted cash, loans and borrowings, and accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition non-derivative financial instruments are measured as described below.

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition, such as cash and cash equivalents, and restricted cash. Financial instruments are designated at fair value through profit or loss if the Company makes purchase and sale decisions based on their fair value in accordance with the Company’s documented risk management strategy. Upon initial recognition, any transaction costs attributable to the financial instruments are recognized through earnings when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in earnings.

Other non-derivative financial instruments, such as accounts receivable, loans and borrowings, and accounts payable and accrued liabilities are measured at amortized cost using the effective interest method, less any impairment losses

The Company has entered into certain financial derivative contracts in order to reduce its exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus has not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the balance sheet at fair value. Attributable transaction costs are recognized in earnings when incurred. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.

The Company applies trade-date accounting for the recognition of a purchase of derivative contracts.

In October 2009, the Accounting Standards Board issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accountable enterprises were required to apply IFRS, in full and without modification, for all financial periods beginning on or after January 1, 2011. The adoption of IFRS required the restatement, for comparative purposes, of amounts reported by the Company for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010. The Company’s first annual financial statements prepared under IFRS are the financial statements for the year ended December 31, 2011. These financial statements include reconciliations of the previously disclosed comparative period financial statements prepared in accordance with Canadian GAAP to IFRS, as set out in Note 26.

The following standards and interpretations have not been adopted as they apply to future periods. They may result in changes to the Company’s existing accounting policies and other note disclosures:

In October 2010, the International Accounting Standards Board (“IASB”) issued amendments to IFRS 7 to provide additional disclosure on the transfer of financial assets including the possible effects of any residual risks that the transferring entity retains. These amendments are effective for annual periods beginning after July 1, 2011; therefore, the Company will adopt them for the year ending December 31, 2012. The Company is currently evaluating the impact of these amendments to its Consolidated Financial Statements, but the impact, if any, is not expected to be material.

In November 2009, the IASB issued IFRS 9 as part of its project to replace IAS 39, “Financial Instruments: Recognition and Measurement”. In October 2010, the IASB updated IFRS 9 to include the requirements for financial liabilities. IFRS 9 replaces the multiple rules in IAS 39 with a single approach to determine whether a financial asset is measured at amortized cost or fair value. The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. IFRS 9 is effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the impact of this standard on its Consolidated Financial Statements.

In May 2011, the IASB issued IFRS 10 to replace SIC-12, “Consolidation – Special Purpose Entities”, and parts of IAS 27, “Consolidated and Separate Financial Statements”. IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 is effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the impact of this standard on its Consolidated Financial Statements.

In May 2011, the IASB issued IFRS 11 to replace IAS 31, “Interests in Joint Ventures”, and SIC-13, “Jointly Controlled Entities – Non-monetary Contributions by Venturers”. IFRS 11 requires entities to follow the substance rather than legal form of a joint arrangement and removes the choice of accounting method. IFRS 11 is effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the impact of this standard on its Consolidated Financial Statements, but the impact, if any, is not expected to be material.

In May 2011, the IASB issued IFRS 12, which aggregates and amends disclosure requirements included within other standards. IFRS 12 requires entities to provide disclosures about subsidiaries, joint arrangements, associates and unconsolidated structured entities. IFRS 12 is effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the impact of this standard on its Consolidated Financial Statements.

In May 2011, the IASB issued IFRS 13 to clarify the definition of fair value and provide guidance on determining fair value. IFRS 13 amends disclosure requirements included within other standards and establishes a single framework for fair value measurement and disclosure. IFRS 13 is effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the impact of this standard on its Consolidated Financial Statements.

In June 2011, the IASB issued amendments to IAS 1 to require separate presentation for items of other comprehensive income that would be reclassified to profit or loss in the future from those that would not. These amendments are effective for annual periods beginning on or after July 1, 2012. The Company is currently evaluating the impact of these amendments to its Consolidated Financial Statements.

In December 2010, the IASB issued amendments to IAS 12 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an asset. The amendments introduce a presumption that entities will assess whether the carrying value of an asset will be recovered through the sale of the asset. These amendments are effective for annual periods beginning on or after January 1, 2012. The Company is currently evaluating the impact of these amendments to its Consolidated Financial Statements, but the impact, if any, is not expected to be material.

In June 2011, the IASB issued amendments to IAS 19 to revise certain aspects of the accounting for pension plans and other benefits. The amendments eliminate the corridor method of accounting for defined benefit plans, change the recognition pattern of gains and losses, and require additional disclosures. These amendments are effective for annual periods beginning on or after January 1, 2013. The Company does not expect the impact of this standard on its Consolidated Financial Statements to be material.

In May 2011, the IASB issued amendments to IAS 28 to prescribe the accounting for investments in associates and set out the requirements for applying the equity method when accounting for investments in associates and joint ventures. These amendments are effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the impact of these amendments to its Consolidated Financial Statements, but the impact, if any, is not expected to be material.

As of December 31, 2011, an evaluation was carried out under the supervision, and with the participation, of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, on the effectiveness of the Company’s disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

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 and as defined in Rule 13a-15 under the US Securities Exchange Act of 1934. 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 IFRS, 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.

All changes in accounting policies that were required to address reporting and the adoption of IFRS have been made in consideration of the integrity of internal control over financial reporting and disclosure controls and procedures. Throughout TransGlobe’s transition project, the Company ensured that all changes in accounting policies relating to IFRS had controls and procedures to ensure that information was captured appropriately. With respect to internal controls over financial reporting and disclosure controls and procedures, the Company did not require any material changes in control procedures as a result of the transition to IFRS; however, the Company supplemented its existing control procedures for the transition period by increasing the level of third party consultation, management and executive involvement, monitoring, and governance, as well as the level of awareness and education of key parties involved in the transition project in order to ensure the project was successful.

Management has assessed the effectiveness of the Company’s internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission framework on Internal Control – Integrated Framework. Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective as at December 31, 2011. No changes were made to the Company’s internal control over financial reporting during the year ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

*	Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital, and may not be comparable to measures used by other companies.
**	Debt-to-funds flow ratio is a measure that represents total current and long-term debt over funds flow from operations for the trailing 12 months, and may not be comparable to measures used by other companies.
***	Financial information presented for 2009 has been prepared in accordance with GAAP. This information has not been restated for differences between GAAP and IFRS.

			$Per Share
	$000s		Diluted		% Variance
2010 net earnings	40,565		0.59
Cash items
Volume variance	80,527		1.07		199
Price variance	100,366		1.33		247
Royalties	(90,359	)	(1.21	)	(223	)
Expenses:
Operating	(9,812	)	(0.14	)	(24	)
Realized derivative loss	856		0.01		2
Exploration	(1,230	)	(0.02	)	(3	)
Cash general and administrative	(2,383	)	(0.03	)	(6	)
Current income taxes	(34,210	)	(0.47	)	(84	)
Realized foreign exchange gain	322		-		1
Interest on long-term debt	(1,313	)	(0.02	)	(3	)
Other income	439		0.01		1
Total cash items variance	43,203		0.53		107
Non-cash items
Unrealized derivative loss	(993	)	(0.01	)	(4	)
Unrealized foreign exchange loss	(416	)	(0.01	)	(1	)
Depletion and depreciation	(6,941	)	(0.10	)	(17	)
Gain on acquisition	13,187		0.18		33
Impairment loss	(12,147	)	(0.16	)	(30	)
Stock-based compensation	(702	)	(0.01	)	(2	)
Deferred income taxes	6,339		0.08		16
Deferred lease inducement	(350	)	-		-
Amortization of deferred financing costs	(353	)	-		(1	)
Total non-cash items variance	(2,376	)	(0.03	)	(6	)
2011 net earnings	81,392		1.09		101

	2011	2010
Dated Brent average oil price ($/Bbl)	111.27	79.42
U.S./Canadian Dollar average exchange rate	0.9918	1.0301

	2011	2010
Egypt - Oil sales	10,671	7,259
Yemen - Oil sales	1,461	2,701
Total Company – daily sales volumes	12,132	9,960

	2011		2010
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	449,794	101.58	268,901	73.97
Royalties and other	202,040	45.63	111,681	30.72
Current taxes	74,017	16.71	39,807	10.95
Operating expenses	36,662	8.28	26,850	7.39
Netback	137,075	30.96	90,563	24.91

(000s)	2011		2010
Realized cash gain (loss) on commodity contracts*	(630	)	(1,486	)
Unrealized gain (loss) on commodity contracts**	(177	)	816
Total derivative gain (loss) on commodity contracts	(807	)	(670	)

*	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 year.

			Dated Brent Pricing
Period	Volume	Type	Put
Crude Oil
January 1, 2012 – June 30, 2012	20,000 Bbl/month	Financial Floor	$ 80.00

		2012

Bbls		120,000
Bopd (January 1, 2012 – June 30, 2012)		659

	2011				2010
(000s, except Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	17,946		4.05		14,171		3.90
Stock-based compensation	3,062		0.69		2,360		0.65
Capitalized G&A and overhead recoveries	(2,115	)	(0.48	)	(1,073	)	(0.29	)
G&A (net)	18,893		4.26		15,458		4.26

Proved
($000s, except volumes and $/Bbl amounts)	2011		2010	2009*
Total capital expenditure	70,119		65,342	35,546
Acquisitions	39,497		-	-
Dispositions	-		-	-
Net change from previous year’s future capital	(6,165	)	4,776	1,816
	103,451		70,118	37,362
Reserve additions and revisions (MBbl)
Exploration and development	4,672		4,845	9,921
Acquisitions, net of dispositions	7,448		-	-
Total reserve additions (MBbl)	12,120		4,845	9,921

Average cost per Bbl
F&D	13.45		14.47	3.77
FD&A	8.54		14.47	3.77

Three-year weighted average cost per Bbl
F&D	8.76		8.06	7.40
FD&A	7.85		8.10	9.75

Proved Plus Probable
($000s, except volumes and $/Bbl amounts)	2011		2010	2009*
Total capital expenditure	70,119		65,342	35,546
Acquisitions	39,497		-	-
Dispositions	-		-	-
Net change from previous year’s future capital	(14,256	)	42,546	4,112
	95,360		107,888	39,658
Reserve additions and revisions (MBbl)
Exploration and development	6,612		9,895	7,670
Acquisitions, net of dispositions	11,586		-	-
Total reserve additions (MBbl)	18,198		9,895	7,670

Average cost per Bbl
F&D	7.07		10.90	5.17
FD&A	5.24		10.90	5.17

Three-year weighted average cost per Bbl
F&D	8.04		8.00	7.27
FD&A	6.79		7.83	8.59

Note:	The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
*	Information presented for 2009 has been prepared in accordance with GAAP. This information has not been restated for differences between GAAP and IFRS.

*	Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Bbl of production.
**	Information presented for 2009 has been prepared in accordance with GAAP. This information has not been restated for differences between GAAP and IFRS.

Recycle Netback Calculation
($000s, except volumes and per Bbl amounts)	2011		2010		2009**
Net earnings	81,392		40,565		(8,417	)
Adjustments for non-cash items:
Depletion, depreciation and accretion	35,081		28,140		47,579
Stock-based compensation	3,062		2,360		2,011
Deferred income taxes	(4,445	)	1,894		-
Amortization of deferred financing costs	1,189		836		569
Amortization of deferred lease inducement	350		-		-
Unrealized (gain) loss on commodity contracts	177		(816	)	3,322
Unrealized foreign exchange (gain) loss	416		-		-
Impairment of exploration and evaluation assets	12,147		-		-
Gain on acquisition	(13,187	)	-		-
Recycle netback*	116,182		72,979		45,064
Sales volumes (MBbl)	4,428		3,635		3,278
Recycle netback per Bbl*	26.24		20.07		13.75

Sources and Uses of Cash
($000s)	2011		2010
Cash sourced
Funds flow from operations*	119,976		75,460
Transfer from restricted cash	1,161		-
Increase in long-term debt	-		95,916
Exercise of options	1,946		9,959
Issuance of common shares, net of share issuance costs	71,583		-
Other	772		-
	195,438		181,335
Cash used
Capital expenditures	70,119		65,343
Acquisitions	73,836		-
Repayment of long-term debt	30,000		55,916
Transfer to restricted cash	-		3,387
Deferred financing costs	-		4,216
Interest paid	3,550		2,481
Other	315		-
	177,820		131,343
	17,618		49,992
Changes in non-cash working capital	(31,516	)	(8,387	)
Increase (decrease) in cash and cash equivalents	(13,898	)	41,605
Cash and cash equivalents – beginning of period	57,782		16,177
Cash and cash equivalents – end of period	43,884		57,782

($000s)	December 31, 2011		December 31, 2010
Bank debt	60,000		90,000
Deferred financing costs	(2,391	)	(3,580	)
Long–term debt (net of deferred financing costs)	57,609		86,420

1	Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2	Payments denominated in foreign currencies have been translated at December 31, 2011 exchange rates.
3	Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

Production Forecast
	2012 Guidance	2011 Actual	% Change
Barrels of oil per day	16,000 – 20,000	12,132	32 - 65

Funds Flow Forecast
($millions)
	2012 Guidance	2011 Actual	% Change
Funds Flow from operations	133.0	120.0	11
Brent oil price ($ per bbl)	90.00	111.27	(19	)

2012 Capital Budget
($ million)		2012
Egypt		69.2
Yemen		5.5
Corporate		1.0
Total		75.7