EXHIBIT 99.1

TRANSGLOBE ENERGY CORPORATION

ANNUAL INFORMATION FORM

Year Ended December 31, 2016

March 13, 2017

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TABLE OF CONTENTS

	Page
CURRENCY AND EXCHANGE RATES	2
ABBREVIATIONS	3
CONVERSIONS	3
FORWARD-LOOKING STATEMENTS	3
NON-GAAP MEASURES	5
CERTAIN DEFINITIONS	6
TRANSGLOBE ENERGY CORPORATION	8
GENERAL DEVELOPMENT OF THE BUSINESS	9
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES	10
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	16
DIVIDEND POLICY	50
DESCRIPTION OF CAPITAL STRUCTURE	41
MARKET FOR SECURITIES	44
PRIOR SALES	46
ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER	46
DIRECTORS AND OFFICERS	47
INTERESTS OF EXPERTS	48
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	48
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	49
TRANSFER AGENT AND REGISTRAR	49
MATERIAL CONTRACTS	49
AUDIT COMMITTEE INFORMATION	50
RISK FACTORS	57
ADDITIONAL INFORMATION	69

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, 2016

March 13, 2017

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, 2016, 2015 and 2014.

	Year Ended December 31, 2016	Year Ended December 31, 2015	Year Ended December 31, 2014
End of Period	Cdn$1.3427	Cdn$1.3840	Cdn$1.1601
Period Average	Cdn$1.3248	Cdn$1.2788	Cdn$1.1048

We have adopted the standard of 6 mcf: 1 bbl when converting natural gas to oil and 1 bbl: 6 mcf when converting oil to natural gas. Disclosure provided herein in respect of boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.In addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

DRILLING LOCATIONS

This Annual Information Form discloses drilling locations in respect of the Company's assets in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 157.4 net undrilled locations disclosed in this Annual Information Form, 33.5 are proved undeveloped locations, 23.9 are probable undeveloped locations, and 100 are unbooked. Proved undeveloped locations and probable undeveloped locations are booked and derived from the DeGolyer Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management of the Company as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and, if drilled, there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof, is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and, therefore, there is more uncertainty whether wells will be drilled in such locations and, if drilled, there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

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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
boe	barrel of oil equivalent
Mboe	thousand barrels of oil equivalent
MMboe	million barrels of oil equivalent
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

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,

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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 and natural gas properties;

• oil and gas production levels;

• the quantity of oil and gas reserves;

• capital expenditure programs;

• supply and demand for oil and gas, 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 flow from operations for 2017;

• the budget for the exploration program;

• future development costs;

• future reserves growth and the success of the 2017/2018 exploration program;

• the continuation of the Company's marketing of its own Egypt entitlement oil on a go-forward basis and the resulting reduced credit risk;

• the satisfaction of work commitments in Egypt;

• the timing and execution of having a drill-ready prospect inventory prepared for South Ghazalat;

• estimated timing of development of undeveloped reserves;

• future abandonment and reclamation costs;

• anticipated average production for 2017;

• 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 and gas; 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 and gas properties in the manner currently contemplated; 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 and gas fields;

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

• continued volatility in market prices for crude oil and natural gas;

• actions taken by OPEC with respect to the supply of oil;

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

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

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

• ability to pay the principal amount of the Debentures in cash;

• payment of crude oil and natural gas marketing contracts and both associated and non-associated financial hedging instruments;

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

• changes in Egyptian or Canadian tax, energy or other laws or regulations;

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

• capital expenditure programs, including changes in 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 and gas properties and the Company's success at acquisition, exploitation and development of reserves;

• failure to achieve production targets on timelines anticipated or at all;

• changes or fluctuations in production levels;

• the quantity of oil and gas reserves;

• supply and demand for oil and gas, and commodity prices;

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

• changes to treatment under governmental regulatory regimes and tax laws;

• failure to realize the anticipated benefits of acquisitions and dispositions;

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

• 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;

• competition from other producers;

• lack of availability of qualified personnel;

• credit risks;

• the potential for reserves evaluators' estimates and assumptions to be inaccurate;

• 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 TransGlobe 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.

NON-GAAP MEASURES AND OTHER MATTERS

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 long-term ability to generate the cash flow necessary to fund future growth through capital investment. Management believes these adjustments to cash generated from operating activities increase comparability between reporting periods. Investors should be cautioned that 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.

Reconciliation of Funds Flow from Operations

($000s)	2016		2015
Cash flow from operating activities	(1,065	)	77,526
Changes in non-cash working capital	(7,296	)	(86,428	)
Funds flow from operations1	(8,361	)	(8,902	)
1  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.

This Annual Information Form and in particular the information in respect of the Company's prospective revenues and anticipated costs may contain future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by Management to provide an outlook of the Company's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading "Forward-Looking Statements". The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Company and Management believe that the FOFI has been prepared on a reasonable basis, reflecting Management’s best estimates and judgments.

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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;

"C$" or "Cdn$" means Canadian dollars;

"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 maintained by The Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time;

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

"Computershare" means Computershare Trust Company of Canada;

"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$13.63 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;

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

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

"Debenture Trustee" means Computershare;

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

"DeGolyer Report" means the report of DeGolyer dated January 18, 2017 evaluating the crude oil, natural gas and NGL reserves of the Company as at December 31, 2016;

"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;

"DSU Plan" means the deferred share unit plan of the Company;

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

"EGPC" means the Egyptian General Petroleum Corporation;

"Egypt" means the Arab Republic of Egypt;

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

"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;

"Gross" or "gross" means:

(i) 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;

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

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

"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 the maturity date of the Debentures, being March 31, 2017;

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"NASDAQ" means the NASDAQ Global Select Market;

"Net" or "net" means:

(i) 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;

(ii) 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

(iii) 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";

"PSA" means production sharing agreement;

"PSC" means production sharing concession;

"PSU Plan" means the performance share unit plan of the Company;

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

"RSU Plan" means the restricted share unit plan of the Company;

"SEDAR" means the System for Electronic Document Analysis and Retrieval of the Canadian Securities Administrators;

"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;

"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;

"TPI" means TransGlobe Petroleum International Inc.;

"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 previous Canadian oil and gas assets and operations were divested in early 2008 to assist with the funding of opportunities in Egypt and Yemen. In 2015, the Company relinquished and divested all of its interests in Yemen. In 2016, the Company re-entered Canada with the acquisition of production and working interests in certain facilities in west central Alberta. 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.

Through its wholly-owned subsidiaries, TransGlobe is primarily engaged in exploring for, developing and producing oil and gas in Egypt and Canada.

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 subsidiaries beneficially owned, controlled or directed, directly or indirectly, by the Company 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 Holdings Yemen Inc.(1)	Turks & Caicos Islands, B.W.I.	100%
TransGlobe Petroleum Egypt 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 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%
Notes:
(1)  These companies are 100% owned directly by TransGlobe Petroleum International Inc., which company is a wholly-owned subsidiary of the Company.
(2)  TG South Alamein Inc. is 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. previously owned 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. 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 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 Holdings Egypt Inc. holds a 100% interest in TG South Alamein Inc. 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. owned TransGlobe's interest in the SE Gharib concession until the relinquishment of the concession in November 2016. 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. TransGlobe's recently acquired Canadian properties are owned by TransGlobe Energy Corporation.

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 and west central Alberta.

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 nine concessions in Egypt (a 100% working interest in the West Gharib Concession, a 100% working interest in the West Bakr Concession, a 50% working interest in the East Ghazalat Concession prior to the sale of TransGlobe GOS Inc. in October 2015, 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 prior to relinquishment in November 2016, a 100% working interest in the South Ghazalat Concession, and a 100% working interest in the NW Sitra Concession) and four PSAs in Yemen prior to the relinquishment and divestiture of all interests in Yemen during 2015 (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). In 2016, the Company acquired production and working interests in certain facilities in the Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west central Alberta.

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.

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 had 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.

2015

In Egypt during 2015, the Company drilled five wells, all of which were drilled during the first quarter, before releasing all drilling rigs. The Company drilled three wells at NW Gharib (one oil well and two dry holes), one dry hole at West Gharib and one water disposal well at West Bakr. The Company also completed the interpretation of the seismic data acquired in 2014 on the Eastern Desert exploration blocks. A drilling program was approved for 2016 to drill and evaluate up to 22 prospects in the Eastern Desert, which was expected to satisfy all remaining Phase 1 commitments on these blocks. Furthermore, the Company completed the acquisition of 408 square kilometers of 3-D seismic on the South Ghazalat concession in the Western Desert during the second quarter of 2015.

TransGlobe began selling its Eastern Desert entitlement oil directly to third party buyers on the open market in 2015, which was a first for the Company. The Company completed the sale of three full tanker liftings during 2015, and held 923 Mbbls of entitlement oil in inventory at year-end 2015. The Company expects to continue marketing its own entitlement oil on a go-forward basis, which reduces the Company's credit risk as it is no longer reliant on receiving payment from EGPC on its entitlement oil sales.

Reserves at year-end 2015 were lower than 2014 due to production, the sale of East Ghazalat and minimal drilling activity in 2015. The negative effects of these factors were partially offset by positive revisions at West Bakr and West Gharib. The positive revisions at West Bakr and West Gharib were the result of production performance at the West Bakr H and K fields and the West Gharib Arta field.

2016

On December 20, 2016, TransGlobe closed the acquisition of producing and development assets in the Harmattan area of west central Alberta. The acquisition provides the Company with approximately 3,000 boepd of production (approximately 60% liquids weighted) and total gross Proved plus Probable reserves of 20.7 million boe as at December 31, 2016, as contained in the DeGoyler Report. The acquisition met the Company's strategic objective to diversify and expand operations into lower political risk OECD countries with attractive netbacks to support growth in the current oil price environment. The assets provide TransGlobe with a stable production base in Canada, with significant future growth potential (45 net drilling locations assigned in Proved plus Probable reserves, and an additional 100 or more net drilling locations identified by TransGlobe).

TransGlobe engaged in an active drilling program in 2016, drilling 17 wells in Egypt. The exploration drilling program at NW Gharib, SE Gharib and SW Gharib, consisting of 14 wells in aggregate, yielded two oil discoveries (NWG 27 and NWG 38) and one well with oil shows that was abandoned due to drilling problems (NWG 26). Subsequent to year-end, the Company drilled NWG 26ST (side-track), resulting in a discovery. At the beginning of the year, due to the continuing weakness in oil prices and widening heavy oil differentials, the Company was aggressively conserving cash and focused on cost cutting initiatives. By mid spring, in light of some stability returning to oil prices, the Company had developed a production recovery plan to recover production that had decreased due to the cash conservation strategy. In addition to the exploration program, the Company drilled two development oil wells at West Bakr and one development oil well at West Gharib as part of the production recovery plan. Capital costs associated with the drilling program

10

trended 30% to 40% below historical norms due to better contract terms and optimized drilling programs, with Red Bed wells (D&A) costing approximately $0.5 million per well versus pre-drill estimates of $0.8 million per well.

Reserves at 2016 year-end were higher compared to 2015 year-end primarily due to the Canadian acquisition and positive revisions of the Arta Red Bed pool performance/technical revisions in addition to positive performance revisions in West Bakr. The Company drilled three development oil wells (two in K-South and one in the Arta Red Bed) during the year. One additional Arta Red Bed development well was drilled and rig released subsequent to December 31, 2016. The Company produced a total of 4.4 MMBbls of crude oil in Egypt in 2016, and production was replaced by the positive technical revisions in the West Gharib and West Bakr concessions. In addition, the Company filed for and received its first development lease in NW Gharib in December. Production from the NWG 3X well commenced prior to year-end 2016, representing a reserve conversion from proved undeveloped to proved producing.

Cancellation of Borrowing Base Facility

In December 2016 the Company terminated its Borrowing Base Facility. There were no amounts outstanding under the Borrowing Base Facility at the time of termination; however, the Company was utilizing approximately $16.0 million in the form of letters of credit to support its exploration commitments in Egypt. The letters of credit outstanding under the borrowing base facility were transferred to a bilateral letter of credit facility with Sumitomo Mitsui Banking Corporation ("SMBC"). The issued letters of credit under the bilateral letter of credit facility are secured by cash collateral which is on deposit with SMBC. The exploration commitments are expected to be fulfilled in 2017.

Recent Developments

Subsequent to year-end, five exploration wells and one development well were drilled.  In West Gharib, one development well (Arta 74) was cased as an oil well in the Arta Red Bed development pool.  In NW Gharib, two exploration wells (NWG 26ST and NWG 27A1ST) were cased as potential Red Bed oil discoveries.  One NW Gharib exploration well (NWG 28) was dry and abandoned.  In SW Gharib, two exploration wells (SWG 2 & SWG 4) were dry and abandoned, completing the Company’s work program commitment in the SW Gharib concession.

On February 10, 2017, TransGlobe announced the execution of a $75 million crude oil prepayment agreement between TPI and Mercuria Energy Trading SA (the "Marketer"). The prepayment agreement has a term of four years, maturing March 31, 2021, with advances bearing interest at a substantially similar rate as the Company's Debentures at current LIBOR rates. Funding under the Agreement is revolving, with each advance to be satisfied through the delivery of crude oil to the Marketer pursuant to the marketing contract described below. Further advances become available upon delivery of crude oil to the Marketer up to a maximum of $75 million subject to compliance with the terms and conditions of the prepayment agreement including maintenance of a cover ratio which is calculated by dividing the value of forecasted production of crude oil over the applicable period by the outstanding obligations of TPI under the prepayment agreement. If crude oil is not delivered in satisfaction of an advance, the obligations in respect of that advance are ultimately payable in cash. The obligations of TPI under the prepayment agreement and the marketing contract described below are guaranteed by the Company and TPI's subsidiaries, and are supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries.

In conjunction with the prepayment agreement, on February 10, 2017, TPI entered into a marketing contract with Mercuria. Pursuant to the marketing contract, TPI will deliver and Mercuria will market up to 9 million barrels of TPI's crude oil entitlement production from its West Bakr and West Gharib oil fields. Mercuria will receive a per barrel marketing fee, and will use commercially reasonable efforts to achieve the highest and best price for the crude oil delivered under the marketing contract. The pricing of crude oil sales will be based on indexed market prices at the time of sale. Subject to earlier termination of the marketing agreement in accordance with the terms thereof, deliveries of crude oil under the marketing agreement will terminate on the later of: (i) the delivery of 9 million barrels of crude oil; (ii) the prepayment agreement maturity date (March 31, 2021); or (iii) satisfaction of all amounts outstanding under the prepayment agreement.

Significant Acquisitions

In a transaction that closed on December 20, 2016 (effective date of December 1, 2016), TransGlobe completed the acquisition of production and working interests in certain facilities in the Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west central Alberta for total consideration of $59.5 million after closing adjustments. The acquisition was funded by $48.3 million cash from the balance sheet and a 10%, 24-month vendor take back loan of $11.2 million. See "General Development of the Business 2016".

The acquisition met the Company's strategic objective to diversify and expand operations into lower political risk OECD countries with netbacks sufficient enough to support growth in the current oil price environment. The Company filed a business acquisition report in the form of NI 51-102F4 regarding the acquisition on December 22, 2016 which is available on the Company's SEDAR profile at www.sedar.com.

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 Canada. 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 during the past 13 years, and operated in Yemen for 19 years before the sale of its Yemen interests in 2015. The Company also operated in Canada from 1999 to 2008, and made a re-entry into Canada in December 2016. In Egypt, the Company currently has an interest in seven PSCs: West Gharib, West Bakr, South Alamein, NW 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), and in October 2015 the Company sold its subsidiary that held interests in Block 75 and Block S-1. In Canada, the Company owns production and working interests in certain facilities in the Cardium light oil and Mannville liquid-rich gas assets in the Harmattan area of west central Alberta.

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A significant portion 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".

Competitive Conditions

There is considerable competition in the worldwide oil and natural gas industry, including in Egypt and Canada where the Company's assets, activities, and employees are located. Operators more established than the Company, with access to broader technical skills, larger amounts of capital and other resources, are active in the industry in Egypt and Canada, where the Company has operations. This represents a significant risk for the Company, which must rely on modest resources as compared to some of its competitors. See "Risk Factors".

Environmental Protection

The Company operates under the jurisdiction of a number of regulatory bodies and agencies in the jurisdictions in which it operates that set forth numerous prohibitions and requirements with respect to planning and approval processes related to land use, sustainable resource management, waste management, responsibility for the release of presumed hazardous materials, protection of wildlife, and the environment and the health and safety of workers. Legislation provides for restrictions and prohibitions on the transport of dangerous goods and the release or emission of various substances, including substances used and produced in association with certain oil and gas industry operations. The legislation addresses various permits, including for drilling, well completion, installation of surface equipment, air monitoring, surface and ground water monitoring in connection with these activities, waste management and access to remote or environmentally sensitive areas.

Historically, environmental protection requirements have not had a significant financial or operational effect on TransGlobe's capital expenditures, earnings or competitive position. Subject to any changes in current environmental protection legislation, or in the way the legislation is interpreted in the jurisdictions in which it operates, TransGlobe does not presently anticipate environmental protection requirements will have a significant effect on such matters in 2017. The Company is exposed to potential environmental liability in connection with its business of oil and gas exploration and production. See "Risk Factors".

Social or Environmental Policies

The Company's Health, Safety, Environment and Social Responsibility Committee reviewed and approved fundamental policies pertaining to health, safety, environment and social responsibility which have the potential to impact the Company's activities and strategies. The Health, Safety, Environment and Social Responsibility Committee reported to the Board on TransGlobe's performance with respect to applicable laws, regulations and Company policies and also in respect to emerging trends, issues and regulations related to health, safety and environment. During 2016, the Health, Safety, Environment and Social Responsibility Committee was combined with the Reserves Committee to form the Reserves, Health, Safety, Environment and Social Responsibility Committee (“RHSES Committee”) to increase Board efficiency. The RHSES Committee is comprised of independent directors and continues to report to the Board on TransGlobe's performance with respect to applicable laws, regulations and Company policies and also in respect to emerging trends, issues and regulations related to health, safety and environment.

Specialized Skill and Knowledge

TransGlobe employs individuals with various professional skills in the course of pursuing its business plan. These professional skills include, but are not limited to, geology, geophysics, engineering, financial, accounting and business skills, which are widely available in the industry. Drawing on significant experience in the oil and gas business, TransGlobe believes its management team has a demonstrated track record of bringing together all of the key components to a successful exploration and production company: strong technical skills; expertise in planning and financial controls; ability to execute on business development opportunities; capital markets expertise; and an entrepreneurial spirit that allows TransGlobe to effectively identify, evaluate and execute on its business plan.

Cyclical and Seasonal Impact of Industry

Our operational results and financial condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect on our financial condition. We mitigate such price risk through closely monitoring the various commodity markets and establishing hedging programs, as deemed necessary, to fix netbacks on production volumes. See "Other Oil and Gas Information - Forward Contracts" for our current hedging program.

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Summary of International Land Holdings as at December 31, 2016

International Land (Egypt)¹ - Summary of PSCs

EASTERN DESERT EGYPT
Block	West Gharib	West Bakr	NW Gharib	SW Gharib
Basin	Gulf of Suez	Gulf of Suez	Gulf of Suez	Gulf of Suez
Year acquired	2007	2011	2013	2013
Status	Development	Development	Exploration/Development	Exploration
Operator	TransGlobe	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	100%	100%	100%	100%
Block Area (acres)	22,775	11,600	148,300	48,000
Expiry date	2019-2026	2020	Dec 2036	May 2017
Extensions
Exploration	N/A	N/A	2 + 2 years	2 + 2 years
Development	+ 5 years	+ 5 years	+ 5 years	20 + 5 years

WESTERN DESERT EGYPT
Block	South Alamein	South Ghazalat	NW Sitra
Basin	Western Desert	Western Desert	Western Desert
Year acquired	2012	2013	2015
Status	Exploration	Exploration	Exploration
Operator	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	100%	100%	100%
Block Area (acres)	197,000	348,974	480,850
Expiry date	May 20181	November 2018	July 2018
Extensions
Exploration	N/A	2 years	3.5 years
Development	20 + 5 years	20 + 5 years	20 + 5 years
Note: (1)  The Company received military approval to access South Alamein on September 8, 2016 and has approximately 20 months from such date until expiry.

13

Egypt

Eastern Desert

14

Summary of International PSC Terms

All of the Company's international blocks are Production Sharing Concessions ("PSCs") between the host government and the contractor (Joint Interest Partner). 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 government's share of production.

The 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 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 PSCs. Each 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 PSCs.

The following tables summarize the Company's international 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

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

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

The West Bakr PSC contains rights on the part of Egypt to take in kind from the Company, Egypt's share of the Profit oil entitlement (but not Cost oil entitlement) at the market price, but only for operating requirements of refineries. The West Gharib PSC contains rights on the part of Egypt to purchase from the Company, but only for the requirements of the Egyptian market, the Company's Profit oil entitlement (but not Cost oil entitlement), proportional to the aggregate of Egypt's contractual rights, at the market price. None of the Egyptian PSCs contain minimum production or sales requirements, and there are no restrictions with respect to pricing of the Company's sales volumes. All crude oil sales are priced at current market rates at the time of sale.

15

Canada

Operations Review

In 2016, the Company's total production decreased by 17% to 12,105 Bopd (2015 – 14,511 Bopd). Production from Egypt averaged 12,015 Bopd to TransGlobe during 2016 (2015 – 14,466 Bopd). Production from Canada averaged 90 Boepd during 2016, as the Canadian property acquisition closed late in the year (December 20, 2016). Current production from the Canadian assets is approximately 2,800 Boepd. Production from Yemen averaged 45 Bopd to TransGlobe during 2015 (no production in 2016 from Yemen as the Company disposed of its interest in Yemen in 2015).

2017 Outlook Highlights

• Production is expected to average between 15,500 and 18,500 Boepd in 2017; and

• Exploration and development spending is budgeted to be up to $56.4 million before capitalized G&A ($35.2 million firm plus $21.2 contingent), to be funded from funds flow from operations and working capital.

• On February 10, 2017, the Company completed a $75 million crude oil prepayment agreement between its wholly owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria Energy Trading SA ("Mercuria") of Geneva, Switzerland. TPI's obligations under the prepayment agreement will be guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. This funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of Libor plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75 million and subject to compliance with the other terms and conditions of the pre-payment agreement. In conjunction with the prepayment agreement, TPI has also entered into a marketing contract with Mercuria to market nine million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on indexed market prices at the time of sale.

The initial advance under the prepayment agreement will be used to refinance the 6.0% convertible debentures of the Company maturing on March 31, 2017 and thereafter for working capital purposes of the Company and its subsidiaries.

Human Resources

TransGlobe currently employs 77 full-time employees and 13 full-time consultants. The Company will add additional professional and administrative staff as the needs arise.

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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 18, 2017, with the effective date being December 31, 2016.

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, 2016. In 2016, 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, 2016.

The reserves data set forth below (the "Reserves Data") was prepared by DeGolyer with an effective date of December 31, 2016. 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 the province of Alberta, Canada and Egypt.

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.

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.

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Reserves Data – Forecast Prices and Costs

SUMMARY OF OIL AND GAS RESERVES

TOTAL COMPANY

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

	Light Crude Oil &				Conventional		Natural
	Medium Crude Oil		Heavy Crude Oil		Natural Gas		Gas Liquids		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)	(Bcf)	(Bcf)	(MMbbls)	(MMbbls)	(MMboe)	(MMboe)
Proved
Developed producing	3.4	2.5	11.3	6.2	14.9	11.8	2.3	1.7	19.5	12.4
Developed non-producing	0.9	0.6	1.2	0.7	0.3	0.2	—	—	2.2	1.3
Undeveloped	2.0	1.6	3.0	1.6	9.0	7.9	1.7	1.5	8.3	6.1
Total Proved	6.2	4.7	15.6	8.5	24.1	19.9	4.1	3.2	29.9	19.8
Probable	3.5	2.6	9.1	4.8	21.8	18.8	3.8	3.1	20.1	13.7
Proved+Probable	9.7	7.3	24.7	13.3	45.9	38.7	7.9	6.4	50.0	33.4
Possible	2.6	1.9	9.3	4.7	11.4	9.4	2.1	1.6	15.9	9.7
Proved+Probable+Possible	12.4	9.2	34.0	18.0	57.3	48.1	9.9	7.9	65.9	43.1
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.

SUMMARY OF OIL AND GAS RESERVES

EGYPT

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

	Light Crude Oil &
	Medium Crude Oil		Heavy Crude Oil		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)
Proved
Developed producing	1.6	1.0	11.3	6.2	12.9	7.3
Developed non-producing	0.8	0.5	1.2	0.7	2.1	1.2
Undeveloped	0.3	0.2	3.0	1.6	3.3	1.8
Total Proved	2.7	1.7	15.6	8.5	18.3	10.2
Probable	1.8	1.2	9.1	4.8	11.0	6.0
Proved+Probable	4.5	2.9	24.7	13.3	29.3	16.3
Possible	1.4	0.9	9.3	4.7	10.7	5.6
Proved+Probable+Possible	6.0	3.9	34.0	18.0	40.0	21.9
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.

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SUMMARY OF OIL AND GAS RESERVES

CANADA

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

	Light Crude Oil &		Conventional		Natural
	Medium Crude Oil		Natural Gas		Gas Liquids		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(MMbbls)	(MMbbls)	(Bcf)	(Bcf)	(MMbbls)	(MMbbls)	(MMboe)	(MMboe)
Proved
Developed producing	1.8	1.5	14.9	11.8	2.3	1.7	6.6	5.2
Developed non-producing	0.1	—	0.3	0.2	—	—	0.1	0.1
Undeveloped	1.7	1.5	9.0	7.9	1.7	1.5	5.0	4.3
Total Proved	3.6	3.0	24.1	19.9	4.1	3.2	11.7	9.5
Probable	1.7	1.4	21.8	18.8	3.8	3.1	9.1	7.6
Proved+Probable	5.2	4.4	45.9	38.7	7.9	6.4	20.7	17.2
Possible	1.2	0.9	11.4	9.4	2.1	1.6	5.1	4.1
Proved+Probable+Possible	6.4	5.3	57.3	48.1	9.9	7.9	25.9	21.2
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.

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

TOTAL COMPANY

AS OF DECEMBER 31, 2016

(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	218.6	180.2	156.1	139.1	126.3	218.6	180.2	156.1	139.1	126.3	12.58
Developed non-producing	28.4	23.8	20.2	17.3	15.1	28.4	23.8	20.2	17.3	15.1	15.59
Undeveloped	79.6	52.6	36.5	26.2	19.2	79.0	52.4	36.5	26.2	19.1	6.01
Total Proved	326.6	256.6	212.8	182.7	160.6	326.0	256.4	212.8	182.7	160.6	10.76
Probable	286.4	185.2	132.9	101.2	80.1	253.4	170.8	125.6	97.1	77.7	9.73
Total Proved+Probable	613.0	441.8	345.7	283.9	240.6	579.4	427.3	338.4	279.8	238.2	10.34
Possible	277.4	152.0	101.8	75.0	58.3	242.8	138.7	94.6	70.3	55.1	10.54
Total Proved+Probable+Possible	890.4	593.8	447.5	358.8	299.0	822.1	566.0	433.0	350.1	293.3	10.38
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

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

EGYPT

AS OF DECEMBER 31, 2016

(FORECAST PRICES & COSTS)

											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	140.5	125.0	113.0	103.4	95.5	140.5	125.0	113.0	103.4	95.5	15.56
Developed non-producing	26.4	22.1	18.8	16.2	14.1	26.4	22.1	18.8	16.2	14.1	15.76
Undeveloped	40.7	34.0	28.8	24.6	21.3	40.7	34.0	28.8	24.6	21.3	16.04
Total Proved	207.6	181.1	160.5	144.2	130.9	207.6	181.1	160.5	144.2	130.9	15.67
Probable	164.6	126.2	99.7	80.8	66.9	164.6	126.2	99.7	80.8	66.9	16.54
Total Proved+Probable	372.1	307.3	260.2	225.0	197.8	372.1	307.3	260.2	225.0	197.8	15.99
Possible	149.7	101.4	73.0	55.2	43.6	149.7	101.4	73.0	55.2	43.6	13.03
Total Proved+Probable+Possible	521.9	408.7	333.2	280.2	241.4	521.9	408.7	333.2	280.2	241.4	15.23
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.

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

CANADA

AS OF DECEMBER 31, 2016

(FORECAST PRICES & COSTS)

													Unit Value
													Before Tax
	Before Income Tax						After Income Tax						(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	78.1	55.2	43.1	35.8	30.8		78.1	55.2	43.1	35.8	30.8		8.37
Developed non-producing	2.0	1.6	1.4	1.2	1.0		2.0	1.6	1.4	1.2	1.0		13.37
Undeveloped	39.0	18.6	7.7	1.5	(2.2	)	38.4	18.5	7.7	1.5	(2.2	)	1.81
Total Proved	119.0	75.5	52.3	38.5	29.7		118.4	75.3	52.2	38.5	29.6		5.48
Probable	121.9	59.0	33.2	20.4	13.2		88.8	44.7	26.0	16.3	10.8		4.35
Total Proved+Probable	240.8	134.5	85.5	58.9	42.8		207.2	120.0	78.2	54.8	40.4		4.98
Possible	127.7	50.6	28.8	19.7	14.8		93.1	37.3	21.6	15.1	11.5		7.11
Total Proved+Probable+Possible	368.5	185.1	114.3	78.6	57.6		300.3	157.3	99.8	69.9	51.9		5.38

20

TOTAL FUTURE NET REVENUE⁽³⁾

(UNDISCOUNTED)

AS OF DECEMBER 31, 2016

(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
Canada	417.4	72.3	146.7	66.1	13.3	119.0	0.6	118.4
Egypt	560.1	106.0	233.9	12.6	—	207.6	—	207.6
Total Company	977.5	178.3	380.5	78.7	13.3	326.6	0.6	326.0
Proved+Probable Reserves
Canada	733.6	123.3	233.9	118.8	16.7	240.8	33.6	207.2
Egypt	950.9	179.7	378.5	20.7	—	372.1	—	372.1
Total Company	1,684.5	303.0	612.3	139.5	16.7	613.0	33.6	579.4
Proved+Probable
Possible Reserves
Canada	956.1	168.7	282.3	118.8	17.8	368.5	68.2	300.3
Egypt	1,354.2	262.6	541.1	28.7	—	521.9	—	521.9
Total Company	2,310.3	431.3	823.4	147.5	17.8	890.4	68.2	822.1
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. In Canada, operating costs are net of processing and other income.
(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, 2016.

21

NET PRESENT VALUE OF FUTURE NET REVENUES

BY PRODUCT TYPE

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

		Future net
		Revenue		Unit Value
		Before Taxes(6)		Before Tax(6)
		(discounted		(discounted
		at		at
		10%/year)		10%/year)
Reserves Category	Product Type	(US$MM)		($/Bbl)
Total Proved	Light Crude Oil and Medium Crude Oil (1)	53.7		9.05
	Heavy Crude Oil (1)	133.2		15.66
	Conventional Natural Gas (3)(4)	(14.2	)	(6.67	)
	Natural Gas Liquids (2)	40.1		12.42
Proved+Probable	Light Crude Oil and Medium Crude Oil (1)	86.8		9.53
	Heavy Crude Oil (2)	214.9		16.12
	Conventional Natural Gas (3)(5)	(30.5	)	(6.57	)
	Natural Gas Liquids (2)	74.5		11.70
Proved+Probable +Possible	Light Crude Oil and Medium Crude Oil (1)	111.8		9.82
	Heavy Crude Oil (1)	274.9		15.27
	Conventional Natural Gas (3)(5)	(27.2	)	(4.70	)
	Natural Gas Liquids (2)	88.0		11.10
Notes:
(1)  Including solution gas.
(2)  By-products from solution gas and non-associated gas.
(3)  Excluding solution gas.
(4)  Unit values are based on net reserves volumes.
(5)  Includes minor amounts of revenue and costs associated with natural gas from coalbed methane and shale gas reserves.
(6) 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.

22

Reserves Data – Constant Prices and Costs

SUMMARY OF OIL AND GAS RESERVES ⁽³⁾

TOTAL COMPANY

AS OF DECEMBER 31, 2016

(CONSTANT PRICES AND COSTS)

	Light Crude Oil &				Conventional		Natural
	Medium Crude Oil		Heavy Crude Oil		Natural Gas		Gas Liquids		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)	(Bcf)	(Bcf)	(MMbbls)	(MMbbls)	(MMboe)	(MMboe)
Proved
Developed producing	3.0	2.2	9.0	5.0	11.4	9.2	1.8	1.3	15.6	10.1
Developed non-producing	0.9	0.6	1.1	0.6	0.2	0.2	—	—	2.1	1.3
Undeveloped	1.2	1.0	1.1	0.7	1.9	1.7	0.3	0.3	2.9	2.3
Total Proved	5.1	3.9	11.3	6.4	13.5	11.2	2.1	1.6	20.7	13.8
Probable	2.4	1.8	9.2	4.8	4.0	3.4	0.7	0.5	13.0	7.8
Proved+Probable	7.5	5.7	20.3	11.2	17.5	14.6	2.8	2.2	33.5	21.5
Possible	3.8	2.9	7.5	4.2	25.6	22.8	5.0	4.5	20.5	15.3
Proved+Probable+Possible	11.3	8.6	27.8	15.4	43.1	37.4	7.8	6.7	54.0	36.9
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.
(3)  Reserves attributed to the Constant Prices and Costs Cases differ from the Forecast Prices and Costs Cases due to economic truncation associated with a fixed lower oil price in the Constant Price cases.

SUMMARY OF OIL AND GAS RESERVES ⁽³⁾

EGYPT

AS OF DECEMBER 31, 2016

(CONSTANT PRICES AND COSTS)

	Light Crude Oil &
	Medium Crude Oil		Heavy Crude Oil		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)	(MMbbls)
Proved
Developed producing	1.5	1.0	9.0	5.0	10.5	6.0
Developed non-producing	0.9	0.6	1.1	0.6	2.0	1.2
Undeveloped	0.2	0.2	1.1	0.7	1.3	0.9
Total Proved	2.6	1.7	11.3	6.4	13.9	8.1
Probable	1.3	0.8	9.0	4.8	10.3	5.6
Proved+Probable	3.9	2.5	20.3	11.2	24.2	13.7
Possible	1.3	0.9	7.5	4.2	8.8	5.1
Proved+Probable+Possible	5.2	3.4	27.8	15.4	33.0	18.8
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.
(3)  Reserves attributed to the Constant Prices and Costs Cases differ from the Forecast Prices and Costs Cases due to economic truncation associated with a fixed lower oil price in the Constant Price cases.

23

SUMMARY OF OIL AND GAS RESERVES ⁽³⁾

CANADA

AS OF DECEMBER 31, 2016

(CONSTANT PRICES AND COSTS)

	Light Crude Oil &		Conventional		Natural
	Medium Crude Oil		Natural Gas		Gas Liquids		Total Bbls
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
By Category	(MMbbls)	(MMbbls)	(Bcf)	(Bcf)	(MMbbls)	(MMbbls)	(MMboe)	(MMboe)
Proved
Developed producing	1.5	1.3	11.4	9.2	1.8	1.3	5.1	4.1
Developed non-producing	—	—	0.2	0.2	—	—	0.1	0.1
Undeveloped	1.0	0.9	1.9	1.7	0.3	0.3	1.6	1.5
Total Proved	2.5	2.2	13.5	11.2	2.1	1.6	6.9	5.7
Probable	1.1	1.0	4.0	3.4	0.7	0.5	2.5	2.1
Proved+Probable	3.6	3.2	17.5	14.6	2.8	2.2	9.3	7.8
Possible	2.4	2.0	25.6	22.8	5.0	4.5	11.7	10.3
Proved+Probable+Possible	6.1	5.2	43.1	37.4	7.8	6.7	21.0	18.1
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.
(3)  Reserves attributed to the Constant Prices and Costs Cases differ from the Forecast Prices and Costs Cases due to economic truncation associated with a fixed lower oil price in the Constant Price cases.

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

TOTAL COMPANY

AS OF DECEMBER 31, 2016

(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 2016 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	60.7	56.0	51.8	48.3		45.4		60.7	56.0	51.8	48.3		45.4		5.11
Developed non-producing	7.1	6.0	5.2	4.5		3.9		7.1	6.0	5.2	4.5		3.9		4.02
Undeveloped	3.6	1.9	0.2	(1.2	)	(2.2	)	3.6	1.9	0.2	(1.2	)	(2.2	)	0.07
Total Proved	71.4	63.9	57.1	51.6		47.1		71.4	63.9	57.1	51.6		47.1		4.15
Probable	60.0	42.7	32.7	26.0		21.3		60.0	42.7	32.7	26.0		21.3		4.21
Proved+Probable	131.4	106.6	89.8	77.6		68.4		131.4	106.6	89.8	77.6		68.4		4.17
Possible	66.0	32.8	18.5	10.9		6.4		66.0	32.8	18.5	10.9		6.4		1.21
Proved+Probable+Possible	197.4	139.5	108.3	88.5		74.8		197.4	139.5	108.3	88.5		74.8		2.94
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.

24

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

EGYPT

AS OF DECEMBER 31, 2016

(CONSTANT PRICES AND COSTS)

											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	42.1	39.6	37.5	35.6	34.0	42.1	39.6	37.5	35.6	34.0	6.25
Developed non-producing	6.3	5.3	4.5	3.9	3.4	6.3	5.3	4.5	3.9	3.4	3.80
Undeveloped	7.7	6.8	6.0	5.4	4.9	7.7	6.8	6.0	5.4	4.9	6.97
Total Proved	56.1	51.7	48.1	45.0	42.3	56.1	51.7	48.1	45.0	42.3	5.97
Probable	39.6	32.3	26.7	22.4	19.0	39.6	32.3	26.7	44.4	19.0	4.73
Proved+Probable	95.7	84.0	74.8	67.4	61.3	95.7	84.0	74.8	67.4	61.3	5.46
Possible	35.6	27.2	21.4	17.3	14.3	35.6	27.2	21.4	17.3	14.3	4.22
Proved+Probable+Possible	131.3	111.2	96.2	84.7	75.6	131.3	111.2	96.2	84.7	75.6	5.13
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.

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

CANADA

AS OF DECEMBER 31, 2016

(CONSTANT PRICES AND COSTS)

																					Unit Value
																					Before Tax
	Before Income Tax										After Income Tax										(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	18.6		16.4		14.3		12.7		11.4		18.6		16.4		14.3		12.7		11.4		3.45
Developed non-producing	0.9		0.8		0.7		0.6		0.5		0.9		0.8		0.7		0.6		0.5		6.80
Undeveloped	(4.1	)	(4.9	)	(5.9	)	(6.6	)	(7.1	)	(4.1	)	(4.9	)	(5.9	)	(6.6	)	(7.1	)	(4.00)
Total Proved	15.4		12.2		9.1		6.6		4.8		15.4		12.2		9.1		6.6		4.8		1.59
Probable	20.4		10.5		6.0		3.6		2.3		20.4		10.5		6.0		3.6		2.3		2.82
Proved+Probable	35.8		22.6		15.0		10.3		7.0		35.8		22.6		15.0		10.3		7.0		1.92
Possible	30.4		5.7		(2.9	)	(6.4	)	(7.9	)	30.4		5.7		(2.9	)	(6.4	)	(7.9	)	(0.28)
Proved+Probable+Possible	66.2		28.3		12.2		3.9		(0.8	)	66.2		28.3		12.2		3.9		(0.8	)	0.67

25

TOTAL FUTURE NET REVENUE⁽³⁾

(UNDISCOUNTED)

AS OF DECEMBER 31, 2016

(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
Canada	139.8	18.7	72.5	24.7	8.4	15.4	—	15.4
Egypt	265.1	52.2	151.0	5.8	—	56.1	—	56.1
Total Company	404.9	71.0	223.5	30.6	8.4	71.4	—	71.4
Proved+Probable Reserves
Canada	195.9	25.6	92.7	33.1	8.6	35.8	—	35.8
Egypt	450.8	86.6	248.8	19.8	—	95.7	—	95.7
Total Company	646.7	112.2	341.5	52.9	8.6	131.4	—	131.4
Proved+Probable+Possible Reserves
Canada	387.0	50.4	161.6	99.3	10.0	66.2	—	66.2
Egypt	617.4	119.1	339.4	27.6	—	131.3	—	131.3
Total Company	1,004.4	169.5	501.0	126.9	10.0	197.4	—	197.4
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, 2015.

26

NET PRESENT VALUE OF FUTURE NET REVENUE

BY PRODUCT TYPE

AS OF DECEMBER 31, 2016

(CONSTANT 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 Type	(US$MM)		($/Bbl)
Total Proved	Light Crude Oil and Medium Crude Oil	8.7		1.82
	Heavy Crude Oil	41.1		6.45
	Conventional Natural Gas	(5.4	)	(5.46	)
	Natural Gas Liquids	12.8		7.86
Proved+Probable	Light Crude Oil and Medium Crude Oil	16.2		2.33
	Heavy Crude Oil	64.1		5.74
	Conventional Natural Gas	(5.6	)	(4.70	)
	Natural Gas Liquids	15.2		6.95
Proved+Probable +Possible	Light Crude Oil and Medium Crude Oil	16.1		1.50
	Heavy Crude Oil	82.0		5.33
	Conventional Natural Gas	(28.5	)	(6.96	)
	Natural Gas Liquids	38.8		5.82
Note:
(1)  Including solution gas.
(2)  By-products from solution gas and non-associated gas.
(3)  Excluding solution gas.
(4)  Unit values are based on net reserves volumes.
(5)  Includes minor amounts of revenue and costs associated with natural gas from coalbed methane and shale gas reserves.
(6) 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.

27

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.

28

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:
(a)	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.
(b)	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.
(c)	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.
(d)	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.

29

For the reserves, crude oil benchmark reference pricing, as at December 31, 2016, 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	Edmonton Par	Reference	AECO					Inflation	Exchange
	Oklahoma	Price 40 API	Price	Gas Price	Ethane	Propane	Butane	Pentane	Rates(1)	Rate
Year	(US$/Bbl)	(C$/Bbl)	(US$/Bbl)	(C$/MMBtu)	(C$/Bbl)	(C$/Bbl)	(C$/Bbl)	(C$/Bbl)	%/Year	(Cdn$/US$)
Forecast
2017	55.00	67.89	56.20	3.55	10.18	23.76	45.49	71.29	—	0.76
2018	59.16	71.37	60.36	3.21	10.71	24.98	49.96	74.94	2.0	0.78
2019	63.46	73.85	64.66	3.28	11.08	25.85	51.70	77.54	2.0	0.80
2020	68.98	78.00	70.18	3.45	11.70	27.30	54.60	81.91	2.0	0.83
2021	72.52	79.59	73.75	3.61	11.94	27.86	55.71	83.57	2.0	0.85
2022	73.97	81.18	75.22	3.87	12.18	28.41	56.83	85.24	2.0	0.85
2023	76.58	84.13	77.85	3.99	12.62	29.44	58.89	88.33	2.0	0.85
2024	80.41	88.51	81.71	4.11	13.28	30.98	61.96	92.94	2.0	0.85
2025	84.36	93.04	85.68	4.23	13.96	32.56	65.13	97.69	2.0	0.85
2026	86.05	94.90	87.40	4.36	14.24	33.22	66.43	99.65	2.0	0.85
2027	87.77	96.80	89.15	4.48	14.52	33.88	67.76	101.64	2.0	0.85
Thereafter	Escalate oil, gas and product prices at 2.0% per year thereafter								+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, 2016 for crude oil was $29.94/Bbl.

Constant Prices and Costs

The constant prices utilized in the constant price case were as follows:

	Egypt1	Canada1
	Oil	Oil	Gas	Condensate	Butane	Propane	Ethane
Year	$US/Bbl	$US/Bbl	$US/Mcf	$US/Bbl	$US/Bbl	$US/Bbl	$US/Bbl
2016	32.78	37.08	1.54	39.02	19.87	5.19	5.81
2015	44.37	—	—	—	—	—	—
1 The constant price case is based on the average of the reference price received on the first day of each month during the respective year adjusted for respective differentials.

30

Reconciliation of Changes in Reserves

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

TOTAL COMPANY

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

	Light Crude Oil & Medium Crude Oil					Heavy Crude Oil
				Gross Proved						Gross Proved
	Gross Proved		Gross Probable	Plus Probable		Gross Proved		Gross Probable		Plus Probable
Factors	(MMBbl)		(MMBbl)	(MMBbl)		(MMBbl)		(MMBbl)		(MMBbl)
December 31, 2015	2.5		1.6	4.2		15.0		9.6		24.6
Discoveries	—		—	—		0.1		0.1		0.1
Extensions and improved recovery	—		—	—		—		—		—
Technical revisions	0.7		0.2	0.9		4.9		(0.7	)	4.2
Acquisitions	3.6		1.7	5.2		—		—		—
Dispositions	—		—	—		—		—		—
Economic Factors	—		—	—		(0.5	)	0.2		(0.3	)
Production	(0.6	)	—	(0.6	)	(3.9	)	—		(3.9	)
December 31, 2016	6.2		3.5	9.7		15.6		9.1		24.7

	Conventional Natural Gas					Natural Gas Liquids
				Gross Proved				Gross Proved
	Gross Proved		Gross Probable	Plus Probable		Gross Proved	Gross Probable	Plus Probable
Factors	(Bcf)		(Bcf)	(Bcf)		(MMBbl)	(MMBbl)	(MMBbl)
December 31, 2015	—		—	—		—	—	—
Discoveries	—		—	—		—	—	—
Extensions and improved recovery	—		—	—		—	—	—
Technical revisions	—		—	—		—	—	—
Acquisitions	24.3		21.8	46.1		4.1	3.8	7.9
Dispositions	—		—	—		—	—	—
Economic Factors	—		—	—		—	—	—
Production	(0.2	)	—	(0.2	)	—	—	—
December 31, 2016	24.1		21.8	45.9		4.1	3.8	7.9

31

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

EGYPT

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

	Light Crude Oil & Medium Crude Oil					Heavy Crude Oil
				Gross Proved						Gross Proved
	Gross Proved		Gross Probable	Plus Probable		Gross Proved		Gross Probable		Plus Probable
Factors	(MMBbl)		(MMBbl)	(MMBbl)		(MMBbl)		(MMBbl)		(MMBbl)
December 31, 2015	2.5		1.6	4.2		15.0		9.6		24.6
Discoveries	—		—	—		0.1		0.1		0.1
Extensions and improved recovery	—		—	—		—		—		—
Technical revisions	0.7		0.2	0.9		4.9		(0.7	)	4.3
Acquisitions	—		—	—		—		—		—
Dispositions	—		—	—		—		—		—
Economic Factors	—		—	—		(0.5	)	0.2		(0.3	)
Production	(0.6	)	—	(0.6	)	(3.9	)	—		(3.9	)
December 31, 2016	2.7		1.8	4.5		15.6		9.1		24.7

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

CANADA

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

	Light Crude Oil & Medium Crude Oil			Conventional Natural Gas
			Gross Proved				Gross Proved
	Gross Proved	Gross Probable	Plus Probable	Gross Proved		Gross Probable	Plus Probable
Factors	(MMBbl)	(MMBbl)	(MMBbl)	(Bcf)		(Bcf)	(Bcf)
December 31, 2015	—	—	—	—		—	—
Discoveries	—	—	—	—		—	—
Extensions and improved recovery	—	—	—	—		—	—
Technical revisions	—	—	—	—		—	—
Acquisitions	3.6	1.7	5.2	24.3		21.8	46.1
Dispositions	—	—	—	—		—	—
Economic Factors	—	—	—	—		—	—
Production	—	—	—	(0.2	)	—	(0.2	)
December 31, 2016	3.6	1.7	5.2	24.1		21.8	45.9

32

	Natural Gas Liquids
			Gross Proved
	Gross Proved	Gross Probable	Plus Probable
Factors	(MMBbl)	(MMBbl)	(MMBbl)
December 31, 2015	—	—	—
Discoveries	—	—	—
Extensions and improved recovery	—	—	—
Technical revisions	—	—	—
Acquisitions	4.1	3.8	7.9
Dispositions	—	—	—
Economic Factors	—	—	—
Production	—	—	—
December 31, 2016	4.1	3.8	7.9

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 Crude Oil and Medium Crude Oil		Heavy Crude Oil
Year	(MMBbl)		(MMBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	—	—	7.2	7.2
2014(1)	0.3	0.3	0.1	4.5
2015(2)	—	0.3	—	3.1
2016(3)	1.7	2.0	1.0	3.0
Notes:
(1)  In 2014, proved undeveloped medium crude 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.
(2)  In 2015 no new proved undeveloped reserves were assigned.
(3)  In 2016, proved undeveloped reserves were assigned to Egypt's Arta Red Bed development program in West Gharib. The acquisition of oil and gas reserves in Canada in the Harmattan area carry the balance of first attributed oil and gas reserves.

	Conventional Natural Gas		Natural Gas Liquids
Year	(Bcf)		(MMBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	—	—	—	—
2014(1)	—	—	—	—
2015(2)	—	—	—	—
2016(3)	9.0	9.0	1.7	1.7
Notes:
(1)  In 2014, proved undeveloped medium crude 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.
(2)  In 2015 no new proved undeveloped reserves were assigned.
(3)  In 2016, proved undeveloped reserves were assigned to Egypt's Arta Red Bed development program in West Gharib. The acquisition of oil and gas reserves in Canada in the Harmattan area carry the balance of first attributed oil and gas reserves.

33

A total of 9.0 Bcf of conventional natural gas, 2.0 MMbbl of light crude oil and medium crude oil, 3.0 MMbbl of heavy crude oil and 1.7 MMbbl of NGLs were assigned in the DeGolyer Report under forecast prices and costs as gross proved undeveloped reserves as at December 31, 2016, representing approximately 27% of total proved reserves, together with $75.4 million of associated undiscounted future capital expenditures. The proved undeveloped reserves are generally associated with infill/development drilling locations supported by offset well data.

The capital associated with developing proved undeveloped reserves in the DeGolyer Report is expected to be spent between 2017 and 2021, with approximately 45% of the capital scheduled to be spent through 2018 and 75% scheduled to be spent through 2019. Although TransGlobe expects the development of the proved undeveloped reserves attributed to the Company's assets to be consistent with that set out above, current industry conditions and other uncertainties as discussed under "Risk Factors" and "Industry Conditions" herein could result in development of such proved undeveloped reserves on a different schedule than set out above.

Probable Undeveloped Reserves

	Light Crude Oil and Medium Crude Oil		Heavy Crude Oil
Year	(MMBbl)		(MMBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	1.5	1.5	2.4	2.4
2014(1)	0.1	0.6	0.3	3.9
2015(2)	—	0.1	—	2.8
2016(3)	1.1	1.2	0.7	3.1
Notes:
(1)  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.
(2)  In 2015 no new probable undeveloped reserves were assigned.
(3)  In 2016, probable undeveloped reserves were assigned to Egypt's Arta Red Bed development program in West Gharib. The acquisition of oil and gas reserves in Canada in the Harmattan area carry the balance of first attributed oil and gas reserves.

	Conventional Natural Gas		Natural Gas Liquids
Year	(Bcf)		(MMBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
Prior thereto	—	—	—	—
2014(1)	—	—	—	—
2015(2)	—	—	—	—
2016(3)	18.9	18.9	3.3	3.3
Notes:
(1)  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.
(2)  In 2015 no new probable undeveloped reserves were assigned.
(3)  In 2016, probable undeveloped reserves were assigned to Egypt's Arta Red Bed development program in West Gharib. The acquisition of oil and gas reserves in Canada in the Harmattan area carry the balance of first attributed oil and gas reserves.

A total of 18.9 Bcf of conventional natural gas, 1.2 MMbbl of light crude oil and medium crude oil, 3.1 MMbbl of heavy crude oil and 3.3 MMbbl of NGLs were assigned in the DeGolyer Report under forecast prices and costs as gross probable undeveloped reserves as at December 31, 2016, representing approximately 53% of total probable reserves, together with $136.1 million of associated undiscounted future capital expenditures. The probable undeveloped reserves are generally associated with infill/development drilling locations supported by offset well data.

The capital associated with developing probable undeveloped reserves in the DeGolyer Report is expected to be spent between 2017 and 2021, with approximately 32% of the capital scheduled to be spent through 2018 and 62% scheduled to be spent through 2019. Although TransGlobe expects the development of the probable undeveloped reserves attributed to the Company's assets to be consistent with that set out above, current industry conditions and other uncertainties as discussed under "Risk Factors" and "Industry Conditions" herein could result in development of such probable undeveloped reserves on a different schedule than set out above.

Significant Factors or Uncertainties Affecting Reserves Data

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.

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

34

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".

Changes in future commodity prices relative to the forecasts described above under "Pricing Assumptions" could have a negative impact on the reserves associated with the Company's assets, and in particular on the development of undeveloped reserves, unless future development costs are adjusted in parallel. The Company's assets include a significant amount of proved and probable undeveloped reserves. At the forecast prices and costs used in the DeGolyer Report, these development activities are expected to be economic. However, should oil and natural gas prices decrease materially, these activities may need to be deferred to ensuing years to remain economic or may not be pursued at all. Other than the foregoing and the factors disclosed or described herein, the Company does not anticipate any other significant economic factors or other significant uncertainties which may affect any particular components of the reserves data in respect of the Company's assets.

The following table sets forth the development costs deducted in the estimation of future net revenue attributable to: (i) proved reserves (in total) estimated using forecast prices and costs; and (ii) proved plus probable reserves (in total) estimated using forecast prices and costs.

Future Development Costs

FUTURE DEVELOPMENT COSTS

TOTAL COMPANY

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

(US$MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2017	11.9	11.9
2018	24.6	34.6
2019	22.9	40.6
2020	—	9.5
2021	19.4	35.6
Remaining	—	7.3
Total Undiscounted	78.8	139.5
Discounted at 10%	64.1	108.0

To fund its capital program, including future development costs, the Company will consider various financing alternatives, including retention of funds from operations, debt financing and issuance of additional Common Shares and other securities. The Company will evaluate the appropriate financing alternatives closely and make use of such options dependent on the given investment situation and the capital markets. If cash flows are other than projected, capital expenditure levels may be adjusted. In addition, depending on a number of factors including commodity prices, industry conditions and the Company's financial and operating results, funds from credit facilities and equity financings may not be available on terms acceptable to the Company, which could also result in adjustments to the capital program as required. There can be no guarantee that funds will be available or that the Company will be able to allocate funding to develop all of the reserves attributed in the DeGolyer Report. Failure to develop those reserves would have a negative impact on future production and cash flow and could result in negative revisions to reserves.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates set forth above and would reduce the reserves and future net revenue to some degree depending upon the funding sources utilized. The Company does not anticipate that interest or other funding costs would make further development of the Company's assets uneconomic. See "Significant Factors or Uncertainties".

35

FUTURE DEVELOPMENT COSTS

EGYPT

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

(US$MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2017	2.9	2.9
2018	6.5	13.8
2019	3.1	3.1
2020	—	0.7
2021	0.2	0.2
Remaining	—	—
Total Undiscounted	12.6	20.7
Discounted at 10%	11.3	18.2

FUTURE DEVELOPMENT COSTS

CANADA

AS OF DECEMBER 31, 2016

(FORECAST PRICES AND COSTS)

(US$MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2017	9.0	9.0
2018	18.1	20.8
2019	19.9	37.5
2020	—	8.8
2021	19.2	35.4
Remaining	—	7.3
Total Undiscounted	66.1	118.8
Discounted at 10%	52.8	89.8

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, 2016. 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	110	110.0	136	136.0	—	—	—	—
Canada	55	51.4	14	9.7	71	65	9	4.0
Total	165	161.4	150	145.7	71	65	9	4.0

36

Properties with No Attributed Reserves

The following table sets out the Company's developed and undeveloped land holdings as at December 31, 2016.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Egypt	35,635	35,635	1,464,150	1,464,150	1,499,785	1,499,785
Canada	—	—	40,294	34,672	40,294	34,672
Total	35,635	35,635	1,504,444	1,498,822	1,540,079	1,534,457

Commitments

In the West Gharib concession, all work commitments have been fulfilled and there are no potential land expiries in 2017.

The West Bakr concession was purchased on December 29, 2011. All work commitments have been fulfilled and there are no potential land expiries in 2017.

The South Alamein concession is in the second two-year extension period which was due to expire on April 5, 2014. EGPC put certain areas within the concession on hold as of July 2012 pending access by the contractor. All work commitments have been fulfilled. In September 2016 the Company was granted access to the concession which re-started the final exploration period which is scheduled to expire in June of 2018.

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, 2016, the Company had expended $30.0 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, which now extends to May 7, 2017. Pursuant to the terms of the concession agreement, 25% of the lands must be relinquished prior to entering the next exploration period (2 year term). If the Company elects to not enter the next exploration period, all remaining land which has not been converted to or in the process of being converted to development leases would be relinquished.

In the South East Gharib concession, the Contractor had 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 2-D seismic during the initial three year exploration period, which commenced on November 7, 2013. The Company met its financial commitment at South East Gharib in 2016, and relinquished its interest in the concession during the fourth quarter as no commercially viable quantities of oil have been discovered.

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, 2016, the Company had expended $6.6 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, which now extends to May 7, 2017. Subsequent to year end the Company completed its work and financial commitments. Since no commercially viable quantities of oil have been discovered at South West Gharib, the Company intends to relinquish its interest in the concession during the first half of 2017.

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, 2016, the Company had met its financial commitment. The first exploration phase ended November 7, 2016. Prior to expiry, the Company elected to enter the first two-year extension period (expiry November 7, 2018). The Company had met its financial commitment for the first phase ($8.0 million) and the first extension ($4.0 million), however the Company had not completed the first phase work program. Prior to entering the first extension the Company posted a $4.0 million performance bond with EGPC to carry forward two exploration commitment wells into the first extension period. The $4.0 million performance bond is supported by a production guarantee from the Company's producing concessions which will be released when the commitment wells have been drilled. In accordance with the concession agreement the Company relinquished 25% of the original exploration acreage prior to entering the first extension period. In addition, the first extension period has an additional financial commitment of $4.0 million, which has been met, and two additional exploration wells.

In the North West Sitra concession, the Company has a minimum financial commitment of $10.0 million ($10.0 million net) and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three and a half year exploration period, which commencedon January 8, 2015. As at December 31, 2016, the Company had expended $0.3 million towards meeting that commitment. There are no potential land expiries in 2017.

At December 31, 2016, TransGlobe had outstanding cash collateralized letters of credit in the amount of $18.3 million to support its work commitments under the Egyptian PSCs. An additional $10.0 million of work commitments were backstopped by the Company's accounts receivable from EGPC.

Approximately 8,080 gross acres of mineral rights could expire prior to December 31, 2017 in Canada as a result of those rights reaching the end of their initial land tenure.

Development of properties with no attributable reserves are subject to current industry conditions and uncertainties as indicated under "Risk Factors" and "Industry Conditions" herein. In addition, the Company expects that funding of development operations on such properties will be evaluated in the context of the Company's 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.

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.

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Forward Contracts

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

Subject to the Company's Hedging Policy, 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, 2016, 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.

In connection with the Company's Canadian operations, the Company will incur abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The expected total reserve well abandonment and reclamation costs, net of estimated salvage value, included in the DeGolyer Report for the 171.5 net wells under the proved reserves category is $13.3 million undiscounted, of which a total of $2.8 million is estimated to be incurred through 2019.

Tax Horizon

In 2016, the Company did not pay any income taxes in Canada and does not anticipate any taxes payable in the near future. In Egypt, the Company's income tax liabilities are paid out of the government's share of production. As such, all current income tax liabilities in Egypt 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, 2016 (excluding Canadian expenditures):

	Egypt	Canada	Total
(US$M)
Property acquisition costs
Proved properties	—	59,475	59,475
Undeveloped properties	—	—	—
Exploration costs	19,425	—	19,425
Development costs	6,618	—	6,618
Corporate and other	615	—	615
Total	26,658	59,475	86,133

Exploration and Development Activities

The following tables set forth the gross and net exploratory and development wells which the Company drilled in Egypt during the year ended December 31, 2016:

Egypt	Gross1			Net1
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	—	—	—	—	—	—
Crude Oil	2.0	3.0	5.0	2.0	3.0	5.0
Service	—	—	—	—	—	—
Dry and Abandoned	12.0	—	12.0	12.0	—	12.0
Total	14.0	3.0	17.0	14.0	3.0	17.0

Current development activities are focused on the West Gharib, West Bakr and NW Gharib concessions. Other key areas for 2016 include the exploration drilling program at NW Gharib, SW Gharib and SE Gharib.

The vendor of the Canadian assets acquired by TransGlobe did not drill, and the Company did not drill any wells on such assets in 2016.

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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, 2017 by DeGolyer which is reflected in the estimate of future net revenue (Forecast Price Case) disclosed in the prior reserves summary tables.

	Egypt					Canada			Total
	West Gharib		West Gharib	West Bakr	NW Gharib				Company
	Light and Medium Crude Oil		Heavy Crude Oil	Heavy Crude Oil	Heavy Crude Oil	Light Crude Oil	Natural Gas	NGLs
	Gross		Gross	Gross	Gross	Gross	Gross	Gross	Gross
	(Bbls/d)		(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(Boe/d)
Proved Developed Producing	1,092		4,440	5,104	343	516	6,008	907	13,403
Proved Developed
Non-Producing	164		74	348	—	4	40	5	602
Proved Undeveloped	(5	)	615	216	—	132	113	20	997
Total Proved	1,251		5,129	5,668	343	652	6,161	932	15,002
Total Probable	105		326	215	321	17	113	18	1,021
Total Proved Plus Probable	1,356		5,455	5,883	664	669	6,274	950	16,023

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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:

	2016
	Quarter Ended
	Mar. 31	Jun. 30	Sep. 30	Dec. 31
Average Daily Production Volumes
Egypt(1)
Heavy Crude Oil (Bbls/d)	10,342	9,851	10,254	11,317
Light Crude Oil and Medium Crude Oil (Bbls/d)	1,716	1,621	1,479	1,473
Canada (2)
Light Crude Oil and Medium Crude Oil (Bbls/d)	—	—	—	71
Natural Gas (Boe/d)	—	—	—	153
Natural Gas Liquids (Bbls/d)	—	—	—	134
Combined (Boe/d) (3)	12,058	11,472	11,733	13,148
Average Daily Sales Volumes
Egypt
Heavy Crude Oil (Bbls/d)	12,116	10,118	10,037	6,147
Light Crude Oil and Medium Crude Oil (Bbls/d)	2,010	1,665	1,448	800
Canada
Light Crude Oil and Medium Crude Oil (Bbls/d)	—	—	—	71
Natural Gas (Boe/d)	—	—	—	153
Natural Gas Liquids (Bbls/d)	—	—	—	134
Combined (Boe/d) (3)	14,126	11,783	11,485	7,305
Average Price Received
Egypt(1)
Heavy Crude Oil (US$/Bbl)	22.58	30.27	34.43	37.35
Light Crude Oil and Medium Crude Oil (US$/Bbl)	22.58	30.27	34.43	37.35
Canada
Light Crude Oil and Medium Crude Oil (US$/Bbl)	—	—	—	40.72
Natural Gas (US$/Boe)	—	—	—	10.82
Natural Gas Liquids (US$/Bbl)	—	—	—	17.36
Combined (US$/Boe)	22.58	30.27	34.43	36.45
Royalties and Taxes
Egypt(1)
Heavy Crude Oil (US$/Bbl)	11.49	15.08	18.68	37.35
Light Crude Oil and Medium Crude Oil (US$/Bbl)	11.49	15.08	18.68	37.35
Canada
Light Crude Oil and Medium Crude Oil (US$/Bbl)	—	—	—	4.01
Natural Gas (US$/Boe)	—	—	—	4.01
Natural Gas Liquids (US$/Bbl)	—	—	—	4.01
Combined (US$/Bbl)	11.49	15.08	18.68	35.72
Operating Expenses
Egypt(1)
Heavy Crude Oil (US$/Bbl)	10.21	9.92	10.36	8.37
Light Crude Oil and Medium Crude Oil (US$/Bbl)	10.21	9.92	10.36	8.37
Canada (4)(5)(6)
Light Crude Oil and Medium Crude Oil (US$/Bbl)	—	—	—	8.17
Natural Gas (US$/Boe)	—	—	—	8.17
Natural Gas Liquids (US$/Bbl)	—	—	—	8.17
Combined (US$/Bbl)	10.21	9.92	10.36	8.36
Selling Costs
Egypt(1)
Heavy Crude Oil (US$/Bbl)	0.64	0.04	—	—
Light Crude Oil and Medium Crude Oil (US$/Bbl)	0.64	0.04	—	—
Canada
Light Crude Oil and Medium Crude Oil (US$/Bbl)	—	—	—	—
Natural Gas (US$/Boe)	—	—	—	—
Natural Gas Liquids (US$/Bbl)	—	—	—	—
Combined (US$/Bbl)	0.64	0.04	0.53	—
Netback Received (7)
Egypt(1)

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Heavy Crude Oil (US$/Bbl)	0.24	5.23	5.39	(8.37	)
Light Crude Oil and Medium Crude Oil (US$/Bbl)	0.24	5.23	5.39	(8.37	)
Canada (8)(9)
Light Crude Oil and Medium Crude Oil (US$/Bbl)	—	—	—	28.54
Natural Gas (US$/Boe)	—	—	—	(1.36	)
Natural Gas Liquids (US$/Bbl)	—	—	—	5.18
Combined (US$/Bbl)	0.24	5.23	4.86	(7.63	)
Notes:
(1) All production from West Gharib, West Bakr and NW 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) Includes minor royalty volumes received but does not deduct royalty volumes paid.
(3) During 2015, the Company began direct marketing its share of entitlement oil from the West Gharib and West Bakr concessions. Reported sales volumes fluctuate quarter to quarter depending on the timing of liftings. Under-lifted entitlement oil is held and booked as inventory. At year-end 2016, the Company held 1,265,080 barrels of entitlement inventory.
(4) Includes solution gas and by-products.
(5) Operating costs have been allocated to each product type based on proportionate revenue splits and other reasonable methods of allocation.
(6) Operating costs include all costs related to the operation of wells, facilities and gathering systems, transportation and NGLs processing.
(7) Netbacks are calculated by subtracting royalties, operating and transportation costs from revenues. Netbacks do not include other income.
(8) Includes NGLs.
(9)  Average prices received, royalties, operating costs and netbacks have not been provided separately for NGLs as they have been included with the amounts stated above for conventional natural gas, as conventional natural gas is the primary revenue stream.

The following table indicates the Company's average daily volumes from its important fields for the year ended December 31, 2016:

		Light and		Natural
	Heavy Crude	Medium	Natural	Gas
	Oil	Crude	Gas	Liquids	Total
	(Bbls/d)	(Bbls/d)	(Mcf/d)	(Bbls/d)	(Boe/d)
Egypt
Arta/East Arta	4,800	—	—	—	4,800
Hana	—	852	—	—	852
Hana West	—	722	—	—	722
Hoshia	667	—	—	—	667
West Bakr	4,958	—	—	—	4,958
NW Gharib	16	—	—	—	16
Other Egypt	—	—	—	—	—
Canada	—	19	224	34	90
Total	10,441	1,593	224	34	12,105

DIVIDEND POLICY

No dividends were paid on the Company's Common Shares in 2016. The Company has paid the following dividends on its Common Shares during the years ended December 31, 2015 and 2014.

Ex-dividend date	Record date	Payment date	Per share amount
May 20, 2014	May 22, 2014	May 28, 2014		$0.10
June 12, 2014	June 16, 2014	June 30, 2014		$0.05
September 11, 2014	September 15, 2014	September 30, 2014		$0.05
December 11, 2014	December 15, 2014	December 31, 2014		$0.05
March 12, 2015	March 16, 2015	March 31, 2015		$0.05
June 11, 2015	June 15, 2015	June 30, 2015		$0.05
September 11, 2015	September 15, 2015	September 30, 2015		$0.05
December 11, 2015	December 15, 2015	December 31, 2015		$0.025

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, 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 credit facilities or other lending arrangements entered into by the Company from time to time and 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. On March 8, 2016, the Company suspended its quarterly dividend payment.

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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 13, 2017 there were 72,205,369 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, Suite 2300, 250 - 5th Street S.W., Calgary, Alberta T2P 0R4, Telephone: (403) 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 Cdn$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.

On February 23, 2017, the Company provided notice that it intends to pay the principal amount of Debentures plus acrrued and unpaid interest in cash on the Maturity Date being March 31, 2017.

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 73.3676 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.

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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 were not permitted to 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 to 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.

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: (i) in a manner inconsistent

43

with the terms (as they exist on the date of issue) of the Debentures; or (ii) 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).

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.

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

44

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.

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
2016
January	2.46	1.52	2,450,788
February	1.97	1.66	1,319,039
March	2.39	1.99	4,101,504
April	2.50	2.14	2,146,999
May	2.52	2.22	1,030,716
June	2.49	2.07	1,572,837
July	2.44	2.12	562,638
August	2.68	2.08	1,923,195
September	2.83	2.36	2,546,095
October	2.80	2.45	1,161,422
November	2.50	2.27	830,608
December	2.57	2.19	2,052,165
2017
January	2.46	2.18	1,268,814
February	2.40	2.16	1,827,613
March (1 to 13)	2.26	2.13	438,836

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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
2016
January	1.78	1.06	3,938,882
February	1.46	1.19	2,293,644
March	1.81	1.49	3,419,101
April	2.01	1.62	2,322,569
May	1.97	1.69	2,336,165
June	1.97	1.60	1,986,865
July	1.87	1.62	759,171
August	2.10	1.59	2,523,491
September	2.16	1.77	2,131,294
October	2.13	1.82	1,382,226
November	1.84	1.70	1,290,884
December	1.93	1.65	3,428,086
2017
January	1.84	1.66	2,083,088
February	1.84	1.63	2,364,181
March (1 to 13)	1.70	1.57	949,412

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
2016
January	91.50	81.01	1,492,000
February	85.50	80.00	1,230,000
March	91.00	85.25	1,990,000
April	92.25	88.25	2,004,000
May	93.00	91.00	1,550,100
June	94.05	91.40	3,509,000
July	95.60	94.50	994,000
August	98.75	95.50	3,931,900
September	100.50	98.02	12,674,000
October	100.75	100.25	5,783,000
November	100.51	100.03	2,980,000
December	100.25	99.80	937,400
2017
January	100.00	99.50	1,627,000
February	100.05	99.50	1,820,000
March (1 to 13)	100.40	99.75	3,262,000

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PRIOR SALES

The following table summarizes the issuance of stock options, which are convertible into Common Shares, during the year ended December 31, 2016:

Date of Issuance	Number of Stock Options	Price per Stock Option
March 18, 2016	1,469,853	Cdn$2.19

The following table summarizes the issuance of restricted share units ("RSUs"), which are cash-settled, during the year ended December 31, 2016:

Date of Issuance	Number of RSUs	Price per RSU
May 20, 2016 (1)	309,386	N/A

Note:

⁽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.

The following table summarizes the issuance of performance share units ("PSUs"), which are cash-settled, during the year ended December 31, 2016:

Date of Issuance	Number of PSUs (2)	Price per PSU
May 20, 2016(1)	691,191	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⁾ At vesting, the number of PSUs granted will be adjusted by a performance payout multiplier (including reinvested dividends) and the value of each PSU on the vesting date will be based on the previous 20-day weighted average price of the Common Shares. The performance payout multiplier will range between 50% and 150% of PSUs granted based on share price performance relative to the TSX Exploration and Producers Index.

The following table summarizes the issuance of deferred share units ("DSUs"), which are cash-settled, during the year ended December 31, 2016:

Date of Issuance	Number of DSUs (2)	Price per DSU
May 20, 2016 (1)	138,320	N/A
June 27, 2016	28,745	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⁾  DSUs are not paid out until a Director departs from the Board, at which time they are paid out in cash equal to the number of DSUs held, multiplied by the price of the Common Shares at the time of payout.

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 contractual restrictions on transfer.

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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 aggregate number of securities of the Company owned by such individuals as at March 13, 2017 is as follows:

		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) 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(3) 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(2) Denmark Copenhagen	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) 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(3) 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(2)(3) 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.
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 Human Resources and Governance Committee.

Member of the Reserves Health Safety Environment and Social Responsibility Committee

(3) As at March 13, 2017, the directors and officers of TransGlobe, as a group, beneficially owned or controlled or directed, directly or indirectly, 3,380,585 Common Shares or approximately 4.8% of the issued and outstanding Common Shares.

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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:

(i) while the person was acting in the capacity as director, chief executive officer or chief financial officer, was the subject of a cease trade order 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

(ii) was subject to an order that resulted, after the director or 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 order 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, executive officer or securityholder.

Penalties or Sanctions

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 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 to 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 report, valuation, statement or opinion 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 Chartered Professional Accountants of Alberta and the rules and standards of the PCAOB and the securities laws and regulations administered by the SEC.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings material to the Company to which the Company is or was a party to, or in respect of which any of its properties are or were the subject of, during the 2016 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 2016 financial year, no other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decision, and no settlement agreements entered into by the Company before a court relating to securities legislation or with a securities regulatory authority during the 2016 financial year.

49

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, directly or indirectly, more than 10% of the outstanding Common Shares or who exercises control or direction over, directly or indirectly, 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 the Company's Profile on SEDAR at www.sedar.com; (ii) the marketing agreement dated February 10, 2017 which is filed on the Company's profile on SEDAR at www.sedar.com; and (iv) the $75 million crude oil prepayment agreement dated February 2017 described under "General Development of the Business - Recent Developments" and is available on the Company's profile on SEDAR.com at www.sedar.com

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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), 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.

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 was most recently Chairman of WesternZagros Resources Ltd., (until 2016) 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.
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 Weir (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 Alberta until 1979. In January 1979, Mr. Jennings co-founded 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, 2016 and December 31, 2015 were as follows (all fees are in Canadian dollars):

	Fiscal Year Ended		Fiscal Year Ended
	December 31, 2016		December 31, 2015
Audit Fees	$	435,490	$	473,897
Audit Related Fees	—		32,281
Tax Fees	9,272		12,625
All Other Fees	NIL		NIL
TOTAL	$	444,762	$	518,803

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 performance of 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, 2016 and 2015, no other fees were incurred other than those described above.

CANADIAN INDUSTRY CONDITIONS

Companies operating in the oil and natural gas industry in Canada are subject to extensive regulation and control of operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government with respect to the pricing and taxation of oil and natural gas, including the governments of Canada and Alberta, both of which investors in the Company should carefully consider. All current legislation is a matter of public record and the Company is unable to predict what additional legislation or amendments governments may enact in the future. The following comprises some of the principal aspects of legislation, regulations and agreements governing the Company's Canadian operations.

Pricing and Marketing

Oil

In Canada, producers of oil are entitled to negotiate sales contracts directly with oil purchasers, which results in the market determining the price of oil. Worldwide supply and demand factors primarily determine oil prices; however, regional market and transportation issues also influence prices. The specific price depends in part on oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, the supply/demand balance and contractual terms of sale. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB"). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB. The NEB underwent a consultation process to update the regulations governing the issuance of export licences. The updating process was necessary to meet the criteria set out in the federal Jobs, Growth and Long-term Prosperity Act(Canada) (the "Prosperity Act") which received Royal Assent on June 29, 2012. The Regulations Amending the National Energy Board Act Part VI (Oil and Gas) Regulations came into effect on July 31, 2015 and provides the requirements for obtaining long-term licences.

Natural Gas

Canada's natural gas market has been deregulated since 1985. Supply and demand determine the price of natural gas and price is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system, at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange, Intercontinental Exchange or the New York Mercantile Exchange in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms. Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m³ per day) must be made pursuant to an NEB order. Natural gas export contracts of a longer duration (to a maximum of 40 years) or that deal with larger quantities of natural gas requires an exporter to obtain an export licence from the NEB.

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The North American Free Trade Agreement

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico came into force on January 1, 1994. In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply.

All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports.NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The new administration in the United States has indicated an intention to seek renegotiation of NAFTA, the impact of which on the oil and gas industry is uncertain.

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations that govern royalties, production rates and other matters. The royalty regime in a given province is a significant factor in the profitability of oilsands projects, crude oil, natural gas liquids, sulphur and natural gas production. Royalties payable on production from lands where the Crown does not hold the mineral rights are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties. Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced. Other royalties and royalty‑like interests are carved out of the working interest owner's interest, from time to time, through non‑public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced when commodity prices are low to encourage exploration and development activity by improving earnings and cash flow within the industry.

The Canadian federal government has signaled that it will inter alia phase out subsidies for the oil and gas industry, which include only allowing the use of the Canadian Exploration Expenses tax deduction in cases of successful exploration, implementing stringent reviews for pipelines and establishing a pan-Canadian framework for addressing climate change. These changes could affect earnings of companies operating in the oil and natural gas industry.

Alberta

In Alberta, the Crown owns 81% of the province's mineral rights. The remaining 19% are 'freehold' mineral rights owned by the federal government on behalf of First Nations or in National Parks, and by individuals and companies. Provincial government royalty rates apply to Crown-owned mineral rights. On January 29, 2016, the Government of Alberta released and accepted the Royalty Review Advisory Panel's recommendations, which outlined the implementation of a "Modernized Royalty Framework" for Alberta (the "MRF"). The MRF formally took effect on January 1, 2017 for wells drilled after this date. Wells drilled prior to January 1, 2017 will continue to be governed by the "New Royalty Framework" (implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008) (the "Alberta Royalty Framework") for a period of 10 years until January 1, 2027. The MRF is structured in three phases: (i) Pre-Payout; (ii) Mid-Life; and (iii) Mature. During the Pre-Payout phase, a fixed 5% royalty will apply until the well reaches payout. Well payout occurs when the cumulative revenue from a well is equal to the Drilling and Completion Cost Allowance (determined by a formula that approximates drilling and completion costs for wells based on total depth, length, and proppant placed). The new royalty rate for Pre-Payout under the MRF will be payable on gross revenue generated from all production streams (oil, gas, and natural gas liquids), eliminating the need to label a well as "oil" or "gas". Post-payout, the Mid-Life phase will apply a higher royalty rate than the Pre-Payout phase. Depending on the commodity price of the substance the well is producing, the royalty rate could range from 5% - 40%. The metrics for calculating the Mid-Life phase royalty are based on commodity prices and are intended, on average, to yield the same internal rate of return as under the Alberta Royalty Framework. In the Mature phase of the MRF, once a well reaches the tail end of its cycle and production falls below a Maturity Threshold, currently the equivalent of 194 m³ (40 barrels of oil equivalent per day or 345,500 m³ of gas per month), the royalty rate will move to a sliding scale (based on volume and price) with a minimum royalty rate of 5%. The downward adjustment of the royalty rate in the Mature phase is intended to account for the higher per-unit fixed cost involved in operating an older well.

On July 11, 2016, the Government of Alberta released details of the Enhanced Hydrocarbon Recovery Program and the Emerging Resources Program. These programs, that came into effect on January 1, 2017, are a part of the MRF and account for the higher costs associated with enhanced recovery methods and with developing emerging resources in an effort to make difficult investments economically viable and to increase royalties. Certain eligibility criteria must be satisfied in order for a proposed project to fall under each program. Enhanced recovery scheme applications can be submitted to the Alberta Energy Regulator ("AER").

Oil sands projects are also subject to Alberta's royalty regime. The MRF does not change the oil sands royalty framework, however, the Government of Alberta plans to increase transparency in the method and figures by which the royalties are calculated. Prior to payout of an oil sands project, the royalty is payable on gross revenues of an oil sands project. Gross revenue royalty rates range between 1% and 9% depending on the market price of oil, determined using the average monthly price, expressed in Canadian dollars, for WTI crude oil at Cushing, Oklahoma. Rates are 1% when the market price of oil is less than or equal to $55 per barrel and increase for every dollar of market price of oil increase to a maximum of 9% when oil is priced at $120 or higher. After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue royalty rate of between 1% and 9% and the net revenue royalty based on the net revenue royalty rate. Net revenue royalty rates start at 25% and increase for every dollar of market price of oil increase above $55 up to 40% when oil is priced at $120 or higher.

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Currently, producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.

Royalties, for wells drilled prior to January 1, 2017 are paid pursuant to the Alberta Royalty Framework until January 1, 2027. Royalty rates for conventional oil are set by a single sliding scale formula, which is applied monthly and incorporates separate variables to account for production rates and market prices. The maximum royalty payable under the royalty regime is 40%. Royalty rates for natural gas under the royalty regime depends on the price of each of the components of the gas stream, the productivity of the well, its acid gas factor and the depth of the producing zone. These factors are employed on a sliding scale formula to determine the natural gas royalty rate per well with the maximum royalty payable under the royalty regime set at 36% and a minimum royalty rate of 5%.

Producers of oil and natural gas from freehold lands in Alberta are required to pay freehold mineral tax. The freehold mineral tax is a tax levied by the Government of Alberta on the value of oil and natural gas production from lands where the Crown does not hold the rights to mines and minerals and is derived from the Freehold Mineral Rights TaxAct (Alberta). The freehold mineral tax is levied on an annual basis on calendar year production using a tax formula that takes into consideration, among other things, the amount of production, the hours of production, the value of each unit of production, the tax rate and the percentages that the owners hold in the title. The basic formula for the assessment of freehold mineral tax is: revenue less allocable costs equals net revenue divided by wellhead production equals the value based upon unit of production. If payors do not wish to file individual unit values, a default price is supplied by the Crown. On average, the tax levied is 4% of revenues reported from freehold mineral title properties.

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage oil and gas development and new drilling. For example, the Innovative Energy Technologies Program (the "IETP") has the stated objectives of increasing recovery from oil and gas deposits, finding technical solutions to the gas over bitumen issue, improving the recovery of bitumen by in-situ and mining techniques and improving the recovery of natural gas from coal seams. The IETP provides royalty adjustments to specific pilot and demonstration projects that utilize new or innovative technologies to increase recovery from existing reserves.

In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources (the "Emerging Resource and Technologies Initiative"). These initiatives apply to wells drilled before January 1, 2017, for a ten-year period, until January 1, 2027. Specifically:

• Coalbed methane wells will receive a maximum royalty rate of 5% for 36 producing months up to 750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;

• Shale gas wells will receive a maximum royalty rate of 5% for 36 producing months with no limitation on production volume, retroactive to wells that began producing on or after May 1, 2010;

• Horizontalgaswells will receive a maximum royalty rate of 5% for 18 producing months up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010; and

• Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty rate of 5% with volume and production month limits set according to the depth of the well (including the horizontal distance), retroactive to wells that commenced drilling on or after May 1, 2010.

Land Tenure

The respective provincial governments predominantly own the rights to crude oil and natural gas located in the western provinces. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Private ownership of oil and natural gas also exists in such provinces and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Each of the provinces of Alberta, British Columbia and Saskatchewan have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or licence. The Government of British Columbia expanded its policy of deep rights reversion for leases issued after March 29, 2007 to provide for the reversion of both shallow and deep formations that cannot be shown to be capable of production at the end of the primary term.

Alberta also has a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licences issued after January 1, 2009 at the conclusion of the primary term of the lease or licence.

Production and Operation Regulations

The oil and natural gas industry in Canada is highly regulated and subject to significant control by provincial regulators. Regulatory approval is required for, among other things, the drilling of oil and natural gas wells, construction and operation of facilities, the storage, injection and disposal of substances and the abandonment and reclamation of well sites. In order to conduct oil and gas operations and remain in good standing with the applicable provincial regulator, producers must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance with such legislation, regulations, orders, directives or other directions can be costly and a breach of the same may result in fines or other sanctions.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation under a variety of Canadian federal, provincial, territorial and municipal laws and regulations, all of which is subject to governmental review and revision from time to time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licences and authorizations, civil liability and the imposition of material fines and penalties. In addition to these specific, known requirements, future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gas ("GHG") emissions, may impose further requirements on operators and other companies in the oil and natural gas industry.

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Federal

Canadian environmental regulation is the responsibility of the federal government and provincial governments. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law will prevail, however, such conflicts are uncommon. The federal government has primary jurisdiction over federal works, undertakings and federally regulated industries such as railways, aviation and interprovincial transport. The Canadian Environmental Protection Act, 1999 and the Canadian Environmental Assessment Act, 2012 provide the foundation for the federal government to protect the environment and cooperate with provinces to do the same.

Pursuant to the Prosperity Act, the Government of Canada amended or repealed several pieces of federal environmental legislation and in addition, created a new federal environmental assessment regime that came in to force on July 6, 2012. The changes to the environmental legislation under the Prosperity Act are intended to provide for more efficient and timely environmental assessments of projects that previously had been subject to overlapping legislative jurisdiction.

On June 20, 2016, the Federal Government launched a review of current environmental and regulatory processes with a focus on rebuilding trust in the environmental assessment processes, modernizing the NEB, and introducing modernized safeguards to both the Fisheries Act and the Navigation Protection Act. An Expert Panel has been convened and is expected to complete its work by March 31, 2017. At such time, the Minister of Environment and Climate Change will consider the recommendations in the Panel’s report and identify next steps to improve federal environmentalprocesses, which is expected to take place during the summer/fall of 2017. Until this process is complete, the Federal Government's interim principles released January 27, 2016 will continue to guide decision-making authorities for projects currently undergoing environmental assessment. The Federal Government has not provided any indication on what changes-if any-will be implemented or when, but increased delays and uncertainty surrounding the environmental assessment process should be expected for large projects.

In a further development, on November 29, 2016, the Government of Canada announced that it would introduce legislation by spring 2017 to formalize a moratorium for crude oil tankers on British Columbia's north coast. It is unclear how the proposed moratorium may affect ongoing LNG export projects currently under consideration and development. On the same day, the Government of Canada also approved, subject to a number of conditions, the Trans Mountain Pipeline system expansion backed by Kinder Morgan Canada as well as the replacement of Enbridge Inc.'s plan to replace its Line 3 pipeline system, while also rejecting Enbridge Inc.'s proposed Northern Gateway project. On January 11, 2017, the Government of British Columbia confirmed that the conditions to the approval of the Trans Mountain Pipeline have been satisfied. Additionally, the new administration in the United States has indicated a willingness to revisit other pipeline projects that had been previously rejected.

Alberta

The AER is the single regulator responsible for all energy development in Alberta. The AER ensures the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources including allocating and conserving water resources, managing public lands, and protecting the environment. The AER's responsibilities exclude the functions of the Alberta Utilities Commission and the Surface Rights Board, as well as Alberta Energy's responsibility for mineral tenure. The objective behind a single regulator is an enhanced regulatory regime that is efficient, attractive to business and investors, and effective in supporting public safety, environmental management and resource conservation while respecting the rights of landowners.

The Government of Alberta relies on regional planning to accomplish its responsible resource development goals. The following frameworks, plans and policies form the basis of Alberta's Integrated Resource Management System ("IRMS"). The IRMS method to natural resource management provides for engagement and consultation with stakeholders and the publicand examines the cumulative impacts of development on the environment and communities, by incorporating the management of all resources, including energy, minerals, land, air, water and biodiversity. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including Alberta Environment and Parks, Alberta Energy, the Policy Management Office, the Aboriginal Consultation Office and the Land Use Secretariat.

In December 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF"). The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.

Proclaimed in force in Alberta on October 1, 2009, the Alberta Land Stewardship Act (the "ALSA") provides the legislative authority for the Government of Alberta to implement the policies contained in the ALUF. Regional plans established under the ALSA are deemed to be legislative instruments equivalent to regulations and will be binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry. In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail. Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan. The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licences, registrations, approvals and authorizations for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan. Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.

On August 22, 2012, the Government of Alberta approved the Lower Athabasca Regional Plan ("LARP") which came into force on September 1, 2012. The LARP is the first of seven regional plans developed under the ALUF. LARP covers a region in the northeastern corner of Alberta that is approximately 93,212 square kilometres in size. The region includes a substantial portion of the Athabasca oil sands area, which contains approximately 82% of the province's oil sands resources and much of the Cold Lake oil sands area.

LARP establishes six new conservation areas and nine new provincial recreation areas. In conservation and provincial recreation areas, conventional oil and gas companies with pre-existing tenure may continue to operate. Any new petroleum and gas tenure issued in conservation and provincial recreation areas will include a restriction that prohibits surface access. In contrast, oil sands companies' tenure has been (or will be) cancelled in conservation areas and no new oil sands tenure will be issued. While new oil sands tenure will be issued in provincial recreation areas, new and existing oil sands tenure will prohibit surface access.

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In July 2014, the Government of Alberta approved the South Saskatchewan Regional Plan ("SSRP") which came into force on September 1, 2014. The SSRP is the second regional plan developed under the ALUF. The SSRP covers approximately 83,764 square kilometres and includes 44% of the provincial population.

The SSRP creates four new and four expanded conservation areas, and two new and six expanded provincial parks and recreational areas. Similar to LARP, the SSRP will honour existing petroleum and natural gas tenure in conservation and provincial recreational areas. However, any new petroleum and natural gas tenures sold in conservation areas, provincial parks, and recreational areas will prohibit surface access. However, oil and gas companies must minimize impacts of activities on the natural landscape, historic resources, wildlife, fish and vegetation when exploring, developing and extracting the resources. Freehold mineral rights will not be subject to this restriction.

Phase 1 Consultation of the North Saskatchewan Region Plan ("NSRP") has been completed and the Regional Advisory Council is currently preparing its Recommendation to Government report. The NSRP is located in central Alberta and is approximately 85,780 square kilometres in size and affects activities in central Alberta, and encompasses an area between the province's borders with British Columbia and Saskatchewan. The Upper Peace Region Plan, Lower Peace Region Plan, Red Deer Region Plan and Upper Athabasca Region Plan have not been started.

Liability Management Rating Programs

Alberta

In Alberta, the AER administers the Licensee Liability Rating Program (the "AB LLR Program"). The AB LLR Program is a liability management program governing most conventional upstream oil and gas wells, facilities and pipelines. Alberta's Oil and Gas Conservation Act ("OGCA") establishes an orphan fund (the "Orphan Fund") to pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program if a licensee or working interest participant ("WIP") becomes defunct or is unable to meet its obligations. The Orphan Fund is funded by licensees in the AB LLR Program through a levy administered by the AER. The AB LLR Program is designed to minimize the risk to the Orphan Fund posed by unfunded liability of licensees and to prevent the taxpayers of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines. The AB LLR Program requires a licensee whose deemed liabilities exceed a portion of its deemed assets to provide the AER with a security deposit. The ratio of deemed assets to deemed liabilities is assessed once each month and failure to post the required security deposit may result in the initiation of enforcement action by the AER. The AER publishes the liability management rating for each licensee on a monthly basis.

Made effective in three phases, from May 1, 2013 to August 1, 2015, the AER implemented important changes to the AB LLR Program (the "Changes") that resulted in a significant increase in the number of oil and gas companies in Alberta that are required to post security. The Changes affect the deemed parameters and costs used in the formula that calculates the ratio of deemed assets to deemed liabilities under the AB LLR Program, increasing a licensee's deemed liabilities and rendering the industry average netback factor more sensitive to asset value fluctuations. The Changes stem from concern that the previous regime significantly underestimated the environmental liabilities of licensees.

On June 20, 2016, the AER issued Bulletin 2016-16,Licensee Eligibility-Alberta Energy Regulator Measures to Limit Environmental Impacts Pending Regulatory Changes to Address the Redwater Decision ("Bulletin 16") in an urgent response to a decision from the Alberta Court of Queen's Bench ("the "Court", which is currently under appeal with the Court of Appeal of Alberta. In Redwater Energy Corporation (Re), 2016 ABQB 278 ("Redwater"), the Court found that there was an operational conflict between the abandonment and reclamation provisions of the OGCA and the Bankruptcy and Insolvency Act ("BIA"), and that receivers and trustees have the right to renounce assets within insolvency proceedings. Such a conflict renders the AER's legislated authority unenforceable to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a transfer when such a licensee is insolvent which effectively means that abandonment costs will be borne by the industry-funded Orphan Well Fund or the province in these instances because any resources of the insolvent licensee will first be used to satisfy secured creditors under the BIA. Bulletin 16 provides interim rules to govern while the case is appealed and while the Government of Alberta can develop appropriate regulatory measures to adequately address environmental liabilities including:

1. The AER will consider and process all applications for licence eligibility under Directive 067: Applying for Approval to Hold EUB Licences as non-routine and may exercise its discretion to refuse an application or impose terms and conditions on a licencee eligibility approval if appropriate in the circumstances.

2. For holders of existing but previously unused licence eligibility approvals, prior to approval of any application (including licence transfer applications), the AER may require evidence that there have been no material changes since approving the licence eligibility. This may include evidence that the holder continues to maintain adequate insurance and that the directors, officers, and/or shareholders are substantially the same as when licence eligibility was originally granted.

3. As a condition of transferring existing AER licences, approvals, and permits, the AER will require all transferees to demonstrate that they have a liabilitymanagement rating ("LMR"), being the ratio of a licensee's assets to liabilities, of 2.0 or higher immediately following the transfer.

In order to clarify and revise the interim rules in Bulletin 16, the AER issued Bulletin 2016-21: Revision and Clarification on Alberta Energy Regulator’s Measures to Limit Environmental Impacts Pending Regulatory Changes to Address the Redwater Decision ("Bulletin 21") on July 8, 2016 and reaffirmed its position that an LMR of 1.0 is not sufficient to ensure that licensees will be able to address their obligations throughout the life cycle of energy development, and 2.0 remains the requirement for transferees. However, Bulletin 21 did provide the AER with additional flexibility to permit licensees to acquire additional AER-licensed assets if:

1. The licensee already has an LMR of 2.0 or higher;

2. The acquisition will improve the licensee's LMR to 2.0 or higher; or

3. The licensee is able to satisfy its obligations, notwithstanding an LMR below 2.0, by other means.

The AER provided no indication of what other means would be considered. The Alberta Court of Appeal heard the appeal of the Redwater decision on October 11, 2016, with the Court reserving its decision.

The AER implemented the Inactive Well Compliance Program (the "IWCP") to address the growing inventory of inactive wells in Alberta and to increase the AER's surveillance and compliance efforts under Directive 013: Suspension Requirements for Wells ("Directive 013"). The IWCP applies to all inactive

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wells that are noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive noncompliant wells under the IWCP into compliance with the requirements of Directive 013 within 5 years. As of April 1, 2015, each licensee is required to bring 20% of its inactive wells into compliance every year, either by reactivating or by suspending the wells in accordance with Directive 013 or by abandoning them in accordance with Directive 020: Well Abandonment. The list of current wells subject to the IWCP is available on the AER's Digital Data Submission system. The AER has announced that from April 1, 2015 to April 1, 2016, the number of noncompliant wells subject to the IWCP fell from 25,792 to 17,470, with 76% of licensees operating in the province having met their annual quota.

Climate Change Regulation

Federal

Climate change regulation at both the federal and provincial level has the potential to significantly affect the regulatory environment of the oil and natural gas industry in Canada. Such regulations, surveyed below, impose certain costs and risks on the industry.

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both GHGs and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets, for application to regulated sectors on a facility-specific basis, sector-wide basis or company-by-company basis. Although the intention was for draft regulations aimed at implementing the Updated Action Plan to become binding on January 1, 2010, the only regulations being implemented are in the transportation and electricity sectors.

As a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") and a participant to the Copenhagen Accord (a non-binding agreement created by the UNFCCC), the Government of Canada announced on January 29, 2010 that it will seek a 17% reduction in GHG emissions from 2005 levels by 2020; however, the GHG emission reduction targets are not binding. In May 2015, Canada submitted its Intended Nationally Determined Contribution ("INDC") to the UNFCCC. INDCs were communicated prior to the 2015 United Nations Climate Change Conference, held in Paris, France, which led to the Paris Agreement that came into force November 4, 2016 (the "Paris Agreement"). Among other items, the Paris Agreement constitutes the actions and targets that individual countries will undertake to help keep global temperatures from rising more than 2° Celsius and to pursue efforts to limit below 1.5° Celsius. The Government of Canada ratified the Paris Agreement on December 12, 2016, and pursuant to the agreement, Canada’s INDC became its Nationally Determined Contributions ("NDC"). As a result, the Government of Canada replaced its INDC of a 17% reduction target established in the Copenhagen Accord with an NDC of 30% reduction below 2005 levels by 2030.

On June 29, 2016, the North American Climate, Clean Energy and Environment Partnership was announced among Canada, Mexico and the United States, which announcement included an action plan for achieving a competitive, low-carbon and sustainable North American economy. The plan includes setting targets for clean power generation, committing to implement the Paris Agreement, setting out specific commitments to address certain short-lived climate pollutants, and the promotion of clean and efficient transportation.

Additionally, on December 9, 2016, the Government of Canada formally announced the Pan-Canadian Framework on Clean Growth and Climate Change. As a result, the federal government will implement a Canada-wide carbon pricing scheme beginning in 2018. This may be implemented through either a cap and trade system or a carbon tax regime at the option of each province or territory. The federal government will impose a price on carbon of $10 per tonne on any province or territory which fails to implement its own system by 2018. This amount will increase by $10 annually until it reaches $50 per tonne in 2022 at which time the program will be reviewed.

In general, there is some uncertainty with regard to the impacts of federal or provincial climate change and environmental laws and regulations, as it is currently not possible to predict the extent of future requirements. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Company's operations and cash flow.

Alberta

As part of its efforts to reduce GHG emissions, Alberta introduced legislation to address GHG emissions: the Climate Change and Emissions Management Act (the "CCEMA") enacted on December 4, 2003 and amended through the Climate Change and Emissions Management Amendment Act, which received royal assent on November 4, 2008. The accompanying regulations include the Specified Gas Emitters Regulation ("SGER"), which imposes GHG limits, and the Specified Gas Reporting Regulation, which imposes GHG emissions reporting requirements. Alberta is the first jurisdiction in North America to impose regulations requiring large facilities in various sectors to reduce their GHG emissions. The SGER applies to facilities emitting more than 100,000 tonnes of GHG emissions in 2003 or any subsequent year ("Regulated Emitters"), and requires reductions in GHG emissions intensity (e.g. the quantity of GHG emissions per unit of production) from emissions intensity baselines established in accordance with the SGER.

On June 25, 2015, the Government of Alberta renewed the SGER for a period of two years with significant amendments while Alberta's newly formed Climate Advisory Panel conducted a comprehensive review of the province's climate change policy. As of 2015, Regulated Emitters are required to reduce their emissions intensity by 2% from their baseline in the fourth year of commercial operation, 4% of their baseline in the fifth year, 6% of their baseline in the sixth year, 8% of their baseline in the seventh year, 10% of their baseline in the eighth year, and 12% of their baseline in the ninth or subsequent years. These reduction targets will increase, meaning that Regulated Emitters in their ninth or subsequent years of commercial operation must reduce their emissions intensity from their baseline by 15% in 2016 and 20% in 2017.

A Regulated Emitter can meet its emissions intensity targets through a combination of the following: (1) producing its products with lower carbon inputs, (2) purchasing emissions offset credits from non-regulated emitters (generated through activities that result in emissions reductions in accordance with established protocols), (3) purchasing emissions performance credits from other Regulated Emitters that earned credits through the reduction of their emissions below the 100,000 tonne threshold, (4) cogeneration compliance adjustments, and (5) by contributing to the Climate Change and Emissions Management Fund (the "Fund"). Contributions to the Fund are made at a rate of $15 per tonne of GHG emissions, increasing to a rate of $20 per tonne of GHG emissions in 2016 and $30 per tonne of GHG emissions in 2017. Proceeds from the Fund are directed at testing and implementing new technologies for greening energy production.

On November 22, 2015, as a result of the Climate Advisory Panel's Climate Leadership report, the Government of Alberta announced its Climate Leadership Plan. On June 7, 2016, the Climate Leadership Implementation Act ("CLIA") was passed into law. The CLIA enacted the Climate Leadership Act ("CLA") introducing a carbon tax on all sources of GHG emissions, subject to certain exemptions. An initial economy-wide levy of $20 per tonne was implemented on January 1, 2017, increasing to $30 per tonne in January of 2018. All fuel consumption-including gasoline and natural gas-will be subject to the levy,

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with certain exemptions, and directors of a corporation may be held jointly and severally liable with a corporation when the corporation fails to remit an owed carbon levy. Regulated Emitters will remain subject to the SGER framework until the end of 2017 and are exempt from paying the carbon levy on fuels used in operations until this time. Upon the expiry of the SGER, the Government of Alberta intends to transition to a proposed Carbon Competitiveness Regulation, in which sector specific output-based carbon allocations will be used to ensure competitiveness. A 100 megatonne per year limit for GHG emissions was implemented for oil sands operations, which currently emit roughly 70 megatonnes per year. This cap exempts new upgrading and cogeneration facilities, which are allocated a separate 10 megatonne limit.

There are certain exemptions to the carbon levy imposed by the CLA. Until 2023, fuels consumed, flared or vented in a production process by conventional oil and gas producers will be exempt from the carbon levy. An exemption also applies for biofuels and fuels sold for export. In addition, marked fuels used in farming operations as well as personal and band uses by First Nations are exempt.

The passing of the CLIA is the first step towards executing the Climate Leadership Plan (other legislation is still pending). In addition to enacting the CLA, the CLIA also enacted the Energy Efficiency Alberta Act, which enables the creation of Energy Efficiency Alberta, a new Crown corporation to support and promote energy efficiency programs and services for homes and businesses.

The Government of Alberta also signaled its intention through its Climate Leadership Plan to implement regulations that would lower methane emissions by 45% by 2025. Regulations are planned to take effect in 2020 to ensure the 2025 target is met.

Alberta is also the first jurisdiction in North America to direct dedicated funding to implement carbon capture and storage technology across industrial sectors. Alberta has committed $1.24 billion over 15 years to fund two large-scale carbon capture and storage projects that will begin commercializing the technology on the scale needed to be successful. On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010. It deemed the pore space underlying all land in Alberta to be, and to have always been the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.

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

Volatility of Commodity Prices

Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by OPEC, slowing growth in China and other emerging economies, market volatility and disruptions in Asia, political upheavals in various countries and sovereign debt levels in various countries, have caused significant weakness and volatility in commodity prices. The volatility and decline in oil and natural gas prices has an adverse impact on the Company's cash flow. These events and conditions have caused a significant decrease in the valuation of oil and gas companies and a decrease in confidence in the oil and gas industry. These difficulties have been exacerbated in Canada by the recent changes in government at a federal level and, in the case of Alberta, at the provincial level, and the resultant uncertainty surrounding regulatory, tax, royalty changes and environmental regulation that have been announced or may be implemented by the new governments. In addition, the inability to get the necessary approvals to build pipelines and other facilities to provide better access to markets for the oil and gas industry in Western Canada has led to additional downward price pressure on oil and gas produced in Western Canada and uncertainty and reduced confidence in the oil and gas industry in Western Canada. Lower commodity prices may also affect the volume and value of the Company's reserves, rendering certain reserves uneconomic. In addition, lower commodity prices have restricted, and are anticipated to continue to restrict, the Company's cash flow resulting in a reduced capital expenditure budget. Consequently, the Company may not be able to replace its production with additional reserves and both the Company's production and reserves could be reduced on a year over year basis. Any decrease in value of the Company's reserves may reduce the borrowing base under its credit facilities, which, depending on the level of the Company's indebtedness, could result in the Company having to repay a portion of its indebtedness. Given the current market conditions and the lack of confidence in the Canadian oil and gas industry, the Company may have difficulty raising additional funds or if it is able to do so, it may be on unfavourable and highly dilutive terms.

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

Numerous factors beyond the Company's control do, and will continue to, affect the marketability and price of oil and natural gas acquired or discovered by the Company. The Company's ability to market its oil and natural gas may depend upon its ability to acquire space on pipelines that deliver natural gas to commercial markets or contract for the delivery of crude oil by rail. Deliverability uncertainties related to the distance of the reserves from pipelines, railway lines, processing and storage facilities, operational problems affecting pipelines, railway lines and facilities as well as government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business may also affect the Company.

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include economic conditions in the United States, Canada, Europe, China and emerging markets, the actions of OPEC, governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the foreign supply and demand of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Prices for oil and natural gas are also subject to the availability of foreign markets and the Company's ability to access such markets. Oil prices are expected to remain volatile and may decline in the near future as a result of global excess supply due to the increased growth of shale oil production in the United States, the decline in global demand for exported crude oil commodities, and OPEC's recent decisions pertaining to the oil production of OPEC member countries, among other factors. A material decline in prices could result in a reduction of the net production revenue attributable to the Company's assets. The economics of producing from some wells may change because of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and the value of the reserves attributable to the Company's assets. The Company might also elect not to produce from certain wells at lower prices.

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All these factors could result in a material decrease in the Company's expected net production revenue from the Company's assets and a reduction in its oil and natural gas acquisition, development and exploration activities. Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on the Company's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Oil and natural gas prices are expected to remain volatile for the near future because of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions, sanctions imposed on certain oil producing nations by other countries and ongoing credit and liquidity concerns. Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

Risks Relating to Egyptian Operations

Doing business in Egypt 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. Since 2011, there has been significant civil unrest and widespread protests and demonstrations throughout the Middle East, including Egypt.

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.

The Egyptian government could adopt new policies that might result in substantially hostile attitudes towards foreign investments such as the Company's. In an extreme case, government actions could result in forced renegotiation of the Company's existing contracts, termination of contract rights and expropriation of its assets (including crude oil inventory) 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 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 Egypt, 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, the Company's ability to lift and sell its crude oil inventory to third parties, or on the terms or enforceability of its production sharing and concession agreements or other contracts with governmental entities.

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

The Company's participation in the 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 represent major undertakings. The exploration programs in Egypt 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.

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The government of Egypt may not honour their agreements with the Company

There can be no assurance that the agreements entered into with the government of Egypt 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 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 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 Health, Safety, Environmental, and Social Responsibility 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.

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

The majority of the Company's current production is located in Egypt. 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 and Egypt affecting foreign trade, taxation and investment. In the event of a dispute arising in connection with the Company's operations in Egypt, 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 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 licences may expire and are subject to minimum work commitments

The properties in Egypt 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.

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 government of Egypt. 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. Historically, the Company has had a significant account receivable outstanding from the government of Egypt. While the government of Egypt has made regular payments on these amounts owing, the timing of these payments has historically been longer than normal industry standard. The receivable balance due from the Egyptian government has been reduced to a manageable level in 2015 as a result of the Company's direct marketing initiative and continued payments from the Egyptian government. However, there remains a balance due from the Egyptian government, and 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

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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 joint marketing arrangement with the Egyptian Government in December 2014. This arrangement, which became effective in January 2015, allows TransGlobe to directly contract oil shipments with international buyers. This direct marketing process has significantly reduced TransGlobe's credit risk.

The Company operates predominantly in Egypt

The Company's business focuses on the petroleum industry in a limited number of properties, the majority of which are in Egypt and one property in Canada. Larger companies have the ability to manage their risk by diversification. However, the nature of the Company's business is focused on one industry, and the geographic scope of the Company's business involves two countries. 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.

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

The oil and gas industry in Egypt 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.

Risks relating to reserve estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in this Report are estimates only. Generally, estimates of economically recoverable oil and natural gas reserves and the future net cash flows from such estimated reserves 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 oil and natural gas;

• royalty rates; and

• the assumed effects of regulation by governmental agencies and future operating costs (all of which may vary materially from actual results).

For those reasons, estimates of the economically recoverable 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 prepared by different engineers, or by the same engineers at different times may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates and such variations could be material.

The estimation of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves. Such variations could be material.

In accordance with applicable securities laws, DMCL has used forecast prices and costs in estimating the reserves and future net cash flows set forth in the DMCL Report. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from the Company's oil and natural gas reserves will vary from the estimates contained in the reserve evaluations, and such variations could be material. The reserve evaluations are based in part on the assumed success of activities the Company intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom and contained in the reserve evaluations will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluations. The reserve evaluations are effective as of a specific effective date and, except as may be specifically stated, has not been updated and therefore does not reflect changes in the Company's reserves since that date.

Alternatives to and changing demand for petroleum products

Full conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and energy generation devices could reduce the demand for oil, natural gas and other liquid hydrocarbons. The Company cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

Hedging risks

From time to time, the Company may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline. However, 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

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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:

• production falls short of the hedged volumes or prices fall significantly lower than projected;

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

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

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

Risks regarding the availability of drilling equipment and access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Company and may delay exploration and development activities

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the reserves from the Company's assets, and the production from them, will decline over time as the Company produces from such reserves. A future increase in the reserves attributable to the Company's assets will depend on both the ability of the Company to explore and develop the Company's assets and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Company will be able to find satisfactory properties to acquire or participate in. Moreover, management of the Company may determine that current markets, terms of acquisition, participation or pricing conditions make potential acquisitions or participations uneconomic. There is also no assurance that the Company will discover or acquire further commercial quantities of oil and natural gas.

Future oil and natural gas exploration may involve unprofitable efforts from dry wells as well as from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing (including hydraulic fracturing), operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, and shut ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, it is not possible to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills and other environmental hazards. These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property, the environment and personal injury. Particularly, the Company may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to the Company.

Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

As is standard industry practice, the Company is not fully insured against all risks, nor are all risks insurable. Although the Company will maintain liability insurance in an amount that it considers consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. In either event the Company could incur significant costs

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.

Risks relating to the prepayment agreement

The Company and its subsidiaries are party to the prepayment agreement and the amount authorized thereunder is dependent on the satisfaction of certain conditions. The Company is required to comply with covenants under the prepayment agreement which may, in certain cases, either affect the availability, or price, of additional funding and in the event that the Company does not comply with these covenants, the Company's access to capital could be restricted or repayment could be required. Events beyond the Company's control may contribute to the failure of the Company to comply with such covenants. A failure to comply with covenants could result in default under the prepayment agreement, which could result in the Company being required to repay amounts owing thereunder. If the Company is unable to repay amounts owing under the prepayment agreement, the Marketer could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.

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The Company may be unable to obtain necessary future financing

The Company's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times and from time to time, the Company may require additional financing in order to carry out its oil and natural gas acquisition, exploration and development activities. Failure to obtain financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. Due to the conditions in the oil and gas industry and/or global economic and political volatility, the Company may from time to time have restricted access to capital and increased borrowing costs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing.

As a result of global economic and political volatility, the Company may from time to time have restricted access to capital and increased borrowing costs. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Company's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Company's ability to expend the necessary capital to replace its reserves or to maintain its production. To the extent that external sources of capital become limited, 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 affected materially and adversely as a result. 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 upon acceptable terms. Alternatively, any available financing may be highly dilutive to existing shareholders. Failure to obtain any 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 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 on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and 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 diverting management's focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided by third parties and assets required to provide such services. In this regard, non core assets may be periodically disposed of so 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 may realize less on disposition than their carrying value on the financial statements of the Company.

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.

Risks Relating to the Canadian Oil and Gas Industry

Shareholders and prospective investors should carefully consider the following risks applicable to the Company's Canadian assets and the Canadian oil and gas industry in general. The risks set out below are not exhaustive and should not be taken as a complete summary or description of all the risks associated with the Canadian oil and gas industry.

Operational Dependence

Other companies operate some of the Company's assets. The Company has limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Company's financial performance. The Company's return on assets operated by others depends upon a number of factors that may be outside of the Company's control, including, but not limited to, the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

In addition, due to the current low and volatile commodity prices, many companies, including companies that may operate some of the Company's assets, may be in financial difficulty, which could impact their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner and satisfy regulatory requirements with respect to abandonment and reclamation obligations. If companies that operate some of the Company's assets fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations the Company may be required to satisfy such obligations and to seek recourse from such companies. To the extent that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in such assets being shut-in, the Company potentially becoming subject to additional liabilities relating to such assets and the Company having difficulty collecting revenue due from such operators. Any of these factors could materially adversely affect the Company's financial and operational results.

Gathering and Processing Facilities, Pipeline Systems and Rail

The Company may deliver its products through gathering and processing facilities and pipeline systems, some of which it does not own, and by rail. The amount of oil and natural gas that the Company can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities, pipeline systems and railway lines. The lack of availability of capacity in any of the gathering and processing facilities, pipeline systems and railway lines, and in particular the processing facilities, could result in the Company's inability to realize the full economic potential of its production or in a reduction of the price offered for the Company's production. The lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and market oil and natural gas production. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and natural gas. Unexpected shut downs or curtailment of capacity of pipelines for maintenance or integrity work or because of actions taken by regulators could also affect the Company's production, operations and financial results. Furthermore, producers are increasingly turning to rail as an alternative means of transportation. In recent years, the volume of crude oil shipped by rail in North America has increased dramatically. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as

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well as any delays in constructing new infrastructure systems and facilities could harm the Company's business and, in turn, the Company's financial condition, results of operations and cash flows. The federal government has signaled that it plans to review the National Energy Board approval process for large projects. This may cause the timeframe for project approvals to increase for current and future applications.

Following major accidents in Lac-Megantic, Quebec and North Dakota, the Transportation Safety Board of Canada and the U.S. National Transportation Board have recommended additional regulations for railway tank cars carrying crude oil. In June 2015, as a result of these recommendations, the Government of Canada passed the Safe and Accountable Rail Act which increased insurance obligations on the shipment of crude oil by rail, imposed a per tonne levy of $1.65 on crude oil shipped by rail to compensate victims and for environmental cleanup in the event of a railway accident. In addition to this legislation, new regulations have implemented the TC-117 standard for all rail tank cars carrying flammable liquids which formalized the commitment to retrofit, and eventually phase out DOT-111 tank cars carrying crude oil. The increased regulation of rail transportation may reduce the ability of railway lines to alleviate pipeline capacity issues and add additional costs to the transportation of crude oil by rail. On July 13, 2016, the Minister of Transport (Canada) issued Protective Direction No. 38, which directed that the shipping of crude oil on DOT-111 tank cars end by November 1, 2016. Tank cars entering Canada from the United States will be monitored to ensure they are complicit with Protective Direction No. 38.

A portion of the Company's production may, from time to time, be processed through facilities owned by third parties over which the Company does not have control. From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could have a materially adverse effect on the Company's ability to process its production and deliver the same for sale.

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 files all required income tax returns and believes that it is in full compliance with the provisions of the Tax Act and all other applicable provincial tax legislation. However, such returns are subject to reassessment by the applicable taxation authority. In the event of a successful reassessment of the Company, whether by re-characterization of exploration and development expenditures or otherwise, such reassessment may have an impact on current and future taxes payable.

Income tax laws relating to the oil and natural gas industry, such as the treatment of resource taxation or dividends, may in the future be changed or interpreted in a manner that adversely affects the Company. Furthermore, tax authorities having jurisdiction over the Company may disagree with how the Company calculates its income for tax purposes or could change administrative practices to the Company's detriment.

Regulatory

Various levels of governments impose extensive controls and regulations on oil and natural gas operations (including exploration, development, production, pricing, marketing and transportation). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes, royalties and the exportation of oil and natural gas. Amendments to these controls and regulations may occur from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase the Company's costs, either of which may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In order to conduct oil and natural gas operations, the Company will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities. There can be no assurance that the Company will be able to obtain all of the permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that it may wish to undertake. In addition to regulatory requirements pertaining to the production, marketing and sale of oil and natural gas mentioned above, the Company's business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada).

Royalty Regimes

There can be no assurance that the federal government and the provincial governments of the western provinces will not adopt new royalty regimes or modify the existing royalty regimes which may have an impact on the economics of the Company's projects. An increase in royalties would reduce the Company's earnings and could make future capital investments, or the Company's operations, less economic. On January 29, 2016, the Government of Alberta adopted a new royalty regime which will take effect on January 1, 2017. See "Canadian Industry Conditions - Royalties and Incentive".

Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of oil and natural gas from reservoirs that were previously unproductive. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase the Company's costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce from the reserves attributable to the Company's assets.

Environmental

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other

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pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it will be in material compliance with current applicable environmental legislation related to the Company's assets, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Liability Management

Alberta has developed a liability management program designed to prevent taxpayers from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines in the event that a licensee or permit holder becomes defunct. This program generally involves an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed a portion of its deemed assets, a security deposit is required. Changes of the ratio of the Company's deemed assets to deemed liabilities or changes to the requirements of liability management programs may result in significant increases to the security that must be posted. In addition, the liability management system may prevent or interfere with the Company's ability to acquire or dispose of assets in the future as both the vendor and the purchaser of oil and gas assets must be in compliance with the liability management programs (both before and after the transfer of the assets) for the applicable regulatory agency to allow for the transfer of such assets. See "Canadian Industry Conditions - Liability Management Rating Programs".

Climate Change

The Company's exploration and production facilities and other operations and activities emit greenhouse gases which may require the Company to comply with greenhouse gas ("GHG") emissions legislation at the provincial or federal level. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. As a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC")and a participant to the Copenhagen Agreement (a non-binding agreement created by the UNFCCC), the Government of Canada announced on January 29, 2010 that it would seek a 17% reduction in GHG emissions from 2005 levels by 2020; however, these GHG emission reduction targets were not binding. As a result of the UNFCCC adopting the Paris Agreement on December 12, 2015, which Canada ratified on October 3, 2016, the Government of Canada implemented new GHG emission reduction targets of a 30% reduction from 2005 levels by 2030. In addition, the Government of Canada announced it would implement a Canada wide price on carbon to further reduce its GHG emissions. In addition, on January 1, 2017 the Climate Leadership Act ("CLA") come into effect in the Province of Alberta introducing a carbon tax on almost all sources of GHG emissions at a rate of $20 per tonne, increasing to $30 per tonne in January 2018. The direct or indirect costs of compliance with these regulations may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Some of the Company's significant facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions. In addition, concerns about climate change have resulted in a number of environmental activists and members of the public opposing the continued exploitation and development of fossil fuels. Given the evolving nature of the debate related to climate change and the control of GHG and resulting requirements, it is not possible to predict the impact on the Company and its operations and financial condition. See "Industry Conditions - Climate Change Regulation".

Aboriginal Claims

Aboriginal peoples have claimed aboriginal title and rights in portions of western Canada. If a claim arises on the Company's assets and is successful, such claim may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays which could have a material adverse effect on the Company's business and financial results.

Seasonality

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. In addition, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding decreases in the demand for the goods and services of the Company.

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, the Canadian dollar denominated convertible debentures, and 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 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 Yeme. 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.

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The Company may become involved in, named as a party to, or be the subject of, various legal and/or arbitration 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. Even if the Company prevails in any such legal proceedings, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from business operations, which could have an adverse affect on the Company's financial condition.

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'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 market price of the Common Shares may be volatile

The market price of the Common Shares may be volatile. The volatility may affect the ability of holders of Common Shares to sell the Common Shares at an advantageous price. Market price fluctuations in the Common Shares 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". The trading price of securities is also subject to substantial volatility based on factors unrelated to the financial performance or prospects of the issuers involved. Factors unrelated to the Company's performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices, or current perceptions of the oil and gas market. Accordingly, the price at which the common sharesof the Company will trade cannot be accurately predicted.

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 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 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.

Future dividends may not be declared or paid or, if declaring and paying dividends resumes, could be reduced or suspended entirely

The declaration of future dividends and amount of future cash dividends paid by the Company, if any, will be subject to the discretion of the Board of Directors of the Company and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, royalty burdens, foreign exchange rates and the satisfaction of the liquidity and solvency tests imposed by applicable corporate law for the declaration and payment of dividends. Depending on these and various other factors, many of which will be beyond the control of the Company, the dividend policy of the Company from time to time and, as a result, future cash dividends may not be made or, if declaring and paying dividends resumes in the future, could be reduced or suspended entirely.

Third party credit risk

The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In addition, the Company may be exposed to third party credit risk from operators of

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properties in which the Company has a working or royalty interest. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner. To the extent that any of such third parties go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in the Company being unable to collect all or portion of any money owing from such parties. Any of these factors could materially adversely affect the Company's financial and operational results.

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 petroleum industry is competitive in all of its phases. The Company competes with numerous other entities in the exploration, development, production and marketing of oil and natural gas. The Company's competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Company. Some of these companies not only explore for, develop and produce oil and natural gas, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than the Company. The Company's ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price, process, and reliability of delivery and storage.

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

The Company's success depends in large measure on certain key personnel. The loss of the services of such key personnel may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. The Company does not have any key personnel insurance in effect for the Company. The contributions of the existing management team to the immediate and near term operations of the Company are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry can be intense and there can be no assurance that the Company will be able to continue to attract and retain all personnel necessary for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of the Company.

Conflicts of interest could adversely affect the Company's business

Certain directors or officers of the Company may also be directors or officers of other oil and natural gas companies and as such may, in certain circumstances, have a conflict of interest. Conflicts of interest, if any, will be subject to and governed by procedures prescribed by the ABCA which require a director of 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 to 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 "Directors and Officers - Conflicts of Interest".

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

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise. The actual interest of the Company in properties may accordingly vary from the Company's records. If a title defect does exist, it is possible that the Company may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. There may be valid challenges to title or legislative changes, which affect the Company's title to the oil and natural gas properties the Company controls that could impair the Company's activities on them and result in a reduction of the revenue received by the Company.

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.

Future financings could negatively impact the market price of the Company's Common Shares

In order to finance future operations or acquisition opportunities, the Company may raise funds through the issuance of Common Shares or the issuance of debt instruments or securities convertible into Common Shares. The Company cannot predict the size of future issuances of Common Shares or the issuance of debt instruments or other securities convertible into Common Shares or the effect, if any, that future issuances and sales of the Company's securities will have on the market price of the Common Shares.

Risks regarding global political uncertainty

In the last several years, the United States and certain European countries have experienced significant political events that have cast uncertainty on global financial and economic markets. During the recent presidential campaign in the United States a number of election promises were made and the new American administration has begun taking steps to implement certain of these promises. Included in the actions that the administration has discussed are the renegotiation of the terms of the North American Free Trade Agreement, withdrawal of the United States from the Trans-Pacific Partnership, imposition of a tax on the importation of goods into the United States, reduction of regulation and taxation in the United States, and introduction of laws to reduce immigration and restrict access into the United States for citizens of certain countries. It is presently unclear exactly what actions the new administration in the United States will implement, and if implemented, how these actions may impact Canada and in particular the oil and gas industry. Any introduction of an import tax by the US may reduce the price the Company receives for its oil and gas production. Any actions taken by the new United States administration may have a negative impact on the Canadian economy and on the businesses, financial conditions, results of operations and the valuation of Canadian oil and gas companies, including the Company.

In addition to the political disruption in the United States, the citizens of the United Kingdom recently voted to withdraw from the European Union and the Government of the United Kingdom has begun taken steps to implement such withdrawal. Some European countries have also experienced the rise

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of anti-establishment political parties and public protests held against open-door immigration policies, trade and globalization. To the extent that certain political actions taken in North America, Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement it could have an adverse effect on the Company's ability to market its products internationally, increase costs for goods and services required for the Company's operations, reduce access to skilled labour and negatively impact the Company's business, operations, financial conditions and the market value of its Common Shares.

The Company could be negatively impacted by security threats, including cybersecurity threats as well as other disasters and related disruptions

The Company's business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs. It is critical to our business that our facilities and infrastructure remain secure. Management cannot guarantee that measures taken to defend against cybersecurity threats will be sufficient for this purpose. The ability of the information technology function to support the Company's business in the event of a security breach or a disaster and our ability to recover key systems and information from unexpected interruptions cannot be fully tested and there is a risk that, if such an event actually occurs, we may not be able to address immediately the repercussions of the breach or disaster. In that event, key information and systems may be unavailable for a number of days or weeks, leading to the inability to conduct business or perform some business processes in a timely manner. The Company has implemented strategies to mitigate the potential impact of these types of events.

The Company's employees have been and will continue to be targeted by parties using fraudulent emails to misappropriate information or to introduce viruses or other malware to our computers. These emails appear to be legitimate emails, but direct recipients to fake websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware. Despite our efforts to mitigate these emails through education and stringent email filters, these fraudulent activities remain a serious problem that may damage our information technology infrastructure.

Further, the Company is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company’s information technology systems by third parties or insiders. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to our business activities or our competitive position. Further, disruption of critical information technology services, or breaches of information security, could have a negative effect on our performance and earnings, as well as on our reputation. The Company applies technical and process controls in line with industry-accepted standards to protect our information assets and systems; however, these controls may not adequately prevent cyber-security breaches. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Company’s business, financial condition and results of operations

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.

Inability to adequately manage growth

The Company may be subject to growth related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Company to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base. The inability of the Company to deal with this growth may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Forward-Looking Statements and FOFI may prove inaccurate

Investors are cautioned not to place undue reliance on forward-looking statements and FOFI. By their nature, forward-looking statements and FOFI involve numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking statements or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

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 the majority (seven out of eight) of the Company's directors and 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

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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 pad 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.

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

The Debentures mature on March 31, 2017. 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.

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.

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 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".

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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 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, 2016. 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, 2016, 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, 2016. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2016, 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.
3.	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
4.	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.
5.	The following table shows the net present value of 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 for the year ended December 31, 2016, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management:

Independent Qualified	Effective		Net Present Value of Future Net Revenue
Reserves Evaluator	Date of Evaluation	Location of	(before income tax, 10% discount rate)
	Report	Reserves	Audited	Evaluated	Reviewed	Total
			MM U.S. $	MM U.S.$	MM U.S.$	MM U.S.$
DeGolyer and	December 31, 2016	Egypt	—	260.2	—	260.2
MacNaughton Canada		Canada	—	85.5	—	85.5
Limited		Total	—	345.7	—	345.7

6.	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.
7.	We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.
8.	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 18, 2017.

DEGOLYERandMACNAUGHTON
CANADA 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.

An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator is presented in Schedule A of this Annual Information Form.

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 the 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 directorshas, 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, contingent resources data, or prospective resources data; and

(c) the content and filing of this report.

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

DATED as of this 13^th day of March, 2017.

Per:	(signed) "Ross Clarkson"	Per:	(signed) "Bob MacDougall"
	Ross Clarkson		Bob MacDougall
	President, Chief Executive Officer and Director		Director and Chair of the Reserves, Health Safety Environment and Social Responsibility 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 13, 2017

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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, (4) performance of the Company’s accounting, internal controls and financial reporting process and monitoring business risks.

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 of the Audit Committee.

• 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.

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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.

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.

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Independence Test

• Take reasonable steps to confirm the independence of the independent 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.

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-GAAP 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.

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• 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.

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

• Meet semi-annually with the Officers’ Risk Committee to discuss the Company’s risk assessment and risk management. One meeting will be an in-depth review of the corporate risk assessment and emerging risks.

• 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.