MANAGEMENT'S DISCUSSION AND ANALYSIS

March 5, 2013

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, 2012 and 2011, together with the notes related thereto (the "Consolidated Financial Statements"). The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board 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.

READER ADVISORIES

Forward-Looking Statements

Certain statements or information contained herein may constitute forward-looking statements or information under applicable securities laws, including, but not limited to, management’s assessment of future plans and operations, anticipated increases to the Company's reserves and production, the possible sale of the Company's assets in Yemen, collection of accounts receivable from the Egyptian Government, drilling plans and the timing thereof, commodity price risk management strategies, adapting to the current political situations in Egypt and Yemen, reserve estimates, management’s expectation for results of operations for 2013, including expected 2013 average production, funds flow from operations, the 2013 capital program for exploration and development, the timing and method of financing thereof, method of funding drilling commitments, and commodity prices and expected volatility thereof. Statements relating to "reserves" are deemed to be forward‑looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

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.

2012 1

MANAGEMENT STRATEGY AND OUTLOOK

The 2013 outlook provides information as to management’s expectation for results of operations for 2013. Readers are cautioned that the 2013 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.

2013 Outlook Highlights

• Production is expected to average between 21,000 Bopd and 24,000 Bopd, a 20% to 37% increase over the 2012 average production;

• Exploration and development spending is budgeted to be $129.0 million excluding acquisitions, a 152% increase from 2012, to be funded from funds flow from operations and cash-on-hand; and

• Funds flow from operations is estimated at $161.0 million, representing an increase of 5% from 2012, using mid-point production guidance and an average oil price assumption of $100.00 per barrel Dated Brent oil price.

2013 Updated Production Outlook

Production for 2013 is expected to average between 21,000 and 24,000 Bopd, representing a 20% to 37% increase over the 2012 average production of 17,496 Bopd. The spread in the estimated production is due to a number of variables outside of the Company’s control such as Government approvals relating to the start of South Alamein production, development drilling results in Egypt and the repair of the export pipeline for Block S-1 in Yemen.

Production Forecast
	2013 Guidance	2012 Actual	% Change
Barrels of oil per day	21,000 – 24,000	17,496	20 - 37

2013 Updated Funds Flow From Operations Outlook

Funds flow from operations is estimated at $161.0 million ($2.13/share) based on an annual average Dated Brent oil price of $100/Bbl and using the mid-point of the production guidance. Variations in production and commodity prices during 2013 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 2013 funds flow by approximately $17.0 million or $0.23/share.

Funds Flow Forecast
($ millions)	2013 Guidance	2012 Actual	% Change
Funds Flow from operations	161.0	153.5	5
Brent oil price ($ per bbl)	100.00	111.56	(10	)

2013 Capital Budget
($ millions)	2013
Egypt	124.0
Yemen	5.0
Total	129.0

The 2013 capital program is split 58:42 between development and exploration, respectively. The Company plans to participate in 51 wells in 2013. It is anticipated that the Company will fund its 2013 capital budget from funds flow from operations and working capital.

The Company will begin to explore the possibility of selling its Yemen assets in 2013, since these assets are unlikely to significantly influence the Company's future production and reserves.

Additional 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 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.

2 2012

Reconciliation of Funds Flow from Operations

($000s)	2012	2011
Cash flow from operating activities	93,992	63,630
Changes in non-cash working capital	59,506	56,346
Funds flow from operations*	153,498	119,976
* Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings and Comprehensive Income.     Cash interest paid is reported as a financing activity on the Consolidated Statements of Cash Flows.

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, plus convertible debentures 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’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”).

BUSINESS ACQUISITIONS

On June 7, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of a wholly-owned subsidiary of EP Energy LLC, which holds, through wholly-owned subsidiaries, a non-operated 50% working interest in the South Alamein Production Sharing Concession ("PSC") in Egypt and an operated 60% working interest in the South Mariut PSC in Egypt. The transaction was structured as an all-cash deal, effective April 1, 2012, funded through working capital and the proceeds of the issuance of convertible debentures. Total consideration for the transaction was $22.9 million, which represents an initial $15.0 million base purchase price plus $7.9 million in consumable drilling equipment inventory (which is classified as exploration and evaluation assets), working capital and other closing adjustments.

On July 26, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of Cepsa Egypt SA B.V. (“Cepsa Egypt”), a wholly-owned subsidiary of Compania Espanola De Petroleos, S.A.U. (“Cepsa”). Cepsa Egypt holds an operated 50% working interest in the South Alamein PSC in Egypt. In conjunction with the EP Energy LLC business combination that was completed in the second quarter of 2012, this transaction brought the Company’s working interest in the South Alamein concession to 100%. The transaction was structured as an all-cash deal, effective July 1, 2012, funded through working capital. Total consideration for the transaction was $4.5 million, which represents an initial $3.0 million base purchase price plus $1.5 million in consumable drilling equipment inventory (which is classified as exploration and evaluation assets), working capital and other closing adjustments.

2012 3

SELECTED ANNUAL INFORMATION

($000s, except per share, price and volume	2012	% Change	2011	% Change	2010
amounts)
Operations
Average sales volumes (Bopd)	17,496	44	12,132	22	9,960
Average price ($/Bbl)	99.01	(3)	101.58	37	73.97
Oil and gas sales	633,992	41	449,794	67	268,901
Oil and gas sales, net of royalties	317,666	28	247,754	58	157,220
Cash flow from operating activities	93,992	48	63,630	12	56,969
Funds flow from operations*	153,498	28	119,976	59	75,460
- Basic per share	2.09		1.65		1.14
- Diluted per share	2.03		1.60		1.10
Net earnings	87,734	8	81,392	101	40,565
- Basic per share	1.20		1.12		0.61
- Diluted per share	1.16		1.09		0.59
Total assets	653,425	24	525,806	52	345,625
Cash and cash equivalents	82,974	89	43,884	(24)	57,782
Convertible debentures	98,742	—	—	—	—
Total long-term debt, including current portion	16,885	(71)	57,609	(33)	86,420
Debt-to-funds flow ratio**	0.8		0.5		1.1
Reserves
Total Proved (MMBbl)***	32.8	16	28.2	37	20.5
Total Proved plus Probable (MMBbl)***	48.7	10	44.2	45	30.4
* 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 long-term debt (including the current portion) plus convertible debentures over funds flow from operations for the trailing        12 months, and may not be comparable to measures used by other companies.
*** As determined by the Company's independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports dated January 18, 2013 and January 10, 2012 with effective dates of December 31, 2012 and December 31, 2011, respectively. The reports of DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time.

In 2012 compared with 2011, TransGlobe,

• Increased Proved reserves by 16% to 32.8 MMBbl and Proved plus Probable reserves by 10% to 48.7 MMBbl, representing production replacements of 172% and 170%, respectively, primarily from the development of its operated West Gharib and West Bakr concessions in Egypt;

• Increased total sales volumes by 44%, as a result of a 56% increase in sales volumes from Egypt offset by a 43% decline in sales volumes in Yemen;

• Increased funds flow from operations by 28% primarily due to increased production;

• Increased net earnings to $87.7 million due to an increase in net sales revenue of $69.9 million, which was partially offset by a combined increase of $51.5 million in operating costs, current income taxes, depletion and depreciation expense, general and administrative expenses and finance costs. The increase in finance costs is due to the issuance of the convertible debentures in February 2012, whereas the other increased costs were the result of increased activity due to the Company's growth through the acquisitions completed in 2012, along with the first full year of operations at West Bakr;

• Issued convertible unsecured subordinated debentures with an aggregate principal amount of $97.9 million; and

• Decreased long-term debt by $40.7 million which assisted in maintaining a strong debt-to-funds flow ratio of 0.8 at December 31, 2012 (0.5 at December 31, 2011).

4 2012

2012 TO 2011 NET EARNINGS VARIANCES

			$ Per Share
	$000s		Diluted		% Variance
2011 net earnings	81,392		1.09
Cash items
Volume variance	195,595		2.57		241
Price variance	(11,397	)	(0.15	)	(14	)
Royalties	(114,286	)	(1.52	)	(140	)
Expenses:
Production and operating	(15,705	)	(0.21	)	(19	)
Cash general and administrative	(7,765	)	(0.10	)	(10	)
Exploration	1,193		0.02		1
Current income taxes	(14,586	)	(0.19	)	(18	)
Realized foreign exchange gain (loss)	(142	)	—		—
Realized derivative gain (loss)	630		0.01		1
Issue costs for convertible debentures	(4,630	)	(0.06	)	(6	)
Interest on long-term debt	(4,212	)	(0.06	)	(5	)
Other income	(15	)	—		—
Total cash items variance	24,680		0.31		31
Non-cash items
Unrealized derivative loss	52		—		—
Unrealized foreign exchange loss	557		0.01		1
Depletion and depreciation	(11,865	)	(0.16	)	(15	)
Unrealized loss on financial instruments	(425	)	(0.01	)	(1	)
Gain on acquisition	(13,187	)	(0.17	)	(16	)
Impairment loss	12,071		0.16		15
Stock-based compensation	(1,440	)	(0.02	)	(2	)
Deferred income taxes	(3,917	)	(0.05	)	(5	)
Deferred lease inducement	(108	)	—		—
Amortization of deferred financing costs	(76	)	—		—
Total non-cash items variance	(18,338	)	(0.24	)	(23	)
2012 net earnings	87,734		1.16		8

Net earnings increased to $87.7 million in 2012 compared to $81.4 million in 2011, which was mostly due to a significant increase in production volumes, which was partially offset by higher royalties and income taxes and increases in operating costs, depletion and depreciation expense, general and administrative expenses and finance costs. The increase in finance costs is due to the issuance of the convertible debentures in February 2012, whereas the other increased costs were the result of increased activity due to the Company's growth through the acquisitions completed in 2012, along with the first full year of operations at West Bakr.

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:

	2012	2011
Dated Brent average oil price ($/Bbl)	111.56	111.27
U.S./Canadian Dollar average exchange rate	0.9994	0.9918

The average price of Dated Brent oil was relatively unchanged in 2012 compared with 2011. All of the Company’s production is priced based on Dated Brent and shared with the respective governments through PSCs. When the price of oil increases, 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. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, the Contractor's share of excess ranges between 0% and 30% depending on the contract. In Yemen, the excess is treated as production sharing oil. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost recovery or cost oil ranges from 25% to 30% in Egypt and 50% to 60% in Yemen. The balance of the production after maximum cost recovery is shared with the respective governments (production sharing oil). Depending on the contract, the government receives 70% to 86% of the production sharing oil or profit 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).

2012 5

During the political change in Egypt, business processes and operations have generally proceeded as normal. The Company continues to expand its footprint in Egypt as evidenced by the closing of recent business acquisitions. While exploration and development activities have generally been uninterrupted, the Company has continued to experience delays in the collection of accounts receivable from the Egyptian Government due to the economic impact caused by the instability in the country. The Company is in continual discussions with the Egyptian Government to determine solutions to the delayed cash collections, and expects to recover the accounts receivable balance in full. The Company collected $157.0 million in accounts receivable from the Egyptian Government during 2012, including $76.1 million in the fourth quarter.

SELECTED QUARTERLY FINANCIAL INFORMATION

	2012				2011
($000s, except per share,
price and volume amounts)	Q-4	Q-3	Q-2	Q-1	Q-4	Q-3	Q-2	Q-1
Average sales volumes (Bopd)	19,148	17,124	16,978	16,720	12,054	13,406	11,826	11,218
Average price ($/Bbl)	98.70	96.88	95.84	104.78	99.12	104.00	105.57	97.06
Oil sales	173,864	152,624	148,078	159,426	109,919	128,265	113,615	97,995
Oil sales, net of royalties	92,281	74,540	73,633	77,212	60,609	71,769	62,513	52,863
Cash flow from operating activities	65,250	2,368	24,603	1,771	2,330	3,456	54,354	3,490
Funds flow from operations*	46,839	35,397	35,174	36,088	26,469	37,980	30,597	24,930
Funds flow from operations per share
- Basic	0.63	0.49	0.48	0.49	0.36	0.52	0.42	0.35
- Diluted	0.57	0.47	0.43	0.48	0.35	0.51	0.40	0.34
Net earnings	34,836	11,774	30,149	10,975	30,519	26,110	21,874	2,889
Net earnings - diluted	32,156	11,774	20,821	10,975	30,519	26,110	21,874	2,889
Net earnings per share
- Basic	0.48	0.16	0.41	0.15	0.42	0.36	0.30	0.04
- Diluted	0.39	0.16	0.25	0.15	0.41	0.35	0.29	0.04
Total assets	653,425	635,529	620,937	648,012	525,806	465,262	420,956	404,184
Cash and cash equivalents	82,974	45,732	72,230	127,313	43,884	105,007	122,659	86,353
Convertible debentures	98,742	102,920	95,043	105,835	—	—	—	—
Total long-term debt, including      current portion	16,885	31,878	37,855	57,910	57,609	57,303	56,998	56,731
Debt-to-funds flow ratio**	0.8	1.0	1.0	1.2	0.5	0.5	0.6	0.7
* 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 measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies.

During the fourth quarter of 2012, TransGlobe has:

• Experienced a significant increase in cash flow from operating activities compared with prior quarters due to increased collections on accounts receivable (collected $76.1 million in Egypt and $12.4 million in Yemen in Q4-2012);

• Maintained a strong financial position, reporting a debt-to-funds flow ratio of 0.8 at December 31, 2012;

• Reported net earnings of $34.8 million;

• Achieved record quarterly funds flow from operations of $46.8 million, an increase of 77% from Q4-2011, which was principally due to a 59% increase in sales volumes; and

• Spent $19.8 million on capital programs, which was funded entirely with funds flow from operations.

The accounting for the convertible debentures continued to have a significant impact on important components of the Company's financial statements. The Company reported an increase in net earnings of $23.1 million from the third quarter of 2012, $12.1 million of which was due to:

• The recording of an unrealized gain on convertible debentures of $2.9 million recognized in the fourth quarter of 2012, combined with an unrealized loss of $4.4 million recognized on the convertible debentures in the third quarter of 2012; and

• An earnings increase of $4.8 million from Q3-2012 to Q4-2012 related to foreign exchange on the convertible debentures.

6 2012

OPERATING RESULTS AND NETBACK

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

Sales Volumes

	2012	2011
Egypt	16,656	10,671
Yemen	840	1,461
Total Company	17,496	12,132

Netback

Consolidated
	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	633,992	99.01	449,794	101.58
Royalties	316,326	49.40	202,040	45.63
Current taxes	88,603	13.84	74,017	16.71
Production and operating expenses	52,367	8.18	36,662	8.28
Netback	176,696	27.59	137,075	30.96

Egypt
	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	600,536	98.51	391,884	100.61
Royalties	303,651	49.81	176,033	45.20
Current taxes	84,935	13.93	66,630	17.11
Production and operating expenses	43,247	7.09	27,407	7.04
Netback	168,703	27.68	121,814	31.26

The netback per Bbl in Egypt decreased 11% in 2012 compared with 2011, which is a result of oil prices decreasing by 2% combined with higher royalty and tax rates principally associated with production from West Bakr. In 2012, the average selling price was $13.05/Bbl lower than the average Dated Brent oil price for the year of $111.56/Bbl which is a result of a gravity/quality adjustment as well as a contracted discounted price for West Bakr crude in 2012.

Royalties and taxes as a percentage of revenue increased to 65% in 2012, compared with 62% in 2011. This increase is due to the fact that 2011 included only West Gharib production, whereas 2012 includes West Gharib and West Bakr production. West Bakr production is subject to higher Government take in accordance with the West Bakr PSC and a lower contracted price as compared to West Gharib.

Production and operating expenses on a per Bbl basis remained consistent in 2012 compared with 2011.

Yemen
	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Oil sales	33,456	108.82	57,910	108.60
Royalties	12,675	41.23	26,007	48.77
Current taxes	3,668	11.93	7,387	13.85
Production and operating expenses	9,120	29.66	9,255	17.36
Netback	7,993	26.00	15,261	28.62

In Yemen, the Company experienced a 9% netback reduction on a per Bbl basis in 2012 compared with 2011. Operating expenses on a per Bbl basis increased substantially (71%) in 2012 compared to 2011 as a result of production being shut-in on Block S-1 from the beginning of the year until July 27, 2012, and again from November 11, 2012 to the end of the year. While production volumes were down, the Company continued to incur the majority of the operating costs on Block S-1 which significantly increased operating expenses per Bbl.

Partially offsetting the increased operating expenses per Bbl was a decrease of 15% in royalties and taxes on a per Bbl basis. The Block S-1 operating costs incurred during the shut-in period from the beginning of 2012 through to July 27, 2012 accumulated in cost recovery pools, which allowed the Company to achieve full cost recovery in accordance with the PSC during the time that Block S-1 was producing in the year. Cost recovery is paid out through a reduction of Government take, which has resulted in a decrease in royalties and taxes on a per Bbl basis in 2012 compared to 2011.

2012 7

DERIVATIVE COMMODITY CONTRACTS

TransGlobe uses hedging arrangements from time to time 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.

As there are no outstanding derivative commodity contracts at December 31, 2012, no assets or liabilities have been recognized on the Consolidated Balance Sheet for the current year. As at December 31, 2012, no production is hedged in future periods.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	2012				2011
(000s, except Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	27,545		4.30		17,946		4.05
Stock-based compensation	4,502		0.70		3,062		0.69
Capitalized G&A and overhead recoveries	(3,841	)	(0.60	)	(2,115	)	(0.48	)
G&A (net)	28,206		4.40		18,893		4.26

G&A expenses (net) increased 49% (3% on a per Bbl basis) in 2012 compared with 2011. The increase is principally due to increased staffing, administration and insurance costs associated with West Bakr, along with increased costs associated with acquisitions completed in 2012 (South Alamein and South Mariut).

The increase in stock-based compensation is due partly to an increase in the total value of new options granted during 2012 as compared to those granted during 2011, combined with an increase in the number of options granted and the expense recorded on share appreciation rights in 2012 compared with 2011.

FINANCE COSTS

Finance costs for the year ended December 31, 2012 increased to $13.9 million compared with $5.0 million in 2011. Finance costs include interest on long-term debt and convertible debentures, issue costs on convertible debentures and amortization of transaction costs associated with long-term debt. The overall increase in finance costs is due to higher debt levels associated with the convertible debentures combined with the costs of issuing the convertible debentures.

(000s)	2012		2011
Interest expense	$	8,006	$	3,794
Issue costs for convertible debentures	4,630		—
Amortization of deferred financing costs	1,265		1,189
Finance costs	$	13,901	$	4,983

The Company had $18.5 million ($16.9 million net of unamortized deferred financing costs) of long-term debt outstanding at December 31, 2012 (December 31, 2011 - $60.0 million). The long-term debt that was outstanding at December 31, 2012 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 sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. Transaction costs of $4.6 million relating to the issuance of the convertible debentures were expensed in the year ended December 31, 2012. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$15.10 per common share. The debentures are not redeemable by the Company on or before March 31, 2015 other than in limited circumstances in connection with a change of control of TransGlobe. 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 (or C$18.88 per common share). Interest of 6% is payable semi-annually in arrears on March 31 and September 30. The first semi-annual interest payment was made on September 30, 2012 which included 39 days prior to March 31, 2012. At maturity or redemption, 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.

8 2012

DEPLETION AND DEPRECIATION (“DD&A”)

	2012		2011
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	44,442	7.29	31,035	7.97
Yemen	2,095	6.81	3,585	6.72
Corporate	409	—	461	—
	46,946	7.33	35,081	7.92

In Egypt, DD&A decreased 9% on a per Bbl basis in the year ended December 31, 2012 compared to 2011. This decrease is mostly due to proved plus probable reserve additions during the third and fourth quarters of 2012.

In Yemen, DD&A increased 1% on a per Bbl basis in the year ended December 31, 2012 compared to 2011. This increase is mostly due to a smaller reserve base over which capital costs are being depleted compared to 2011.

CAPITAL EXPENDITURES

($000s)	2012	2011
Egypt	50,220	63,177
Yemen	1,239	5,495
Acquisitions	27,259	74,814
Corporate	192	1,447
Total	78,910	144,933

In Egypt, total capital expenditures in 2012 were $50.2 million (2011 - $63.2 million). During 2012, the Company drilled 24 wells in West Gharib (13 at Arta, seven at East Arta, three at Hoshia and one at Fadl). The Company also drilled seven wells at West Bakr and two wells at East Ghazalat. Production was constrained at West Gharib during 2012 due to volume constraints at the processing facility. As a result, the capital cost per well drilled at West Gharib was lower in 2012 as the Company chose not to proceed with the completion and equipping of some of the new wells. The wells are scheduled for completion in 2013, now that some of the production constraints have been removed.

On June 7, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of a wholly-owned subsidiary of EP Energy LLC which holds, through wholly-owned subsidiaries, a non-operated 50% interest in the South Alamein PSC in Egypt and an operated 60% working interest in the South Mariut PSC in Egypt. The transaction was structured as an all-cash deal, effective April 1, 2012, funded through working capital and the proceeds of the issuance of convertible debentures. Total consideration for the transaction was $22.9 million, which represents a $15.0 million base purchase price plus $7.9 million in working capital and other closing adjustments.

On July 26, 2012, the Company closed a Share Purchase Agreement to acquire 100% of the common shares of Cepsa Egypt, a wholly-owned subsidiary of Cepsa. Cepsa Egypt holds an operated 50% working interest in the South Alamein PSC in Egypt. As a result, the Company now holds a 100% working interest in the South Alamein concession through two wholly-owned subsidiaries. The Cepsa transaction was structured as an all-cash deal, effective July 1, 2012, funded through working capital. Total consideration for the transaction was $4.5 million, which represents a $3.0 million base purchase price plus $1.5 million in consumable drilling inventory (which is classified as exploration and evaluation assets), working capital and other closing adjustments.

2012 9

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

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.

Proved
($000s, except volumes and $/Bbl amounts)	2012		2011		2010
Total capital expenditure	51,651		70,119		65,342
Acquisitions	27,305		39,497		—
Dispositions	—		—		—
Net change from previous year’s future capital	(4,706	)	(6,165	)	4,776
	74,250		103,451		70,118
Reserve additions and revisions (MBbl)
Exploration and development	10,999		4,672		4,845
Acquisitions, net of dispositions	—		7,448		—
Total reserve additions (MBbl)	10,999		12,120		4,845
Average cost per Bbl
F&D	4.27		13.45		14.47
FD&A	6.75		8.54		14.47
Three-year weighted average cost per Bbl
F&D	8.77		8.76		8.06
FD&A	8.86		7.85		8.10
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.

Proved Plus Probable
($000s, except volumes and $/Bbl amounts)	2012	2011		2010
Total capital expenditure	51,651	70,119		65,342
Acquisitions	27,305	39,497		—
Dispositions	—	—		—
Net change from previous year’s future capital	1,191	(14,256	)	42,546
	80,147	95,360		107,888
Reserve additions and revisions (MBbl)
Exploration and development	10,888	6,612		9,895
Acquisitions, net of dispositions	—	11,586		—
Total reserve additions (MBbl)	10,888	18,198		9,895
Average cost per Bbl
F&D	4.46	7.07		10.90
FD&A	7.36	5.24		10.90
Three-year weighted average cost per Bbl
F&D	7.42	8.04		8.00
FD&A	7.27	6.79		7.83
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.

RECYCLE RATIO

	Three-Year
Proved	Weighted
	Average	2012	2011	2010
Netback ($/Bbl)*	22.85	22.08	26.24	20.07
Proved F&D costs ($/Bbl)	8.77	4.27	13.45	14.47
Proved FD&A costs ($/Bbl)	8.86	6.75	8.54	14.47
F&D Recycle ratio	2.61	5.17	1.95	1.39
FD&A Recycle ratio	2.58	3.27	3.07	1.39
* 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.

10 2012

	Three-Year
Proved Plus Probable	Weighted
	Average	2012	2011	2010
Netback ($/Bbl)*	22.85	22.08	26.24	20.07
Proved plus Probable F&D costs ($/Bbl)	7.42	4.46	7.07	10.90
Proved plus Probable FD&A costs ($/Bbl)	7.27	7.36	5.24	10.90
F&D Recycle ratio	3.08	4.95	3.71	1.84
FD&A Recycle ratio	3.14	3.00	5.01	1.84
* Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, G&A (excluding non-cash items), realized foreign exchange (gain) loss, cash finance costs and current income tax expense per Bbl of production.

The recycle ratio variances between 2012 and 2011 are driven primarily by changes in F&D and FD&A costs on a per Bbl basis, combined with a reduction in netback per Bbl. In 2011, FD&A costs per Bbl were less than F&D costs per Bbl as a result of the West Bakr acquisition, which added reserves at a cost of $5.47/Bbl on a Proved basis and $4.20/Bbl on a Proved plus Probable basis including future capital costs. The Company completed two acquisitions during 2012, neither of which contributed reserves on a Proved or Proved plus Probable basis. As such, FD&A costs per Bbl are higher than F&D costs per Bbl in 2012.

Due to the nature of international projects, the Company considers the three-year weighted average recycle ratios to provide a more useful measure of the Company's ability to successfully add reserves on an economic basis. 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.

Recycle Netback Calculation
($000s, except volumes and per Bbl amounts)	2012		2011		2010
Net earnings	87,734		81,392		40,565
Adjustments for non-cash items:
Depletion, depreciation and amortization	46,946		35,081		28,140
Stock-based compensation	4,502		3,062		2,360
Deferred income taxes	(528	)	(4,445	)	1,894
Amortization of deferred financing costs	1,265		1,189		836
Amortization of deferred lease inducement	458		350		—
Unrealized (gain) loss on commodity contracts	125		177		(816	)
Unrealized foreign exchange (gain) loss	(141	)	416		—
Unrealized (gain) loss on financial instruments	425		—		—
Impairment of exploration and evaluation assets	76		12,147		—
Gain on acquisition	—		(13,187	)	—
Recycle netback*	140,862		116,182		72,979
Sales volumes (MBbl)	6,380		4,428		3,635
Recycle netback per Bbl*	22.08		26.24		20.07
* 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.

OUTSTANDING SHARE DATA

As at December 31, 2012, the Company had 73,793,638 common shares issued and outstanding and 5,110,001 options issued and outstanding, which are exercisable in accordance with their terms into a maximum of 5,110,001 common shares of the Company.

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 operations (calculated on a 12-month trailing basis). TransGlobe’s debt-to-funds flow from operations ratio, a key short-term leverage measure, remained strong at 0.8 times at December 31, 2012 (December 31, 2011 - 0.5). This was within the Company’s target range of no more than 2.0 times.

2012 11

The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2012 and 2011:

Sources and Uses of Cash
($000s)	2012		2011
Cash sourced
Funds flow from operations*	153,498		119,976
Transfer from restricted cash	1,445		1,161
Issue of convertible debentures	97,851		—
Exercise of options	3,333		1,946
Issuance of common shares, net of share issuance costs	—		71,583
Other	639		772
	256,766		195,438
Cash used
Capital expenditures	51,651		70,118
Deferred financing costs	440		—
Acquisitions	27,259		73,836
Repayment of long-term debt	41,550		30,000
Finance costs	11,367		3,550
Other	592		315
	132,859		177,819
	123,907		17,619
Changes in non-cash working capital	(84,817	)	(31,517	)
Increase (decrease) in cash and cash equivalents	39,090		(13,898	)
Cash and cash equivalents – beginning of year	43,884		57,782
Cash and cash equivalents – end of year	82,974		43,884
* 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.

Funding for the Company’s capital expenditures was provided by funds flow from operations. The Company funded its 2012 exploration and development program of $51.4 million and contractual commitments through the use of working capital and cash generated by operating activities. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks including timely collections of accounts receivable from the Egyptian Government may impact capital resources.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2012, the Company had working capital of $262.2 million (December 31, 2011 - $140.0 million). The increase to working capital in 2012 is due almost entirely to increases in accounts receivable and cash, combined with a decrease in accounts payable. The majority of the Company’s accounts receivable are due from Egyptian General Petroleum Company ("EGPC"), and the recent political changes in the country have increased the Company’s credit risk. The Company is in continual discussions with EGPC and the Egyptian Government to determine solutions to the delayed cash collections, and expects to recover the entire accounts receivable balance in full. During the fourth quarter of 2012, collections of accounts receivable outpaced billings, resulting in a decrease in accounts receivable from Q3-2012 to Q4-2012 of $22.5 million. Subsequent to December 31, 2012, the Company collected $40.5 million of the receivables that were outstanding in Egypt at year end.

In February 2012, the Company sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. Transaction costs of $4.6 million relating to the issuance of the convertible debentures were expensed during the year ended December 31, 2012. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$15.10 per common share. The debentures are not redeemable by the Company on or before March 31, 2015 other than in limited circumstances in connection with a change of control of TransGlobe. 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 (or C$18.88 per common share). Interest of 6% is payable semi-annually in arrears on March 31 and September 30. The first semi-annual interest payment was made on September 30, 2012 which includes 39 days prior to March 31, 2012. At maturity or redemption, 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.

At December 31, 2012, TransGlobe had $71.0 million available under a Borrowing Base Facility of which $18.5 million was drawn. As repayments on the Borrowing Base Facility are not expected to commence until 2014, the entire balance is presented as a long-term liability on the Consolidated Balance Sheets. Repayments will be made as required according to the scheduled reduction of the facility.

($000s)	December 31, 2012		December 31, 2011
Bank debt	18,450		60,000
Deferred financing costs	(1,565	)	(2,391	)
Long–term debt (net of deferred financing costs)	16,885		57,609

12 2012

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 Period 1 2
	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	48,587	48,587	—	—	—
Long-term debt	Yes - Liability	18,450	—	18,450	—	—
Convertible debentures	Yes - Liability	98,742	—	—	98,742	—
Office and equipment leases 3	No	14,728	6,819	2,324	2,072	3,513
Minimum work commitments 4	No	4,350	4,350	—	—	—
Total		184,857	59,756	20,774	100,814	3,513
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, 2012 exchange rates.
3 Office and equipment leases includes all drilling rig contracts.
4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

Pursuant to the PSC for Block 75 in Yemen, the Contractor (Joint Interest Partners) has a remaining minimum financial commitment of $3.0 million ($0.8 million to TransGlobe) for one exploration well in the first exploration period, which has been extended to March 9, 2014.

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. Based on the Company's annual Reserve Report effective December 31, 2012, no additional fees are due in 2013.

Pursuant to the June 7, 2012 share purchase agreement for a 60% operated interest in the South Mariut concession in Egypt, the Contractor (Joint Interest Partners) has a minimum financial commitment of $9.0 million ($5.4 million to TransGlobe) for three exploration wells ($3.0 million each) which were commitments from the original exploration period and were carried into the first three-year extension period, which expires on April 5, 2013. The Company issued three $3.0 million letters of credit to guarantee performance under this extension period and finished drilling the first of three planned wells subsequent to December 31, 2012 which has reduced the letters of credit to $6.0 million ($3.6 million to TransGlobe). There is a further two-year extension available under the terms of the PSC.

Pursuant to the June 7, 2012 and July 26, 2012 share purchase agreements for a combined 100% operated interest in the South Alamein PSC in Egypt, the Company has a commitment to drill one well (all financial commitments have been met) prior to the termination of the final two-year extension period, which expires on April 5, 2014.

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, 2012.

OFF BALANCE SHEET ARRANGEMENTS

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, 2012.

RISKS

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

• Financial risks including market risks (such as commodity price, foreign exchange and interest rates), credit risks and liquidity risks;

• Operational risks including capital, operating and reserves replacement risks;

• Safety, environmental and regulatory risks; and

• Political risks.

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:

2012 13

Financial Risk

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$97.9 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 over-allotment 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 ongoing 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 2013 capital budget and the Company’s long-term plans. The Company has designed its 2013 budget to be flexible allowing spending to be adjusted for any unforeseen events and changes in commodity prices.

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.

Commodity price risk

The Company’s operational results and financial condition are dependent on the commodity prices received for its oil production.

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 uses financial derivative contracts from time to time as deemed necessary 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, convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars and Egyptian pounds. 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 a decrease in the net earnings for the year ended December 31, 2012 of approximately $10.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would increase net earnings by $8.3 million for the same period. The Company does not utilize derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds on an expedited basis, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2012 was $3.7 million in equivalent U.S. dollars.

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 2012 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 $0.5 million for the year ended December 31, 2012. The effect of interest rates decreasing by 1% would increase the Company’s net earnings by $0.5 million for year ended December 31, 2012.

Credit Risk

Credit risk is the risk of loss if 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 is and may in the future be exposed to third-party credit risk through its contractual arrangements with its current or future joint interest 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. Despite these factors, the Company 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.

14 2012

In Egypt, the Company sold all of its 2012 and 2011 production to one purchaser. In Yemen, the Company sold all of its 2012 Block 32 production to one purchaser, and all of its 2011 Block 32 production to another purchaser. Block S-1 production was sold to one purchaser in 2012 and 2011. Management considers such transactions normal for the Company and the international oil industry in which it operates.

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.

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 in February 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.

Although the Company's Egyptian PSCs clearly state that the Company may transfer funds out of Egypt at its discretion, there is no certainty that in the future exchange controls will not be implemented that would prevent the Company from transferring funds abroad. In Egypt, the Government has 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 the Company 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.

Operational Risk

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.

Safety, Environmental and Regulatory Risk

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.

Political Risk

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, 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 including drilling and/or completing fewer wells than anticipated, which will have a negative effect on current and future production volumes and cash flows.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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.

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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.

Oil and Gas Reserves

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.

Property and equipment and intangible exploration and evaluation assets

Recognition and measurement

Exploration and evaluation ("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 incurred and presented as exploration expenses on the Consolidated Statements of Earnings and Comprehensive Income.

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 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 cash generating unit 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.

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.

Subsequent costs

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 carrying amount of any replaced or sold component is derecognized.

Depletion, depreciation and amortization

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.

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Production Sharing Concessions

International operations conducted pursuant to PSCs are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSCs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSC 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 interest 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.

Financial Instruments

Non-derivative financial instruments

Non-derivative financial instruments comprise investment in cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, convertible debentures payable and long-term debt. 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.

Financial assets at fair value through profit or loss

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 convertible debentures payable. 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

Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities, and long-term debt are measured initially at fair value, then at amortized cost using the effective interest method, less any impairment losses.

Derivative financial instruments

The Company enters into certain financial derivative contracts from time to time 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 does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, the Company's policy is to classify all financial derivative contracts as at fair value through profit or loss and to record on the Consolidated 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 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.

CHANGES IN ACCOUNTING POLICIES

New accounting policies

IFRS 7 (revised) "Financial Instruments: 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. In December 2011, the IASB issued further amendments to IFRS 7 to provide additional disclosures about offsetting financial assets and financial liabilities on the entity's balance sheet when permitted. These amendments are effective for annual periods beginning on or after January 1, 2013. The Company has adopted these amendments for the year ended December 31, 2012. These amendments had no material impact to the Consolidated Financial Statements.

IAS 12 (revised) “Income Taxes”

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; therefore, the Company has adopted them for the year ended December 31, 2012. These amendments had no material impact on the Consolidated Financial Statements.

Future changes to accounting policies

As at the date of authorization of the Consolidated Financial Statements the following Standards and Interpretations which have not yet been applied in the Consolidated Financial Statements have been issued but are not yet effective:

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IFRS 9 (revised) "Financial Instruments: Classification and Measurement"

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, 2015. The Company is currently evaluating the impact of this standard on its Consolidated Financial Statements.

IFRS 10 (new) "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 does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IFRS 11 (new) "Joint Arrangements"

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 does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IFRS 12 (new) "Disclosure of Interests in Other Entities"

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 does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IFRS 13 (new) "Fair Value Measurement"

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 does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IAS 1 (revised) “Presentation of 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 does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IAS 19 (revised) “Employee Benefits”

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.

IAS 28 (revised) “Investments in Associates and Joint Ventures”

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 does not expect the impact of this standard on its Consolidated Financial Statements to be material.

IAS 32 (revised) “Financial Instruments: Presentation”

In December 2011, the IASB issued amendments to IAS 32 to address inconsistencies when applying the offsetting criteria. These amendments clarify some of the criteria required to be met in order to permit the offsetting of financial assets and financial liabilities. These amendments are effective for annual periods beginning on or after January 1, 2014. The Company is currently evaluating the impact of these amendments to its Consolidated Financial Statements.

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2012, 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 all information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

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INTERNAL CONTROLS OVER FINANCIALREPORTING

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.

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, 2012. No changes were made to the Company's internal control over financial reporting during the year ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

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