EXHIBIT 99.1

TRANSGLOBE ENERGY CORPORATION

ANNUAL INFORMATION FORM

Year Ended December 31, 2014

March 11, 2015

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TABLE OF CONTENTS

	Page
CURRENCY AND EXCHANGE RATES	2
ABBREVIATIONS	2
CONVERSIONS	3
FORWARD-LOOKING STATEMENTS	3
ADDITIONAL MEASURES	4
CERTAIN DEFINITIONS	5
TRANSGLOBE ENERGY CORPORATION	7
GENERAL DEVELOPMENT OF THE BUSINESS	8
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES	9
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	14
DIVIDEND POLICY	31
DESCRIPTION OF CAPITAL STRUCTURE	31
MARKET FOR SECURITIES	35
PRIOR SALES	36
ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER	37
DIRECTORS AND OFFICERS	37
INTERESTS OF EXPERTS	39
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	39
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	40
TRANSFER AGENT AND REGISTRAR	40
MATERIAL CONTRACTS	40
AUDIT COMMITTEE INFORMATION	40
RISK FACTORS	42
ADDITIONAL INFORMATION	51

SCHEDULE "A"	Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor
SCHEDULE "B"	Report of Management and Directors on Oil and Gas Disclosure
SCHEDULE "C"	Charter of Audit Committee

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TRANSGLOBE ENERGY CORPORATION

ANNUAL INFORMATION FORM

Year Ended December 31, 2014

March 11, 2015

CURRENCY AND EXCHANGE RATES

All dollar amounts in this Annual Information Form, unless otherwise indicated, are stated in United States ("U.S.") currency. TransGlobe Energy Corporation ("TransGlobe" or the "Company") has adopted the U.S. dollar as the functional currency for its consolidated financial statements. The exchange rates for the average of the daily noon buying rates during the period and the end of period noon buying rate for the U.S. dollar in terms of Canadian dollars as reported by the Bank of Canada were as follows for each of the years ended December 31, 2014, 2013 and 2012.

	Year Ended December 31, 2014	Year Ended December 31, 2013	Year Ended December 31, 2012
End of Period	Cdn$1.1601	Cdn$1.0636	Cdn$0.9949
Period Average	Cdn$1.1048	Cdn$1.0299	Cdn$0.9996

ABBREVIATIONS

Oil and Natural Gas Liquids		Natural Gas
Bbl	Barrel	Mcf	thousand cubic feet
Bbls	Barrels	MMcf	million cubic feet
Mbbls	thousand barrels	Mcf/d	thousand cubic feet per day
MMbbls	million barrels	MMcf/d	million cubic feet per day
Mstb	1,000 stock tank barrels	MMBtu	million British Thermal Units
Bbls/d	barrels per day	Bcf	billion cubic feet
Bopd or bopd	barrels of oil per day	Tcf	trillion cubic feet
Mbopd	thousand barrels of oil per day	GJ	gigajoule
NGLs	natural gas liquids
STB	stock tank barrels
Other
km2	square kilometres
m3	cubic metres
$M	thousands of dollars
$MM	millions of dollars
Brent	Brent Crude Oil
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade
psi	pounds per square inch

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CONVERSIONS

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By
Mcf	cubic metres	0.28174
cubic metres	cubic feet	35.494
Bbls	cubic metres	0.159
cubic metres	Bbls oil	6.293
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.405
hectares	acres	2.471
gigajoules	MMBtu	0.950

FORWARD-LOOKING STATEMENTS

This annual information form (the "Annual Information Form") may include certain statements deemed to be "forward-looking statements" within the meaning of applicable Canadian and United States securities laws. These statements relate to future events or the Company's future performance. All statements other than statements of historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "may", "will", "should", "expect", "plan", "anticipate", "continue", "believe", "estimate", "predict", "project", "potential", "targeting", "intend", "could", "might", "continue", "should" or the negative of these terms or other comparable terminology. These statements are only predictions. In addition, this Annual Information Form may contain forward-looking statements attributed to third-party industry sources. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this Annual Information Form should not be unduly relied upon.

Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur and may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Forward-looking statements in this Annual Information Form include, but are not limited to, statements with respect to:

• the performance characteristics of the Company's oil properties;

• oil production levels;

• the quantity of oil reserves;

• capital expenditure programs;

• supply and demand for oil and commodity prices;

• drilling plans;

• expectations regarding the Company's ability to raise capital and to continually add to reserves though acquisitions, exploration and development;

• estimated funds from operations for 2015;

• estimated timing of development of undeveloped reserves;

• future abandonment and reclamation costs;

• anticipated average production for 2015;

• expected exploration and development spending and the funding thereof;

• treatment under governmental regulatory regimes and tax laws;

• realization of the anticipated benefits of acquisitions and dispositions;

• tax horizon;

• adverse technical factors associated with exploration, development, production, transportation or marketing of crude oil reserves; and

• changes or disruptions in the political or fiscal regimes in the Company's areas of activity.

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that some or all of the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this Annual Information Form and certain documents incorporated by reference herein are expressly qualified by this cautionary statement.

Although the forward-looking statements contained in this Annual Information Form are based upon assumptions which management of the Company believes to be reasonable, the Company cannot assure investors that actual results will be consistent with these forward-looking statements. With respect to forward-looking statements contained in this Annual Information Form, the Company has made assumptions regarding: current commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; royalty rates; future operating costs; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company's conduct and results of operations will be consistent with its expectations; that the Company will have the ability to develop the Company's oil properties in the manner currently contemplated;

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current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; the estimates of the Company's reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; and other matters.

Actual operational and financial results may differ materially from TransGlobe's expectations contained in the forward-looking statements as a result of various risk factors, many of which are beyond the control of the Company. These risk factors include, but are not limited to:

• unforeseen changes in the rate of production from the Company's oil fields;

• changes or disruptions in the political or fiscal regimes in the Company's areas of activity;

• changes in the price of crude oil;

• exposure to third party credit risk due to the significant receivable due from EGPC;

• general economic conditions in Canada, the United States, Egypt, Yemen and globally;

• general economic stability of the Company’s financial lenders and creditors;

• payment of crude oil marketing contracts and associated financial hedging instruments;

• adverse technical factors associated with exploration, development, production, transportation or marketing of the Company's crude oil reserves;

• changes in Egypt or Yemen tax, energy or other laws or regulations;

• geopolitical risks associated with the Company's operations in Egypt and Yemen;

• changes in significant capital expenditures;

• delays in production starting up due to an industry shortage of skilled manpower, equipment or materials;

• the cost of inflation;

• the performance characteristics of the Company's oil properties;

• oil production levels;

• the quantity of oil reserves;

• capital expenditure programs;

• supply and demand for oil and commodity prices;

• drilling plans;

• expectations regarding the Company's ability to raise capital and to continually add to reserves through acquisitions, exploration and development;

• treatment under governmental regulatory regimes and tax laws;

• realization of the anticipated benefits of acquisitions and dispositions;

• industry conditions, including fluctuations in the price of oil;

• governmental regulation of the oil and gas industry, including environmental regulation;

• fluctuation in foreign exchange or interest rates;

• risks inherent in oil and natural gas operations;

• geological, technical, drilling and processing problems;

• unanticipated operating events which can reduce production or cause production to be shut-in or delayed;

• failure to obtain industry partner and other third-party consents and approvals, when required;

• stock market volatility and market valuations;

• competition for, among other things, capital, acquisitions of reserves, undeveloped land and skilled personnel;

• incorrect assessments of the value of acquisitions;

• the need to obtain required approvals from regulatory authorities; and

• the other factors considered under "Risk Factors" in this Annual Information Form.

Forward-looking statements and other information contained herein concerning the oil and natural gas industry in the countries in which it operates and the Company's general expectations concerning this industry are based on estimates prepared by management of the Company using data from publicly available industry sources as well as from resource reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which the Company believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While the Company is not aware of any material misstatements regarding any industry data presented herein, the oil and natural gas industry involves numerous risks and uncertainties and is subject to change based on various factors.

The Company has included the above summary of assumptions and risks related to forward-looking information provided in this Annual Information Form in order to provide shareholders with a more complete perspective on the Company's current and future operations and such information may not be appropriate for other purposes. The Company believes that the expectations reflected in the forward-looking statements contained in this Annual Information Form are reasonable, but no assurance can be given that these expectations will prove to be correct, and investors should not attribute undue certainty to, or place undue reliance on, such forward-looking statements. Such statements speak only as of the date of this Annual Information Form. If circumstances or management’s beliefs, expectations or opinions should change, the Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable Canadian and United States securities laws. Please consult the Company's SEDAR profile at www.sedar.com for further, more detailed information concerning these matters.

ADDITIONAL MEASURES

Funds Flow from Operations

This Annual Information Form 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 does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies.

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Reconciliation of Funds Flow from Operations

($000s)	2014		2013
Cash flow from operating activities	146,977		199,508
Changes in non-cash working capital	(26,488	)	(60,390	)
Funds flow from operations*	120,489		139,118
* Funds flow from operations does not include interest or financing costs. Interest expense is included in financing costs on the Company's Consolidated Statements of Earnings and     Comprehensive Income. Cash interest paid is reported as a financing activity on the Company's Consolidated Statements of Cash Flows.

CERTAIN DEFINITIONS

In this Annual Information Form, the following words and phrases have the following meanings, unless the context otherwise requires:

"ABCA" means the Business Corporations Act, R.S.A. 2000, c. B 9, as amended, including the regulations promulgated thereunder;

"Brent" means the reference price paid in U.S. dollars for a barrel of light sweet crude oil produced from the Brent field in the UK sector of the North Sea;

"Business Day" means a day, other than a Saturday or Sunday, or a statutory holiday, on which major Canadian chartered banks are open for business in Calgary, Alberta;

"Cdn" means Canadian;

"Change of Control" has the meaning attributed thereto under "Description of Capital Structure - Debentures - Repurchase upon a Change of Control";

"COGE Handbook" means 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;

"Common Shares" means the common shares of the Company;

"Contingent Resource Report" means the report of DeGolyer dated February 23, 2015 evaluating the contingent resources of the Company as at December 31, 2014;

"Conversion Date" means the date on which a Debenture is surrendered for conversion when the register of the Debenture Trustee is open and in accordance with the provisions of the Indenture;

"Conversion Price" means Cdn$14.45 per Common Share, subject to adjustment in accordance with the Indenture;

"CSA 51-324" means CSA Staff Notice 51-324 (Revised) Standards of Disclosure For Oil And Gas Activities of the Canadian Securities Administrators;

"Current Market Price" means, on any day, the volume weighted average trading price of the Common Shares on the TSX (or such other recognized stock exchange) for the 20 consecutive trading days ending on the fifth trading day preceding such date;

"Debenture Offer" has the meaning attributed thereto under "Description of Capital Structure - Debentures - Repurchase Upon a Change of Control";

"Debenture Trustee" means Olympia Trust Company;

"Debentures" means the Cdn$97,750,000 aggregate principal amount of 6.00% convertible unsecured subordinated debentures due on the Maturity Date;

"DeGolyer" means DeGolyer and MacNaughton Canada Limited, independent petroleum consultants;

"DeGolyer Report" means the report of DeGolyer dated January 30, 2015 evaluating the Egypt crude oil reserves of the Company as at December 31, 2014;

"Dry Hole" or "Dry Well" or "Non-Productive Well" means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well;

"East Ghazalat" means the East Ghazalat Concession area in Egypt;

"Exploratory Well" means a well drilled either in search of a new, as-yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir;

"Egypt" means the Arab Republic of Egypt;

"Event of Default" has the meaning attributed thereto under "Description of Capital Structure - Debentures - Events of Default";

"Gross" or "gross" means:

(a) in relation to the Company's interest in production and reserves, its "Company gross reserves", which are the Company's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company;

(b) in relation to wells, the total number of wells in which the Company has an interest; and

(c) in relation to properties, the total area of properties in which the Company has an interest;

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"IFRS" means International Financial Reporting Standards as issued by the International Accounting Standards Board;

"Indenture" means the amended and restated convertible debenture indenture dated February 22, 2012 between the Company and the Debenture Trustee under which the Debentures were issued;

"Interest Obligation" means the Company's obligation to pay interest on the Debentures in accordance with the Indenture;

"Interest Payment Date" means the date interest is paid on the Debentures, being March 31 and September 30 in each year;

"Maturity Date" means March 31, 2017;

"NASDAQ" means National Association of Securities Dealers Automated Quotations, OMX Global Select Market;

"Net" or "net" means:

(a) in relation to the Company's interest in production and reserves, the Company's working interest (operating and non-operating) share after deduction of royalty obligations, plus the Company's royalty interest in production or reserves;

(b) in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and

(c) in relation to the Company's interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company;

"NGLs" means natural gas liquids;

"NI 51-101" means National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities;

"NI 51-102" means National Instrument 51-102 - Continuous Disclosure Obligations;

"NW Gharib" means the North West Gharib Concession area in Egypt;

"NW Sitra" means the North West Sitra Concession area in Egypt;

"Offer Price" has the meaning attributed thereto under "Description of Capital Structure - Debentures - Repurchase Upon a Change of Control";

"OXY" means Occidental Petroleum Corporation and its subsidiaries;

"PSA" means production sharing agreement;

"PSC" means production sharing concession;

"Redemption Date" means the date set for the redemption of the Debentures;

"SEDAR" means the System for Electronic Document Analysis and Retrieval;

"S Ghazalat" means the South Ghazalat Concession area in Egypt;

"SE Gharib" means the South East Gharib Concession area in Egypt;

"Senior Indebtedness" has the meaning attributed thereto under "Description of Capital Structure - Debentures - Subordination";

"shareholders" means the holders from time to time of Common Shares;

"South Alamein" means the South Alamein Concession area in Egypt;

"South Mariut" means the South Mariut Concession area in Egypt;

"SW Gharib" means the South West Gharib Concession area in Egypt;

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), as amended, including the regulations promulgated thereunder, each as amended from time to time;

"TransGlobe" or the "Company" means TransGlobe Energy Corporation, a corporation organized and registered under the laws of Alberta, Canada, and as the context requires, its subsidiary companies;

"TSX" means the Toronto Stock Exchange;

"U.S." means the United States of America;

"West Bakr" means the West Bakr Concession area in Egypt;

"West Gharib" means the West Gharib Concession area in Egypt; and

"Yemen" means the Republic of Yemen.

Certain other terms used herein but not defined herein are defined in NI 51-101 and/or CSA 51-324, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 and/or CSA 51-324.

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TRANSGLOBE ENERGY CORPORATION

General

TransGlobe Energy Corporation ("TransGlobe" or the "Company") was incorporated on August 6, 1968 and was organized under variations of the name "Dusty Mac" as a mineral exploration and extraction venture under The Company Act (British Columbia). In 1992, the Company entered into the oil and gas exploration and development field in the United States and later in Yemen, Canada and Egypt, ceasing operations as a mining company. The Company's U.S. oil and gas properties were sold in 2000 to fund opportunities in Yemen and the Company's Canadian oil and gas assets and operations were divested in early 2008 to assist with the funding of opportunities in Egypt and Yemen. The Company changed its name to TransGlobe Energy Corporation on April 2, 1996 and on June 9, 2004, the Company continued from the Province of British Columbia to the Province of Alberta pursuant to the ABCA.

TransGlobe, through its wholly-owned subsidiaries, is primarily engaged in the exploration for, and the development and production of, oil in Egypt and Yemen.

The Common Shares have been listed on the TSX under the symbol "TGL" since November 7, 1997 and on the NASDAQ under the symbol "TGA" since January 18, 2008. Prior to listing on the NASDAQ, the Company had its U.S. listing on the American Stock Exchange since 2003. The Debentures have been listed on the TSX under the symbol "TGL.DB" since February 22, 2012.

The Company's principal office is located at 2300, 250 - 5th Street S.W., Calgary, Alberta, T2P 0R4. The Company's registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

Intercorporate Relationships

The following table sets out the name and jurisdiction of incorporation of the Company's direct and indirect wholly-owned subsidiaries and the Company's ownership interest therein as of the date hereof:

Name of Subsidiary	Jurisdiction of Incorporation	Ownership
TransGlobe Petroleum International Inc.	Turks & Caicos Islands, B.W.I.	100%
TransGlobe West Gharib Inc.(1)	Turks & Caicos Islands, B.W.I.	100%
TG West Yemen Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TG Holdings Yemen Inc.(1)	Turks & Caicos Islands, B.W.I.	100%
TransGlobe Petroleum Egypt Inc.(1)	Turks & Caicos Islands, B.W.I.	100%
TransGlobe GOS Inc.(1)	Turks & Caicos Islands, B.W.I.	100%
TG South Alamein II Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TransGlobe West Bakr Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TG Holdings Egypt Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TG South Alamein Inc. (2)	Turks & Caicos Islands, B.W.I.	100%
TG South Mariut Inc. (2)	Turks & Caicos Islands, B.W.I.	100%
TG NW Gharib Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TG SW Gharib Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TG SE Gharib Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TG S Ghazalat Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
TG Energy Marketing Inc. (1)	Turks & Caicos Islands, B.W.I.	100%
Note:
(1)  These companies are 100% owned directly by TransGlobe Petroleum International Inc., which company is a wholly-owned subsidiary of the Company.
(2)  These companies are 100% owned directly by TG Holdings Egypt Inc., which company is wholly-owned by TransGlobe Petroleum International Inc., which company is a wholly-owned subsidiary of the Company.

TG Holdings Yemen Inc. owns TransGlobe's interests in Block 32 and Block 72 in Yemen. TransGlobe provided notice of relinquishment on Block 32 and Block 72 in January 2015, with effective dates of March 31, 2015 and February 28, 2015, respectively. TG West Yemen Inc. owns TransGlobe's interests in Block 75 and Block S1 in Yemen. TransGlobe Petroleum Egypt Inc. owned TransGlobe's interest in the Nuqra Block 1 in Egypt until the expiry of the Nuqra Block 1 PSC in July 2012, and now holds TransGlobe's interest in the NW Sitra concession. TransGlobe West Gharib Inc. owns TransGlobe's interest in the West Gharib concession in Egypt. TransGlobe GOS Inc. owns TransGlobe's interest in the East Ghazalat concession in Egypt. TransGlobe West Bakr Inc. owns TransGlobe's interest in the West Bakr concession in Egypt. TG South Alamein II Inc. owns 50% of TransGlobe's interest in the South Alamein concession. TG South Alamein Inc. owns 50% of TransGlobe's interest in the South Alamein concession. TG South Mariut Inc. owned TransGlobe's interest in the South Mariut concession in Egypt until the expiry of the South Mariut concession in June 2013. TG Holdings Egypt Inc. holds a 100% interest in the TG South Alamein Inc. and TG South Mariut Inc. companies. TG NW Gharib Inc. owns TransGlobe's interest in the NW Gharib concession. TG SW Gharib Inc. owns TransGlobe's interest in the SW Gharib concession. TG SE Gharib Inc. owns the TransGlobe's interest in the SE Gharib concession. TG S Ghazalat Inc. owns TransGlobe's interest in the South Ghazalat concession. TG Energy Marketing Inc. was established for TransGlobe's oil marketing business.

Unless the context otherwise requires, reference in this Annual Information Form to "TransGlobe" or the "Company" includes the Company and its direct and indirect wholly-owned subsidiaries.

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GENERAL DEVELOPMENT OF THE BUSINESS

TransGlobe is an independent international upstream oil and gas company with headquarters in Calgary, Canada whose main business activities consist of the exploration, development and production of crude oil and natural gas liquids. The Company currently has exploration and production operations in Egypt with additional legacy non-operated assets in Yemen.

During the past three years, TransGlobe has developed its business interests through a combination of acquisitions, divestitures, exploration and development. During this period, TransGlobe's primary focus has been on 11 concessions in Egypt (a 100% working interest in the West Gharib Concession, a 100% working interest in West Bakr Concession, a 50% working interest in the East Ghazalat Concession, a 100% working interest in the South Alamein Concession, a 100% working interest in the NW Gharib concession, a 100% working interest in the SW Gharib concession, a 100% working interest in the SE Gharib concession, a 100% working interest in the South Ghazalat concession, a 60% working interest in the South Mariut Concession prior to expiry in April 2013 and a 71.43% working interest in Nuqra Block 1 prior to expiry in July 2012) and four PSAs in Yemen (a 13.81087% working interest in Block 32, a 25% working interest in Block S-1, a 20% working interest in Block 72 and a 25% working interest in Block 75).

2012

In Egypt during 2012, the Company drilled 24 wells in West Gharib, seven wells in West Bakr and two wells in East Ghazalat. The West Gharib drilling resulted in 21 oil wells and three dry holes. The drilling was primarily focused on the Upper and Lower Nukhul oil appraisal and development in the Arta/East Arta leases. The drilling at West Bakr resulted in five oil wells and two dry holes. In East Ghazalat, the Company participated in drilling two exploration dry holes during 2012. The operator of the East Ghazalat concession received approval of the Safwa development lease in July 2011, and Safwa first production was achieved during the third quarter of 2012.

On February 22, 2012, the Company completed a short form prospectus financing pursuant to which Cdn$85.0 million aggregate principal amount of 6.00% convertible unsecured subordinated debentures were issued (the "Debenture Offering"). A syndicate of underwriters co-led by Scotia Capital Inc. and Macquarie Capital Markets Canada Ltd., and including Canaccord Genuity Corp., RBC Dominion Securities Inc., Dundee Securities Ltd., FirstEnergy Capital Corp. and GMP Securities L.P. (collectively, the "Underwriters") acted as underwriters for the Debenture Offering. Pursuant to the Debenture Offering, the Underwriters were also granted an over-allotment option, exercisable, in whole or in part, at any time up until 30 days after completion of the Debenture Offering, to purchase up to an additional Cdn$12.75 million aggregate principal amount of 6.00% convertible unsecured subordinated debentures due on the Maturity Date, to cover over-allotments. The over-allotment option was exercised by the Underwriters in full and on February 29, 2012 the Company issued Cdn$12.75 million aggregate principal amount of 6.00% convertible unsecured subordinated debentures. For a summary of the terms of the Debentures, see "Description of Capital Structure - Debentures".

On June 7, 2012, the Company completed the acquisition pursuant to a Share Purchase Agreement of 100% of the common shares of a wholly-owned subsidiary of EP Energy LLC which holds, though 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 South Alamein concession covers an area of 355,832 acres and an extensive 3-D seismic covers the entire area. There is currently one oil discovery well in the South Alamein concession. The South Mariut concession covers an area of approximately 828,000 acres. The transaction was structured as an all-cash deal, effective April 1, 2012, funded through working capital and the proceeds of the issuance of the Debentures. Total consideration for the transaction was $22.9 million, which included the 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 completed the acquisition pursuant to a Share Purchase Agreement of 100% of the common shares of Cepsa Egypt, a wholly-owned subsidiary of Compania Espanola De Petroleos, S.A.U. (“Cepsa”), a company registered in Spain. 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 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 included the 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.

On November 6, 2012, the Company was informed by Egyptian General Petroleum Company ("EGPC") that it was the successful bidder on four concessions in the 2011/2012 bid round. TransGlobe won three concessions in the Eastern Desert near the West Gharib/West Bakr operations (NW Gharib, SW Gharib and SE Gharib) and one concession in the Western Desert (South Ghazalat). The concessions were awarded in November 2013 following the ratification process which culminates when each concession is passed into law. The new concessions increased the Company's Egyptian exploration land holdings by approximately 3,241 square kilometers (~ 800,000 acres). Three concessions (NW Gharib, SW Gharib and SE Gharib) are proximal to the Company's core producing area at West Gharib/West Bakr onshore Gulf of Suez in the Eastern Desert. The South Ghazalat concession is located in the Western Desert west of the Company's East Ghazalat concession. All four concessions have a 7 year exploration term which commenced when the respective concessions were passed into law on November 7, 2013. The seven year term is comprised of three phases starting with an initial three year exploration period and two additional two year extension periods. The new concessions provide for the approval of 20 year development leases on commercial discoveries. The Company committed to spending $101.1 million in the first exploration period (3 years) including signature bonuses, the acquisition of new 2-D and 3-D seismic, and an extensive drilling program approaching 40 wells.

2013

In Egypt during 2013, the Company drilled 18 wells at West Gharib, 16 wells at West Bakr, four wells at East Ghazalat, three wells at South Mariut and two wells at South Alamein. The West Gharib drilling resulted in 15 oil wells, one service well and two dry holes. The drilling was primarily focused on the Upper and Lower Nukhul oil appraisal and development in the Arta/East Arta leases. The drilling at West Bakr resulted in 15 oil wells and one dry hole. The drilling at East Ghazalat resulted in two oil wells, one gas/condensate discovery and one dry hole. The exploration wells drilled at South Mariut and South Alamein were dry holes. South Mariut was relinquished at the end of the exploration term in June 2013.

The four new concessions that were won in the 2011/2012 EGPC bid round were signed on November 7, 2013 at an official signing ceremony with the Egyptian Ministry of Petroleum. These new concessions added approximately 800,000 net acres to TransGlobe's land holdings in Egypt and increased the total number of TransGlobe Egyptian PSCs to eight (seven are operated by TransGlobe). Three of the new concessions (NW Gharib, SW Gharib and SE Gharib) are in the Eastern Desert and are adjacent to the Company's existing West Gharib and West Bakr properties. The other new concession

9

(South Ghazalat) is in the Western Desert and is immediately west of the East Ghazalat concession. The Company committed to $101.1 million of expenditures on the new blocks over three years. The total commitment included $40.6 million in signature bonuses that were settled through an offset to TransGlobe's outstanding accounts receivable with the government of Egypt. Each concession consists of an initial three-year exploration period with the provision for two extension periods of two years each for a total exploration period of seven years.

2014

In Egypt during 2014, the Company drilled 15 wells at NW Gharib, 13 wells at West Bakr, ten wells at West Gharib, and five wells at East Ghazalat. The NW Gharib drilling resulted in five oil wells and ten dry holes. The drilling at West Bakr resulted in 11 oil wells, one service well and one dry hole. The drilling at West Gharib resulted in nine oil wells and one dry hole. The drilling at East Ghazalat resulted in three oil wells, one gas/condensate well and one dry hole. Furthermore, the Company spent a total of $16.8 million on a seismic acquisition program in 2014 that covered NW Gharib, SW Gharib and SE Gharib. The seismic shoot included approximately 1,000 square kilometers of 3-D and 325 kilometers of 2-D. Processing and interpretation of the data is expected to be completed during the first half of 2015.

On March 15, 2014, TransGlobe announced a proposed merger with Caracal Energy Inc. ("Caracal"). On April 14, 2014, the arrangement agreement was terminated due to the fact that Caracal received an unsolicited cash offer to acquire all of the outstanding shares of Caracal, and the unsolicited offer constituted a "Superior Proposal" under the terms of the arrangement agreement. Accordingly, Caracal terminated the agreement and paid TransGlobe a reverse termination fee of $9.25 million in accordance with the terms of the agreement.

TransGlobe was the successful bidder on the NW Sitra concession (100% working interest) in the 2014 EGPC bid round which closed on July 7, 2014. The ratification approval process of NW Sitra was completed on January 8, 2015. The 1,946 square kilometer (480,850 acre) NW Sitra concession is located in the Western Desert immediately to the west of the Company's South Ghazalat concession. TransGlobe committed to acquire a minimum of 300 square kilometers of 3-D seismic and drill two exploration wells in the first exploration phase. The concession has a 7 year exploration term which is comprised of two 3.5 year (42 month) exploration phases. The new concession provides for the approval of 20 year development leases on commercial discoveries.

Reserves at year-end 2014 were significantly lower compared to 2013 due to a reclassification of Yemen reserves to contingent resources, annual production and negative revisions which exceeded positive revisions and new additions. The primary negative revision occurred in the West Gharib Lower Nukhul pool in the Arta/East Arta field which offset gains in the Hana/Hana West areas of West Gharib and gains in the West Bakr fields. In Yemen, reserves were reclassified as contingent resources due to the political instability and security issues in the country. Future reserve growth is highly dependent on the new exploration lands. The 3-D seismic acquired in the Eastern Desert in 2014 and in the Western Desert in 2015 is expected to provide an exploration portfolio that could provide future reserve increases.

Recent Developments

Five additional wells were drilled in Egypt subsequent to year-end, resulting in one oil well, one water disposal well, two dry holes and one well that was plugged back to surface casing and suspended due to wellbore stability issues. No further drilling is currently budgeted for 2015.

Significant Acquisitions

TransGlobe did not complete any significant acquisitions during its most recently completed financial year for which disclosure is required under Part 8 of NI 51-102.

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES

General

TransGlobe is engaged in the exploration for and the development and production of crude oil and natural gas in Egypt and Yemen. The Company also regularly reviews potential acquisitions and new international exploration blocks to supplement its exploration and development activities.

TransGlobe's major operations and principal activities are in the oil and gas exploration and production business. The Company has had operations in Egypt and Yemen during the past 11 and 18 years respectively. The Company also operated in Canada from 1999 to 2008. In Egypt, the Company has an interest in nine PSCs: West Gharib, West Bakr, East Ghazalat, South Alamein, NW Gharib, SE Gharib, SW Gharib, South Ghazalat and NW Sitra. In Yemen, the Company had interests in four PSAs as at December 31, 2014: Block 32, Block 72, Block 75 and Block S-1. In January 2015, the Company relinquished its interests in Block 32 and Block 72 in Yemen (effective dates of March 31, 2015 and February 28, 2015, respectively). The Company sold its Canadian assets located in the Province of Alberta on April 30, 2008.

All of the Company's operations occur outside of Canada and therefore are subject to political and regulatory risk in those other jurisdictions. See "Risk Factors".

10

Summary of International Land Holdings

International Land (Egypt and Yemen) - Summary of PSCs/PSAs

EASTERN DESERT EGYPT
Block	West Gharib	West Bakr	NW Gharib	SE Gharib	SW Gharib
Basin	Gulf of Suez	Gulf of Suez	Gulf of Suez	Gulf of Suez	Gulf of Suez
Year acquired	2007	2011	2013	2013	2013
Status	Development	Development	Exploration	Exploration	Exploration
Operator	TransGlobe	TransGlobe	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	100%	100%	100%	100%	100%
Block Area (acres)	24,035	11,600	148,300	125,000	48,000
Expiry date	2019-2026	2020	November 2016	November 2016	November 2016
Extensions
Exploration	N/A	N/A	2 + 2 years	2 + 2 years	2 + 2 years
Development	+ 5 years	+ 5 years	20 + 5 years	20 + 5 years	20 + 5 years

WESTERN DESERT EGYPT
Block	East Ghazalat	South Alamein	South Ghazalat	NW Sitra
Basin	Western Desert	Western Desert	Western Desert	Western Desert
Year acquired	2010	2012	2013	2015
Status	Development	Exploration	Exploration	Exploration
Operator	North Petroleum	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	50%	100%	100%	100%
Block Area (acres)	14,698	197,000	465,299	480,850
Expiry date	2031 - 2034	April 2014 *	November 2016	July 2018
Extensions
Exploration	N/A	N/A	2 + 2 years	3.5 years
Development	+ 5 years	20 + 5 years	20 + 5 years	20 + 5 years
* The expiry date of the Boraq area of South Alamein has been suspended pending military approvals for access. When access is granted, the Company will have approximately 20 months until expiry.

11

Egypt

Eastern Desert

12

YEMEN
Block	32*	72*	S-1	75
Basin	Masila	Masila	Marib	Marib
Year acquired	1997	2004/2005	1998	2007
Status	Development	Exploration	Development	Exploration
Operator	DNO	Total	OXY	OXY
TransGlobe WI (%)	13.81087%	20%	25%	25%
Block Area (acres)	146,000	450,000	285,000	263,000
Expiry date	Nov 2020	2014	Oct 2023	March 2015
Extensions
Exploration	N/A	N/A	N/A	2nd Phase
				36 months
Development	+ 5 years	20 + 5 years	+ 5 years	20 + 5 years
* In January 2015, the Company relinquished its interests in Block 32 (13.81% working interest) and 72 (20% working interest) in Yemen (effective March 31, 2015 and February 28, 2015, respectively) due to ongoing political and tribal turmoil in the vicinity of the blocks.

Yemen

13

Summary of International PSA/PSC Terms

All of the Company's international blocks are PSAs or PSCs between the host government and the Contractor (Joint Interest Partners). The government and the contractors take their share of production based on the terms and conditions of the respective contracts. The contractors' share of all taxes and royalties are paid out of the governments' share of production.

The PSAs/PSCs provide for the government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, if any, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSA/PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the government and the Contractor as defined in the specific PSAs/PSCs. Each PSA/PSC is treated individually in respect of cost recovery and production sharing purposes. The remaining production sharing oil (total production, less gross royalty, less cost oil) is shared between the government and the Contractor as defined in the specific PSAs/PSCs.

The following tables summarize the Company's international PSA/PSC terms for the first tranche(s) of production for each block. All of the contracts have different terms for production levels above the first tranche, which are unique to each contract. The government's share of production increases and the contractor's share of production decreases as the production volumes go to the next production tranche.

PSC Terms –Egypt and Yemen

EASTERN DESERT - EGYPT
Block	West Gharib	West Bakr	NW Gharib	SE Gharib	SW Gharib
Production Tranche (MBopd)	0-5 / 5-10	0-50	0-5 / 5-10	0-5 / 5-10	0-5 / 5-10
	10-15		>10	>10	>10
Max. cost oil	30%	30%	25%	25%	25%
Excess cost oil
Contractor	30%	0%	5%	5%	5%
Depreciation per quarter
Operating	100%	100%	100%	100%	100%
Capital	6.25%	5%	5%	5%	5%
Production Sharing Oil:
Contractor	30% / 27.5%	15%	15.0% / 14.5%	15.0% / 14.5%	15.0% / 14.5%
	25%		14.0%	14%	14.0%
Government	70% / 72.5%	85%	85% / 85.5%	85% / 85.5%	85% / 85.5%
	75%		86%	86%	86%

WESTERN DESERT EGYPT
Block	East Ghazalat	South Alamein	S Ghazalat	NW Sitra
Production Tranche (MBopd)	0-5	0-5	0-5	0-5
Max. cost oil	25%	30%	25%	28%
Excess cost oil
Contractor	0%	0%	5%	10%
Depreciation per quarter
Operating	100%	100%	100%	100%
Capital	5%	5%	5%	5%
Production Sharing Oil:
Contractor	20%	14%	17%	24%
Government	80%	86%	83%	76%

14

YEMEN
Block	32*	72*	S-1	75
Production Tranche (MBopd)	0-25	0-25	0-25	0-25
Gross royalty	3%	3%	3%	3%
Max. cost oil	60%	50%	50%	50%
Excess cost oil	Prod. Sharing	Prod. Sharing	Prod. Sharing	Prod. Sharing
Depreciation per quarter
Operating	100%	100%	100%	100%
Capital	12.5%	12.5%	12.5%	12.5%
Production Sharing Oil:
Contractor	33.25%	32.4%	34.2%	34.2%
Government	66.75%	67.6%	65.8%	65.8%
* In January 2015, the Company relinquished its interests in Block 32 (13.81% working interest) and 72 (20% working interest) in Yemen (effective March 31, 2015 and February 28, 2015, respectively) due to ongoing political and tribal turmoil in the vicinity of the blocks.

Operations Review (2014)

In 2014, the Company's total production decreased by 12% to 16,103 Bopd (2013 – 18,284 Bopd). Production from Egypt averaged 15,767 Bopd to TransGlobe during 2014 (2013 – 17,874 Bopd). Production from Yemen averaged 336 Bopd to TransGlobe during 2014 (2013 – 410 Bopd).

2015 Outlook Highlights

• Production is expected to average 14,500 Bopd in Q1-2015 and 13,300 Bopd in Q2-2015; and

• Exploration and development spending is budgeted to be $37.5 million, to be funded from funds flow from operations and working capital.

Human Resources

The Company currently employs 96 full-time employees and 14 full-time consultants. The Company intends to add additional professional and administrative staff as the needs arise.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The report on reserves data in Form 51-101F2 and the report of management and directors on oil and gas disclosure in Form 51-101F3 are attached as Schedules "A" and "B", respectively, to this Annual Information Form, which forms are incorporated herein by reference.

The statement of reserves data and other oil and gas information set forth below (the "DeGolyer Report") is dated January 30, 2015, with the effective date being December 31, 2014.

Disclosure of Reserves Data

All of the Company's reserves herein reported were evaluated by independent evaluators in accordance with NI 51-101 for the year ended December 31, 2014. In 2014, DeGolyer and MacNaughton Canada Limited ("DeGolyer"), independent petroleum engineering consultants based in Calgary, Alberta and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company's Reserves Committee to independently evaluate 100% of TransGlobe's reserves as at December 31, 2014.

The reserves data set forth below (the "Reserves Data") was prepared by DeGolyer with an effective date of December 31, 2014. The Reserves Data summarizes the crude oil, natural gas liquids and natural gas reserves of the Company and the net present values of future net revenue for these reserves using forecast prices and costs and constant prices and costs. The Company reports in U.S. currency and therefore the reports have been converted to U.S. dollars at the prevailing conversion rate at December 31 of the respective years. See "Currency and Exchange Rates". All of the Company's reserves are located in Egypt; the Company's reserves in Yemen were reclassified as Contingent Resources at year-end 2014.

The DeGolyer Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101 and the COGE Handbook. The Reserves Data conforms with the requirements of NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which the Company believes is important to the readers of this information.

All evaluations and reviews of future net revenue are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net revenue shown below is representative of the fair market value of the Company's properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGLs and natural gas reserves may be greater than or less than the estimates provided herein.

15

In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of crude oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies, and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery, and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development and operating expenditures with respect to the reserves associated with the Company's properties may vary from the information presented herein and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the DeGolyer Report will be attained and variances could be material.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

The information relating to the Company's reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costs related thereto, forecast operating costs and anticipated production. See "Forward-Looking Statements" and "Risk Factors".

Possible reserves are those additional reserves that are less certain to be recovered than probable resources. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

16

Reserves Data – Forecast Prices and Costs

SUMMARY OF OIL AND GAS RESERVES

AS OF DECEMBER 31, 2014

(FORECAST PRICES AND COSTS)

	Light & Medium
	Crude Oil		Heavy Oil		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
Proved
Developed producing	3,447	2,185	12,851	7,314	16,298	9,499
Developed non-producing	213	140	883	497	1,096	637
Undeveloped	260	170	4,484	2,043	4,744	2,213
Total Proved	3,920	2,495	18,218	9,854	22,138	12,349
Probable	2,314	1,371	9,029	4,246	11,343	5,617
Proved+Probable	6,234	3,866	27,247	14,100	33,481	17,966
Possible	1,357	729	8,504	3,723	9,861	4,452
Proved+Probable+Possible	7,591	4,595	35,751	17,823	43,342	22,418
Notes:
1)  Gross reserves are the Company's working interest share before the deduction of royalties.
2)  Net reserves are the Company's working interest share after the deduction of royalties. Net reserves in Egypt include the Company's share of future cost recovery and production sharing oil after the Government's royalty interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.

NET PRESENT VALUES OF FUTURE NET REVENUES

AS OF DECEMBER 31, 2014

(FORECAST PRICES & COSTS)

The estimated future net revenues presented in the tables below do not represent fair market value. The estimated future net revenues presented below are calculated using the price forecasts and inflation rates set forth below under "Pricing Assumptions".

											Unit value
											Before Tax(1)
	Before Income Tax(1)					After Income Tax(1)					(discounted at
US$	Discounted at %/yr					Discounted at %/yr					10% / year)
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%	($/Bbl)
Proved
Developed producing	268.8	233.7	207.2	186.6	170.1	268.8	233.7	207.2	186.6	170.1	21.81
Developed non-producing	26.3	20.6	16.5	13.6	11.5	26.3	20.6	16.5	13.6	11.5	25.90
Undeveloped	47.1	37.8	30.9	25.6	21.6	47.1	37.8	30.9	25.6	21.6	13.96
Total Proved	342.3	292.0	254.6	225.8	203.2	342.3	292.0	254.6	225.8	203.2	20.62
Probable	160.8	117.9	89.7	70.5	56.9	160.8	117.9	89.7	70.5	56.9	15.97
Total Proved+Probable	503.1	409.9	344.3	296.3	260.1	503.1	409.9	344.3	296.3	260.1	19.16
Possible	149.4	102.5	74.8	57.3	45.7	149.4	102.5	74.8	57.3	45.7	16.80
Total Proved+Probable+Possible	652.5	512.4	419.1	353.6	305.8	652.5	512.4	419.1	353.6	305.8	18.69
Note:
1) In Egypt, under the terms of the PSCs, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax.

17

TOTAL FUTURE NET REVENUES

(UNDISCOUNTED)

AS OF DECEMBER 31, 2014

(FORECAST PRICES AND COSTS)

						Future Net		Future Net
					Abandonment	Revenue		Revenue
					and	Before		After
			Operating	Development	Reclamation	Income	Income	Income
	Revenue	Royalties	Costs(1)	Costs	Costs(2)	Taxes(1)	Taxes(1)	Taxes(1)
Reserves Category	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)
Proved Reserves	894.2	173.8	350.4	27.7	—	342.3	—	342.3
Proved+Probable Reserves	1,353.8	269.2	521.4	60.1	—	503.1	—	503.1
Proved+Probable
Possible Reserves	1,730.9	357.2	643.2	78.1	—	652.5	—	652.5
Notes:
1)   In Egypt, under the terms of the PSCs, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax. Income taxes payable in Egypt have been recorded as Operating Costs for reporting purposes.
2)   Please see "Additional Information Concerning Abandonment and Reclamation Costs" below.
3)   Values are calculated by considering existing tax pools for the Company in the evaluation of the Company's properties and take into account current federal tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see the Company's financial statements and management's discussion and analysis for the year ended December 31, 2014.

NET PRESENT VALUE OF FUTURE NET REVENUES

BY PRODUCTION GROUP

AS OF DECEMBER 31, 2014

(FORECAST PRICES AND COSTS)

		Future net
		Revenue	Unit Value
		Before Taxes(1)	Before Tax(1)
		(discounted	(discounted
		at	at
		10%/year)	10%/year)
Reserves Category	Product Group	(US$MM)	($/Bbl)
Total Proved	Light and Medium Oil	50.4	20.2
	Heavy Oil	204.2	20.7
Proved+Probable	Light and Medium Oil	75.2	19.5
	Heavy Oil	269.1	19.1
Proved+Probable +Possible	Light and Medium Oil	91.8	20.0
	Heavy Oil	327.3	18.4
Note:
(1) In Egypt, under the terms of the PSCs, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax.

18

Reserves Data – Constant Prices and Costs

SUMMARY OF OIL AND GAS RESERVES

AS OF DECEMBER 31, 2014

(CONSTANT PRICES AND COSTS)

	Light & Medium
	Crude Oil		Heavy Oil		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)	(Mbbls)
Proved
Developed producing	3,531	2,162	12,917	6,917	16,448	9,079
Developed non-producing	236	133	895	390	1,131	523
Undeveloped	260	157	4,507	1,733	4,767	1,890
Total Proved	4,027	2,452	18,319	9,040	22,346	11,492
Probable	2,249	1,207	8,955	3,792	11,204	4,999
Proved+Probable	6,276	3,659	27,274	12,832	33,550	16,491
Possible	1,315	682	8,519	3,509	9,834	4,191
Proved+Probable+Possible	7,591	4,341	35,793	16,341	43,384	20,682
Notes:
(1)  Gross reserves are the Company's working interest share before the deduction of royalties.
(2)  Net reserves are the Company's working interest share after the deduction of royalties. Net reserves in Egypt include the Company's share of future cost recovery and production sharing oil after the Government's royalty interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.

NET PRESENT VALUES OF FUTURE NET REVENUES

AS OF DECEMBER 31, 2014

(CONSTANT PRICES AND COSTS)

The estimated future net revenues presented do not represent fair market value. The estimated future net revenues presented below are calculated using the average of the reference price received on the first day of each month during 2014 adjusted for respective differentials. The prices were held constant and costs were not inflated for the life of the reserves as summarized below under "Pricing Assumptions".

											Unit value
											Before Tax(1)
	Before Income Tax(1)					After Income Tax(1)					(discounted at
US$	Discounted at %/yr					Discounted at %/yr					10% / year)
$MM	0%	5%	10%	15%	20%	0%	5%	10%	15%	20%	($/Bbl)
Proved
Developed producing	375.2	334.7	303.9	279.8	260.3	375.2	334.7	303.9	279.8	260.3	33.47
Developed non-producing	21.2	17.0	14.1	12.0	10.4	21.2	17.0	14.1	12.0	10.4	26.96
Undeveloped	46.8	37.2	30.3	25.1	21.1	46.8	37.2	30.3	25.1	21.1	16.03
Total Proved	443.1	388.9	348.3	316.9	291.8	443.1	388.9	348.3	316.9	291.8	30.31
Probable	165.0	122.6	94.7	75.5	61.8	165.0	122.6	94.7	75.5	61.8	18.94
Proved+Probable	608.1	511.6	443.0	392.4	353.6	608.1	511.6	443.0	392.4	353.6	26.86
Possible	158.8	113.0	85.0	66.7	54.3	158.8	113.0	85.0	66.7	54.3	20.28
Proved+Probable+Possible	766.9	624.5	528.0	459.1	407.9	766.9	624.5	528.0	459.1	407.9	25.53
Note:
(1)  In Egypt, under the terms of the PSCs, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax.

19

TOTAL FUTURE NET REVENUES

(UNDISCOUNTED)

AS OF DECEMBER 31, 2014

(CONSTANT PRICES AND COSTS)

					Well	Future Net		Future Net
					Abandonment	Revenue		Revenue
					and	Before		After
			Operating	Development	Reclamation	Income	Income	Income
	Revenue	Royalties	Costs(1)	Costs	Costs(2)	Taxes(1)	Taxes(1)	Taxes(1)
	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)	(US$MM)
Proved Reserves	1,017.7	212.8	334.5	27.2	—	443.1	—	443.1
Proved+Probable Reserves	1,459.2	312.0	480.1	59.0	—	608.1	—	608.1
Proved+Probable+Possible Reserves	1,833.1	403.3	586.2	76.6	—	766.9	—	766.9
Notes:
(1)    In Egypt, under the terms of the PSCs, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax. Income taxes payable in Egypt have been recorded as operating costs for reporting purposes.
(2)    Please see "Additional Information Concerning Abandonment and Reclamation Costs" below.
(3)    The evaluation of the Company's properties values are calculated by considering existing tax pools for the Company, and take into account current federal tax regulations. Values do not represent an estimate of the value at the business entity level, which may be significantly different. For information at the business entity level, please see the Company's financial statements and management's discussion and analysis for the year ended December 31, 2014.

NET PRESENT VALUE OF FUTURE NET REVENUES

BY PRODUCTION GROUP

AS OF DECEMBER 31, 2014

(CONSTANT PRICES AND COSTS)

		Future net	Unit Value
		Revenue	Before Tax(1)
		Before Taxes(1)	(discounted
		(discounted at	at
	Product	10%/year)	10%/year)
Reserves Category	Group	(US$MM)	($/Bbl)
Total Proved	Light and Medium Oil	72.9	29.7
	Heavy Oil	275.4	30.5
Proved+Probable	Light and Medium Oil	99.3	27.1
	Heavy Oil	343.7	26.8
Proved+Probable +Possible	Light and Medium Oil	118.1	27.2
	Heavy Oil	409.9	25.1
Note:
(1)   In Egypt, under the terms of the PSCs, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax.

20

1.	Columns may not add due to rounding.
2.	The crude oil, NGLs and natural gas reserve estimates presented in the Reserves Data are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions is set forth below.
	"Development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
	(a)	gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;
	(b)	drill and equip development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly;
	(c)	acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and
	(d)	provide improved recovery systems.
	"Exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to as "prospecting" costs) and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
	(a)	costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (sometimes referred to as "geological and geophysical costs");
	(b)	costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records;
	(c)	dry hole contributions and bottom hole contributions;
	(d)	costs of drilling and equipping exploratory wells; and
	(e)	costs of drilling exploratory type stratigraphic test wells.
	Reserve Categories
	Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:
	•	analysis of drilling, geological, geophysical and engineering data;
	•	the use of established technology; and
	•	specified economic conditions which are generally accepted as being reasonable and shall be disclosed.

21

Reserves are classified according to the degree of certainty associated with the estimates.
(a)	Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(b)	Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(c)	Possible reserves are those additional reserves that are even less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will be greater than the sum of the estimated proved plus probable plus possible reserves.
	Other criteria that must also be met for the categorization of reserves are provided in Section 5.5.4 of the COGE Handbook.
Each of the reserve categories (proved, probable and possible) may be divided into developed and undeveloped categories:
(d)	Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
(e)	Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(f)	Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
(g)	Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.
In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
Levels of Certainty for Reported Reserves
The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(i) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;

(ii) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus

probable reserves; and

(iii) at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in Section 5 of the COGE Handbook.

Pricing Assumptions

Forecast Prices and Costs

The forecast cost and price assumptions assume changes in wellhead selling prices and take into account inflation with respect to future operating and capital costs.

22

For the reserves, crude oil benchmark reference pricing, as at December 31, 2014, inflation and exchange rates utilized by DeGolyer in the Reserves Data, which were DeGolyer's then current forecasts at the date of the Reserves Data, were as follows:

		Brent
	WTI Cushing	Reference	Inflation	Exchange
	Oklahoma	Price	Rates(1) %	Rate
Year	(US$Bbl)	(US$/Bbl)	Year	(Cdn$/US$)
2014	95.93	102.70	2.1	0.91
Forecast
2015	65.00	69.00	—	0.85
2016	71.40	75.40	2.0	0.85
2017	78.03	82.03	2.0	0.85
2018	84.90	88.90	2.0	0.85
2019	92.01	96.01	2.0	0.85
2020	93.85	97.85	2.0	0.85
2021	95.72	99.72	2.0	0.85
Thereafter	+2.0%/year	+2.0%/year	+2.0%/year	+0%/year
Note:
(1) Inflation rates for forecasting expenditure prices and costs.

The weighted average historical price in US$ realized by the Company in Egypt, for the year ended December 31, 2014 for crude oil was $86.63/Bbl.

The weighted average historical price in US$ realized by the Company in Yemen, for the year ended December 31, 2014 for crude oil was $101.50/Bbl.

Constant Prices and Costs

In Egypt, a constant price of $87.84/Bbl for crude oil was utilized in the constant price case. The constant price case for 2014 is based on the average of the reference price received on the first day of each month during 2014 adjusted for respective differentials.

Reconciliation of Changes in Reserves

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

COMPANY

AS OF DECEMBER 31, 2014

(FORECAST PRICES AND COSTS)

	Light & Medium Oil						Heavy Oil
					Gross Proved						Gross Proved
	Gross Proved		Gross Probable		Plus Probable		Gross Proved		Gross Probable		Plus Probable
Factors	(MBbl)		(MBbl)		(MBbl)		(MBbl)		(MBbl)		(MBbl)
December 31, 2013	5,548		4,548		10,096		26,086		9,095		35,181
Extensions	—		86		86		736		328		1,064
Improved recovery	—		—		—		—		—		—
Technical Revisions	(398	)	(2,266	)	(2,664	)	(3,741	)	(656	)	(4,397	)
Discoveries	—		—		—		214		348		562
Acquisitions	—		—		—		—		—		—
Dispositions	—		—		—		—		—		—
Economic Factors	(112	)	(54	)	(166	)	(241	)	(86	)	(327	)
Production	(1,118	)	—		(1,118	)	(4,836	)	—		(4,836	)
December 31, 2014	3,920		2,314		6,234		18,218		9,029		27,247

23

RECONCILIATION OF GROSS RESERVES

BY PRINCIPAL PRODUCT TYPE

EGYPT

AS OF DECEMBER 31, 2014

(FORECAST PRICES AND COSTS)

	Light & Medium Oil						Heavy Oil
					Gross Proved						Gross Proved
	Gross Proved		Gross Probable		Plus Probable		Gross Proved		Gross Probable		Plus Probable
Factors	(MBbl)		(MBbl)		(MBbl)		(MBbl)		(MBbl)		(MBbl)
December 31, 2013	2,734		2,883		5,617		26,086		9,095		35,181
Extensions	—		86		86		736		328		1,064
Improved recovery	—		—		—		—		—		—
Technical Revisions	2,182		(637	)	1,545		(3,741	)	(656	)	(4,397	)
Discoveries	—		—		—		214		348		562
Acquisitions	—		—		—		—		—		—
Dispositions	—		—		—		—		—		—
Economic Factors	(18	)	(18	)	(36	)	(241	)	(86	)	(327	)
Production	(978	)	—		(978	)	(4,836	)	—		(4,836	)
December 31, 2014	3,920		2,314		6,234		18,218		9,029		27,247

RECONCILIATION OF GROSS RESERVES

BY PRINCIPAL PRODUCT TYPE

YEMEN

AS OF DECEMBER 31, 2014

(FORECAST PRICES AND COSTS)

	Light & Medium Oil
	Gross		Gross		Gross Proved
	Proved		Probable		Plus Probable
Factors	(MBbl)		(MBbl)		(MBbl)
December 31, 2013	2,814		1,666		4,480
Extensions	—		—		—
Improved recovery	—		—		—
Technical Revisions	(2,580	)	(1,630	)	(4,210	)
Discoveries	—		—		—
Acquisitions	—		—		—
Dispositions	—		—		—
Economic Factors	(94	)	(36	)	(130	)
Production	(140	)	—		(140	)
December 31, 2014	—		—		—

24

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped reserves are attributed by DeGolyer in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Proved and probable undeveloped reserves have been assigned in accordance with engineering and geological practices as defined under NI 51-101. In general, undeveloped reserves are planned to be developed over the next two years.

In some cases, it will take longer than two years to develop these reserves. There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iii) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (iv) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (v) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). For more information, see "Risk Factors" herein.

The following tables set forth the gross proved undeveloped reserves and the gross probable undeveloped reserves, each by product type, attributed to the Company in the most recent three financial years and, in the aggregate, before that time, as applicable.

Proved Undeveloped Reserves

	Light and Medium Oil		Heavy Oil
Year	(MBbl)		(MBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	364	364	1,576	1,576
2012(1)	127	127	120	983
2013(2)	—	—	5,174	7,220
2014(3)	260	260	125	4,485
Notes:
(1)  In 2012, proved undeveloped medium oil was assigned to Egypt with one vertical development well at Hana and heavy oil to Egypt with water flood development at H-Field. No new proved undeveloped reserves were assigned in Yemen.
(2)  In 2013, proved undeveloped heavy oil was assigned to Egypt with twelve vertical development wells at K-Field, five at H-Field, one at Arta and one at Hoshia. No new proved undeveloped reserves were assigned in Yemen.
(3)  In 2014, proved undeveloped medium oil was assigned to Egypt with one vertical development well at Hana West and heavy oil to Egypt with three vertical development wells at NW Gharib. No proved undeveloped reserves were assigned in Yemen.

Probable Undeveloped Reserves

	Light and Medium Oil		Heavy Oil
Year	(MBbl)		(MBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	2,300	2,300	4,461	4,461
2012(1)	36	2,075	2,074	4,455
2013(2)	300	1,548	2,317	2,385
2014(3)	88	552	251	3,863
Notes:
(1)  In 2012, probable undeveloped heavy oil was assigned to Egypt with one vertical development well at Arta, one at Fadl, one at H-Field and four at K-Field. Light oil was assigned to Yemen with one vertical development well at Tasour. All development activities are anticipated to take place during 2013.
(2)  In 2013, probable undeveloped medium oil was assigned to Egypt with one vertical development well at Hana. Heavy oil was assigned to Egypt with two vertical development wells at H-Field and twelve at K-Field. Light oil was assigned to Yemen with one vertical development well at Salsala. All development activities are anticipated to take place during 2014 with the exception of eight K-Field wells which will be done in 2015.
(3)  In 2014, probable undeveloped heavy oil was assigned to Egypt with three vertical development wells at NW Gharib. No probable undeveloped reserves were assigned in Yemen. All development activities are anticipated to take place between 2015 and 2017.

Significant Factors or Uncertainties

The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions and other factors and assumptions that may affect the reserve estimates and the present worth of the future net revenue therefrom. These factors and assumptions include, among others: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulations; and (viii) other government levies imposed over the life of the reserves. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates.

25

As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and government restrictions. Revisions to reserve estimates can arise from changes in year-end prices, commodity prices, reservoir performance, governmental restrictions, economic conditions, geologic conditions or production. These revisions can be either positive or negative. See "Risk Factors".

Future Development Costs

FUTURE DEVELOPMENT COSTS

AS OF DECEMBER 31, 2014

(US$MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2015	3.3	3.3
2016	16.7	34.2
2017	5.1	19.4
2018	0.7	1.1
2019	1.1	1.1
Remaining	0.6	1.0
Total Undiscounted	27.5	60.1

The Company expects to fund the future development costs noted above primarily through the use of working capital, cash flow, debt and equity financing as required. If debt and/or equity financing is required at a future time to fund development costs, the Company will evaluate the costs associated with the financing to determine whether these costs would affect the economic viability of the development project.

Other Oil and Gas Information

Oil and Gas Wells

The following table sets forth the number and status of wells in which the Company has a working interest as at December 31, 2014. All of the Company's wells are located onshore.

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Egypt	135	131.0	123	122.5	—	—	2	1
Yemen	14	1.9	37	7.9	—	—	5	1.3
Total	149	132.9	160	130.4	—	—	7	2.3

Properties with No Attributed Reserves

The following table sets out the Company's developed and undeveloped land holdings as at December 31, 2014.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Egypt	17,105	16,385	1,515,947	1,509,318	1,533,052	1,525,703
Yemen	36,210	7,121	1,107,294	239,900	1,143,504	247,021
Total	53,315	23,506	2,623,241	1,749,218	2,676,556	1,772,724

Egypt

In the West Gharib concession, all work commitments have been fulfilled and there are no potential land expiries in 2015.

The West Bakr concession was purchased on December 29, 2011. All work commitments have been fulfilled and there are no potential land expiries in 2015.

In the East Ghazalat concession, all work commitments have been fulfilled and there are no potential land expiries in 2015.

The South Alamein concession is in the second two-year extension period which expires on April 5, 2014. EGPC has put certain areas within the concession on hold as of July 2012 pending access by the contractor. All work commitments have been fulfilled.

In the North West Gharib concession, the Contractor has a minimum financial commitment of $35.0 million gross ($35.0 million net) and a work commitment for 30 wells and 200 square kilometers of 3-D seismic during the initial three year exploration period, which commenced on November 7, 2013. As at December 31, 2014, the Company had expended $18.7 million towards meeting that commitment.

26

In the South East Gharib concession, the Contractor has a minimum financial commitment of $7.5 million gross ($7.5 million net) and a work commitment for two wells, 200 square kilometers of 3-D seismic and 300 square kilometers of 2D seismic during the initial three year exploration period, which commenced on November 7, 2013. As at December 31, 2014, the Company had expended $5.0 million towards meeting that commitment.

In the South West Gharib concession, the Contractor has a minimum financial commitment of $10.0 million gross ($10.0 million net) and a work commitment for four wells and 200 square kilometers of 3-D seismic during the initial three year exploration period, which commenced on November 7, 2013. As at December 31, 2014, the Company had expended $4.9 million towards meeting that commitment.

In the South Ghazalat concession, the Contractor has a minimum financial commitment of $8.0 million gross ($8.0 million net) and a work commitment for two wells and 400 square kilometers of 3-D seismic during the initial three year exploration period, which commenced on November 7, 2013. As at December 31, 2014, the Company had expended $0.3 million towards meeting that commitment.

Yemen

The Company does not have any work commitments associated with its undeveloped lands in Block S-1.

In Yemen Block 75, the Contractor has a remaining commitment of $3.0 million gross ($0.8 million net) for the first exploration work-period (36 months) commencing March 8, 2008 representing one exploration well. Due to political unrest and security issues in Yemen that have prevented the Contractor from engaging in drilling activity, the first exploration period has been extended to March 9, 2016.

In January 2015, the Company relinquished its interests in Block 32 (13.81% working interest) and Block 72 (20% working interest) (effective March 31, 2015 and February 28, 2015, respectively) due to ongoing political and tribal turmoil in the vicinity of the blocks. There are no forward obligations or commitments on Block 32 or Block 72.

Development of the Company's properties with no attributed reserves are subject to current industry conditions and uncertainties as indicated under "Risk Factors" herein. In addition, we expect that funding of development operations on such properties will be evaluated in the context of our total capital requirements having regard to rates of return, the likelihood of success and risked return versus cost of capital, and availability and reliability of methods of hydrocarbon delivery.

Forward Contracts

The Company's contracts to sell crude oil are at prevailing market pricing.

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 at December 31, 2014, there were no outstanding derivative commodity contracts and therefore no production is hedged in future periods.

Additional Information Concerning Abandonment and Reclamation Costs

In Egypt, estimated future abandonment and reclamations costs related to properties evaluated have not been taken into account by DeGolyer. Under the terms of the PSCs, ownership in the facilities and wells is transferred to the Government of Egypt through cost recovery. Therefore the future abandonment and reclamation costs have been assessed a zero value.

Tax Horizon

In 2014, the Company did not pay any income taxes in Canada and does not anticipate any taxes payable in the future. In Egypt and Yemen, the Company's income tax liabilities are paid out of the respective governments' share of production. As such, all current income tax liabilities in Egypt and Yemen are settled immediately as they become due.

Capital Expenditures

The following table summarizes the capital expenditures (including capitalized general and administrative expenses) related to the Company's activities for the year ended December 31, 2014 (excluding Canadian expenditures):

	Egypt	Yemen	Total
(US$M)
Property acquisition costs
Proved properties	—	—	—
Undeveloped properties	—	—	—
Exploration costs	35,745	938	36,683
Development costs	67,844	630	68,474
Corporate and other	2,382	—	2,382
Total	105,971	1,568	107,539

Exploration and Development Activities

The following tables set forth the gross and net exploratory and development wells which the Company drilled during the year ended December 31, 2014:

27

Egypt	Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	—	1.0	1.0	—	0.5	0.5
Crude Oil	4.0	24.0	28.0	4.0	22.5	26.5
Service	—	1.0	1.0	—	1.0	1.0
Dry and Abandoned(1)	9.0	4.0	13.0	8.5	4.0	12.5
Total	13.0	30.0	43.0	12.5	28.0	40.5

Current exploration and development activities are focused on the West Gharib, West Bakr and NW Gharib concessions. Other key areas for 2015 include the seismic acquisition program at S Ghazalat, and the completion of seismic interpretation on the Eastern Desert exploration blocks (NW Gharib, SW Gharib and SE Gharib).

Production Estimates

The following table sets out the volume of the Company's daily production (working interest before royalties) estimated for the year ending December 31, 2015 by DeGolyer which is reflected in the estimate of future net revenue disclosed in the prior reserves summary tables.

	Egypt				Yemen	Total
	West Gharib	West Gharib	West Bakr	East Ghazalat	Block S1&32	Company
				Light and	Light and
	Medium Oil	Heavy Oil	Heavy Oil	Medium Oil	Medium Oil	Bbls
	Gross	Gross	Gross	Gross	Gross	Gross
	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)
Proved Developed Producing	1,734	5,196	4,937	458	—	12,325
Proved Developed
Non-Producing	—	53	178	—	—	231
Proved Undeveloped	9	75	663	—	—	747
Total Proved	1,743	5,324	5,778	458	—	13,303
Total Probable	120	352	532	28	—	1,031
Total Proved Plus Probable	1,863	5,676	6,310	486	—	14,334

28

Production History

The following table summarizes certain information in respect of sales volumes, product prices received, royalties paid, operating expenses and resulting netbacks made by the Company (and its subsidiaries) for the periods indicated:

	2014
	Quarter Ended
	Mar. 31	Jun. 30	Sep. 30		Dec. 31
Average Daily Sales Volumes
Egypt(1)
Heavy Crude Oil (Bbls/d)	14,789	13,333	12,286		13,145
Light and Medium Crude Oil (Bbls/d)	2,502	2,623	2,612		1,817
Yemen
Light and Medium Crude Oil (Bbls/d)	641	529	234		177
Combined (Bbls/d)	17,932	16,485	15,132		15,139
Average Price Received
Egypt(1)
Heavy Crude Oil (US$/Bbl)	94.43	95.74	88.36		66.47
Light and Medium Crude Oil (US$/Bbl)	94.43	95.74	88.36		66.47
Yemen
Light and Medium Crude Oil (US$/Bbl)	107.40	107.79	102.84		61.29
Combined (US$/Bbl)	94.89	96.14	88.59		66.41
Royalties and Taxes
Egypt(1)
Heavy Crude Oil (US$/Bbl)	59.41	58.14	51.34		36.24
Light and Medium Crude Oil (US$/Bbl)	59.41	58.14	51.34		36.24
Yemen
Light and Medium Crude Oil (US$/Bbl)	38.31	38.54	(7.06	)	34.33
Combined (US$/Bbl)	58.66	57.51	50.44		36.22
Operating Expenses
Egypt(1)
Heavy Crude Oil (US$/Bbl)	10.48	11.01	11.39		12.40
Light and Medium Crude Oil (US$/Bbl)	10.48	11.01	11.39		12.40
Yemen(2)
Light and Medium Crude Oil (US$/Bbl)	56.70	63.15	122.31		156.41
Combined (US$/Bbl)	12.13	12.68	13.11		14.09
Netback Received
Egypt(1)
Heavy Crude Oil (US$/Bbl)	24.54	26.59	25.63		17.83
Light and Medium Crude Oil (US$/Bbl)	24.54	26.59	25.63		17.83
Yemen(2)
Light and Medium Crude Oil (US$/Bbl)	12.39	6.10	(12.41	)	(129.45	)
Combined (US$/Bbl)	24.10	25.95	25.04		16.10
Notes:
(1) Under the terms of the current marketing contract, all production from West Gharib is sold as a blended crude oil. Royalties and taxes are calculated on a concession basis without distinction between Heavy Crude Oil and, Medium and Light Crude Oil.
(2) In Yemen, the Company experienced increased operating costs per Bbl in both 2013 and 2014, which negatively impacted the netback per Bbl received. Operating expenses on a per Bbl basis were elevated in 2013 and 2014 as a result of production being shut-in on Block S-1 for the majority of both years. While production volumes were down, the Company continued to incur the majority of the production and operating costs on Block S-1 which significantly increased operating expenses per Bbl.

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The following table indicates the Company's average daily volumes from its important fields for the year ended December 31, 2014:

		Light and
	Heavy Crude	Medium
	Oil	Crude	Total
	(Bbls/d)	(Bbls/d)	(Bbls/d)
Egypt
Arta/East Arta	7,020	—	7,020
Hana	—	1,074	1,074
Hana West	—	847	847
Hoshia	674	—	674
West Bakr	5,499	—	5,499
East Ghazalat	—	616	616
Other Egypt	33	—	33
Yemen
Block S-1	—	162	162
Block 32	—	178	178
Total	13,226	2,877	16,103

Independent Resource Evaluations

The Company's contingent resource evaluation was prepared by DeGolyer in accordance with NI 51-101 and the COGE Handbook. The contingent resource evaluation is dated February 23, 2015 with an effective date of December 31, 2014 (the "Contingent Resource Report").

Contingent Resources

The following is a summary of the Contingent Resource Report. The Company did not have contingent resources evaluated at year ended December 31, 2013. The recovery and contingent resource estimates of crude oil, NGLs and natural gas resources provided herein are estimates only, and there is no guarantee that the estimated resources will be recovered. Actual crude oil, NGL and natural gas resources may be greater than, or less than, the estimates provided herein. All contingent resources presented are based on DeGolyer forecast pricing effective December 31, 2014.

Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of the resources.

Contingent Resource Summary

(Working interest, before royalties)

Contingent Resources at December 31, 2014
(Mbbls)
	Low Estimate	Best Estimate	High Estimate
Egypt
South Alamein	475	1,426	2,881
Total Egypt	475	1,426	2,881
Yemen
Block S-1	2,775	3,734	4,333
Block 32 *	180	254	354
Total Yemen *	2,955	3,988	4,686
Total Company *	3,430	5,415	7,567
Note:
* Effective March 31, 2015, the Company relinquished its interest in Block 32 in Yemen.

Uncertainty Ranges as described by the COGE Handbook as low, best and high estimates for resources are as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

30

High Estimate: This is considered to be an optimistic estimate of the quantity that will be actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

Contingencies

Development Area	Contingency	Chance of Contingency being Removed
Egypt - South Alamein	Unable to gain military regulatory approval to access lands.	50%
Yemen - Block S-1: An Nagyah and Osaylan	Political stability and unrest	60%
Yemen - Block 32: Tasour, Godah and Salsala	Political stability and unrest	80%

In Egypt, contingent resources were assigned to the Boraq 2 oil discovery in the South Alamein concession which was acquired in 2012. The contingent resources assigned to Boraq are contingent on the approval of access from the military and approval of a development plan. During 2012 the Company prepared and submitted an eight well drilling program for approval, which includes two appraisal/development wells at Boraq and six exploration wells on the concession. To date, the Company has not received the military access approvals necessary to commence the drilling program. Upon receiving the necessary approvals, the Company expects to proceed with the appraisal/development of the Boraq 2 discovery. In 2014 the Company reached an agreement with EGPC to suspend the South Alamein final exploration period effective July 8, 2012 over the restricted access area of approximately 800 square kilometers. The balance of the South Alamein lands were relinquished on April 4, 2014. The restricted lands are continued until access is approved by the military. The Company will have approximately 20 months from the date of access approval to conduct exploration and appraisal activities.

In Yemen, Block S-1 has been shut-in since February 2014 due to ongoing labor negotiations with local tribes. Prior thereto, Block S-1 had produced intermittently since the Arab Spring in 2011. The contingency for producing from Block S-1 is political stability and local unrest.

In Yemen, Block 32 has generally remained on production, however, political instability and local tribal unrest have restricted the operator from accessing projects to increase production and reduce operating costs which has rendered the project sub-economic in the foreseeable future. The contingency for Block 32 is political stability and local unrest. The Company relinquished its interest in Block 32 effective March 31, 2015.

Contingent Resources Estimated Future Net Revenues

All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which resources have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Company's properties. There is no assurance that such price and cost assumptions will be attained, and variances could be material. The recovery and resource estimates of crude oil, NGL and natural gas resources provided herein are estimates only and there is no guarantee that the estimated resources will be recovered. Actual crude oil, NGL and natural gas resources may be greater than or less than the estimates provided herein. The estimates of contingent resources and future net revenue for individual properties may not reflect the same confidence level as estimates of contingent resources and future net revenue for all properties, due to the effects of aggregation.

The estimated future net revenues for year ended 2014 presented below in thousands of U.S. dollars are calculated using DeGolyer's price forecast at December 31, 2014 and constant pricing for 2014. In the constant price case, the prices were held constant for the life of the resources.

Forecast Pricing

Present Value of Future Net Revenues, After Tax ($000s)

As at December 31, 2014

	Economic Contingent Resources			Economic Contingent Resources
	Undiscounted			Discounted at 10%
	Low estimate	Best estimate	High estimate	Low estimate	Best estimate	High estimate
Egypt
South Alamein	7,546	23,942	55,176	5,414	15,569	33,571
Total Egypt	7,546	23,942	55,176	5,414	15,569	33,571
Yemen
Block S-1	44,821	63,069	73,674	29,152	39,697	45,792
Block 32 *	493	571	1,886	418	378	1,139
Total Yemen *	45,314	63,640	75,560	29,570	40,074	46,931
Total Company *	52,860	87,582	130,736	34,984	55,643	80,503
Note:
* Effective March 31, 2015, the Company relinquished its interest in Block 32 in Yemen.

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The following table summarizes DeGolyer reference price forecast used to estimate future net revenues:

DeGolyer Forecast Pricing ($/bbl)
Brent Forecast Pricing ($/Bbl)	2015	2016	2017	2018	2019
Year-end 2014	$69.00	$75.40	$82.03	$88.90	$96.01

Constant Pricing

Present Value of Future Net Revenues, After Tax ($000s)

As at December 31, 2014

	Economic Contingent Resources			Economic Contingent Resources
	Undiscounted			Discounted at 10%
	Low estimate	Best estimate	High estimate	Low estimate	Best estimate	High estimate
Egypt
South Alamein	10,283	30,794	66,600	7,459	20,496	41,439
Total Egypt	10,283	30,794	66,600	7,459	20,496	41,439
Yemen
Block S-1	54,503	74,647	86,482	36,358	48,153	55,055
Block 32 *	2,372	3,434	4,948	2,145	2,906	3,878
Total Yemen *	56,875	78,081	91,430	38,503	51,059	58,933
Total Company *	67,158	108,876	158,030	45,961	71,555	100,372
Note:
* Effective March 31, 2015, the Company relinquished its interest in Block 32 in Yemen.

Constant Pricing ($Bbl)	Year-end 2014
South Alamein	$91.64
Block S-1	$100.08
Block 32	$98.92

DIVIDEND POLICY

The Company paid a special dividend of $0.10 per common share in May 2014, and initiated a quarterly dividend of $0.05 per common share in the second quarter of 2014. The Board of Directors of the Company will determine the timing, payment and amount of dividends, if any, that may be paid by the Company from time to time based upon, among other things, the cash flow, results of operations and financial condition of the Company, the need for funds to finance ongoing operations, restrictions that may be imposed under the Company's credit facilities and other business considerations as the board of directors of the Company considers relevant, including the ability of the Company to pay dividends upon the satisfaction of the liquidity and insolvency tests imposed by the ABCA for the declaration and payments of dividends. Depending on these and various other factors, many of which are beyond the control of the Company, the dividend policy of the Company may change from time to time.

DESCRIPTION OF CAPITAL STRUCTURE

Common Shares

TransGlobe is authorized to issue an unlimited number of Common Shares without nominal or par value. As at March 11, 2015 there were 75,259,161 Common Shares issued and outstanding.

Each Common Share entitles its holder to: (i) vote at any meeting of shareholders of the Company; (ii) to receive any dividend declared by the Company; and (iii) to receive the remaining property of the Company upon dissolution.

The Company's articles have been filed in accordance with NI 51-102 and are available on the Company's SEDAR profile at www.sedar.com.

Rights Plan

On June 10, 2014, the Company amended and restated its shareholder protection rights plan agreement (the "Rights Plan") with Olympia Trust Company, as rights agent, which was approved by TransGlobe's shareholders on June 10, 2014 at the 2014 annual general and special meeting of shareholders. The Rights Plan generally provides that following any person or entity acquiring 20% or more of the issued and outstanding Common Shares (except pursuant to certain permitted or excepted transactions) and upon the occurrence of certain other events, each holder of Common Shares, other than such person or entity, shall be entitled to acquire Common Shares at a discounted price. The Rights Plan is similar to other shareholder rights plans adopted in the energy sector. A copy of the Rights Plan may be obtained on request without charge from the Corporate Secretary of the Company,

32

Suite 2300, 250 - 5th Street S.W., Calgary, Alberta T2P 0R4, Telephone: (430) 264-9888. In addition, a copy of the Rights Plan, as filed with the securities commission or similar authorities in Canada, may be obtained from the Company's SEDAR profile at www.sedar.com.

Debentures

On February 22, 2012 and February 29, 2012, the Company issued Cdn$97.75 million aggregate principal amount of 6.00% convertible unsecured subordinated debentures at a price of $1,000 per Debenture. The Debentures were issued under the Indenture. The following description of the Debentures is a summary of their material attributes and characteristics and is subject to the detailed provisions of the Indenture and is qualified in its entirety by reference to the Indenture. The following summary uses words and terms which are defined in the Indenture. For full particulars, reference is made to the Indenture, which is available for inspection at the offices of the Company and was filed on SEDAR on March 23, 2012 at www.sedar.com. Particular provisions of the Indenture, which are referred to in this Annual Information Form, are qualified in their entirety by the reference to the Indenture.

General

The Debentures are limited to an aggregate principal amount of Cdn$97.75 million; however, the Company may, from time to time, without the consent of the holders of any outstanding Debentures, issue additional debentures. The Debentures have a maturity date of March 31, 2017 and on that date, the holders shall be entitled to receive the principal amount of the Debentures at par together with all accrued and unpaid interest thereon.

The Debentures bear interest from the date of issue at 6.00% per annum, which is payable semi-annually on March 31 and September 30 in each year, computed on the basis of a 365-day year.

Unless an Event of Default has occurred and is continuing, the Company may elect, from time to time, subject to applicable regulatory approval, to satisfy its obligation to pay all or any portion of the Interest Obligation on an Interest Payment Date by delivering sufficient Common Shares to the Debenture Trustee for sale, to satisfy the Interest Obligation, or portion thereof, as applicable, on the Interest Payment Date, in which event holders of the Debentures will be entitled to receive a cash payment equal to the interest payable from the proceeds of the sale of such Common Shares. See "Debentures - Interest Payment Election" below.

Principal on the Debentures is payable in lawful money of Canada or, at the Company's option and subject to applicable regulatory approval and provided no Event of Default has occurred and is continuing, by delivery of Common Shares to satisfy, in whole or in part, the Company's obligation to repay principal under the Debentures, as further described under "Debentures - Payment upon Redemption or Maturity" and "Debentures - Redemption and Purchase".

The Debentures are the Company's direct obligations and are not secured by any mortgage, pledge, hypothec or other charge and are subordinated to the Senior Indebtedness, as described under "Debentures - Subordination". The Indenture does not restrict the Company or its Subsidiaries from incurring additional indebtedness for borrowed money or from mortgaging, pledging or charging its assets to secure any indebtedness.

Conversion Privilege

Each Debenture is convertible at the option of the holder thereof into fully paid and non-assessable Common Shares at any time prior to 5:00 p.m. (Calgary time) on the earliest of: (i) the Business Day immediately preceding the Maturity Date; and (ii) the last Business Day immediately preceding the Redemption Date, in each case, at the Conversion Price, representing a conversion rate of approximately 69.2042 Common Shares per Cdn$1,000 principal amount of Debentures, subject to adjustment in accordance with the Indenture. Interest will be paid on conversion from the last Interest Payment Date up to, but not including, the Conversion Date.

Holders converting their Debentures will become holders of record of Common Shares on the date of conversion provided that, if a Debenture is surrendered for conversion on a day on which the register of Common Shares is closed, the person entitled to receive Common Shares shall become the holder of record of such Common Shares as at the date on which such register is next reopened. Notwithstanding the foregoing, if Debentures are surrendered for conversion on an Interest Payment Date or during the five business days preceding an Interest Payment Date the person or persons entitled to receive Common Shares in respect of the Debentures so surrendered for conversion shall not become the holder of record of such Common Shares until the business day following the Interest Payment Date.

Subject to the provisions thereof, the Indenture provides for the adjustment of the Conversion Price in certain events. In the event of certain transactions involving the Company, the Indenture provides for adjustments to the Conversion Price and provides that the Company is required to give notice to the holders of Debentures at least 30 days prior to the effective date of such transaction stating the consideration into which the Debentures will be convertible after the effective date of such transaction.

No fractional Common Shares will be issued upon conversion of the Debentures; in lieu thereof, the Company will satisfy such fractional interests by a cash payment equal to the fraction of the Common Share multiplied by the Current Market Price of the Common Shares on the date of conversion of such fractional interest.

Redemption and Purchase

The Debentures may not be redeemed by the Company before March 31, 2015 (except in certain limited circumstances following a Change of Control). See "Debentures - Repurchase upon a Change of Control" below. On or after March 31, 2015 and prior the Maturity Date, the Debentures may be redeemed by the Company in whole or in part from time to time at the Company's option on not more than 60 days' and not less than 30 days' prior written notice at a redemption price equal to the principal amount plus accrued and unpaid interest thereon, if any, up to but excluding the Redemption Date, provided that the Current Market Price of the Common Shares on the date on which notice of redemption is given exceeds 125% of the Conversion Price.

33

In the case of redemption of less than all of the Debentures, the Debentures to be redeemed will be selected by the Debenture Trustee on a pro rata basis or in such other manner as the Debenture Trustee deems equitable, subject to regulatory approvals.

The Company has the right to purchase Debentures for cancellation in the market, by tender or by private contract, at any time, subject to regulatory requirements.

Payment upon Redemption or Maturity

On any Redemption Date or on the Maturity Date, as applicable, the Company will repay the indebtedness represented by the Debentures by paying to the Debenture Trustee in lawful money of Canada an amount equal to the principal amount of the outstanding Debentures, together with accrued and unpaid interest thereon, if any, up to but excluding the date set for redemption. On any Redemption Date or on the Maturity Date, as applicable, the Company may, at its option, on not more than 60 days' and not less than 30 days' prior notice and subject to any required regulatory approvals, provided that no Event of Default has occurred and is continuing, elect to satisfy its obligation to repay, in whole or in part, the principal amount of the Debentures which are to be redeemed or which have matured, and any accrued and unpaid interest thereon, by issuing and delivering Common Shares to the holders of the Debentures. Payment for such Debentures subject to the election would be satisfied by delivering that number of Common Shares obtained by dividing the principal amount of the Debentures subject to the election which are to be redeemed or have matured, and any accrued and unpaid interest thereon, by 95% of the Current Market Price of the Common Shares on the Redemption Date or Maturity Date, as applicable. In the event a holder of Debentures exercises its conversion rights following delivery of a notice of redemption by the Company, such holder shall be entitled to receive the applicable number of Common Shares to be received on conversion on the Business Day immediately preceding the Redemption Date.

Rank

The Debentures are direct, unsecured obligations of the Company and are fully subordinated to all Senior Indebtedness, as more particularly described below under "Subordination". The Debentures rank pari passu with one another and rank pari passu with all other existing and future unsecured subordinated indebtedness of the Company to the extent subordinated on the same terms. The Indenture does not restrict the ability of the Company or its subsidiaries from incurring additional indebtedness, including Senior Indebtedness, or from mortgaging, pledging or charging their respective properties to secure any indebtedness or liabilities, including Senior Indebtedness.

Subordination

The payment of the principal and premium, if any, of, and interest on, the Debentures is subordinated and postponed, and subject in right of payment in the circumstances more particularly as set forth in the Indenture, to the full and final payment of all Senior Indebtedness of the Company. "Senior Indebtedness" of the Company is defined in the Indenture and includes all obligations, liabilities and indebtedness of the Company and its Subsidiaries which would, in accordance with IFRS, be classified upon a consolidated balance sheet of the Company as liabilities of the Company or its Subsidiaries and, whether or not so classified, shall include certain items as described in the Indenture. "Senior Indebtedness" shall not include any indebtedness that would otherwise be Senior Indebtedness if it is expressly stated to be subordinate to or rank pari passu with the Debentures.

The Indenture provides that in the event of any insolvency or bankruptcy proceedings, or any receivership, liquidation, reorganization or other similar proceedings relative to the Company, or to its property or assets, or in the event of any proceedings for voluntary liquidation, dissolution or other winding-up of the Company, whether or not involving insolvency or bankruptcy, or any marshalling of the assets and liabilities of the Company, then holders of Senior Indebtedness will receive payment in full before the holders of Debentures will be entitled to receive any payment or distribution of any kind or character, whether in cash, property or securities, which may be payable or deliverable in any such event in respect of any of the Debentures or any unpaid interest accrued thereon. The Indenture also provides that the Company will not make any payment, and the holders of the Debentures will not be entitled to demand, institute proceedings for the collection of, or receive any payment or benefit (including, without any limitation, by set-off, combination of accounts or otherwise in any manner whatsoever) on account of indebtedness represented by the Debentures: (a) in a manner inconsistent with the terms (as they exist on the date of issue) of the Debentures; or (b) at any time when a default or an event of default has occurred under the Senior Indebtedness permitting (either at that time or upon notice, lapse of time or satisfaction of other conditions precedent) the holder thereof to demand payment or accelerate the maturity thereof, unless the Senior Indebtedness has been repaid in full.

Repurchase upon a Change of Control

Within 30 days following the occurrence of a Change of Control, the Company will be required to make a cash offer to purchase all of the Debentures (the "Debenture Offer") at a price equal to 100% of the principal amount thereof plus accrued and unpaid interest thereon (the "Offer Price"). A Change of Control will be deemed to occur upon: (i) an acquisition by a person or group of persons acting jointly or in concert (within the meaning of Multilateral Instrument 62-104 - Take-Over Bids and Issuer Bids and in Ontario, the Securities Act (Ontario) and Ontario Securities Commission Rule 62-504 - Take-Over Bids and Issuer Bids) of ownership of, or voting control or direction over, more than 50% of the issued and outstanding Common Shares; or (ii) the sale or other transfer of all or substantially all of the Company's consolidated assets, excluding a sale, merger, reorganization or similar transaction if the previous holders of the Common Shares immediately prior to such transaction hold at least 50% of the voting control or direction in such merged, reorganized, arranged, combined or other continuing entity (and in the case of a sale of all or substantially all of the assets, in the entity which has acquired such assets) (each a "Change of Control").

If Debentures representing 90% or more of the aggregate principal amount of the Debentures outstanding on the date of the giving of notice of the Change of Control are tendered for purchase following a Change of Control (other than Debentures held at such date by or on behalf of the Company, associates or affiliates of the Company or any one acting jointly or in concert with the Company), the Company has the right to redeem all remaining Debentures in cash on the purchase date at the Offer Price.

34

Cash Change of Control

In addition to the requirement for the Company to make a Debenture Offer in the event of a Change of Control, if a Change of Control occurs on or before the Maturity Date in which 10% or more of the consideration for the Common Shares in the transaction or transactions constituting a Change of Control consists of: (i) cash (other than cash payments for fractional Common Shares and cash payments made in respect of dissenters' appraisal rights); (ii) equity securities (including trust units, limited partnership units or other participating securities of a trust, limited partnership or similar entity) that are not traded or intended to be traded immediately following such transactions on a recognized stock exchange; or (iii) other property that is not traded or intended to be traded immediately following such transactions on a recognized stock exchange, then subject to regulatory approvals, during the period beginning ten trading days before the anticipated date on which the Change of Control becomes effective and ending 30 days after the Debenture Offer is delivered, holders of Debentures will be entitled to convert their Debentures, subject to certain limitations, and receive, subject to and upon completion of the Change of Control, in addition to the number of Common Shares they would otherwise be entitled to receive as set out under "Debentures - Conversion Privilege" above, an additional number of Common Shares per Cdn$1,000 principal amount of Debentures as set out in the Indenture (in each case, a "Make-Whole Premium"), subject to regulatory approvals.

The number of additional Common Shares per Cdn$1,000 principal amount of Debentures constituting the relevant Make-Whole Premium is determined by reference to the table contained in the Indenture and is based on the date on which the Change of Control becomes effective (the "Effective Date") and the Offer Price paid per Common Share in the transaction constituting the Change of Control. If holders of Common Shares receive (or are entitled and able in all circumstances to receive), only cash in the transaction, the Offer Price will be the cash amount paid per Common Share. Otherwise, the Offer Price will be equal to the Current Market Price of the Common Shares on the day immediately preceding the Effective Date of such transaction.

Interest Payment Election

Unless an Event of Default has occurred and is continuing, the Company may elect, from time to time, subject to applicable regulatory approval, to satisfy its obligation to pay all or any portion of the Interest Obligation on an Interest Payment Date by delivering sufficient Common Shares to the Debenture Trustee for sale, to satisfy the Interest Obligation, or portion thereof, as applicable, on the Interest Payment Date, in which event holders of the Debentures will be entitled to receive a cash payment equal to the Interest Obligation or portion thereof, as applicable, from the proceeds of the sale of such Common Shares.

Modification

The rights of the holders of Debentures may be modified in accordance with the terms of the Indenture. For that purpose, among others, the Indenture contains certain provisions which make binding on all holders of outstanding Debentures, resolutions passed at meetings of the holders of outstanding Debentures by votes cast thereat by holders of not less than 66 2/3 % of the principal amount of the then-outstanding Debentures present at the meeting or represented by proxy, or rendered by instruments in writing signed by the holders of not less than 66 2/3 % of the principal amount of the then-outstanding Debentures. Under the Indenture, certain amendments of a technical nature or which are not prejudicial to the rights of the holders of the Debentures may be made to the Indenture without the consent of the holders of the Debentures.

Events of Default

The Indenture provides that an Event of Default in respect of the Debentures will occur if certain events described in the Indenture occur, including, without limitation, if any one or more of the following described events has occurred and continuing: (i) failure for 30 days to pay interest on the Debentures when due; (ii) failure to pay principal or premium, if any (whether by payment in cash or delivery of Common Shares), on the Debentures when due, whether at maturity, upon redemption, on a Change of Control, by declaration or otherwise; (iii) default in the delivery, when due, of any Common Shares or other consideration, including any Make-Whole Premium, payable upon conversion with respect to the Debentures, which default continues for 15 days; (iv) default in the observance or performance of any covenant or condition of the Indenture and the failure to cure (or obtain a waiver for) such default for a period of 30 days after notice in writing has been given by the Debenture Trustee or from holders of not less than 25% of the aggregate principal amount of the Debentures specifying such default and requiring the Company to rectify or obtain a waiver for same; (v) certain events of bankruptcy, insolvency or reorganization of the Company under bankruptcy or insolvency laws; and (vi) if an event of default occurs or exists under any agreement evidencing indebtedness for borrowed money (other than non-recourse debt) of the Company or any Subsidiary and as a result of such event of default (a) indebtedness for borrowed money thereunder in excess of Cdn$20,000,000 (or the equivalent amount in any other currency) has become due and payable before the date it would otherwise have been due and payable, and (b) the holders of such indebtedness are entitled to commence, and have commenced, the enforcement of security they hold for such indebtedness (if any) or the exercise of any other creditors' remedies to collect such indebtedness.

If an Event of Default has occurred and is continuing, the Debenture Trustee may, in its discretion, and will, upon the request of holders of not less than 25% in principal amount of the then outstanding Debentures declare the principal of (and premium, if any) and interest on all outstanding Debentures to be immediately due and payable. In certain cases, the holders of more than 50% of the principal amount of the Debentures then outstanding may, on behalf of the holders of all Debentures, waive any Event of Default and/or cancel any such declaration upon such terms and conditions as such holders shall prescribe.

Governing Laws

The Indenture and the Debentures are governed by, and construed in accordance with, the laws of the Province of Alberta and the federal laws of Canada applicable therein.

35

MARKET FOR SECURITIES

TransGlobe's Common Shares are listed and posted for trading on the TSX and the NASDAQ under the trading symbols "TGL" and "TGA" respectively. The Debentures are listed and posted for trading on the TSX under the trading symbol "TGL.DB".

Common Shares

The following table sets out the monthly high and low closing prices and the total monthly trading volumes for the Common Shares on the TSX for the indicated periods:

(Canadian dollars, except volumes)	Price Range
	High	Low
	($/share)	($/share)	Volume
2014
January	9.39	8.09	4,346,604
February	8.29	7.50	8,237,043
March	8.69	8.09	5,273,260
April	8.84	7.89	5,143,728
May	8.96	6.91	7,070,158
June	8.20	7.59	4,233,779
July	8.15	6.80	4,723,545
August	7.42	6.67	3,868,263
September	7.41	6.49	5,317,774
October	6.60	4.89	6,276,351
November	4.88	3.64	5,192,657
December	4.82	3.32	14,465,787
2015
January	4.79	3.28	8,178,162
February	4.17	3.57	4,856,946
March (1 to 11)	3.91	3.68	1,579,223

The following table sets out the monthly high and low closing prices and the total monthly trading volumes for the Common Shares on the NASDAQ for the indicated periods:

(U.S. dollars, except volumes)	Price Range
	High	Low
	($/share)	($/share)	Volume
2014
January	8.58	7.28	3,034,322
February	7.48	6.78	2,735,953
March	7.84	7.30	3,747,428
April	8.00	7.16	2,452,220
May	8.22	6.38	2,350,373
June	7.58	6.94	2,601,023
July	7.53	6.27	2,380,250
August	6.84	6.10	3,337,561
September	6.78	5.83	2,676,669
October	5.91	4.34	5,081,009
November	4.31	3.26	4,808,425
December	4.14	2.86	8,825,386
2015
January	4.08	2.75	8,415,706
February	3.34	2.87	5,294,287
March (1 to 11)	3.17	2.90	2,215,891

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Convertible Debentures

The following table sets out the monthly high and low closing prices and the total monthly trading volumes for the Debentures on the TSX for the indicated periods:

(Canadian dollars, except volumes)	Price Range
	High	Low
	($/share)	($/share)	Volume
2014
January	96.50	94.00	1,586,000
February	94.50	92.00	7,884,000
March	100.63	94.25	27,162,000
April	99.43	97.00	2,255,000
May	99.25	95.02	2,017,000
June	97.38	96.02	982,400
July	97.74	95.00	2,908,000
August	96.50	94.50	914,000
September	96.50	93.51	1,607,500
October	95.75	93.35	4,281,000
November	93.50	87.00	1,199,000
December	86.50	77.50	1,327,000
2015
January	83.00	76.00	3,551,000
February	85.99	82.25	2,220,500
March (1 to 11)	85.75	84.25	533,000

PRIOR SALES

The following table summarizes the issuance of stock options, which are convertible into Common Shares, during the year ended December 31, 2014:

Date of Issuance	Number of Stock Options	Price per Stock Option
March 6, 2014	75,000	Cdn$8.50
May 20, 2014	1,133,000	Cdn$7.26

The following table summarizes the issuance of restricted share units ("RSUs"), which are cash-settled, during the year ended December 31, 2014:

Date of Issuance	Number of RSUs	Price per RSU
May 20, 2014 (1)	288,500	N/A
May 28, 2014 (2)	4,313	N/A
June 30, 2014 (2)	1,986	N/A
August 14, 2014 (1)	54,682	N/A
August 24, 2014 (1)	23,343	N/A
September 30, 2014 (2)	3,169	N/A
November 19, 2014 (1)	47,603	N/A
December 31, 2014 (2)	5,738	N/A

Notes:

⁽¹⁾ The number of RSUs granted is determined in accordance with the RSU Plan and is based on a targeted level of base salary divided by the weighted-average price of the Common Shares traded on the TSX for the five business days preceding the date of grant.

⁽²⁾ Represents RSUs credited to the RSU holders' accounts as of each dividend payment date in respect of cash dividends which were paid on Common Shares throughout the fiscal year in accordance with the RSU Plan. The number of additional RSUs credited is determined by dividing: (a) the dividends that would have been paid to the holder if each RSU in the holder's account on the relevant dividend record date had been one Common Share, by (b) the weighted-average trading price of the Common Shares on the TSX for the last five trading days prior to the award date.

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The following table summarizes the issuance of performance share units ("PSUs"), which are cash-settled, during the year ended December 31, 2014:

Date of Issuance	Number of PSUs	Price per PSU
May 20, 2014 (1)	280,900	N/A
May 28, 2014 (2)	4,199	N/A
June 30, 2014 (2)	1,934	N/A
September 30, 2014 (2)	2,455	N/A
December 31, 2014 (2)	4,017	N/A

Notes:

⁽¹⁾ The number of PSUs granted is determined in accordance with the PSU Plan and is based on a targeted level of base salary divided by the weighted-average price of the Common Shares traded on the TSX for the five business days preceding the date of grant.

⁽²⁾ Represents PSUs credited to the PSU holders' accounts as of each dividend payment date in respect of cash dividends which were paid on Common Shares throughout the fiscal year in accordance with the PSU Plan. The number of additional PSUs credited is determined by dividing: (a) the dividends that would have been paid to the holder if each PSU in the holder's account on the relevant dividend record date had been one Common Share, by (b) the weighted-average trading price of the Common Shares on the TSX for the last five trading days prior to the award date.

The following table summarizes the issuance of deferred share units ("DSUs"), which are cash-settled, during the year ended December 31, 2014:

Date of Issuance	Number of DSUs	Price per DSU
May 20, 2014 (1)	86,453	N/A
May 28, 2014 (2)	1,292	N/A
June 30, 2014 (2)	595	N/A
August 14, 2014 (1)	57,802	N/A
September 30, 2014 (2)	1,249	N/A
December 31, 2014 (2)	2,044	N/A

Notes:

⁽¹⁾ DSUs are granted to directors of the Company. The number of DSUs granted is determined in accordance with the DSU Plan and is based on the portion of the annual retainer that the director elects to have paid in DSUs divided by the weighted-average price of the Common Shares traded on the TSX for the five business days preceding the date of grant.

⁽²⁾ Represents DSUs credited to the DSU holders' accounts as of each dividend payment date in respect of cash dividends which were paid on Common Shares throughout the fiscal year in accordance with the DSU Plan. The number of additional DSUs credited is determined by dividing: (a) the dividends that would have been paid to the holder if each DSU in the holder's account on the relevant dividend record date had been one Common Share, by (b) the weighted-average trading price of the Common Shares on the TSX for the last five trading days prior to the award date.

ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER

As at the date hereof, none of the Company's securities are subject to escrow or subject to contractual restrictions on transfer.

DIRECTORS AND OFFICERS

The name and place of residence of each director and officer, the offices held by each in the Company, the principal occupation of each director and officer, the period served as director or officer and the number of securities of the Company owned by such individuals as at March 11, 2015 is as follows:

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		Year Became
Name and Place of		Director or	Principal Occupation and Positions
Residence	Position Held	Officer	for the Past Five Years
Robert G. Jennings (1)(3) Alberta, Canada	Chairman of the Board and Director	2011	Retired as Chairman and CEO of Jennings Capital Inc. in May, 2011. Prior to founding Jennings Capital in 1993, Senior Vice President and Director with Midland Walwyn Capital Inc, co-founder of Carson Jennings & Associates, Director and Vice President with McLeod Young Weir.
Ross G. Clarkson Alberta, Canada	President, Chief Executive Officer and Director	1995	President and Chief Executive Officer of the Company since December 4, 1996, with over 40 years' oil and gas industry experience as a senior geological advisor.
Lloyd W. Herrick Alberta, Canada	Vice-President, Chief Operating Officer and Director	1999	Vice-President and Chief Operating Officer of the Company since April 28, 1999, with over 40 years' experience in both domestic and international oil and gas exploration and development.
Geoffrey C. Chase (1)(2)(4) Alberta, Canada	Director	2000	Retired Senior Vice-President, Business Development with Ranger Oil Limited, with over 35 years' experience in the oil and gas industry.
David B. Cook(1)(3) Alberta, Canada	Director	2014	Currently Chief Executive Officer of DONG Exploration and Production (part of the DONG Energy Group) located in Copenhagen, Denmark. Previously served as Executive Officer and Head of Oil and Gas at TAQA North ltd ("TAQA") where he lead the Company's upstream and midstream interests in the Middle East, North America, the United Kingdom and Europe. Prior to joining TAQA, he served as Vice President for BP Russia, responsible for British Petroleum's ("BP") non-TNK-BP exploration and production activities in Russia.
Fred J. Dyment (1)(2)(3) Alberta, Canada	Director	2004	Chartered accountant with over 30 years' experience in the oil and gas industry. Previously President and Chief Executive Officer, Maxx Petroleum Company (2000 – 2001). Prior thereto Controller, Vice-President, Finance and President and Chief Executive Officer of Ranger Oil Limited from 1978 – 2000.
Bob (G.R.) MacDougall(2)(4) Alberta, Canada	Director	2014	Previously served as Executive Vice President and Chief Operating Officer of Vermilion Energy Inc. from 2004 until his retirement in 2012 where he led the company's operating business both domestically and internationally, with assets in France, The Netherlands, Australia and Ireland. Prior to this, Mr. MacDougall was with Chevron for nearly 20 years in production and drilling operations and served as General Manager of Production and Operations for ChevronTexaco's Western Canadian producing properties. He has over 30 years’ experience in domestic and international oil and gas operations as well as and senior executive management experience.
Susan M. MacKenzie Alberta, Canada	Director	2014	Served as Chief Operating Officer with Oilsands Quest Inc., a NYSE Amex-listed oil sands company, from April - September 2010. Prior thereto, Ms. MacKenzie was employed for 12 years at PetroCanada, where she held senior roles including Vice President, Human Resources and Vice President of In Situ Development and Operations. Prior thereto employed with Amoco Canada Petroleum Company Ltd. for 14 years in a variety of engineering and leadership roles in natural gas, conventional oil and heavy oil exploitation.
Randy C. Neely Alberta, Canada	Vice-President, Finance, Chief Financial Officer and Secretary	2012	Vice President Finance and Chief Financial Officer of the Company since May 8, 2012 with over 20 years in executive financial positions within the oil and gas industry.
Albert E. Gress Alberta, Canada	Vice President, Business Development	2011	Vice President Business Development since March 13, 2011. Certified Public Accountant with over 15 years’ experience in the international petroleum industry. Prior to joining TransGlobe as Country Manager of Egypt in 2007, led operations in Egypt for Madrid-based CEPSA and for Devon Energy and worked as a business development advisor for CEPSA in Madrid.
Brett Norris Alberta, Canada	Vice President, Exploration	2012	Vice President Exploration since April 8, 2012 and with the Company since 2006. A professional geologist with over 24 years of domestic and international experience. A registered member of the Association of Professional Engineer and Geosciences of Alberta ("APEGGA").

Notes:

(1) Member of the Company's Audit Committee.

(2) Member of the Company's Compensation Committee.

(3) Member of the Company's Governance and Nominating Committee.

(4) Member of the Company's Reserves Committee.

(5) As at March 11, 2015, the directors and officers of TransGlobe, as a group, beneficially owned or controlled or directed, directly or indirectly, 3,349,276 Common Shares or approximately 4% of the issued and outstanding Common Shares.

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(6) Mr. Gary S. Guidry tendered his resignation from the Company's board of directors on March 11, 2014.

(7) Mr. Erwin Noyes retired from the Company's board of directors on June 10, 2014.

Cease-Trade Orders

No current director or executive officer of the Company has, within the last ten years prior to the date of this Annual Information Form, been a director, chief executive officer or chief financial officer of any issuer (including the Company) that:

(a) while the person was acting in the capacity as director, chief executive officer or chief financial officer, was the subject of a cease trade or similar order or an order that denied the company access to any exemption under securities legislation, that was in effect for a period of more than thirty (30) consecutive days; or

(b) was subject to an order that resulted, after the director, executive officer ceased to be a director, chief executive officer or chief financial officer of an issuer, in the issuer being the subject of a cease trade or similar order or an order that denied the relevant issuer access to any exemption under securities legislation, for a period of more than thirty (30) consecutive days, which resulted from an event that occurred while that person was acting as a director, chief executive officer or chief financial officer of the issuer.

Bankruptcies

No current director or executive officer or securityholder holding a sufficient number of securities of the Company to affect materially the control of the Company has, within the last ten years prior to the date of this document, been a director or executive officer of any company (including the Company) that, while such person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement for compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.

In addition, no current director or executive officer or securityholder holding a sufficient number of securities of the Company to affect materially the control of the Company has, within the last ten years prior to the date of this document, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, officer or securityholder.

Penalties or Sanctions

No current director or officer or securityholder holding a sufficient number of securities of the Company to affect materially the control of the Company has been subject to: (i) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

Conflicts of Interest

Directors and officers of the Company may, from time to time, be involved with the business and operations of other oil and gas issuers, in which case a conflict may arise. Conflicts of interest, if any, which arise will be subject to and governed by procedures prescribed by the ABCA, which require a director or officer of a corporation who is a party to, or is a director or an officer of, or has a material interest in any person who is a party to, a material contract or proposed material contract with the Company disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the ABCA. See "Risk Factors".

INTERESTS OF EXPERTS

Names of Experts

Other than as described below, there is no person or corporation who is named as having prepared or certified a statement, report or valuation described and included in the filing, or referred to in a filing, made under NI 51-102 by the Company during, or relating to the Company's most recently completed financial year whose profession or business gives authority to the statement, report or valuation made by the person, or Company, other than DeGolyer, the Company's independent engineering evaluator, and Deloitte LLP, the Company's independent auditor.

Interests of Experts

There were no registered or beneficial interests, direct or indirect, in any securities or other property of the Company or of one of its associates or affiliates: (i) held by DeGolyer or by the "designated professionals" (as defined in Form 51-102F2 to NI 51-102) of DeGolyer, when DeGolyer prepared the report, valuation, statement or opinion referred to herein as having been prepared by DeGolyer; (ii) received by DeGolyer or by the "designated professionals" of DeGolyer, after the time specified above; or (iii) to be received by DeGolyer or by the "designated professionals" of DeGolyer; except in each case for the ownership of Common Shares, which in respect of DeGolyer and DeGolyer's "designated professionals", as a group, has at all relevant times represented less than one percent of the outstanding Common Shares. In addition, neither DeGolyer, nor any director, officer or employee of DeGolyer, is or is expected to be elected, appointed or employed as a director, officer or employee of the Company or of any associate or affiliate of the Company.

Deloitte LLP is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the applicable rules and regulations thereunder adopted by the SEC and the Public Company Accounting Oversight Board (United States).

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings material to the Company to which the Company is or was a party or in respect of which any of its respective properties are or were the subject of during the 2014 financial year, nor are there any such proceedings known to be contemplated. In addition, there were no penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority during the 2014 financial year, no other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to

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a reasonable investor in making an investment decision, and no settlement agreements entered into by the Company with a court relating to securities legislation or with a securities regulatory authority during the 2014 financial year.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Other than as set forth herein, there were no material interests, direct or indirect, of any directors or executive officers of the Company, any shareholder who beneficially owns more than 10% of the outstanding Common Shares or who exercises control or direction over more than 10% of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or is reasonably expected to materially affect the Company.

TRANSFER AGENT AND REGISTRAR

Computershare Trust Company, at its principal offices in Calgary, Alberta and Toronto, Ontario is the transfer agent and registrar of the Common Shares and the transfer agent and registrar and the Debenture Trustee of the Debentures.

MATERIAL CONTRACTS

Other than discussed herein, there are no material contracts, other than the contracts entered into in the ordinary course of business, that are material to the Company and that were entered into within the most recently completed financial year, or before the most recently completed financial year but are still in effect other than: (i) the Indenture, which is filed on SEDAR at www.sedar.com; and (ii) the credit agreement dated July 22, 2010, for which an amendment was finalized on June 11, 2013, between a subsidiary of the Company and a syndicate of three financial institutions in respect of a $100.0 million borrowing base credit facility. The credit facility bears interest at the LIBOR rate plus an applicable margin, which ranges from 5.0% to 5.5% dependent on the utilizations outstanding, and are secured by a pledge over certain bank accounts of certain of the Company's subsidiaries, a pledge over the shares of certain of the Company's subsidiaries, a fixed and floating charge over certain assets of the Company and parent and subsidiary corporate guarantees. A copy of the Company's credit agreement is filed on SEDAR at www.sedar.com.

AUDIT COMMITTEE INFORMATION

Composition of the Audit Committee

The audit committee of the Company (the "Audit Committee") is currently comprised of Messrs. Fred Dyment (Chair), Geoffrey Chase, Robert Jennings and David Cook. The following chart sets out the assessment of each Audit Committee member's independence, financial literacy and relevant educational background and experience supporting such financial literacy.

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Name and Place of Residence	Independent	Financially Literate	Relevant Education and Experience
Fred J. Dyment Alberta, Canada	Yes	Yes	Mr. Dyment is an independent businessman. Mr. Dyment is an experienced senior executive and board director, with over 40 years of experience in the oil and natural gas industry. From 1978 to 2000, Mr. Dyment held increasingly senior positions with Ranger Oil Limited, including Chief Financial Officer, President and Chief Executive Officer. Mr. Dyment also held the position of President and Chief Executive Officer at Maxx Petroleum Company from 2000 to 2001. Mr. Dyment is currently Chairman of WesternZagros Resources Ltd., an international resource company engaged in acquiring properties and exploring for, developing and producing crude oil and natural gas. Mr. Dyment received a Chartered Accountant designation from the province of Ontario in 1972.
Geoffrey C. Chase Alberta, Canada	Yes	Yes	Mr. Chase is a retired (1999) professional engineer. Mr. Chase has over 40 years’ experience in both Canadian and international oil and gas operations, the majority of which was gained while at Ranger Oil Limited. As well as responsibility for production, drilling and construction operations as Vice President - Production at Ranger, Mr. Chase was involved in numerous merger and acquisition activities in Canada and internationally. In 1995, as Senior Vice President of Business Development, he became responsible for identifying and assessing development opportunities in West Africa, South America and elsewhere. Also while at Ranger, Mr. Chase participated in the formation of Direct Energy Marketing Ltd., a joint venture marketing company, serving on its Board from 1986 and was Chairman from 1990 until 1994. Mr. Chase obtained his ICD.D designation from the Institute of Corporate Directors in 2010 and is a Life Member of APEGA.
Robert G. Jennings Alberta, Canada	Yes	Yes	Mr. Jennings is an independent businessman. He retired in 2011 from Jennings Capital Inc. which he established in 1993, as a full service, independent investment firm providing corporations with research, corporate finance and sales services in both the national and international marketplace. From 1969 to 1979, Mr. Jennings was with McLeod Young (predecessor to ScotiaMcLeod), where he held positions of increasing responsibility, initially as an oil and gas analyst, then in the corporate finance area. In 1976 he was promoted to Vice President of corporate finance for the Alberta area and held that position until 1979. In January 1979, Mr. Jennings created a boutique firm, Carson Jennings & Associates, focused on oil and gas private placements and merger/acquisition activities. In September 1988, Mr. Jennings sold the firm to Walwyn Stodgell Ltd., (prior to Walwyn’s takeover of Midland Doherty), accepting the position of Senior Vice President and Director of Corporate and Government Finance for Western Canada with Midland Walwyn Capital Inc. He remained in the position until August 1993, when he founded Jennings Capital Inc. in Calgary. Mr. Jennings has and currently serves as a board member on certain private companies as well as educational and charitable organizations
David B. Cook Copenhagen, Denmark	Yes	Yes	Mr. Cook is currently Chief Executive Officer of DONG Exploration and Production (part of the DONG Energy Group) located in Copenhagen, Denmark. Mr. Cook previously served as Executive Officer and Head of Oil and Gas at TAQA North ltd ("TAQA") where he lead the Company's upstream and midstream interests in the Middle East, North America, the United Kingdom and Europe. Prior to joining TAQA, he served as Vice President for BP Russia, responsible for British Petroleum's ("BP") non-TNK-BP exploration and production activities in Russia. Mr. Cook has held a variety of global technical, commercial and managerial positions based from the US, UK, Russia and the Middle East as well as board of director roles. Mr. Cook holds a BSc in Geophysics and a PhD in Geological Sciences.

Pre-Approval of Policies and Procedures

It is within the mandate of the Company’s Audit Committee to approve all audit and non-audit related fees. The Audit Committee is informed routinely as to the non-audit services to be provided by the auditor pursuant to this pre-approval process. The auditors also present the estimate for the annual audit related services to the Audit Committee for approval prior to undertaking the annual audit of the financial statements.

The Audit Committee’s pre-approval procedure is to approve all non-audit services to be performed by the Company’s auditors in advance of the engagement of the Company’s auditors to perform such services. The pre-approval process involves management presenting the Audit Committee with a description of any proposed non-audit services. The Audit Committee considers the appropriateness of such services and whether the provision of those services would impact the auditor’s independence, including the magnitude of the potential fees. Once the committee has satisfied itself of its concerns, if any, it then votes either in favor of or against contracting the Company’s auditors to perform the proposed non-audit services.

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Audit Committee Charter

The full text of the Company's audit committee charter is included in Schedule "C" to this Annual Information Form.

Principal Accountant Fees and Services

The aggregate fees for professional services billed to TransGlobe by Deloitte LLP during the fiscal years ended December 31, 2014 and December 31, 2013 were as follows (all fees are in Canadian dollars):

	Fiscal Year Ended		Fiscal Year Ended
	December 31, 2014		December 31, 2013
Audit Fees	$	456,816	$	541,969
Audit Related Fees	$	39,824	$	15,459
Tax Fees	$	94,080	$	6,206
All Other Fees	NIL		NIL
TOTAL	$	590,720	$	563,634

The nature of the services provided by Deloitte LLP under each of the categories indicated in the table is described below.

Audit Fees

Audit fees were for professional services rendered by Deloitte LLP for the audit of the Company’s annual financial statements, as well as for the review of the Company's interim quarterly financial statements and services provided in connection with statutory and regulatory filings or engagements.

Audit Related Fees

Audit related fees were for professional services rendered by Deloitte LLP for assurance and related services that are reasonably related to the audit of the Company’s annual financial statements (not included in audit fees).

Tax Fees

Tax fees were for tax compliance, including the review of tax returns, tax advice and tax planning and advisory services relating to common forms of domestic and international taxation (i.e. income tax, capital tax, goods and services tax and payroll tax).

All Other Fees

During the fiscal years ended December 31, 2014 and 2013, no other fees were incurred other than those described above.

RISK FACTORS

The Company is engaged in the exploration, development, production and acquisition of crude oil and natural gas. These activities involve a number of risks and uncertainties inherent in the industry, some of which are summarized below. If any of the risks described below materializes, the Company's business, financial condition, operating results or prospects could be materially and adversely affected. The following are material risks identified by the Company; however, risks that are at this time unknown to management of the Company or that the Company currently deems immaterial may develop and may have a material adverse effect upon its business, financial condition, operating results and prospects.

Risks relating to the Company's business

The marketability and price of oil may be affected by numerous factors beyond the Company's control

The marketability and price of crude oil which may be acquired or discovered by the Company may be affected by numerous factors beyond the control of the Company. Historically, crude oil prices have been volatile, and the Company expects this price volatility to continue in the future. Crude oil prices may fluctuate widely in response to relatively minor changes in the supply of and demand for crude oil, market uncertainty and a variety of additional factors that are beyond the Company's control, such as:

• the differential between the price paid by refiners for light, quality oil and various grades of oil produced by the Company;

• the level of consumer demand for oil and natural gas;

• the domestic and foreign supply of oil and natural gas;

• commodity processing, gathering and transportation availability, and the availability of refining capacity;

• the price and level of imports of foreign oil and natural gas;

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

• domestic and foreign governmental regulations and taxation;

• the price and availability of alternative fuel sources;

• weather conditions, accidents;

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• political conditions or hostilities in oil and natural gas producing regions, including the Middle East, Africa and South America;

• technological advances affecting energy consumption and energy supply;

• the availability of pipeline capacities and infrastructure;

• the availability of crude oil transportation and refining capacity;

• variations between product prices at sales points and applicable index prices; and

• worldwide economic conditions.

The Company makes price assumptions that are used for planning purposes, and a significant portion of its cash outlays, including rent, salaries and non-cancellable capital commitments, are largely fixed in nature. Accordingly, if oil or natural gas prices are below the expectations on which these commitments were based, the Company's financial results are likely to be adversely and disproportionately affected because these cash outlays are often fixed in the short term and cannot be quickly reduced to respond to unanticipated decreases in oil and natural gas prices.

Significant or extended price declines could also adversely affect the amount of crude oil that the Company can produce economically. A reduction in production could result in a shortfall in expected cash flows and require the Company to reduce capital spending or borrow funds to cover any such shortfall. This could raise delays or part payment in some of the Company's projects and limit its access to sources of capital. Significant or extended price declines could also result in a reduction in the carrying value of goodwill. Any of these factors could negatively affect the Company's ability to replace production and its future growth rate.

The Company has historically entered into derivative contracts occasionally to hedge price risk associated with a portion of its crude oil production. Because the Company's derivative contracts do not apply to all of its crude oil production, they provide only partial price protection against declines in crude oil prices.

The operations and earnings of the Company and its subsidiaries are also affected by local, regional and global events or conditions that affect supply and demand for oil and natural gas. These events or conditions are generally not predictable and include, among other things, the development of new supply sources; supply disruptions; weather; international political events; technological advances; and the competitiveness of alternative energy sources or product substitutes. The Company's operations will be further affected by the remoteness of, and restrictions on access to, certain properties as well as climatic conditions. In addition, there is no assurance that further commercial quantities of crude oil will be discovered by the Company.

The Company operates only in Egypt and Yemen

The Company's business focuses on the petroleum industry in a limited number of properties, namely in Egypt and Yemen. Larger companies have the ability to manage their risk by diversification. However, the Company lacks diversification, in terms of both the nature and geographic scope of its business. As a result, factors affecting the industry or the regions in which it operates will likely impact the Company more acutely than if the Company's business was more diversified.

Doing business in Egypt and Yemen subjects the Company to significant political risks that may adversely affect its operations

Beyond the risks inherent in the petroleum industry, the Company is subject to additional political risks resulting from doing business in Egypt and Yemen. Since 2011, there has been significant civil unrest and widespread protests and demonstrations throughout the Middle East, including in Egypt and Yemen.

On February 11, 2011, after widespread protests, demonstrations and civil unrest, Hosni Mubarak resigned as the President of Egypt. He relinquished the administration of power first to his Vice President and then to a transitional government led by the Egyptian military, which then appointed a civilian prime minister and cabinet to run the Egyptian government. A public referendum in Egypt produced a temporary constitutional framework that empowered the Egyptian military to govern Egypt in the interim, with the goal of transferring power to a civilian government and drafting a new constitution in 2012. In December 2011 and January 2012, a parliament was elected to the People's Assembly but was later determined to be unconstitutional by the High Constitutional Court of Egypt and disbanded. On June 24, 2012 Mohamed Morsi became the first democratically elected president of Egypt in a run-off election with Ahmed Shafiq. On November 22, 2012 President Morsi, in an effort to expedite the approval and referendum on a new constitution, issued a Presidential decree making his decisions impervious to judicial challenge. On December 25, 2012 Egypt formally approved the new constitution. On February 25, 2013 President Morsi announced that new parliamentary elections would take place from April to June, however, these elections were postponed. In late June 2013, massive civil protests in Cairo and other large population centres in Egypt began which ultimately led to the Egyptian military removing the President from his office on July 3, 2013. Additional protests held by supporters of Mohamed Morsi continued in Cairo and other major cities in Egypt for several weeks following his removal from office. An Egyptian military appointed interim President and cabinet were responsible for governing Egypt from July 3, 2013 until June 8, 2014, when the current President, Abdel Fattah el-Sisi, was elected.

In Yemen, civil unrest led to the resignation of that country's President, Ali Abdullah Saleh, in late-November 2011. On February 21, 2012, presidential elections were held electing then Vice President Abd Rabboh Mansour Hadi the President of Yemen who was tasked with securing political stability in Yemen, including implementing a power-sharing deal with political opponents of the Saleh regime under an agreement negotiated to remove Mr. Saleh after 33 years in power. In January 2015, tribal forces overran the capital in Sana'a and President Hadi retreated to Aden. The UN and other parties are working to broker a resolution to the political turmoil but it remains unresolved at this time. There is no guarantee that the new leadership in Yemen will be able to secure political stability.

Governments in Egypt and Yemen could adopt new policies that might result in substantially hostile attitudes towards foreign investments such as the Company's. In an extreme case, these governments could result in forced renegotiation of the Company's existing contracts, termination of contract rights and expropriation of its assets or resource nationalization. Loss of property (damage to, or destruction of, the Company's wells, production facilities or other operating assets) and/or interruption of its business plans (including lack of availability of drilling rigs, oilfield equipment or services if third party providers decide to exit the region or inability of the Company's service equipment providers to deliver necessary items for the Company to continue operations) as a direct or indirect result of political protests, demonstrations or civil unrest in Egypt or Yemen could have a material adverse impact on the Company's results of operations and financial condition. In addition, the Company cannot provide assurance that future political developments in

44

Egypt or Yemen, including changes in government, changes in laws or regulations, export restrictions or further civil unrest or other disturbances, would not have an adverse impact on ongoing operations, the Company's ability to comply with its current contractual obligations, or on the terms or enforceability of its production sharing and concession agreements or other contracts with governmental entities.

Unless the Company replaces its crude oil reserves, its reserves and production will decline, which would adversely affect the Company's cash flow and results of operations.

Unless the Company conducts successful development and exploration activities or acquires properties containing proved reserves, its proved reserves will decline as those reserves are produced. Producing crude oil reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The Company's future crude oil reserves and production, and therefore its cash flow and results of operations, are highly dependent on the Company's success in efficiently developing and exploiting its current reserves and economically finding or acquiring additional recoverable reserves. The Company may not be able to develop, exploit, find or acquire sufficient additional reserves to replace its current and future production.

The Company's exploration and development programs may not be successful

The Company's participation in the East Ghazalat, West Gharib, West Bakr, North West Gharib, South West Gharib, South East Gharib, South Ghazalat, South Alamein and North West Sitra production sharing contracts in Egypt and Blocks 75 and S-1 in Yemen, represent major undertakings. The exploration programs in Egypt and Yemen are high-risk ventures with uncertain prospects for ongoing success. Existing and new wells that the Company drills may not be productive, or the Company may not recover all or any portion of its investment in such wells. No known technologies allow the Company to know conclusively prior to drilling a well that crude oil is present or may be produced economically. Drilling often involves unprofitable results, not only from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Furthermore, the Company's drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

• unexpected drilling conditions;

• pressure or lost circulation in formations;

• equipment failure or accidents;

• fracture stimulation accidents or failures;

• adverse weather conditions;

• compliance with environmental, governmental or contractual requirements; and

• increases in the cost of, or shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

The governments of Egypt and Yemen may not honour their agreements with the Company

There can be no assurance that the agreements entered into with the governments of Egypt and Yemen and others are enforceable or binding in accordance with the Company’s understanding of their terms or that if breached, the Company would be able to find a remedy. The Company bears the risk that a change of government could occur and a new government may void the agreements, laws and regulations that the Company is relying on.

The sale of the Company's crude oil production depends in part on gathering, transportation and processing facilities. Any limitation in the availability of, or the Company's access to, those facilities would interfere with its ability to market the crude oil that the Company produces and could adversely impact the Company's drilling program, cash flows and results of operations.

The Company delivers crude oil through gathering, processing and pipeline systems that the Company does not own. The amount of crude oil that the Company can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. The lack of availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing facilities, could result in the Company's inability to realize the full economic potential of its production. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities could harm the Company's business and, in turn, its financial condition, results of operations and cash flows.

The market price of the Common Shares and Debentures may be volatile

The market price of the Common Shares and Debentures (collectively, the "Listed Securities") may be volatile. The volatility may affect the ability of holders of Listed Securities to sell the Listed Securities at an advantageous price. Market price fluctuations in the Listed Securities may be due to the Company's operating results failing to meet the expectations of securities analysts or investors in any quarter, downward revision in securities analysts' estimates, governmental regulatory action, adverse change in general market conditions or economic trends, acquisitions, dispositions or other material public announcements by the Company or its competitors, along with a variety of additional factors, including, without limitation, those set forth under "Forward-Looking Statements". In addition, the market price for securities in the stock markets can experience significant price and trading fluctuations. These fluctuations can result in volatility in the market prices of securities that is often unrelated or disproportionate to changes in operating performance. These broad market fluctuations may adversely affect the market prices of the Listed Securities.

Changes in governments or actions by governmental authorities could have an adverse impact on the Company's joint ventures, licenses or other legal arrangements

There can be no assurance that joint ventures, licenses, license applications or other legal arrangements will not be adversely affected by changes in governments, the actions of government authorities, or the effectiveness and enforcement of such arrangements.

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The Company may be adversely affected by foreign currency fluctuations

The Canadian dollar to US dollar and Egyptian pound to US dollar exchange rates have fluctuated over time. The Company's exposure to currency exchange rate risks is primarily limited to Canadian general and administrative expenses which are paid for in Canadian dollars, along with Egyptian pound cash balances. The Company prepares its financial statements in US dollars and, as a result, the Company’s statement of comprehensive income, statement of cash flows and statement of financial position are impacted by changes in exchange rates between Canadian dollars, Egyptian pounds and US dollars.

The Company is exposed to third-party credit risk

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 crude oil production and other parties, including the governments of Egypt and Yemen. Significant changes in the crude 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 has in the past made regular payments on these amounts owing, the timing of these payments has historically been longer than normal industry standard. There can be no assurance that future payments will occur on a more timely basis or occur at all. 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 operations and its ability to conduct its ongoing capital expenditure program.

The Company entered into a new joint marketing agreement with the Egyptian Government in December 2014. The new agreement, which became effective in January 2015, allows TransGlobe to directly contract oil shipments with international buyers. The first oil shipment under this agreement was lifted on January 24, 2015 and was delivered to the end buyer in February, and the second lifting is scheduled for April 2015. TransGlobe anticipates that this new marketing process will be extended and thereby reduce or eliminate future issues regarding receivables for oil sales.

The Company's financing arrangements could negatively impact its business

The Company currently has an $85.5 million credit facility. Currently, no amounts are drawn on this credit facility which is syndicated with three financial institutions. A redetermination of the borrowing base of the credit facility is made on a semi-annual basis at which time the lenders determine the level of the facility that they are willing to extend to the Company based on the Company’s proved and probable reserves, oil prices, applicable discount rate and other factors. In the event that the facility’s borrowing base is reduced below the amount drawn, the difference will be repayable at that date. A reduction in the borrowing base could affect the Company's ability to fund ongoing operations.

The Company is required to comply with covenants under the credit facility. In the event that the Company does not comply with covenants under the credit facility, the Company's access to capital could be restricted or repayment could be required.

The Company's ability to obtain cash from its foreign subsidiaries may be restricted

The Company currently conducts all of its operations through its foreign subsidiaries and foreign branches. Therefore, the Company will be dependent on the cash flows of these subsidiaries to meet its obligations. The ability of its subsidiaries to make payments to the Company may be constrained by, among other things: the level of taxation, particularly corporate profits and withholding taxes, in the jurisdictions in which it operates; the introduction of exchange controls or repatriation restrictions or the availability of hard currency to be repatriated; and contractual restrictions with third parties.

The Company may be unable to obtain necessary future financing

As a result of global economic volatility, the Company, along with all other oil and gas entities, may have restricted access to capital and increased borrowing costs. The lending capacity of all financial institutions has diminished and risk premiums have increased independent of the Company's business and asset base. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, the Company's ability to do so is dependent on, among other factors, the overall state of capital markets, the Company’s credit rating, interest rates, tax burden due to new tax laws and investor appetite for investments in the energy industry and the Company's securities in particular.

To the extent that external sources of capital become limited or unavailable or available on onerous terms, the Company's ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result.

If cash flow from operations is lower than expected or capital costs for these projects exceed current estimates, or if the Company incurs major unanticipated expenses related to development or maintenance of its existing properties, it may be required to seek additional capital to maintain its capital expenditures at planned levels. In addition, the future development of the Company's petroleum properties may require additional financing and there are no assurances that such financing will be available or, if available, will be available on acceptable terms. Failure to obtain financing necessary for the Company's capital expenditure plans may result in a delay in development or production on the Company's properties.

The Company's foreign operations may become subject to exchange controls

Exchange controls may be implemented which could prevent the Company from transferring funds abroad. For example, certain governments have imposed a number of 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. These central banks may require prior authorization and may or may not grant such authorization for the Company's foreign subsidiaries to transfer funds to it and there may be a tax imposed with respect to the expatriation of the proceeds from the Company's foreign subsidiaries.

The Company could experience periods of higher costs if commodity prices rise and these increases could reduce its profitability, cash flow and ability to complete development activities as planned

Historically, the Company's capital and operating costs have risen during periods of increasing commodity prices. These cost increases result from a variety of factors beyond the Company's control, such as: increases in the cost of electricity, steel and other raw materials that the Company and its vendors rely upon; increased demand for labour, services and materials as drilling activity increases; and increased taxes. Increased levels of drilling

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activity in the petroleum industry in recent periods has led to increased costs of certain drilling equipment, materials and supplies. Such costs may rise faster than increases in the Company's revenue, thereby negatively affecting its profitability, cash flow and ability to complete development activities as scheduled and on budget.

The Company is subject to, and could be adversely affected by, the risks normally incident to petroleum exploration and production operations, and the Company is not fully insured against all these risks

The Company's operations are subject to all the risks normally incident to the exploration for and production of petroleum including geological risks, operating risks, political risks, development risks, marketing risks and logistical risks of operating in Egypt and Yemen. The risks normally incident to the operation and development of petroleum properties and the drilling of wells include encountering unexpected formations or pressures, premature decline of reservoirs, invasion of water into producing formations, blow-outs, cratering, fires and oil spills, all of which could result in personal injuries, loss of life and damage to the property of the Company and others. The Company is also subject to risks associated with deliverability uncertainties related to the proximity of its reserves to pipeline and processing facilities, extensive government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of its production and many other aspects of the petroleum business. The Company is not fully insured against all of these risks, nor are all such risks insurable, and, as a result, liability of the Company arising from these risks could have a material adverse effect upon its financial condition.

In addition to political risks, the Company is subject to other risks inherent to doing business exclusively in foreign jurisdictions

All of the Company's current production is located in Egypt and Yemen. As such, and in addition to the specific political risks mentioned above, the Company is subject to political, economic, and other uncertainties, including, but not limited to, expropriation of property without fair compensation, changes in energy policies or the personnel administering them, a change in oil or natural gas pricing policy, the actions of national labour unions, nationalization, currency fluctuations and devaluations, renegotiation or nullification of existing concessions and contracts, exchange controls and royalty and tax increases and retroactive tax claims, investment restrictions, import and export regulations and other risks arising out of foreign governmental sovereignty over the areas in which the Company's operations are conducted, as well as risks of loss due to civil strife, acts of war, terrorist activities and insurrections, economic sanctions, the imposition of specific drilling obligations and the development and abandonment of fields.

The Company's operations may also be adversely affected by laws and policies of Canada, Egypt and Yemen affecting foreign trade, taxation and investment. In the event of a dispute arising in connection with the Company's operations in Egypt and Yemen, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign oil ministries and national oil companies, to the jurisdictions of the courts of Canada or enforcing Canadian judgments in such other jurisdictions. The Company may also be hindered or prevented from enforcing its rights with respect to a governmental instrumentality because of the doctrine of sovereign immunity. Accordingly, the Company's exploration, development and production activities in Egypt and Yemen could be substantially affected by factors beyond the Company's control, any of which could have a material adverse effect on the Company.

If the Company's operations are disrupted and/or the economic integrity of its projects are threatened for unexpected reasons, its business may be harmed. These unexpected events may be due to technical difficulties, operational difficulties which impact the production, transport or sale of the Company's products, security risks related to terrorist activities and insurrections, difficult geographic and weather conditions, unforeseen business reasons or otherwise. Prolonged problems may threaten the commercial viability of its operations.

The Company's commodity price risk management and trading activities may prevent it from benefiting fully from price increases and may expose the Company to further risks.

To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, it may also be prevented from realizing the full benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Company's hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:

• the Company's production falls short of the hedged volumes;

• there is a widening of price-basis differentials between delivery points for the Company's production and the delivery point assumed in the hedge arrangement;

• the counterparties to the Company's hedging or other price risk management contracts fail to perform under those arrangements; or

• a sudden unexpected event materially impacts oil and natural gas prices.

The Company's licences may expire and are subject to minimum work commitments

The properties in Egypt and Yemen in which the Company holds a participating interest, directly or indirectly, are held by production sharing concessions and agreements that impose minimum work and expenditure obligations within specified time frames. The failure to meet such minimum work and expenditure obligations within the specified time frames may result in the termination of such production sharing concessions and agreements. There can be no assurance that the minimum work and expenditure obligations will be met by the Company and its participating interest partners. The termination of such production sharing concessions and agreements may have a material adverse effect on the Company's business, financial conditions, results of operations and production.

Local oil and gas industry conditions are not as developed as the North American industry

The oil and gas industry in Egypt and Yemen is not as efficient or developed as the oil and gas industry in North America. As a result, the Company's exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. The Company expects that such factors will subject its operations to economic and operating risks that may not be experienced in North American operations.

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The Company operates in a highly competitive industry

The Company is subject to risks due to the relatively small size of the Company, its level of cash flow, and the nature of the Company's involvement in the exploration for, and the acquisition, development and production of, crude oil, which even a combination of experience, knowledge and careful evaluation may not be able to overcome.

The Company encounters strong competition from other independent operators and from major oil companies in acquiring properties suitable for development, in contracting for drilling equipment, production equipment and in securing trained personnel. Many of these competitors have financial resources and staffs substantially larger than those available to the Company, which can be particularly important in the areas in which it operates. Those companies may be able to pay more for productive crude oil properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or personnel resources permit. In addition, those companies may be able to offer better compensation packages to attract and retain qualified personnel than the Company is able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. The Company's ability to acquire additional prospects and to find and develop reserves in the future will depend on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. There is also substantial competition for capital available for investment in the oil and natural gas industry. The Company may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. The Company's failure to acquire properties, market its production and secure trained personnel and adequately compensate personnel could have a material adverse effect on the Company's production, revenues and results of operations.

The Company is subject to significant governmental laws and regulations in each jurisdiction in which it operates and changes to such laws and regulations could negatively impact its results of operations and production

In the areas where the Company conducts activities, there are statutory laws and regulations governing the activities of oil and gas companies. These laws and regulations allow administrative agencies to govern the activities of oil companies in the development, production and sale of both oil and gas. Changes in these laws and regulations may result in forced divestitures of assets; restrictions on production, imports and exports; price controls; tax increases; royalty increases and retroactive tax claims; expropriation of property; and cancellation of contract rights. Both the likelihood of such occurrences and their overall effect upon the Company can vary greatly, are not predictable and may substantially increase or decrease the costs of conducting any exploration or development project. Compliance costs can be significant. Failure to comply with these laws may result in the suspension or termination of operations and subject the Company to liability and administrative, civil and criminal remedies.

The Company may be unable to meet all of its joint venture commitments and it does not control all of the properties in which it has an interest

The Company participates in Egypt and Yemen with industry partners with access to greater resources from which to meet their joint venture capital commitments. Should the Company be unable to meet its commitments, the joint venture partners may assume some or all of the Company's deficiency and thereby assume a pro-rata portion of the Company's interest in production from the joint venture lands. The Company is not a majority interest owner in and does not operate all of its properties and does not have sole control over the future course of development in those properties in which it holds less than 100% interest. For all the properties that are operated by others, the Company is dependent on their decision-making with respect to day-to-day operations over which the Company may have limited control. The success and timing of the drilling and development activities on properties operated by others depend upon a number of factors largely outside of the Company’s control, including the timing and amount of capital expenditures, prioritization of projects, the operator’s expertise and financial resources, the inclusion of other participants, the use of technology and the rate of production of reserves, if any. This limited ability to exercise influence over the operations of some of the Company's concessions may cause a material adverse effect on its results of operations and financial condition.

The Company's business could be adversely affected by the loss of one or more key officers or employees

The Company is largely dependent upon the personal efforts and abilities of its key corporate officers and employees. Failure to retain or to attract and retain additional key officers and employees with necessary skills could have a materially adverse impact upon the Company's growth and profitability. The loss or unavailability to the Company of these individuals may have a material adverse effect upon the Company's business, especially in Egypt and Yemen.

You should not unduly rely on reserve information because reserve information represents estimates

The reserve and recovery information contained in this Annual Information Form are only estimates and the actual production and ultimate reserves from the Company's properties may be greater or less than the estimates prepared in the applicable reports. Such information has been prepared using certain commodity price assumptions. If lower prices for crude oil are realized by the Company and substituted for the price assumptions utilized in preparing the reserves data, the present value of estimated future net cash flows for the Company's reserves would be reduced and the reduction could be significant, particularly based on the constant price case assumptions. Estimates of economically recoverable oil and natural gas reserves and of future cash flows depend upon a number of variable factors and assumptions, including:

• historical production from the area compared with production from other producing areas;

• the assumed effects of regulations by governmental agencies;

• the quality, quantity and interpretation of available relevant data;

• assumptions concerning future commodity prices; and

• assumptions concerning future operating costs; severance, ad valorem and excise taxes; development costs; and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:

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• the quantities of oil and natural gas that are ultimately recovered;

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• future commodity prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. The Company's actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

The Company may be subject to a higher than expected past or future income tax liability in the event that it is subject to a successful reassessment by Canadian tax authorities

As the Company is engaged in the petroleum industry, its operations are subject to certain unique provisions of the Tax Act and applicable provincial income tax legislation relating to characterization of costs incurred in its business which effects whether such costs are deductible and, if deductible, the rate at which they may be deducted for the purposes of calculating taxable income. The Company has reviewed its historical income tax returns with respect to the characterization of the costs incurred in its business as well as other matters generally applicable to all corporations including the ability to offset future income against prior year losses. The Company has filed or will file all required income tax returns, but such returns are subject to reassessment. In the event of a successful reassessment of the Company it may be subject to a higher than expected past or future income tax liability as well as potentially interest and penalties and such amount could be material.

Conflicts of interest could adversely affect the Company's business

The directors of the Company may be engaged and may continue to be engaged in the search for oil and gas interests on their own behalf and on behalf of other companies, and situations may arise where the directors may be in direct competition with the Company. Conflicts of interest, if any, which arise will be subject to and governed by procedures prescribed by the corporation's governing corporate law statute which require a director of a corporation who is a party to, or is a director or an officer of, or has some material interest in any person who is a party to, a material contract or proposed material contract with the Company, disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under such legislation.

Defects in title to the Company's properties could adversely affect the Company

There may be valid challenges to the title to the oil and natural gas producing properties the Company controls that, if successful, could impair its activities on them and result in a reduction of the revenue received by the Company. The title reviews that the Company commissions prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of the Company.

The Company is subject to extensive environmental regulations and compliance with such regulations could be costly and negatively impact its business

National and local environmental laws and regulations in Egypt and Yemen affect the operations of the Company. These laws and regulations set various standards regulating certain aspects of health and safety and environmental quality, provide for penalties and other liabilities for the violation of such standards and establish in certain circumstances obligations to remediate current and former facilities and locations where operations are or were conducted. In addition, special provisions may be appropriate or required in environmentally sensitive areas of operation. While the Company maintains a Social, Environmental, Health and Safety Policy and liability insurance, including insurance for certain environmental claims, the insurance is subject to coverage limits and certain of the Company's policies exclude coverage for damages resulting from environmental contamination. The Company cannot provide assurance that insurance will continue to be available to it on commercially reasonable terms, that the possible types of liabilities that may be incurred by the Company will be covered by its insurance, or that the dollar amount of such liabilities will not exceed the Company's policy limits. Even a partially uninsured claim, if successful and of sufficient magnitude, could have a material adverse effect on the Company's business, financial condition and results of operations. There can be no assurance that the Company will not incur substantial financial obligations in connection with environmental compliance.

Significant liability could be imposed on the Company for damages, clean-up costs or penalties in the event of certain discharges into the environment, environmental damage caused by previous owners of properties purchased by the Company or non-compliance with environmental laws or regulations. Such liability could have a material adverse effect on the Company. Moreover, the Company cannot predict what environmental legislation or regulations will be enacted in the future or how existing or future laws or regulations will be administered or enforced. Compliance with more stringent laws or regulations, or more vigorous enforcement policies of any regulatory authority, could in the future require material expenditures by the Company for the installation and operation of systems and equipment for remedial measures, any or all of which may have a material adverse effect on the Company’s business, financial condition and results of operations.

Failure to comply with those laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of site clean up and site restoration, costs and liens, and in some cases, issuance of orders or injunctions limiting or requiring discontinuance of certain operations.

Natural disasters or other disruptions common in the Company's industry may adversely affect it

The Company is subject to operating hazards normally associated with the exploration and production of crude oil, including blowouts, explosions, oil spills, pollution, earthquakes, labour disruptions and fires. The occurrence of any such operating hazards could result in substantial losses to the Company due to injury or loss of life and damage to or destruction of crude oil wells, formations, production facilities or other properties.

The Company may issue additional securities

TransGlobe may make future acquisitions or enter into financing or other transactions involving the issuance of securities of TransGlobe which may be dilutive.

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The Company may fail to realize the anticipated benefits of acquisitions and dispositions

The Company considers acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as the Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, non core assets may be periodically disposed of, so that the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such non core assets, certain non core assets of the Company, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Company.

The Company's insurance may not be sufficient to cover the full extent of liabilities

The Company's involvement in the exploration for and development of oil and natural gas properties may result in the Company becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards. Although the Company maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

The Company may become involved in, named as a party to, or be the subject of, various legal proceedings

In the normal course of the Company's operations, it may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, related to personal injuries, property damage, property tax, land rights, the environment and contract disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the Company and as a result, could have a material adverse effect on the Company's assets, liabilities, business, financial condition and results of operations.

A breach of confidentiality obligations could put the Company at competitive risk and may cause significant damage to its business

While discussing potential business relationships or other transactions with third parties, the Company may disclose confidential information relating to the business, operations or affairs of this Company. Although confidentiality agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put the Company at competitive risk and may cause significant damage to its business. The harm to the Company's business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, the Company will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may cause.

You may be unable to bring actions or enforce judgments against the Company or any of its officers and directors in Canada or to serve process on any of them in countries other than Canada, including the United States

The Company is incorporated under the laws of the Province of Alberta, Canada, and all of the Company's directors and all of its officers are residents of Canada. Consequently, it may be difficult for U.S. investors, and other investors from outside of Canada, to effect service of process upon the Company or upon those directors or officers, or to realize judgments of non-Canadian courts, including judgments of U.S. courts predicated upon civil liabilities under applicable U.S. laws. Furthermore, it may be difficult for U.S. and other non-Canadian investors to enforce judgments of U.S. and other non-Canadian courts based on civil liability provisions of the U.S. federal or other non-Canadian securities laws in a Canadian court against the Company or any of the Company's executive officers or directors. There is substantial doubt whether an original lawsuit could be brought successfully in Canada against any of such persons or the Company predicated solely upon such non-Canadian civil liabilities.

Risks relating to the Debentures

The Debentures are subordinate to Senior Indebtedness of the Company

The Debentures are subordinate to Senior Indebtedness of the Company. The Debentures are also effectively subordinate to claims of creditors of the Company's Subsidiaries, except to the extent that the Company is a creditor of such Subsidiaries ranking at least pari passu with such creditors. In the event of the Company's insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up, its assets would be made available to satisfy the obligations of the creditors of such Senior Indebtedness before being available to pay the Company's obligations to the holders of the Debentures. Accordingly, all or a substantial portion of the Company's assets could be unavailable to satisfy the claims of the holders of the Debentures.

The Company's ability to meet its debt-service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the Company's financial performance, debt-service obligations, working capital and future capital-expenditure requirements. In addition, the Company's ability to borrow funds in the future and to make payments on outstanding debt will depend on the satisfaction of covenants in then existing credit agreements and other agreements. A failure to comply with any covenants or obligations under the Company's consolidated indebtedness could result in a default, which, if not cured or waived, could result in the acceleration of the relevant indebtedness. If such indebtedness were to be accelerated, there can be no assurance that the Company's assets would be sufficient to repay such indebtedness in full. There can also be no assurance that the Company will generate cash flow in amounts sufficient to pay outstanding indebtedness or to fund any other liquidity needs.

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The Company may not be able to pay the principal amount of the Debentures in cash

The Company may not be able to refinance the principal amount of the Debentures in order to repay the principal outstanding or may not have generated enough cash from operations to meet this obligation. The Company may, at its option, on not more than 60 days' and not less than 30 days' prior notice and subject to any required regulatory approvals, unless an Event of Default has occurred and is continuing, elect to satisfy its obligation to repay, in whole or in part, the principal amount of the Debentures which are to be redeemed or which have matured, and any accrued and unpaid interest thereon, by issuing and delivering Common Shares to the holders of the Debentures. There is no guarantee that the Company will be able to repay the outstanding principal amount in cash upon maturity of the Debentures.

Prevailing Yields on Similar Debentures may affect the market value of the Debentures

Prevailing yields on similar Debentures will affect the market value of the Debentures. Assuming all other factors remain unchanged, the market value of the Debentures will decline as prevailing yields for similar Debentures rise, and will increase as prevailing yields for similar Debentures decline.

The Company may not be able to purchase for cash all outstanding Debentures upon the occurrence of a Change of Control

The Company is required to offer to purchase for cash all outstanding Debentures upon the occurrence of a Change of Control. However, it is possible that following a Change of Control, the Company will not have sufficient funds at that time to make the required purchase of outstanding Debentures or that restrictions contained in other indebtedness will restrict those purchases. See "Description of Capital Structure - Debentures – Repurchase Upon a Change of Control". In addition, the Company's ability to purchase the Debentures in such an event may be limited by law, by the Indenture, by the terms of other present or future agreements relating to indebtedness, and agreements that the Company may enter into in the future which may replace, supplement or amend the Company's future debt. The Company's future credit agreements or other agreements may contain provisions that could prohibit the purchase of the Debentures by the Company. The Company's failure to purchase the Debentures would constitute an Event of Default under the Indenture, which might constitute a default under the terms of the Company's other indebtedness at that time.

If a holder of Debentures converts its Debentures in connection with a Change of Control, the Company may, in certain circumstances, be required to increase the conversion rate, as described under "Description of Capital Structure Debentures – Cash Change of Control". While the increased conversion rate is designed, inter alia, to compensate a holder of Debentures for the lost option time value of its Debentures as a result of a Change of Control in certain circumstances, the increased conversion rate amount is only an approximation of such lost value and may not adequately compensate the holder for such loss. In addition, in some circumstances as described under "Description of Capital Structure - Debentures – Cash Change of Control", no adjustment will be made.

The Indenture does not contain any provisions specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving the Company or any of its Subsidiaries

The Indenture does not restrict the Company or any of its Subsidiaries from incurring additional indebtedness or from mortgaging, pledging or charging its assets to secure any indebtedness. The Indenture does not contain any provisions specifically intended to protect holders of the Debentures in the event of a future leveraged transaction involving the Company or any of its Subsidiaries.

The Debentures may be redeemed prior to the Maturity Date

The Debentures may be redeemed, at the option of the Company, on or after March 31, 2015 and prior to the Maturity Date at any time and from time to time, at the redemption prices set forth in the Indenture, together with any accrued and unpaid interest. See "Description of Capital Structure - Debentures – Redemption and Purchase". Holders of Debentures should assume that this redemption option will be exercised if the Company is able to refinance at a lower interest rate or it is otherwise in the interest of the Company to redeem the Debentures.

The issuance of Common Shares upon conversion, redemption or maturity of the Debentures may be dilutive

The Company may issue Common Shares upon conversion, redemption or maturity of the Debentures. Additionally, the Company may issue Common Shares in connection with the payment of interest on the Debentures. Accordingly, holders of Common Shares may suffer dilution.

The Debentures are convertible in certain transactions

In the event of certain transactions, pursuant to the terms of the Indenture, each Debenture will become convertible into securities, cash or property receivable by a holder of Common Shares in such transactions. This change could substantially reduce or eliminate any potential future value of the conversion privilege associated with the Debentures. For example, if the Company were acquired in a cash merger, each Debenture would become convertible solely into cash and would no longer be convertible into securities whose value would vary depending on future prospects and other factors. See "Description of Capital Structure - Debentures – Conversion Privilege".

Payments to holders of Debentures will depend on the Company's financial health and creditworthiness

The likelihood that purchasers of the Debentures will receive payments owing to them under the terms of the Debentures will depend on the Company's financial health and creditworthiness at the time of such payments.

Holders of Debentures may be subject to withholding tax

Effective January 1, 2008, the Tax Act was amended to generally eliminate withholding tax on interest paid or credited to non-residents of Canada with whom the payor deals at arm's length. However, Canadian withholding tax continues to apply to payments of "participating debt interest". For purposes of the Tax Act, participating debt interest is generally interest that is paid on an obligation where all or any portion of such interest is contingent or dependent on the use of or production from property in Canada or is computed by reference to revenue, profit, cash flow, commodity price or any similar criterion.

Under the Tax Act, when a debenture or other debt obligation issued by a person resident in Canada is assigned or otherwise transferred by a non-resident person to a person resident in Canada (which would include a conversion of the obligation or payment on maturity), the amount, if any, by which the price for which the obligation was assigned or transferred exceeds the price for which the obligation was issued is deemed to be a payment of interest on that obligation made by the person resident in Canada to the non-resident (an "excess"). The deeming rule does not apply in respect of

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certain "excluded obligations", although it is not clear whether a particular convertible debenture would qualify as an "excluded obligation". If a convertible debenture is not an "excluded obligation", issues that arise are whether any excess would be considered to exist, whether any such excess which is deemed to be interest is "participating debt interest", and if the excess is participating debt interest, whether that results in all interest on the obligation being considered to be participating debt interest.

The Canada Revenue Agency ("CRA") has stated that no excess, and therefore no participating debt interest, would in general arise on the conversion of a "traditional convertible debenture" and therefore, there would be no withholding tax in such circumstances (provided that the payor and payee deal at arm's length for purposes of the Tax Act). The CRA has published guidance on what it believes to be a "traditional convertible debenture" for these purposes. The Debentures should generally meet the criteria set forth in CRA's published guidance; however, there can be no assurance that amounts paid or payable by the Company to a Holder of Debentures on account of interest or any "excess" amount will not be subject to Canadian withholding tax at 25% (subject to any reduction in accordance with a relevant tax treaty).

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Company's securities and options to purchase securities, if applicable, is contained in the Company's Information Circular for the most recent annual meeting of shareholders that involved the election of directors. Additional financial information is provided for in the Company's financial statements and the management's discussion and analysis for the year ended December 31, 2014. These documents, along with other documents affecting the rights of securityholders and other information relating to the Company, may be found on SEDAR at www.sedar.com and in the Company's Form 40-F Annual Report for the fiscal year ended December 31, 2014, filed on the Electronic Data Gathering and Retrieval System of the U.S. Securities and Exchange Commission at www.sec.gov.

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SCHEDULE "A"

FORM 51-101F2

REPORT ON RESERVES DATA

BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

Report on Reserves Data

To the board of directors of TransGlobe Energy Corporation (the "Company"):

1.	We have evaluated the Company's reserves data as at December 31, 2014. The reserves data are estimates of proved reserves and probable reserves and related future net revenues as at December 31, 2014, estimated using forecast prices and costs.
2.	The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
3.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
4.	The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2014 and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's management.

Independent Qualified	Description and		Net Present Value of Future Net Revenue
Reserves Evaluator or	Preparation Date of	Location of	(before income tax, 10% discount rate)
Auditor	Evaluation Report	Reserves	Audited	Evaluated	Reviewed	Total
			MM U.S. $	MM U.S.$	MM U.S.$	MM U.S.$
DeGolyer and	Appraisal Report as of	Egypt	—	344.3	—	344.3
MacNaughton Canada	December 31, 2014 on	Total	—	344.3	—	344.3
Limited	Certain Properties owned
	by TransGlobe Energy
	Corporation in Egypt
	dated January 30, 2015

5.	In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
6.	We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates.
7.	Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

DeGolyer and MacNaughton Canada Limited, Calgary, Alberta, dated January 30, 2015.

DEGOLYERandMACNAUGHTONCANADA
LIMITED
Per:	(signed) "Nahla Boury, P.Eng."
	Nahla Boury, P.Eng.
	President
	DeGolyer and MacNaughton Canada Limited

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SCHEDULE "B"

FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Report of Management and Directors on Reserves Data and Other Information

Management of TransGlobe Energy Corporation (the "Company") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of, proved reserves and probable reserves and related future net revenues as at December 31, 2014, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company's reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.

The Reserves Committee of the board of directors of the Company has

(a) reviewed the Company's procedures for providing information to the independent qualified reserves evaluator;

(b) met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of each such independent qualified reserves evaluator to report without reservation; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee of the board of directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Reserves Committee, approved

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing the reserves data and other oil and gas information;

(b) the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and

(c) the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Per:	(signed) "Ross Clarkson"	Per:	(signed) "Geoffrey Chase"
	Ross Clarkson		Geoffrey Chase
	President, Chief Executive Officer and Director		Director and Chair of the Reserves Committee
Per:	(signed) "Lloyd Herrick"	Per:	(signed) "Robert Jennings"
	Lloyd Herrick		Robert Jennings
	Vice-President, Chief Operating Officer and		Director and Chairman of the Board
	Director

March 11, 2015

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SCHEDULE "C"

CHARTER OF AUDIT COMMITTEE

Our Audit Committee Charter outlines the specific roles and duties of the Committee’s members.

GENERAL FUNCTIONS, AUTHORITY AND ROLE

The Audit Committee is a committee of the Board of Directors appointed to assist the Board in monitoring (1) the integrity of the financial statements of the Company, (2) compliance by the Company with legal and regulatory requirements related to financial reporting, (3) qualifications, independence and performance of the Company's independent auditors, and (4) performance of the Company’s accounting, internal controls and financial reporting process.

The Audit Committee has the power to conduct or authorize investigations into any matters within its scope of responsibilities, with full access to all books, records, facilities and personnel of the Company, its auditors and its legal advisors. In connection with such investigations or otherwise in the course of fulfilling its responsibilities under this charter, the Audit Committee has the authority to independently retain special legal, accounting, or other consultants to advise it, and may request any officer or employee of the Company, its independent legal counsel or independent auditor to attend a meeting of the Audit Committee or to meet with any members of, or consultants to, the Audit Committee. In its capacity as a committee of the Board of Directors, the Audit Committee has the power to determine the amount of Company funds that are appropriate for payment of (1) compensation to the Company’s independent auditor engaged for the purpose of preparing audit reports and performing other audit and non-audit services, (2) independent counsel and other advisers as it determines necessary to carry out its duties and (3) ordinary administrative expenses as it determines necessary to carry out its duties. The Audit Committee also has the power to create specific sub-committees with all of the investigative powers described above.

The Company's independent auditor is ultimately accountable to the Board of Directors and to the Audit Committee; and the Board of Directors and Audit Committee, as representatives of the Company's shareholders, have the ultimate authority and responsibility to retain and evaluate the independent auditor, to nominate annually the independent auditor to be proposed for shareholder approval and to determine appropriate compensation for the independent auditor. In the course of fulfilling its specific responsibilities hereunder, the Audit Committee must maintain free and open communication between the Company's independent auditors, Board of Directors and Company management. The responsibilities of a member of the Audit Committee are in addition to such member's duties as a member of the Board of Directors.

While the Audit Committee has the responsibilities and powers set forth in this charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company's financial statements are complete, accurate, and in accordance with generally accepted accounting principles. This is the responsibility of management and the independent auditor. Nor is it the duty of the Audit Committee to conduct investigations, to resolve disagreements, if any, between management and the independent auditor (other than disagreements regarding financial reporting), or to assure compliance with laws and regulations or the Company's own policies.

MEMBERSHIP

The membership of the Audit Committee will be as follows:

• The Committee will consist of a minimum of three members of the Board of Directors, appointed annually, each of whom is affirmatively confirmed by the Board of Directors as having satisfied the independence standards specified in all applicable rules of the Canadian provincial securities commissions, the U.S. Securities and Exchange Commission (the “SEC”) and any securities exchange on which the Company’s shares are traded, with such affirmation disclosed in the Company’s Management Proxy Circular.

• The Committee will also consist of all members that meet the definition of “Financially Literate” as defined in National Instrument 52-110 Part 1(1.5) and are able to read and understand fundamental financial statements, including the Company’s balance sheet, income statement and cash flow statement. The Committee shall have at least one member that qualifies as a financial expert as defined by the SEC.

• The Committee will not have participated in the preparation of the financial statements of the Company or its subsidiaries at any time during the past three years.

• The Board will elect, by a majority vote, one member as chairperson.

• A member of the Audit Committee may not, other than in his or her capacity as a member of the Audit Committee, the Board of Directors, or any other Board committee, accept any consulting, advisory, or other compensatory fee from the Company, and may not be an affiliated person of the Company or any subsidiary thereof.

RESPONSIBILITIES

The responsibilities of the Audit Committee shall be as follows:

Frequency of Meetings

• Meet on at least a quarterly basis, either in person or by telephone.

• Meet with the independent auditor on at least a quarterly basis, either in person or by telephone.

Reporting Responsibilities

• Provide to the Board of Directors proper Committee minutes.

• Report Committee actions to the Board of Directors with such recommendations as the Committee may deem appropriate.

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Charter Review

• Annually review and reassess the adequacy of this Charter and recommend any proposed changes to the Board of Directors for approval.

Advice of Counsel

• The Committee shall receive and review any reports from counsel to the Company concerning evidence of any material violation of law by the Company.

Whistleblower Mechanisms

• Adopt and review annually a mechanism through which employees and others can directly and anonymously contact the Audit Committee with concerns about accounting, internal accounting controls and auditing matters. The mechanism must include procedures for receiving, responding to, and keeping of records of, any such expressions of concern.

Independent Auditor

• Recommend to the Board the annual nomination of the independent auditor to be proposed for shareholder approval.

• Approve the compensation of the independent auditor and evaluate the performance of the independent auditor.

• Establish policies and procedures for the engagement of the independent auditor to provide non-audit services. The Audit Committee’s pre-approval procedure is to approve all non-audit services to be performed by the Company’s auditors in advance of the engagement of the Company’s auditors to perform such services. The pre-approval process involves management presenting the Audit Committee with a description of any proposed non-audit services. The Audit Committee considers the appropriateness of such services and whether the provision of those services would impact the auditor’s independence, including the magnitude of the potential fees. Once the committee has satisfied itself of its concerns, if any, it then votes either in favor of or against contracting the Company’s auditors to perform the proposed non-audit services.

• Ensure that the independent auditor is not engaged for any activities not allowed by any of the Canadian provincial securities commissions, the SEC or any securities exchange on which the Company’s shares are traded.

• Ensure that the independent auditor is not engaged for any of the following nine types of non-audit services contemporaneous with the audit:

◦ Bookkeeping or other services related to accounting records or financial statements of the Company;

◦ Financial information systems design and implementation;

◦ Appraisal or valuation services, fairness opinions, or contributions-in-kind reports;

◦ Actuarial services;

◦ Internal audit outsourcing services;

◦ Any management or human resources function;

◦ Broker, dealer, investment advisor, or investment banking services;

◦ Legal services; and

◦ Expert services related to the auditing service.

• Ensure that the independent auditor is compliant with the SEC, any security exchange on which the Company’s shares are traded and the Institute of Chartered Accountants of Alberta (Rules of Professional Conduct) regarding Audit Partner Rotation requirements.

Hiring Practices

• Ensure that no senior officer or employee who is, or in the past full year has been, affiliated with or employed by a present or former auditor of the Company or an affiliate, is hired by the Company until at least one full year after the end of either the affiliation or the auditing relationship.

Independence Test

• Take reasonable steps to confirm the independence of the auditor which shall include:

◦ ensuring receipt from the independent auditor of a formal written statement delineating all relationships between the independent auditor and the Company, consistent with the Independence Standards Board Standard No. 1 and related Canadian regulatory body standards;

◦ considering and discussing with the independent auditor any relationships or services, including non-audit services, that may impact the objectivity and independence of the independent auditor; and

◦ as necessary, taking, or recommending that the Board of Directors take, appropriate action to oversee the independence of the independent auditor.

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Audit Committee Meetings

• The Audit Committee may request the presence of the independent auditor at any Audit Committee meeting.

• At the request of the independent auditor, convene a meeting of the Audit Committee to consider matters the auditor believes should be brought to the attention of the directors or shareholders.

• Keep minutes of its meetings and report to the Board for approval of any actions taken or recommendations made.

Restrictions

• Ensure no restrictions are placed by management on the scope of the auditors’ review and examination of the Company’s accounts.

• Ensure that no Officer or Director attempts to fraudulently influence, coerce, manipulate or mislead any accountant engaged in auditing of the Company’s financial statements.

AUDIT AND REVIEW PROCESS AND RESULTS

Scope

• Consider, in consultation with the independent auditor, the audit scope and plan of the independent auditor.

Review Process and Results

• Consider and review with the independent auditor the matters required to be discussed by Statement on Auditing Standards No. 61, as the same may be modified or supplemented from time to time.

• Review and discuss with management and the independent auditor at the completion of the annual examination:

◦ the Company's audited financial statements and related notes;

◦ the Company’s MD&A and news releases related to financial results;

◦ the independent auditor's audit of the financial statements and its report thereon;

◦ any significant changes required in the independent auditor's audit plan;

◦ any non-IFRS related financial information;

◦ any serious difficulties or disputes with management encountered during the course of the audit; and

◦ other matters related to the conduct of the audit, which are to be communicated to the Audit Committee under generally accepted auditing standards.

• Review and discuss with management and the independent auditor annual and interim financial statements (including related notes and MD&A) at the completion of any review engagement or other examination and prior to public disclosure, and resolve to recommend approval of said documents to the Board of Directors.

• Review and discuss with management and the independent auditor the adequacy of the Company's internal control over financial reporting that management and the Board of Directors have established and the effectiveness of those systems, including, but not limited to, review and discussion of (1) management’s report on its assessment of the effectiveness of internal control over financial reporting as of the end of each fiscal year and the independent auditor’s report on management’s assessment and the effectiveness of internal control over financial reporting, (2) inquiry of management and the independent auditor about significant financial risks, exposures, deficiencies or material weaknesses identified and the steps management has taken to minimize such risks, exposures, deficiencies and material weaknesses to the Company and (3) any changes in internal control over financial reporting that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting and are required to be disclosed, as well as any other changes in internal control over financial reporting that were considered for disclosure in the Company’s periodic filings with the SEC.

• Meet separately with the independent auditor, management and the CFO as necessary or appropriate to discuss any matters that the Audit Committee or any of these groups believe should be discussed privately with the Audit Committee.

• Review and discuss with management and the independent auditor the accounting policies which may be viewed as critical, including all alternative treatments for financial information within generally accepted accounting principles that have been discussed with management, and review and discuss any significant changes in the accounting policies of the Company and industry accounting and regulatory financial reporting proposals that may have a significant impact on the Company's financial reports.

• Review with management and the independent auditor the effect of regulatory and accounting initiatives as well as off-balance sheet structures, if any, on the Company's financial statements.

• Review with management and the independent auditor any correspondence with regulators or governmental agencies and any employee complaints or published reports which raise material issues regarding the Company's financial statements or accounting policies.

• Review with the Company's General Counsel legal matters that may have a material impact on the financial statements, the Company's financial compliance policies and any material reports or inquiries received from regulators or governmental agencies related to financial matters.

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SECURITIES REGULATORY FILINGS

• Review, prior to filing with regulatory bodies, annual and periodic filings with the Canadian provincial securities commissions and the SEC and other published documents containing the Company's financial statements.

RISK ASSESSMENT

• Review the Company’s policies with respect to risk assessment and risk management including, without limitation, environmental risk, insurance coverage and the risk of fraud. The Committee also shall discuss the Company’s major risk exposures and the steps management has taken to monitor and control them.

AMENDMENTSTOAUDITCOMMITTEECHARTER

• Annually review this Charter and propose amendments to be ratified by a simple majority of the Board of Directors.