EXHIBIT 99.1

TRANSGLOBE ENERGY CORPORATION

ANNUAL INFORMATION FORM

Year Ended December 31, 2017

March 7, 2018

TABLE OF CONTENTS

	Page
CURRENCY AND EXCHANGE RATES	3
ABBREVIATIONS	4
CONVERSIONS	4
FORWARD-LOOKING STATEMENTS	4
NON-GAAP MEASURES	6
CERTAIN DEFINITIONS	7
TRANSGLOBE ENERGY CORPORATION	9
GENERAL DEVELOPMENT OF THE BUSINESS	10
DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES	11
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	17
DIVIDEND POLICY	42
DESCRIPTION OF CAPITAL STRUCTURE	42
MARKET FOR SECURITIES	42
PRIOR SALES	45
ESCROWED SECURITIES AND SECURITIES SUBJECT TO CONTRACTUAL RESTRICTIONS ON TRANSFER	45
DIRECTORS AND OFFICERS	46
INTERESTS OF EXPERTS	47
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	47
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	48
TRANSFER AGENT AND REGISTRAR	48
MATERIAL CONTRACTS	48
AUDIT COMMITTEE INFORMATION	49
RISK FACTORS	57
ADDITIONAL INFORMATION	71

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, 2017

March 6, 2018

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") uses the Canadian dollar as 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, 2017, 2016 and 2015.

	Year Ended December 31, 2017	Year Ended December 31, 2016	Year Ended December 31, 2015
End of Period	Cdn$1.2551	Cdn$1.3427	Cdn$1.3840
Period Average	Cdn$1.2978	Cdn$1.3248	Cdn$1.2788

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 174.5 net undrilled locations disclosed in this Annual Information Form, 34.0 are proved undeveloped locations, 29.5 are probable undeveloped locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the GLJ 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 2018;

• the budget for the exploration program;

• future development costs;

• future reserves growth and the success of the 2018/2019 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 2018;

• 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;

• 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;

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

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• 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)	2017		2016
Cash flow from operating activities	59,450		(1,065	)
Changes in non-cash working capital	(3,858	)	(7,296	)
Funds flow from operations1	55,592		(8,361	)
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 Loss and     Comprehensive Loss. 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. The FOFI was made as of the date hereof and the Company does not assume any obligation to update such FOFI, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

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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;

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

"Debentures" means the Cdn$97,750,000 aggregate principal amount of 6.00% convertible unsecured subordinated debentures which matured on March 31, 2017;

"Debenture Trustee" means Computershare;

"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;

"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;

"GLJ" means GLJ Petroleum Consultants Ltd, independent petroleum consultants;

"GLJ Report" means the report of GLJ dated January 9, 2018 evaluating the crude oil, natural gas and NGL reserves of the Company as at December 31, 2017;

"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;

"Mercuria" means Mercuria Energy Trading SA;

"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;

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"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;

"PSA" means production sharing agreement;

"PSC" means production sharing concession;

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

“RBL” means revolving reserves-based lending facility;

"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;

"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 were listed on the TSX under the symbol "TGL.DB" from February 22, 2012 to March 31,2017. The Company repaid the Debentures in full on March 31, 2017, which was the maturity date of the Debentures.

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 South Mariut Inc.(3)	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.
(3)  TG South Mariut 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 South Mariut Inc. previously owned TransGlobe's interest in the South Mariut concession in Egypt which was subsequently relinquished. TG Holdings Egypt Inc. holds a 100% interest in TG South Alamein Inc and TG South Mariut Inc. TG NW Gharib Inc. owns TransGlobe's interest in the NW Gharib concession. TG SW Gharib Inc. previously owned TransGlobe's interest in the SW Gharib concession until the relinquishment of the concession in May 2017. TG SE Gharib Inc. previously 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 prior to relinquishment in May 2017, 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.

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). 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.

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 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.

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.

2017

TransGlobe engaged in a 2017 drilling program that included a return to Canada, drilling 15 wells in Egypt and three wells in Canada. The exploration drilling program at NW Gharib and SW Gharib, consisting of nine wells in aggregate, yielded two oil discoveries (NWG 26ST and NWG 27ST). The exploration program at South Alamein consisted of one well which was cased, tested and subsequently abandoned. The Company fulfilled its exploration work program commitments in NW Gharib and SW Gharib in 2017. In addition to the exploration program, the Company drilled seven development oil wells and one appraisal oil well in NW Gharib, West Gharib, West Bakr, and Canada resulting in six oil wells.

11

Reserves at 2017 year-end were lower compared to 2016 year-end primarily due to 2017 production and negative technical revisions of undeveloped Canadian Mannville gas locations. The Company drilled four development oil wells (one in K-South, one in the Arta Red Bed pool, and two in the NW Gharib Red Bed pool) during the year. In addition, the Company filed for and received its second, third and fourth development leases in NW Gharib during 2017. In Canada, the Company successfully drilled three development oil wells in the Harmattan area. The Company produced a total of 5.7 MMBoe of crude oil, natural gas and natural gas liquids in 2017. One additional Arta Red Bed development well and one K South development well were drilled and rig released subsequent to December 31, 2017.

On February 10, 2017, TransGlobe announced the execution of a $75 million crude oil prepayment agreement between TPI and Mercuria Energy Trading SA ("Mercuria"). 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 prepayment agreement is revolving, with each advance to be satisfied through the delivery of crude oil to Mercuria pursuant to the marketing contract described below. Further advances become available upon delivery of crude oil to Mercuria 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.

On May 16, 2017, TransGlobe announced they had entered into a credit agreement for a revolving reserves-based lending facility (“RBL”) with Alberta Treasury Branches. Pursuant to the credit agreement, the RBL commitment is up to a maximum of C$30 million. The amount available to be drawn on the RBL will be dependent upon the borrowing base, which is determined with reference to the Company’s proved oil and gas reserves in Canada, as evaluated in the most recent annual reserve report(s) and delivered pursuant to the credit agreement. As of the closing date, the borrowing base was set at C$30 million. TransGlobe initially used the funds available under the RBL to repay the existing C$15 million vendor-take-back loan outstanding, which had an interest rate of 10% per annum. Additional funds were allocated as necessary to carry out the Company’s capital expenditure program in Canada.

GLJ Petroleum Consultants Ltd. ("GLJ") of Calgary, Alberta, independent petroleum engineering consultants based in Calgary, were retained by the Company’s Reserve Committee to independently evaluate 100% of TransGlobe’s reserves as at December 31, 2017, following the closure of DeGolyer and MacNaughton Canada Limited (“DeGolyer”) Calgary office. The Company’s selection of GLJ was based upon its domestic and extensive international experience. GLJ has worked with over 100 separate organizations encompassing petroleum assets in more than 50 countries. DeGolyer and MacNaughton Canada Limited (“DeGolyer”) of Calgary, Alberta, independent petroleum engineering consultants based in Calgary and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company’s Reserve Committee to independently evaluate 100% of TransGlobe’s reserves as at December 31, 2016.

Recent Developments

Subsequent to year-end, two development wells were drilled.  In West Gharib, one development well (Arta 48) was cased as an oil well in the Arta Red Bed development pool.  In West Bakr, one development well (K 46) was cased as an oil well in the K South development pool. 

Significant Acquisitions

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

DESCRIPTION OF THE BUSINESS AND PRINCIPAL PROPERTIES

General

TransGlobe is engaged in the exploration for and the development and production of crude oil and natural gas in Egypt and 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 six PSCs: West Gharib, West Bakr, South Alamein, NW 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.

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".

12

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 2018. 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 Reserves, Health, Safety, Environment and Social Responsibility Committee (“RHSES 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 RHSES 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. 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.

13

Summary of International Land Holdings as at December 31, 2017

International Land (Egypt)¹ - Summary of PSCs

EASTERN DESERT EGYPT
Block	West Gharib	West Bakr	NW Gharib
Basin	Gulf of Suez	Gulf of Suez	Gulf of Suez
Year acquired	2007	2011	2013
Status	Development	Development	Development
Operator	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	100%	100%	100%
Block Area (acres)	22,775	11,600	11,200
Expiry date	2019-2026	2020	Dec 2036
Extensions
Exploration	N/A	N/A	N/A
Development	+ 5 years	+ 5 years	+ 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	349,302	480,850
Expiry date	June 2018	November 2018	July 2018
Extensions
Exploration	N/A	2 years	3.5 years
Development	20 + 5 years	20 + 5 years	20 + 5 years

14

Egypt

Eastern Desert

15

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
Production Tranche (MBopd)	0-5 / 5-10	0-50	0-5 / 5-10
	10-15		>10
Max. cost oil	30%	30%	25%
Excess cost oil
Contractor	30%	0%	5%
Depreciation per quarter
Operating	100%	100%	100%
Capital	6%	5%	5%
Production Sharing Oil:
Contractor	30% / 27.5%	15%	15.0% / 14.5%
	25%		14%
Government	70% / 72.5%	85%	85% / 85.5%
	75%		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.

16

Canada

In Canada, the Company drilled three Cardium formation oil wells (completed with multi-stage fracture stimulation) in the Harmattan area. The wells were completed and placed on production in the fourth quarter. An additional 10 new undeveloped Cardium oil locations were assigned reserves as of December 31, 2017. These positive additions offset negative technical revisions primarily attributed to undeveloped Mannville gas locations removed from the Company’s reserves which were deemed uneconomic due to a lower gas price forecast and reduced ultimate recovery assignments per well.

Operations Review

In 2017, the Company's total production increased by 28% to 15,506 Boepd (2016 – 12,105 Boepd). Production from Egypt averaged 12,822 Bopd to TransGlobe during 2017 (2016 – 12,015 Bopd). Production from Canada averaged 2,684 Boepd during 2017 (2016 - 90 Boepd).

2018 Outlook Highlights

• Production is expected to average between 14,200 and 15,600 Boepd in 2018 (mid-point of 14,900 Boepd); and

• Exploration and development spending is budgeted to be $41.3 million (before capitalized G&A) and includes $29.1 million for Egypt and $12.2 million (C$15.3 million) for Canada, to be funded from funds flow from operations and working capital.

Human Resources

TransGlobe currently employs 73 full-time employees and 16 full-time consultants. The Company will add additional professional and administrative staff as the needs arise.

17

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 "GLJ Report") is dated January 9, 2018, with the effective date being December 31, 2017.

18

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, 2017. In 2017, GLJ Petroleum Consultants Ltd. ("GLJ"), independent petroleum engineering consultants based in Calgary, Alberta, were retained by the Company's Reserves Committee to independently evaluate 100% of TransGlobe's reserves as at December 31, 2017.

The reserves data set forth below (the "Reserves Data") was prepared by GLJ and DeGolyer with an effective date of December 31, 2017 and December 31, 2016, respectively. 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 GLJ 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 GLJ 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.

19

Reserves Data – Forecast Prices and Costs

SUMMARY OF OIL AND GAS RESERVES

TOTAL COMPANY

AS OF DECEMBER 31, 2017

(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	3.2	2.4	11.0	6.1	16.3	13.3	2.6	1.9	19.5	12.7
Developed non-producing	0.4	0.3	1.5	0.8	0.3	0.2	—	—	1.9	1.1
Undeveloped	2.8	2.4	1.4	0.7	6.4	5.7	1.0	0.8	6.2	4.9
Total Proved	6.3	5.1	13.9	7.5	22.9	19.3	3.5	2.8	27.5	18.6
Probable	3.8	3.0	9.0	4.7	17.4	15.8	2.7	2.4	18.3	12.7
Proved+Probable	10.1	8.0	22.8	12.2	40.3	35.1	6.2	5.1	45.9	31.3
Possible	3.1	2.2	8.4	4.2	17.2	15.2	2.2	1.9	16.6	10.9
Proved+Probable+Possible	13.2	10.3	31.2	16.5	57.5	50.3	8.5	7.0	62.5	42.1
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, 2017

(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	1.7	1.1	11.0	6.1	12.7	7.2
Developed non-producing	0.3	0.2	1.5	0.8	1.8	1.0
Undeveloped	0.3	0.2	1.4	0.7	1.6	0.8
Total Proved	2.3	1.5	13.9	7.5	16.1	9.0
Probable	1.5	1.0	9.0	4.7	10.5	5.7
Proved+Probable	3.8	2.5	22.8	12.2	26.6	14.7
Possible	1.7	1.1	8.4	4.2	10.1	5.3
Proved+Probable+Possible	5.5	3.6	31.2	16.4	36.7	20.0
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, 2017

(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	1.5	1.3	16.3	13.3	2.6	1.9	6.8	5.5
Developed non-producing	0.1	—	0.3	0.2	—	—	0.1	0.1
Undeveloped	2.5	2.2	6.4	5.7	1.0	0.8	4.5	4.0
Total Proved	4.1	3.6	22.9	19.3	3.5	2.8	11.4	9.6
Probable	2.2	2.0	17.4	15.8	2.7	2.4	7.8	7.0
Proved+Probable	6.3	5.5	40.3	35.1	6.2	5.1	19.3	16.5
Possible	1.4	1.1	17.2	15.2	2.2	1.9	6.5	5.6
Proved+Probable+Possible	7.7	6.6	57.5	50.3	8.4	7.0	25.8	22.1
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.

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

TOTAL COMPANY

AS OF DECEMBER 31, 2017

(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	242.0	203.6	177.1	157.8	143.2	242.0	203.6	177.1	157.8	143.2	14.00
Developed non-producing	17.0	14.8	12.9	11.3	10.1	17.0	14.8	12.9	11.3	10.1	11.88
Undeveloped	107.7	66.3	43.4	29.6	20.7	94.6	59.9	40.1	27.8	19.7	8.91
Total Proved	366.7	284.6	233.3	198.8	174.0	353.6	278.2	230.0	197.0	173.0	12.54
Probable	275.2	168.3	116.5	87.5	69.4	233.6	148.3	105.6	81.0	65.3	9.20
Total Proved+Probable	641.9	452.9	349.8	286.2	243.4	587.2	426.5	335.7	278.0	238.3	11.19
Possible	241.3	137.3	93.1	69.7	55.6	204.7	121.5	84.7	64.7	52.3	8.58
Total Proved+Probable+Possible	883.2	590.2	442.9	355.9	299.0	791.9	548.0	420.3	342.7	290.6	10.51
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.

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SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

EGYPT

AS OF DECEMBER 31, 2017

(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	145.1	128.7	116.3	106.7	99.0	145.1	128.7	116.3	106.7	99.0	16.16
Developed non-producing	14.8	12.9	11.4	10.1	9.0	14.8	12.9	11.4	10.1	9.0	11.59
Undeveloped	16.1	13.6	11.6	10.0	8.7	16.1	13.6	11.6	10.0	8.7	13.70
Total Proved	176.0	155.2	139.3	126.8	116.7	176.0	155.2	139.3	126.8	116.7	15.43
Probable	121.1	94.9	76.9	64.1	54.5	121.1	94.9	76.9	64.1	54.5	13.47
Total Proved+Probable	297.1	250.1	216.2	190.9	171.2	297.1	250.1	216.2	190.9	171.2	14.67
Possible	106.0	79.0	62.1	50.7	42.7	106.0	79.0	62.1	50.7	42.7	11.73
Total Proved+Probable+Possible	403.1	329.1	278.3	241.6	213.9	403.1	329.1	278.3	241.6	213.9	13.89
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, 2017

(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	96.9	74.9	60.8	51.1	44.2	96.9	74.9	60.8	51.1	44.2	11.14
Developed non-producing	2.3	1.8	1.5	1.2	1.0	2.3	1.8	1.5	1.2	1.0	14.65
Undeveloped	91.6	52.7	31.8	19.6	12.0	78.5	46.3	28.4	17.8	11.0	7.90
Total Proved	190.8	129.4	94.0	71.9	57.2	177.7	123.0	90.7	70.1	56.2	9.82
Probable	154.2	73.4	39.6	23.4	14.8	112.5	53.4	28.7	17.0	10.8	5.69
Total Proved+Probable	344.9	202.8	133.5	95.3	72.0	290.2	176.4	119.4	87.1	67.0	8.08
Possible	135.3	58.3	31.0	19.0	12.9	98.7	42.5	22.6	14.0	9.6	5.57
Total Proved+Probable+Possible	480.2	261.1	164.5	114.3	84.9	388.9	218.9	142.0	101.1	76.6	7.45

22

TOTAL FUTURE NET REVENUE⁽³⁾

(UNDISCOUNTED)

AS OF DECEMBER 31, 2017

(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	446.6	65.8	121.6	56.9	11.5	190.8	13.1	177.7
Egypt	889.6	485.3	219.8	8.6	—	175.9	—	175.9
Total Company	1,336.3	551.1	341.4	65.5	11.5	366.7	13.1	353.6
Proved+Probable Reserves
Canada	787.3	105.9	211.3	109.8	15.3	344.9	54.7	290.2
Egypt	1,528.6	840.0	373.9	17.6	—	297.0	—	297.0
Total Company	2,315.9	945.9	585.2	127.4	15.3	641.9	54.7	587.2
Proved+Probable+
Possible Reserves
Canada	1,068.5	148.7	289.8	132.0	17.9	480.2	91.3	388.9
Egypt	2,186.6	1,220.1	543.6	19.8	—	403.0	—	403.0
Total Company	3,255.1	1,368.8	833.4	151.8	17.9	883.2	91.3	791.9
Notes:
(1)   In Egypt, under the terms of the PSCs, income tax is current and assessed on all production sharing oil; therefore all Egypt future net revenues are after income tax. Income taxes payable in Egypt have been recorded as Operating Costs for reporting purposes. 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, 2017.

23

NET PRESENT VALUE OF FUTURE NET REVENUES

BY PRODUCT TYPE

AS OF DECEMBER 31, 2017

(FORECAST PRICES AND COSTS)

		Future net
		Revenue	Unit Value
		Before Taxes(6)	Before Tax(4)(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)	100.1	12.05
	Heavy Crude Oil (1)	116.6	15.44
	Conventional Natural Gas (3)(5)	4.3	3.97
	Natural Gas Liquids (2)	12.4	7.41
Proved+Probable	Light Crude Oil and Medium Crude Oil (1)	148.1	11.40
	Heavy Crude Oil (2)	180.4	14.73
	Conventional Natural Gas (3)(5)	4.4	1.66
	Natural Gas Liquids (2)	16.8	5.01
Proved+Probable +Possible	Light Crude Oil and Medium Crude Oil (1)	186.9	11.45
	Heavy Crude Oil (1)	228.0	13.86
	Conventional Natural Gas (3)(5)	3.3	0.79
	Natural Gas Liquids (2)	24.6	4.81
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.

24

Reserves Data – Constant Prices and Costs

SUMMARY OF OIL AND GAS RESERVES ⁽³⁾

TOTAL COMPANY

AS OF DECEMBER 31, 2017

(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	3.1	2.4	10.1	5.7	15.1	12.4	2.4	1.8	18.2	11.9
Developed non-producing	0.4	0.3	1.5	0.8	0.2	0.2	—	—	1.9	1.1
Undeveloped	2.7	2.3	1.9	0.9	6.0	5.4	0.9	0.8	6.5	5.0
Total Proved	6.2	5.0	13.4	7.3	21.4	18.1	3.3	2.6	26.6	18.0
Probable	3.8	3.1	7.8	4.1	17.2	15.6	2.6	2.4	17.1	12.2
Proved+Probable	10.0	8.1	21.2	11.5	38.6	33.7	6.0	5.0	43.7	30.2
Possible	2.9	2.2	6.9	3.7	13.0	11.3	2.1	1.8	14.0	9.5
Proved+Probable+Possible	12.9	10.3	28.2	15.1	51.6	45.1	8.0	6.8	57.7	39.7
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, 2017

(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	1.7	1.1	10.1	5.7	11.8	6.8
Developed non-producing	0.3	0.2	1.5	0.8	1.8	1.0
Undeveloped	0.3	0.2	1.9	0.9	2.1	1.1
Total Proved	2.3	1.5	13.4	7.3	15.7	8.8
Probable	1.5	1.0	7.8	4.1	9.3	5.1
Proved+Probable	3.8	2.5	21.2	11.5	25.0	14.0
Possible	1.5	1.0	6.9	3.7	8.4	4.6
Proved+Probable+Possible	5.3	3.4	28.2	15.1	33.5	18.6
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.

25

SUMMARY OF OIL AND GAS RESERVES ⁽³⁾

CANADA

AS OF DECEMBER 31, 2017

(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	15.1	12.4	2.4	1.8	6.4	5.2
Developed non-producing	0.1	—	0.2	0.2	—	—	0.1	0.1
Undeveloped	2.4	2.2	6.0	5.4	0.9	0.8	4.4	3.9
Total Proved	3.9	3.5	21.4	18.1	3.3	2.6	10.8	9.2
Probable	2.3	2.1	17.2	15.6	2.6	2.4	7.8	7.1
Proved+Probable	6.2	5.6	38.6	33.7	6.0	5.0	18.6	16.2
Possible	1.4	1.2	13.0	11.3	2.1	1.8	5.6	4.9
Proved+Probable+Possible	7.6	6.9	51.6	45.1	8.0	6.8	24.2	21.1
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, 2017

(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 2017 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	147.5	127.7	113.4	102.6	94.1	147.5	127.7	113.4	102.6	94.1	9.50
Developed non-producing	8.9	7.8	6.9	6.1	5.4	8.9	7.8	6.9	6.1	5.4	6.34
Undeveloped	61.0	38.0	24.8	16.6	11.2	61.0	38.0	24.8	16.6	11.2	4.97
Total Proved	217.4	173.5	145.0	125.2	110.7	217.4	173.5	145.0	125.2	110.7	8.05
Probable	138.6	89.2	64.2	49.8	40.5	123.7	82.9	61.4	48.3	39.7	5.26
Proved+Probable	356.1	262.8	209.3	175.0	151.2	341.1	256.5	206.4	173.6	150.5	6.93
Possible	130.3	83.5	61.2	48.3	39.9	112.6	75.6	57.2	46.0	38.5	6.44
Proved+Probable+Possible	486.4	346.3	270.5	223.3	191.1	453.8	332.1	263.6	219.6	189.0	6.81
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.

26

SUMMARY OF NET PRESENT VALUE OF FUTURE NET REVENUE

EGYPT

AS OF DECEMBER 31, 2017

(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	84.1	76.2	70.0	64.9	60.8	84.1	76.2	70.0	64.9	60.8	10.32
Developed non-producing	7.3	6.5	5.8	5.2	4.6	7.3	6.5	5.8	5.2	4.6	5.87
Undeveloped	11.3	9.9	8.8	7.9	7.1	11.3	9.9	8.8	7.9	7.1	8.29
Total Proved	102.7	92.6	84.6	78.0	72.5	102.7	92.6	84.6	78.0	72.5	9.58
Probable	63.0	52.4	44.5	38.4	33.6	63.0	52.4	44.5	38.4	33.6	8.66
Proved+Probable	165.7	145.1	129.1	116.4	106.1	165.7	145.1	129.1	116.4	106.1	9.24
Possible	64.3	52.0	43.0	36.4	31.3	64.3	52.0	43.0	36.4	31.3	9.32
Proved+Probable+Possible	230.0	197.0	172.1	152.8	137.4	230.0	197.0	172.1	152.8	137.4	9.26
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, 2017

(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	63.4	51.5	43.4	37.6	33.3	63.4	51.5	43.4	37.6	33.3	8.42
Developed non-producing	1.6	1.3	1.1	0.9	0.8	1.6	1.3	1.1	0.9	0.8	10.82
Undeveloped	49.7	28.1	16.0	8.7	4.1	49.7	28.1	16.0	8.7	4.1	4.07
Total Proved	114.7	80.9	60.5	47.3	38.2	114.7	80.9	60.5	47.3	38.2	6.59
Probable	75.7	36.8	19.7	11.4	6.9	60.7	30.5	16.8	9.9	6.2	2.79
Proved+Probable	190.4	117.7	80.2	58.6	45.1	175.4	111.4	77.3	57.2	44.4	4.94
Possible	66.1	31.6	18.2	11.9	8.6	48.4	23.7	14.1	9.7	7.2	3.72
Proved+Probable+Possible	256.4	149.2	98.4	70.6	53.7	223.8	135.1	91.4	66.9	51.7	4.65

27

TOTAL FUTURE NET REVENUE⁽³⁾

(UNDISCOUNTED)

AS OF DECEMBER 31, 2017

(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	293.8	40.3	82.4	49.3	7.1	114.7	—	114.7
Egypt	378.2	72.0	195.2	8.3	—	102.7	—	102.7
Total Company	672.0	112.3	277.6	57.6	7.1	217.4	—	217.4
Proved+Probable Reserves
Canada	487.5	57.0	135.6	96.3	8.3	190.4	14.9	175.4
Egypt	598.7	113.4	302.6	17.0	—	165.7	—	165.7
Total Company	1,086.3	170.4	438.2	113.3	8.3	356.1	14.9	341.1
Proved+Probable+Possible Reserves
Canada	618.7	72.7	171.8	109.1	8.6	256.4	32.7	223.8
Egypt	796.7	150.5	397.1	19.1	—	230.0	—	230.0
Total Company	1,415.5	223.2	569.0	128.3	8.6	486.4	32.7	453.8
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, 2017.

28

NET PRESENT VALUE OF FUTURE NET REVENUE

BY PRODUCT TYPE

AS OF DECEMBER 31, 2017

(CONSTANT PRICES AND COSTS)

		Future net
		Revenue		Unit Value
		Before Taxes(6)		Before Tax(4)(6)
		(discounted		(discounted
		at		at
		10%/year)		10%/year)
Reserves Category	Product Type	(US$MM)		($/Bbl)
Total Proved	Light Crude Oil and(1) Medium Crude Oil	64.2		7.86
	Heavy Crude Oil(1)	70.6		9.60
	Conventional Natural Gas(3)(5)	(11.1	)	(11.52	)
	Natural Gas Liquids(2)	21.4		14.06
Proved+Probable	Light Crude Oil and(1) Medium Crude Oil	92.9		7.11
	Heavy Crude Oil(1)	108.0		9.40
	Conventional Natural Gas(3)(5)	(15.7	)	(6.18	)
	Natural Gas Liquids(2)	24.2		7.72
Proved+Probable +Possible	Light Crude Oil and(1)  Medium Crude Oil	118.3		7.23
	Heavy Crude Oil(1)	142.7		9.43
	Conventional Natural Gas(3)(5)	(25.8	)	(7.00	)
	Natural Gas Liquids(2)	35.3		7.79
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.

29

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.

30

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.

31

For the reserves, crude oil benchmark reference pricing, as at December 31, 2017, inflation and exchange rates utilized by GLJ in the Reserves Data, which were GLJ'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
2018	59.00	70.25	65.50	2.20	6.75	40.40	53.74	76.42	2.0	0.79
2019	59.00	70.25	63.50	2.54	7.95	36.53	49.18	74.68	2.0	0.79
2020	60.00	70.31	63.00	2.88	9.12	35.93	49.22	74.38	2.0	0.80
2021	63.00	72.84	66.00	3.24	10.34	36.06	50.99	77.16	2.0	0.81
2022	66.00	75.61	69.00	3.47	11.14	36.29	52.93	79.88	2.0	0.82
2023	69.00	78.31	72.00	3.58	11.51	37.59	54.82	82.53	2.0	0.83
2024	72.00	81.93	75.00	3.66	11.76	39.33	57.35	86.14	2.0	0.83
2025	75.00	85.54	78.00	3.73	12.02	41.06	59.88	89.76	2.0	0.83
2026	77.33	88.35	80.33	3.80	12.27	42.41	61.84	92.57	2.0	0.83
2027	78.88	90.22	81.88	3.88	12.53	43.30	63.15	94.43	2.0	0.83
2028	80.46	92.02	83.52	3.96	12.78	44.17	64.41	96.32	2.00	0.83
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, 2017 for crude oil was $44.55/Bbl.

The weighted average historical price in US$ realized by the Company in Canada, for the year ended December 31, 2017 for crude oil and natural gas liquids was $44.69/Bbl and $20.80/Bbl respectively and for conventional natural gas was $1.70/Mcf.

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
2017	42.84	47.63	1.71	50.36	30.16	21.79	4.83
2016	32.78	37.08	1.54	39.02	19.87	5.19	5.81
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.

32

Reconciliation of Changes in Reserves

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

TOTAL COMPANY

AS OF DECEMBER 31, 2017

(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, 2016	6.2		3.5		9.7		15.6		9.1		24.7
Discoveries	—		—		—		0.4		0.6		1.0
Extensions and improved recovery	0.8		0.6		1.4		—		—		—
Technical revisions	—		(0.4	)	(0.4	)	2.1		(0.7	)	1.5
Acquisitions	—		0.1		0.1		—		—		—
Dispositions	—		—		—		—		—		—
Economic Factors	—		—		—		—		(0.1	)	(0.1	)
Production	(0.7	)	—		(0.7	)	(4.3	)	—		(4.3	)
December 31, 2017	6.3		3.8		10.1		13.9		8.9		22.8

	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, 2016	24.1		21.8		45.9		4.1		3.8		7.9
Discoveries	—		—		—		—		—		—
Extensions and improved recovery	1.9		1.5		3.4		0.3		0.3		0.6
Technical revisions	(0.5	)	(5.9	)	(6.4	)	(0.4	)	(1.4	)	(1.8	)
Acquisitions	—		0.2		0.2		—		—		—
Dispositions	—		—		—		—		—		—
Economic Factors	(0.2	)	(0.2	)	(0.5	)	—		—		(0.1	)
Production	(2.4	)	—		(2.4	)	(0.4	)	—		(0.4	)
December 31, 2017	22.9		17.4		40.3		3.5		2.7		6.2

33

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

EGYPT

AS OF DECEMBER 31, 2017

(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, 2016	2.7		1.8		4.5		15.6		9.1		24.7
Discoveries1	—		—		—		0.4		0.6		1.0
Extensions and improved recovery	—		—		—		—		—		—
Technical revisions2	0.1		(0.3	)	(0.2	)	2.1		(0.7	)	1.5
Acquisitions	—		—		—		—		—		—
Dispositions	—		—		—		—		—		—
Economic Factors	—		—		—		—		(0.1	)	(0.1	)
Production	(0.5	)	—		(0.5	)	(4.3	)	—		(4.3	)
December 31, 2017	2.3		1.5		3.8		13.9		9.0		22.8
1. Attributed to NW Gharib discoveries. 2. Positive technical revisions primarily attributed to improved performance.

RECONCILIATION OF GROSS RESERVES

BY PRODUCT TYPE

CANADA

AS OF DECEMBER 31, 2017

(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, 2016	3.6		1.7		5.2		24.1		21.8		45.9
Discoveries	—		—		—		—		—		—
Extensions and improved recovery1	0.8		0.6		1.4		1.9		1.5		3.4
Technical revisions2	(0.1	)	(0.1	)	(0.2	)	(0.5	)	(5.9	)	(6.4	)
Acquisitions	—		0.1		0.1		—		0.2		0.2
Dispositions	—		—		—		—		—		—
Economic Factors	—		—		—		(0.2	)	(0.2	)	(0.5	)
Production	(0.2	)	—		(0.2	)	(2.4	)	—		(2.4	)
December 31, 2017	4.1		2.3		6.3		22.9		17.4		40.3

34

	Natural Gas Liquids
					Gross Proved
	Gross Proved		Gross Probable		Plus Probable
Factors	(MMBbl)		(MMBbl)		(MMBbl)
December 31, 2016	4.1		3.8		7.9
Discoveries	—		—		—
Extensions and improved recovery1	0.3		0.3		0.6
Technical revisions2	(0.4	)	(1.4	)	(1.8	)
Acquisitions	—		—		—
Dispositions	—		—		—
Economic Factors	(0.1	)	—		(0.1	)
Production	(0.4	)	—		(0.4	)
December 31, 2017	3.5		2.7		6.2
1. Positive extension additions primarily due to the addition of undeveloped Cardium oil locations. 2. Negative technical revisions primarily attributed to undeveloped Mannville gas locations deemed uneconomic at current natural gas price forecasts.

Additional Information Relating to Reserves Data

Undeveloped Reserves

Undeveloped reserves are attributed by GLJ 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.

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
2015(1)	—	—	—	—
2016(2)	1.7	2.0	1.0	3.0
2017(3)	0.7	2.8	0.2	1.4
Notes:
(1)  In 2015 no new proved undeveloped reserves were assigned.
(2)  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.
(3)  In 2017, proved undeveloped reserves were assigned to Egypt’s NW Gharib Red Bed development program and to Canada’s Cardium development program.

	Conventional Natural Gas		Natural Gas Liquids
Year	(Bcf)		(MMBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
2015(1)	—	—	—	—
2016(2)	9.0	9.0	1.7	1.7
2017(3)	1.7	6.4	0.3	1.0
Notes:
(1)  In 2015 no new proved undeveloped reserves were assigned.
(2)  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.
(3)  In 2017, proved undeveloped reserves were assigned to Egypt’s NW Gharib Red Bed development program and to Canada’s Cardium development program.

35

A total of 6.4 Bcf of conventional natural gas, 2.8 MMbbl of light crude oil and medium crude oil, 1.4 MMbbl of heavy crude oil and 1.0 MMbbl of NGLs were assigned in the GLJ Report under forecast prices and costs as gross proved undeveloped reserves as at December 31, 2017, representing approximately 23% of total proved reserves, together with $61.8 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 GLJ Report is expected to be spent between 2018 and 2021, with approximately 28% of the capital scheduled to be spent through 2018 and 48% 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
2015(1)	—	0.1	—	2.8
2016(2)	1.1	1.2	0.7	3.1
2017(3)	0.6	2.0	0.6	3.4
Notes:
(1)  In 2015 no new probable undeveloped reserves were assigned.
(2)  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.
(3)  In 2017, probable undeveloped reserves were assigned to Egypt’s NW Gharib Red Bed development program and to Canada’s Cardium development program.

	Conventional Natural Gas		Natural Gas Liquids
Year	(Bcf)		(MMBbl)
	First Attributed	Cumulative at Year End	First Attributed	Cumulative at Year End
2015(1)	—	—	—	—
2016(2)	18.9	18.9	3.3	3.3
2017(3)	1.5	13.5	0.2	2.1
Notes:
(1)  In 2015 no new probable undeveloped reserves were assigned.
(2)  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.
(3)  In 2017, probable undeveloped reserves were assigned to Egypt’s NW Gharib Red Bed development program and to Canada’s Cardium development program.

A total of 13.5 Bcf of conventional natural gas, 2.0 MMbbl of light crude oil and medium crude oil, 3.4 MMbbl of heavy crude oil and 2.1 MMbbl of NGLs were assigned in the GLJ Report under forecast prices and costs as gross probable undeveloped reserves as at December 31, 2017, representing approximately 53% of total probable reserves, together with $122.3 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 GLJ Report is expected to be spent between 2018 and 2022, with approximately 17% of the capital scheduled to be spent through 2018 and 33% 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 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

36

GLJ 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, 2017

(FORECAST PRICES AND COSTS)

(US$MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2018	17.5	21.9
2019	14.2	20.7
2020	13.8	18.0
2021	11.1	13.3
2022	8.9	26.2
Remaining	—	27.2
Total Undiscounted	65.5	127.3
Discounted at 10%	54.1	95.7

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 GLJ 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 Affecting Reserves Data".

FUTURE DEVELOPMENT COSTS

EGYPT

AS OF DECEMBER 31, 2017

(FORECAST PRICES AND COSTS)

(US$MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2018	3.5	5.9
2019	3.9	8.4
2020	0.9	3.1
2021	0.2	0.2
2022	0.2	0.2
Remaining	—	—
Total Undiscounted	8.6	17.6
Discounted at 10%	7.6	15.5

37

FUTURE DEVELOPMENT COSTS

CANADA

AS OF DECEMBER 31, 2017

(FORECAST PRICES AND COSTS)

(US$MM)	Forecast Prices and Costs
		Proved Plus
	Proved	Probable
Year	Reserves	Reserves
2018	14.1	16.1
2019	10.3	12.3
2020	12.9	15.0
2021	11.0	13.2
2022	8.7	26.0
Remaining	—	27.2
Total Undiscounted	57.0	109.8
Discounted at 10%	46.5	80.3

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, 2017. 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	104.0	104.0	123.0	123.0	—	—	—	—
Canada	55.0	53.3	12.0	10.7	66.0	60.9	12.0	8.0
Total	159.0	157.3	135.0	133.7	66.0	60.9	12.0	8.0

Properties with No Attributed Reserves

The following table sets out the Company's developed and undeveloped land holdings as at December 31, 2017.

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Egypt	8,220	8,220	1,026,329	1,026,329	1,034,549	1,034,549
Canada	35,379	32,658	49,814	42,266	85,193	74,924
Total	43,599	40,878	1,076,143	1,068,595	1,119,742	1,109,473

Commitments

In the West Gharib concession, all work commitments have been fulfilled and there are no potential land expiries in 2018.

The West Bakr concession was purchased on December 29, 2011. All work commitments have been fulfilled and there are no potential land expiries in 2018.

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 in Egypt, the Company had a minimum financial commitment of $35.0 million 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. The Company received a six month extension to the initial exploration period, which extended to May 7, 2017. The Company completed the initial exploration period work program and met all financial commitments during the second quarter of 2017. The Company elected not to enter the second exploration period and has relinquished the remaining exploration lands not covered by the four development leases.

In the South West Gharib concession in Egypt, the Company had a minimum financial commitment of $10.0 million 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. The Company received a six month extension to the initial exploration period, which extended to May 7, 2017. As no commercially viable quantities of oil were discovered at South West Gharib, the Company relinquished its interest in the concession on May 7, 2017. The Company met its financial commitment during the first quarter of 2017.

38

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, 2017, 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, 2017, the Company had acquired 600 kilometers of seismic and expended $4.9 million towards meeting that commitment. The initial exploration period expires July 7, 2018, and may be extended to meet the Company’s financial and work commitment program.

At December 31, 2017, TransGlobe had no outstanding cash collateralized letters of credit to support its work commitments under the Egyptian PSCs. Approximately, $5.1 million of work commitments were backstopped by the Company's accounts receivable from EGPC.

Approximately 9,440 gross acres of mineral rights could expire prior to December 31, 2018 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.

Forward Contracts

In conjunction with the prepayment agreement executed in 2017, TPI has also entered into a marketing contract with Mercuria to market 9 million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale. In conjunction with the prepayment and marketing agreements, the Company is committed to hedge 60% of its forecasted 1P entitlement production.

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.

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings at each reporting period. TransGlobe has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

There were eleven outstanding derivative commodity contracts as at December 31, 2017 (December 31, 2016 - nil), the fair values of which have been presented as liabilities on the Consolidated Balance Sheet.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at December 31, 2017:

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
7-Apr-17	Mar-18	3-Way Collar	250,000	53.00	61.15	44.00
12-Apr-17	Jun-18	3-Way Collar	250,000	54.00	63.10	45.00
12-Apr-17	Sep-18	3-Way Collar	250,000	54.00	64.15	45.00
12-Apr-17	Dec-18	3-Way Collar	250,000	54.00	65.45	45.00
23-May-17	Jul 2020 - Dec 20201	3-Way Collar	300,000	54.00	63.45	45.00
31-Aug-17	Jan 2020 - Jun 20202	3-Way Collar	300,000	54.00	61.25	46.50
12-Oct-17	Jan 2019 - Dec 20193	3-Way Collar	396,000	53.00	62.10	46.00
26-Oct-17	Jan 2019 - Dec 20194	3-Way Collar	399,996	54.00	61.35	46.00
1. 50,000 bbls per calendar month through Jul 2020 - Dec 2020
2. 50,000 bbls per calendar month through Jan 2020 - Jun 2020
3. 33,000 bbls per calendar month through Jan 2019 - Dec 2019
4.33,333 bbls per calendar month through Jan 2019 - Dec 2019

39

Financial WTI Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Sold Swap USD$/bbl	Bought Put CAD$/bbl	Sold Call CAD$/bbl
15-Dec-17	Jan 2018 - Dec 20181	Swap	60,225	56.35	—	—
15-Dec-17	Jan 2018 - Dec 20181	Put Option	60,225	—	64.00	—
15-Dec-17	Jan 2018 - Dec 20181	Call Option	60,255	—	—	78.85
1. 165 bbls per day

The estimated fair value of the financial crude oil contracts has been determined based on the amount the Company would receive or pay to terminate the crude oil contracts at year end. At December 31, 2017, the amount the Company would have paid had it terminated the outstanding crude oil contracts would have been $8.0, million resulting in an unrealized loss of $8.0 million for the year ended December 31, 2017 (December 31, 2016 - nil).

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 GLJ. 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 GLJ Report for the 201.3 net wells under the proved reserves category is $11.5 million undiscounted, of which a total of $0.2 million is estimated to be incurred through 2019.

Tax Horizon

In 2017, 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, 2017:

	Egypt	Canada	Total
(US$M)
Property acquisition costs
Proved properties	—	—	—
Undeveloped properties	—	—	—
Exploration costs	16,905	—	16,905
Development costs	13,335	6,967	20,302
Corporate and other	911	41	952
Total	31,151	7,008	38,159

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, 2017:

Egypt	Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	—	—	—	—	—	—
Crude Oil	3.0	4.0	7.0	3.0	4.0	7.0
Service	—	—	—	—	—	—
Dry and Abandoned	7.0	1.0	8.0	7.0	1.0	8.0
Total	10.0	5.0	15.0	10.0	5.0	15.0

Canada	Gross			Net
	Exploration	Development	Total	Exploration	Development	Total
Natural Gas	—	—	—	—	—	—
Crude Oil	—	3.0	3.0	—	2.9	2.9
Service	—	—	—	—	—	—
Dry and Abandoned	—	—	—	—	—	—
Total	—	3.0	3.0	—	2.9	2.9

40

Current development activities are focused on the West Gharib, West Bakr and NW Gharib concessions in Egypt, and the Harmattan area in Canada. Other key areas for 2018 include the exploration drilling program at NW Sitra, South Ghazalat and South Alamein in Egypt.

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, 2018 by GLJ 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	1,187	3,513	4,610	752	608	5,714	873	12,494
Proved Developed
Non-Producing	79	216	437	—	—	—	—	733
Proved Undeveloped	135	—	139	93	260	212	36	698
Total Proved	1,402	3,729	5,186	845	867	5,926	909	13,925
Total Probable	159	527	563	300	77	115	17	1,662
Total Proved Plus Probable	1,561	4,256	5,749	1,145	944	6,041	926	15,587

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:

	2017
	Quarter Ended
	Mar. 31	Jun. 30	Sep. 30	Dec. 31
Average Daily Production Volumes
Egypt(1)
Heavy Crude Oil (Bbls/d)	12,696	12,580	10,819	10,355
Light Crude Oil and Medium Crude Oil (Bbls/d)	1,252	1,271	1,449	897
Canada (2)
Light Crude Oil and Medium Crude Oil (Bbls/d)	566	496	518	775
Conventional Natural Gas (Boe/d)	1,179	1,199	1,045	1,010
Natural Gas Liquids (Bbls/d)	1,037	919	1,081	915
Combined (Boe/d) (3)	16,730	16,465	14,912	13,952
Average Daily Sales Volumes
Egypt
Heavy Crude Oil (Bbls/d)	10,053	15,118	13,560	12,469
Light Crude Oil and Medium Crude Oil (Bbls/d)	991	1,527	1,816	1,080
Canada
Light Crude Oil and Medium Crude Oil (Bbls/d)	566	496	518	775
Conventional Natural Gas (Boe/d)	1,179	1,199	1,045	1,010
Natural Gas Liquids (Bbls/d)	1,037	919	1,081	915
Combined (Boe/d) (3)	13,826	19,259	18,020	16,249
Average Price Received
Egypt(1)
Heavy Crude Oil (US$/Bbl)	41.29	39.31	44.82	53.22
Light Crude Oil and Medium Crude Oil (US$/Bbl)	41.29	39.31	44.82	53.22
Canada
Light Crude Oil and Medium Crude Oil (US$/Bbl)	48.82	44.47	44.91	53.72
Conventional Natural Gas (US$/Boe)	11.73	12.84	9.87	5.66
Natural Gas Liquids (US$/Bbl)	19.08	21.08	18.90	26.86
Combined (US$/Boe)	37.41	36.92	41.24	48.80
Royalties and Taxes
Egypt(1)
Heavy Crude Oil (US$/Bbl)	28.50	18.90	19.57	29.28
Light Crude Oil and Medium Crude Oil (US$/Bbl)	28.50	18.90	19.57	29.28

41

Canada
Light Crude Oil and Medium Crude Oil (US$/Bbl)	4.70		4.84	4.22	5.79
Conventional Natural Gas (US$/Boe)	4.70		4.84	4.22	5.79
Natural Gas Liquids (US$/Bbl)	4.70		4.84	4.22	5.79
Combined (US$/Bbl)	23.72		16.99	17.31	25.38
Operating Expenses
Egypt(1)
Heavy Crude Oil (US$/Bbl)	8.60		8.95	9.36	7.51
Light Crude Oil and Medium Crude Oil (US$/Bbl)	8.60		8.95	9.36	7.51
Canada (4)(5)(6)
Light Crude Oil and Medium Crude Oil (US$/Bbl)	7.09		6.41	5.26	6.94
Conventional Natural Gas (US$/Boe)	7.09		6.41	5.26	6.94
Natural Gas Liquids (US$/Bbl)	7.09		6.41	5.26	6.94
Combined (US$/Bbl)	8.30		8.60	8.76	7.41
Selling Costs
Egypt(1)
Heavy Crude Oil (US$/Bbl)	—		0.99	0.30	0.46
Light Crude Oil and Medium Crude Oil (US$/Bbl)	—		0.99	0.30	0.46
Canada
Light Crude Oil and Medium Crude Oil (US$/Bbl)	—		—	—	—
Conventional Natural Gas (US$/Boe)	—		—	—	—
Natural Gas Liquids (US$/Bbl)	—		—	—	—
Combined (US$/Bbl)	—		0.86	0.26	0.38
Netback Received (7)
Egypt(1)
Heavy Crude Oil (US$/Bbl)	4.19		10.47	15.59	15.97
Light Crude Oil and Medium Crude Oil (US$/Bbl)	4.19		10.47	15.59	15.97
Canada (8)(9)
Light Crude Oil and Medium Crude Oil (US$/Bbl)	37.03		33.22	35.43	40.99
Conventional Natural Gas (US$/Boe)	(0.06	)	1.59	0.39	(7.07	)
Natural Gas Liquids (US$/Bbl)	7.29		9.83	9.42	14.13
Combined (US$/Bbl)	5.39		10.47	14.91	15.63
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 2017, the Company held 776,754 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, 2017:

		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	4,244	—	—	—	4,244
Hana	—	705	—	—	705
Hana West	—	515	—	—	515
Hoshia	493	—	—	—	493
West Bakr	5,752	—	—	—	5,752
NW Gharib	1,113	—	—	—	1,113
Other Egypt	—	—	—	—	—
Canada	—	589	6,644	988	2,684
Total	11,602	1,809	6,644	988	15,506

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DIVIDEND POLICY

No dividends were paid on the Company's Common Shares in 2016 or 2017. The Company has paid the following dividends on its Common Shares during the year ended December 31, 2015.

Ex-dividend date	Record date	Payment date	Per share amount
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 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.

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 7, 2018 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.

Debentures

The Company repaid the Debentures in full on March 31, 2017, which was the maturity date of the Debentures. The Debentures were denominated in Canadian dollars, and the aggregate face value of all outstanding Debentures was C$97.8 million ($73.4 million). The repayment was made using the funds received by drawing on the $75 million prepayment agreement with Mercuria.

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 were 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:

43

(Canadian dollars, except volumes)	Price Range
	High	Low
	($/share)	($/share)	Volume
2017
January	2.46	2.18	1,268,814
February	2.40	2.16	1,827,613
March	2.26	1.98	1,280,151
April	2.17	2.00	650,716
May	2.21	1.91	761,360
June	1.95	1.61	1,115,366
July	1.72	1.65	296,213
August	1.67	1.49	701,479
September	1.78	1.30	3,644,867
October	2.18	1.78	1,343,787
November	2.28	1.85	1,454,979
December	1.90	1.63	1,616,159
2018
January	1.86	1.72	1,318,441
February	1.81	1.60	742,485
March (1 to 6)	1.67	1.60	94,115

44

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
2017
January	1.84	1.66	2,083,088
February	1.84	1.63	2,364,181
March	1.70	1.49	2,561,251
April	1.64	1.46	1,205,737
May	1.62	1.38	1,689,280
June	1.45	1.22	1,896,740
July	1.38	1.27	764,435
August	1.34	1.18	1,227,551
September	1.44	1.07	2,232,807
October	1.68	1.42	1,416,886
November	1.79	1.44	1,894,795
December	1.45	1.26	1,853,538
2018
January	1.49	1.39	1,991,769
February	1.46	1.27	1,409,111
March (1 to 6)	1.29	1.25	188,796

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
2017
January	100.00	99.50	1,627,000
February	100.05	99.50	1,820,000
March1	91.00	85.25	1,990,000
1. The Company repaid the Debentures in full on March 31, 2017, which was the maturity date of the Debentures.

45

PRIOR SALES

The following table summarizes the issuance of stock options, which are convertible into Common Shares, during the year ended December 31, 2017:

Date of Issuance	Number of Stock Options	Price per Stock Option
May 19, 2017	1,043,300	Cdn$2.16

The following table summarizes the issuance of restricted share units ("RSUs"), which are cash-settled, during the year ended December 31, 2017:

Date of Issuance	Number of RSUs	Price per RSU
March 9, 2017 (1)	71,564	N/A
March 13, 2017 (1)	11,374	N/A
May 19, 2017 (1)	560,300	N/A
June 19, 2017 (1)	5,714	N/A
August 15, 2017 (1)	109,091	N/A
September 8, 2017 (1)	34,688	N/A
December 19, 2017 (1)	14,286	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, 2017:

Date of Issuance	Number of PSUs (2)	Price per PSU
March 9, 2017 (1)	71,564	N/A
May 19, 2017(1)	470,700	N/A
August 15, 2017(1)	19,481	N/A
September 7, 2017(1)	11,563	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 prior to 2017, and 0% to 200% for PSUs granted in 2017 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, 2017:

Date of Issuance	Number of DSUs (2)	Price per DSU
May 19, 2017 (1)	214,120	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.

46

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 6, 2018 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	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.
Matthew Brister (3) Alberta, Canada	Director	2017	Previously President and CEO of Chinook Energy and most recently Chairman of the Company. Previously served as CEO Storm Ventures International (SVI), President and CEO of Storm Energy Ltd and Storm Energy Inc. Held various positions with Pinnacle Resources including President and CEO. Over 40 years experience in the domestic and international energy sector.
David B. Cook (1)(2) Denmark Copenhagen	Director	2014	Head of Strategy for INEOS Oil & Gas, recently having transitioned from his role as CEO INEOS DeNoS, located in Copenhagen, Denmark. Previously served as CEO of DONG Oil & Gas, part of the DONG (now Orsted) Energy Group, before the business was sold to INEOS.  Prior to that was Executive Officer and Head of Oil and Gas at the Abu Dhabi National Energy Company ("TAQA") where he led the Company's upstream and midstream interests in the Middle East, North America, the United Kingdom and Europe.  Before joining TAQA, he served as Vice President for BP Russia, responsible for BP’s 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.
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	President	2012	President of the Company since January 10, 2018 and previously Vice President Finance and CFO since May 8, 2012. Prior to joining TransGlobe was Chief Financial Officer at Zodiac Exploration Inc and Chief Financial Officer at BlackPearl Resources Inc. Industry professional with over 25 years' experience.
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 25 years of domestic and international experience. A registered member of the Association of Professional Engineers and Geosciences of Alberta ("APEGA").
Edward D. Ok Alberta, Canada	Vice-President, Finance, Chief Financial Officer	2018	Vice President, Finance and Chief Financial Officer of the Company since January 2018 and with the Company since 2012 in senior financial roles. Prior to joining TransGlobe was at Zodiac Exploration. Mr. Ok is a Chartered Accountant with over 10 years industry experience.
Steven Sinclair (1) Alberta, Canada	Director	2017	Previously served as Senior Vice President and Chief Financial Officer of ARC Resources Ltd until his retirement in 2014. Mr. Sinclair has over 30 years' financial and operating experience and senior management experience.
Marilyn Vrooman-Robertson Alberta, Canada	Corporate Secretary	2017	Corporate Secretary since 2017 and previously served as Assistant Corporate Secretary. Governance professional with over 18 years' experience. A student of ICSA ("International Chartered Secretary Association") and a member of Governance Professionals of Canada.

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 6, 2018, the directors and officers of TransGlobe, as a group, beneficially owned or controlled or directed, directly or indirectly, 3,594,789 Common Shares or approximately 4.9% 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 GLJ, 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 GLJ or by the "designated professionals" (as defined in Form 51-102F2 to NI 51-102) of GLJ, when GLJ prepared the report, valuation, statement or opinion referred to herein as having been prepared by GLJ; (ii) received by GLJ or by the "designated professionals" of GLJ, after the time specified above; or (iii) to be received by GLJ or by the "designated professionals" of GLJ; except in each case for the ownership of Common Shares, which in respect of GLJ and GLJ's "designated professionals", as a group, has at all relevant times represented less than one percent of the outstanding Common Shares. In addition, neither GLJ, nor any director, officer or employee of GLJ, 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 2017 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 2017 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 2017 financial year.

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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 marketing agreement dated February 10, 2017 described under "General Development of the Business - 2017", which is available on the Company's profile on SEDAR.com at www.sedar.com; and (ii) the $75 million crude oil prepayment agreement dated February 2017 described under "General Development of the Business - 2017", which 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, David Cook and Steven Sinclair. 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.
Steven Sinclair	Yes	Yes	Mr. Sinclair is a corporate director. Mr Sinclair previously served as Senior Vice President and Chief Financial Officer of ARC Resources Ltd until his retirement 2014. Mr. Sinclair has over 30 years of financial and operating experience. Mr Sinclair is also a director and chair of the audit committee of a Calgary headquartered private oil and gas company. Mr Sinclair received his Bachelor of Commerce degree from the University of Calgary in 1978 and his Chartered Accountant's designation in 1981.

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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.

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, 2017 and December 31, 2016 were as follows (all fees are in Canadian dollars):

	Fiscal Year Ended		Fiscal Year Ended
	December 31, 2017		December 31, 2016
Audit Fees	$	499,957	$	435,490
Audit Related Fees	137,767		—
Tax Fees	115,268		9,272
All Other Fees	NIL		NIL
TOTAL	$	752,992	$	444,762

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.

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, 2017 and 2016, no other fees were incurred other than those described above.

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CANADIAN INDUSTRY CONDITIONS

Companies carrying on business in the crude oil and natural gas sector in Canada are subject to extensive controls and regulations imposed through legislation of the federal government and the provincial governments where the companies have assets or operations. While these regulations do not affect the Company's operations in any manner that is materially different than how they affect other similarly-sized industry participants with similar assets and operations, investors should consider such regulations carefully. Although governmental legislation is a matter of public record, the Company is unable to predict what additional legislation or amendments governments may enact in the future.

The Company holds interests in crude oil and natural gas properties, along with related assets, primarily in the Canadian province of Alberta. The Company's assets and operations are regulated by administrative agencies deriving authority from underlying legislation. Regulated aspects of the Company's upstream crude oil and natural gas business include all manner of activities associated with the exploration for and production of crude oil and natural gas, including, among other matters: (i) permits for the drilling of wells; (ii) technical drilling and well requirements; (iii) permitted locations and access of operation sites; (iv) operating standards regarding conservation of produced substances and avoidance of waste, such as restricting flaring and venting; (v) minimizing environmental impacts; (vi) storage, injection and disposal of substances associated with production operations; and (vii) the abandonment and reclamation of impacted sites. In order to conduct crude oil and natural gas operations and remain in good standing with the applicable provincial regulatory scheme, 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 in this regard can be costly and a breach of the same may result in fines or other sanctions. The discussion below outlines certain pertinent conditions and regulations that impact the crude oil and natural gas industry in Western Canada.

Pricing and Marketing in Canada

Crude Oil

Producers of crude oil are entitled to negotiate sales contracts directly with crude oil purchasers, which results in the market determining the price of crude oil. Worldwide supply and demand factors primarily determine crude oil prices; however, regional market and transportation issues also influence prices. The specific price depends, in part, on crude oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, supply/demand balance and contractual terms of sale.

Natural Gas

The price of natural gas sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. The price received by a natural gas producer depends, in part, on the price of competing natural gas supplies and other fuels, natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions, supply/demand balance and other contractual terms. Spot and future prices can also be influenced by supply and demand fundamentals on various trading platforms.

Natural Gas Liquids

The price of condensate and other natural gas liquids such as ethane, butane and propane ("NGLs") sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. Such price depends, in part, on the quality of the NGLs, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply/demand balance and other contractual terms.

Exports from Canada

Crude oil, natural gas and NGLs exports from Canada are subject to the National Energy Board Act (Canada) (the "NEB Act") and the National Energy Board Act Part VI (Oil and Gas) Regulation (the "Part VI Regulation"). The NEB Act and the Part VI Regulation authorize crude oil, natural gas and NGLs exports under either short-term orders or long-term licences. To obtain a crude oil export licence, a mandatory public hearing with the National Energy Board (the "NEB") is required, which is no longer the case for natural gas and NGLs. For natural gas and NGLs, the NEB uses a written process that includes a public comment period for impacted persons. Following the comment period, the NEB completes its assessment of the application and either approves or denies the application. For natural gas, the maximum duration of an export licence is 40 years and, for crude oil and other gas substances (e.g. NGLs), the maximum term is 25 years. All crude oil, natural gas and NGLs licences require the approval of the cabinet of the Canadian federal government.

Orders from the NEB provide a short-term alternative to export licences and may be issued more expediently, since they do not require a public hearing or approval from the cabinet of the Canadian federal government. Orders are issued pursuant to the Part VI Regulation for up to one or two years depending on the substance, with the exception of natural gas (other than NGLs) for which an order may be issued for up to twenty years for quantities not exceeding 30,000 m³ per day.

As to price, 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 federal government.

The Company does not directly enter into contracts to export its Canadian production outside of Canada.

As discussed in more detail below, one major constraint to the export of crude oil, natural gas and NGLs outside of Canada is the deficit of overall pipeline and other transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline or other transportation projects are underway, many contemplated projects have been cancelled or are delayed due to regulatory hurdles, court challenges and economic and political factors. The transportation capacity deficit is not likely to be resolved quickly given the significant length of time required to complete major pipeline or other transportation projects once all regulatory and other hurdles have been cleared. In addition, production of crude oil, natural gas and NGLs in Canada is expected to continue to increase, which may further exacerbate the transportation capacity deficit.

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Transportation Constraints and Market Access

Producers negotiate with pipeline operators (or other transport providers) to transport their products, which may be done on a firm or interruptible basis. Due to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low pricing relative to other markets in the last several years. Transportation availability is highly variable across different areas and regions, which can determine the nature of transportation commitments available, the number of potential customers that can be reached in a cost-effective manner and the price received.

Developing a strong network of transportation infrastructure for crude oil, natural gas and NGLs, including by means of pipelines, rail, marine and trucks, in order to obtain better access to domestic and international markets has been a significant challenge to the Canadian crude oil and natural gas industry. Improved means of access to global markets, especially the Midwest United States and export shipping terminals on the west coast of Canada, would help to alleviate the pricing pressures discussed. Several proposals have been announced to increase pipeline capacity out of Western Canada in order to reach Eastern Canada, the United States and international markets via export shipping terminals on the west coast of Canada. While certain projects are proceeding, the regulatory approval process as well as economic and political factors for transportation and other export infrastructure have led to the delay of many pipeline projects or their cancellation altogether.

Under the Canadian constitution, interprovincial and international pipelines fall within the federal government's jurisdiction and require approval by both the NEB and the cabinet of the federal government. However, recent years have seen a perceived lack of policy and regulatory certainty at a federal level. Although the current federal government recently introduced draft legislation to amend the current federal approval processes, it is uncertain when the new legislation will be brought into force and whether any changes to the draft legislation will be made before the legislation is brought into force. It is also uncertain whether any new processes adopted by the federal government will result in a more efficient approval process. The lack of regulatory certainty is likely to have an influence on investment decisions for major projects. Even when projects are approved on a federal level, such projects often face further delays due to interference by provincial and municipal governments as well as court challenges on various issues such as indigenous title, the government's duty to consult and accommodate indigenous peoples and the sufficiency of environmental review processes, which creates further uncertainty. Export pipelines from Canada to the United States face additional uncertainty as such pipelines require approvals of several levels of government in the United States.

Natural gas prices in Alberta and British Columbia have also been constrained in recent years due to increasing North American supply, limited access to markets and limited storage capacity. While companies that secure firm access to transport their natural gas production out of Western Canada may be able to access more markets and obtain better pricing, other companies may be forced to accept spot pricing in Western Canada for their natural gas, which in the last several years has generally been depressed (at times producers have received negative pricing for their natural gas production). Required repairs or upgrades to existing pipeline systems have also led to further reduced capacity and apportionment of firm access, which in Western Canada may be further exacerbated by natural gas storage limitations. Additionally, while a number of liquefied natural gas export plants have been proposed for the west coast of Canada, government decision-making, regulatory uncertainty, opposition from environmental and indigenous groups, and changing market conditions have resulted in the cancellation or delay of many of these projects.

The North American Free Trade Agreement and Other Trade Agreements

The North American Free Trade Agreement ("NAFTA") between the governments of Canada, the United States and Mexico came into force on January 1, 1994. Under the terms of NAFTA, Canada remains 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 Canada 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. Further, all three signatory counties are prohibited from imposing a minimum or maximum price requirement on exports (where any other form of quantitative restriction is prohibited) and imports (except as permitted in the enforcement of countervailing and anti-dumping orders and undertakings). NAFTA also requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of such changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements.

In 2017, the United States government announced its intention to renegotiate NAFTA. As a result, Canada, the United States and Mexico began renegotiating the terms of NAFTA in mid-2017. The United States has suggested that it might give notice of the termination of NAFTA if it is not satisfied with the outcome of the renegotiations. If the United States does give notice of its intent to terminate or withdraw from NAFTA, the earliest such termination or withdrawal could occur would be six months after such notice is given. The renegotiations are still underway and theoutcome of such negotiations remain unclear, but as the United States remains by far Canada's largest trade partner and the largest international market for the export of crude oil, natural gas and NGLs from Canada, any changes to, or termination of, NAFTA could have an impact on Western Canada's crude oil and natural gas industry at large, including the Company's business.

Canada has also pursued a number of other international free trade agreements with other countries around the world. As a result, a number of free trade or similar agreements are in force between Canada and certain other countries while in other circumstances Canada has been unsuccessful in its efforts. Canada and the European Union recently agreed to the Comprehensive Economic and Trade Agreement ("CETA"), which provides for duty-free, quota-free market access for Canadian oil and gas products to the European Union. Although CETA remains subject to ratification by certain national legislatures in the European Union, provisional application of CETA commenced on September 21, 2017. In addition, Canada and ten other countries recently concluded discussions and agreed on the draft text of the Comprehensive and Progressive Agreement for Trans-Pacific Partnership ("CPTPP"), which is intended to allow for preferential market access among the countries that are parties to the CPTPP. The text of CPTPP has not been finalized or published and the agreement remains subject to ratification by the governments of each of the countries involved. While it is uncertain what effect CETA, CPTPP or any other trade agreements will have on the oil and gas industry in Canada, the lack of available infrastructure for the offshore export of oil and gas may limit the ability of Canadian oil and gas producers to benefit from such trade agreements.

Land Tenure

The respective provincial governments (i.e. the Crown), predominantly own the mineral rights to crude oil and natural gas located in Western Canada, with the exception of Manitoba (which owns only 20% of the mineral rights). Provincial governments grant rights to explore for and produce crude 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. The provincial governments in Western Canada's provinces conduct regular land sales where crude oil and

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natural gas companies bid for leases to explore for and produce crude oil and natural gas pursuant to mineral rights owned by the respective provincial governments. The leases generally have a fixed term; however, a lease may generally be continued after the initial term where certain minimum thresholds of production have been reached, all lease rental payments have been paid on time and other conditions are satisfied.

To develop crude oil and natural gas resources, it is necessary for the mineral estate owner to have access to the surface lands as well. Each province has developed its own process for obtaining surface access to conduct operations that operators must follow throughout the lifespan of a well, including notification requirements and providing compensation for affected persons for lost land use and surface damage.

Each of the provinces of Alberta, British Columbia, Saskatchewan and Manitoba 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. Additionally, the provinces of Alberta and British Columbia have shallow rights reversion for shallow, non-productive geological formations for new leases and licences.

In addition to Crown ownership of the rights to crude oil and natural gas, private ownership of crude oil and natural gas (i.e. freehold mineral lands) also exists in the provinces of Alberta, British Columbia, Saskatchewan and Manitoba. In each of the provinces of Alberta, British Columbia, Saskatchewan and Manitoba approximately 19%, 6%, 30% and 80%, respectively, of the mineral rights are owned by private freehold owners. Rights to explore for and produce such crude oil and natural gas are granted by a lease or other contract on such terms and conditions as may be negotiated between the owner of such mineral rights and crude oil and natural gas explorers and producers.

An additional category of mineral rights ownership includes ownership by the Canadian federal government of some legacy mineral lands and within indigenous reservations designated under the Indian Act (Canada). Indian Oil and Gas Canada ("IOGC"), which is a federal government agency, manages subsurface and surface leases, in consultation with the applicable indigenous peoples, for exploration and production of crude oil and natural gas on indigenous reservations.

Royalties and Incentives

General

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 and crude oil, natural gas and NGLs 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 substance produced.

Occasionally the governments of Western Canada's provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are often introduced when commodity prices are low to encourage exploration and development activity. In addition, such programs may be introduced to encourage producers to undertake initiatives using new technologies that may enhance or improve recovery of crude oil, natural gas and NGLs.

Producers and working interest owners of crude oil and natural gas rights may also carve out additional royalties or royalty-like interests through non-public transactions, which include the creation of instruments such as overriding royalties, net profits interests and net carried interests.

Alberta

In Alberta, the provincial government royalty rates apply to Crown-owned mineral rights. In 2016, Alberta adopted a modernized Alberta royalty framework (the "Modernized Framework") that applies to all wells drilled after January 1, 2017. The previous royalty framework (the "Old Framework") will continue to apply to wells drilled prior to January 1, 2017 for a period of ten years ending on December 31, 2026. After the expiry of this ten-year period, these older wells will become subject to the Modernized Framework.

The Modernized Framework applies to all hydrocarbons other than oil sands which will remain subject to their existing royalty regime. Royalties on production from non-oil sands wells under the Modernized Framework are determined on a "revenue-minus-costs" basis with the cost component based on a Drilling and Completion Cost Allowance formula for each well, depending on its vertical depth and/or horizontal length. The formula is based on the industry’s average drilling and completion costs as determined by the Alberta Energy Regulator (the "AER") on an annual basis.

Producers pay a flat royalty rate of 5% of gross revenue from each well that is subject to the Modernized Framework until the well reaches payout. Payout for a well is the point at which cumulative gross revenues from the well equals the Drilling and Completion Cost Allowance for the well set by the AER. After payout, producers pay an increased post-payout royalty on revenues of between 5% and 40%determined by reference to the then current commodity prices of the various hydrocarbons. Similar to the Old Framework, the post-payout royalty rate under the Modernized Framework varies with commodity prices. Once production in a mature well drops below a threshold level where the rate of production is too low to sustain the full royalty burden, its royalty rate is adjusted downward towards a minimum of 5% as the mature well's production declines. As the Modernized Framework uses deemed drilling and completion costs in calculating the royalty and not the actual drilling and completion costs incurred by a producer, low cost producers benefit if their well costs are lower than the Drilling and Completion Cost Allowance and, accordingly, they continue to pay the lower 5% royalty rate for a period of time after their wells achieve actual payout.

The Old Framework is applicable to all conventional crude oil and natural gas wells drilled prior to January 1, 2017 and bitumen production. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for conventional crude oil production under the Old Framework range from a base rate of 0% to a cap of 40%. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for natural gas production under the Old Framework range from a base rate of 5% to a cap of 36%. The Old Framework also includes a natural gas royalty formula which provides for a reduction based on the measured depth of the well below 2,000 metres deep, as well as the acid gas content of the produced gas. Under the Old Framework, the royalty rate applicable to NGLs is a flat rate of 40% for pentanes and 30% for butanes and propane.

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

Oil sands production is also subject to Alberta's royalty regime. The Modernized Framework did not change the oil sands royalty framework. 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 crude oil, determined using the average monthly price, expressed in Canadian dollars, for Western Texas Intermediate crude oil at Cushing, Oklahoma. Rates are 1% when the market price of crude oil is less than or equal to $55 per barrel and increase for every dollar of market price of crude oil increase to a maximum of 9% when crude 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 crude oil increase above $55 up to 40% when crude oil is priced at $120 or higher.

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage crude oil and natural gas development and new drilling. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources, including as applied to coalbed methane wells, shale gas wells and horizontal crude oil and natural gas wells.

Freehold mineral taxes are levied for production from freehold mineral lands on an annual basis on calendar year production. Freehold mineral taxes are calculated 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. On average, in Alberta the tax levied is 4% of revenues reported from freehold mineral title properties. The freehold mineral taxes would be in addition to any royalty or other payment paid to the owner of such freehold mineral rights, which are established through private negotiation.

Freehold and Other Types of Non-Crown Royalties

Royalties on production from privately-owned freehold lands are negotiated between the mineral freehold owner and the lessee under a negotiated lease or other contract.

In addition to the royalties payable to the mineral owners, producers of crude oil and natural gas from freehold lands in each of the Western Canadian provinces are required to pay freehold mineral taxes or production taxes. Freehold mineral taxes or production taxes are taxes levied by a provincial government on crude oil and natural gas production from lands where the Crown does not hold the mineral rights. A description of the freehold mineral taxes payable in each of the Western Canadian provinces is included in the above descriptions of the royalty regimes in such provinces.

IOGC is a special agency responsible for managing and regulating the crude oil and natural gas resources located on indigenous reservations across Canada. IOGC's responsibilities include negotiating and issuing the crude oil and natural gas agreements between indigenous groups and crude oil and natural gas companies, as well as collecting royalty revenues on behalf of indigenous groups and depositing the revenues in their trust accounts. While certain standards exist, the exact terms and conditions of each crude oil and natural gas lease dictate the calculation of royalties owed, which may vary depending on the involvement of the specific indigenous group. Ultimately, the relevant indigenous group must approve the terms.

Regulatory Authorities and Environmental Regulation

General

The crude 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 are subject to governmental review and revision from time to time. Such regulations provide for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain crude oil and natural 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 regulations 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 crude oil and natural gas industry.

Federal

Canadian environmental regulation is the responsibility of both the federal 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 including interprovincial pipelines.

On June 20, 2016, the federal government launched a review of current environmental and regulatory processes. On February 8, 2018, the Government of Canada introduced draft legislation to overhaul the existing environmental assessment process and replace the NEB with the Canadian Energy Regulator ("CER"). Pursuant to the draft legislation, the Impact Assessment Agency of Canada (the "Agency") would replace the Canadian Environmental Assessment Agency. It appears that additional categories of projects may be included within new impact assessment process, such as large-scale wind power facilities and in-situ oilsands facilities. The revamped approval process for applicable major developments will have specific legislated timelines at each stage of the formal impact assessment process. The Agency's process would focus on: (i) early engagement by proponents to engage the Agency and all stakeholders such as the public and indigenous groups prior to the formal impact assessment process; (ii) potentially increased public participation where the project undergoes a panel review; (iii) providing analysis of the potential impacts and effects of a project without making recommendations, to support a public-interest approach to decision-making, with cost-benefit determinations and approvals made by the Minister of Environment and Climate Change or the cabinet of the federal government; (iv) analyzing further specified factors for projects such as alternatives to the project and social and indigenous issues in addition to health, environmental and economic impacts; and (v) overseeing an expanded follow-up, monitoring and enforcement process with increased involvement of indigenous peoples and communities. As to the proposed CER, many of its activities would be similar

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to the NEB, albeit with a different structure and the notable exception that the CER would no longer have primary responsibility in the consideration of the new major projects, instead focusing on the lifecycle regulation (e.g. overseeing construction, tolls and tariffs, operations and eventual winding down) of approved projects, while providing for expanded participation by communities and indigenous peoples. It is unclear when the new regulatory scheme will come into force or whether any amendments will be made prior to coming into force. Until then, the federal government's interim principles released on January 27, 2016 will continue to guide decision-making authorities for projects currently undergoing environmental assessment. The eventual effects of the proposed regulatory scheme on proponents of major projects remains unclear.

On May 12, 2017, the federal government introduced the Oil Tanker Moratorium Act in Parliament. This legislation is aimed at providing coastal protection in northern British Columbia by prohibiting crude oil tankers carrying more than 12,500 metric tonnes of crude oil or persistent crude oil products from stopping, loading, or unloading crude oil in that area. Parliament is still considering the bill, which passed second reading on October 4, 2017. If implemented, the legislation may prevent the building of pipelines to, and export terminals located on, the portion of the British Columbia coast subject to the moratorium and, as a result, negatively affect the ability of producers to access global markets.

Alberta

The AER is the single regulator responsible for all resource development in Alberta. The AER is responsible for ensuring 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 intended to be 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. Its approach 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.

The Government of Alberta's land-use policy for surface land in Alberta 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. As a result, several regional plans have been implemented and others are in the process of being implemented. These regional plans may affect further development and operations in such regions.

Liability Management Rating Program

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 crude oil and natural gas wells, facilities and pipelines. Alberta's Oil and Gas Conservation Act (the "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 insolvent 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 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 where a security deposit is deemed to be required, the failure to post any required amounts 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 on its public website.

In Redwater Energy Company (Re) ("Redwater"), the Court of Queen's Bench of Alberta found that there was an operational conflict between the abandonment and reclamation provisions of the OGCA, including the AB LLR Program, and the Bankruptcy and Insolvency Act (the "BIA"). This ruling meant that receivers and trustees have the right to renounce assets within insolvency proceedings, which was affirmed by a majority of the Alberta Court of Appeal. 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. Effectively, this means that abandonment costs will be borne by the industry-funded Orphan Well Fund or the province in these instances because any financial resources of the insolvent licensee will first be used to satisfy secured creditors under the BIA. This decision is currently under appeal to the Supreme Court of Canada, with final resolution expected in 2018.

In response to Redwater, the AER issued several bulletins and interim rule changes to govern while the case is appealed and to allow the Government of Alberta to develop appropriate regulatory measures to adequately address environmental liabilities. The AER's Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals, which deals with licence eligibility to operate wells and facilities, was amended and now requires extensive corporate governance and shareholder information, with a particular focus on any previous companies of directors and officers that have been subject to insolvency proceedings in the last five years. All transfers of well, facility and pipeline licences in the province are subject to AER approval. As a condition of transferring existing AER licences, approvals and permits, all are assessed on a non-routine basis and the AER now requires all transferees to demonstrate that they have a liability management rating ("LMR"), being the ratio of a licensee's assets to liabilities, of 2.0 or higher immediately following the transfer, or to otherwise prove that it can satisfy its abandonment and reclamation obligations. The AER may make further rule changes in response to Redwater at any time, especially as the case heads towards a final determination, which means that additional obligations and/or different requirements may be forthcoming.

The AER has also 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 wells that are noncompliant with Directive 013 as of April 1, 2015. The objective is to bring all inactive non-compliant wells under the IWCP into compliance with the requirements of Directive 013 within five years. As of April 1, 2015, each licensee is required to bring 20% of its inactive wells

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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 non-compliant 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. The IWCP completed its second year on March 31, 2017. Overall, the AER has announced that licensees brought 19% of non-compliant wells in the IWCP into compliance with AER requirements in the second year of the IWCP.

Climate Change Regulation

Climate change regulation at both the federal and provincial level has the potential to significantly affect the regulatory environment of the crude oil and natural gas industry in Canada.

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.

Federal

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC") since 1992. Since its inception, the UNFCCC has instigated numerous policy experiments with respect to climate governance. On April 22, 2016, 197 countries signed the Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. As of February 1, 2018, 174 of the 197 parties to the convention have ratified the Paris Agreement.

Following the Paris Agreement and its ratification in Canada, the Government of Canada pledged to cut its emissions by 30% from 2005 levels by 2030. Further, on December 9, 2016, the Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change (the "Framework"). The Framework provided for a carbon-pricing strategy, with a carbon tax starting at $10/tonne, increasing annually until it reaches $50/tonne in 2022. A draft legislative proposal for the federal carbon pricing system was released on January 15, 2018. This system would apply in provinces and territories that request it and in those that do not have a carbon pricing system in place that meets the federal standards in 2018. Four provinces currently have carbon pricing systems in place that would meet federal requirements (Alberta, British Columbia, Ontario and Quebec). The federal government will accept comments on the draft legislative proposals to implement the federal carbon pricing system until February 12, 2018.

On May 27, 2017, the federal government published draft regulations to reduce emissions of methane from the crude oil and natural gas sector. The proposed regulations aim to reduce unintentional leaks and intentional venting of methane, as well as ensuring that crude oil and natural gas operations use low-emission equipment and processes, by introducing new control measures. Among other things, the proposed regulations limit how much methane upstream oil and gas facilities are permitted to vent. These facilities would need to capture the gas and either re-use it, re-inject it, send it to a sales pipeline, or route it to a flare. In addition, in provinces other than Alberta and British Columbia (which already regulate such activities), well completions by hydraulic fracturing would be required to conserve or destroy gas instead of venting. The federal government anticipates that these actions will reduce GHG emissions by about 20 megatonnes by 2030.

Alberta

On November 22, 2015, the Government of Alberta introduced its Climate Leadership Plan (the "CLP"). The CLP has four areas of focus: implementing a carbon price on GHG emissions, phasing out coal-generated electricity and developing renewable energy, legislating an oil sands emission limit, and introducing a new methane emissions reduction plan. The Government of Alberta has since introduced new legislation to give effect to these initiatives. The Climate Leadership Act came into force on January 1, 2017 and enabled a carbon levy that increased from $20 to $30 per tonne on January 1, 2018. The levy is anticipated to increase again in 2021 in line with the federal legislation. On December 14, 2016, the Oil Sands Emissions Limit Act came into force, establishing a 100 megatonne limit for GHG emissions from all oil sands sites, excluding some attributable to upgraders, the electric energy portion of cogeneration and other prescribed emissions.

The Carbon Competitiveness Incentives Regulation (the "CCIR"), which replaces the Specified Gas Emitters Regulation, came into effect on January 1, 2018. Unlike the previous regulation, which set emission reduction requirements, the CCIR imposes an output-based benchmark on competitors in the same emitting industry. The aim is to reduce emissions by 20 million tonnes by 2020 and 50 million tonnes by 2030, and targets facilities that emit more than 100,000 tonnes of GHGs per year and mandates quarterly and final reporting requirements. The CCIR compliance obligations will be reduced by 50% and 25% for 2018 and 2019, respectively, with no reduction for 2020 onward. In addition to the industry-specific benchmarks, each benchmark will decrease annually at a rate of 1%, beginning in 2020. The Government of Alberta intends for this strategy to align with the federal Framework.

The Government of Alberta also signaled its intention through its CLP 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 was 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.

Accountability and Transparency

In 2015, the federal government's Extractive Sector Transparency Measures Act (the "ESTMA") came into effect, which imposed mandatory reporting requirements on certain entities engaged in the "commercial development of oil, gas or minerals", including exploration, extraction and holding permits. All companies subject to ESTMA must report payments over CAD$100,000 made to any level of a Canadian or foreign government (including indigenous groups), including royalty payments, taxes (other than consumption taxes and personal income taxes), fees, production entitlements, bonuses, dividends (other than ordinary dividends paid to shareholders), infrastructure improvement payments and other prescribed categories of payments.

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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.

Weakness in the Oil and Gas Industry

Weakness and volatility in the market conditions for the oil and gas industry may affect the value of the Company's reserves, restrict its cash flow and its ability to access capital to fund the development of its properties

Recent market events and conditions, including global excess oil and natural gas supply, recent actions taken by the Organization of the Petroleum Exporting Countries ("OPEC"), slowing growth in emerging economies, market volatility and disruptions in Asia, sovereign debt levels and political upheavals in various countries have caused significant weakness and volatility in commodity prices. 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 political and other actions resulting in uncertainty surrounding regulatory, tax, royalty changes and environmental regulation. In addition, the inability to get the necessary approvals to build pipelines, liquefied natural gas plants 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 restrict the Company's cash flow resulting in less funds from operations being available to fund the Company's 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. In addition to possibly resulting in a decrease in the value of the Company's economically recoverable reserves, lower commodity prices may also result in a decrease in the value of the Company's infrastructure and facilities, all of which could also have the effect of requiring a write down of the carrying value of the Company's oil and gas assets on its balance sheet and the recognition of an impairment charge in its income statement. Given the current market conditions and the lack of confidence in the 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.

Prices, Markets and Marketing

Various factors may adversely impact the marketability of oil and natural gas, affecting net production revenue, production volumes and development and exploration activities

Numerous factors beyond the Company's control do, and will continue to, affect the marketability and price of oil and natural gas acquired, produced, or discovered by the Company. The Company's ability to market its oil and natural gas may depend upon its ability to acquire capacity 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 the Company's reserves are from pipelines, railway lines, processing and storage facilities; operational problems affecting pipelines, railway lines and facilities; and 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 and political conditions in the United States, Canada, Europe, China and emerging markets, the actions of OPEC and other oil and gas exporting nations, 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. A material decline in prices could result in a reduction of the Company's net production revenue. 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 Company's reserves. The Company might also elect not to produce from certain wells at lower prices.

All these factors could result in a material decrease in the Company's expected net production revenue and a reduction in its oil and natural gas production, 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, increased growth of shale oil production in the United States, OPEC actions, political uncertainties, 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.

Reserves Replacement

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

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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.

Political Uncertainty

The Company's business may be adversely affected by recent political and social events and decisions made in the United States, Europe and elsewhere

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 2016 presidential campaign 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 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 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.

Gathering and Processing Facilities and Pipeline Systems

Lack of capacity and/or regulatory constraints on gathering and processing facilities and pipeline systems may have a negative impact on the Company's ability to produce and sell its oil and natural gas

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 and 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 or in a reduction of the price offered for the Company's production. The lack of firm pipeline capacity continues to affect the Canadian oil and natural gas industry and limit the ability to transport produced oil and gas to market. In addition, the rationing of capacity on Canadian 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 Canadian production, operations and financial results. As a result, Canadian 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 well as any delays or uncertainty in constructing new infrastructure systems and facilities could harm the Company's business and, in turn, the Company's financial condition, operations and cash flows. In addition, the federal government has signaled that it plans to review the Canadian Energy Regulator approval process for large federally regulated projects. This may cause the timeframe for project approvals to increase for current and future applications.

A portion of the Company's production may, from time to time, be processed through facilities owned by third parties and 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.

Substantial Capital Requirements

The Company's access to capital may be limited or restricted as a result of factors related and unrelated to the Company, impacting its ability to conduct future operations, acquire and develop reserves

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, the Company's ability to do so is dependent on, among other factors:

• the overall state of the capital markets;

• the Company's credit rating (if applicable);

• commodity prices;

• interest rates;

• royalty rates;

• tax burden due to current and future tax laws; and

• investor appetite for investments in the energy industry and the Company's securities in particular.

Further, if the Company's revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access additional financing. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The Company may be required to seek

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additional equity financing on terms that are highly dilutive to existing shareholders. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business financial condition, results of operations and prospects.

Egyptian Operations

Doing business in Egypt subjects the Company to significant political and economic 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.

Abdel Fattah el-Sisi was elected in 2014 President in Egypt following several years of widespread protests, demonstrations and civil unrest. Since this time, political and economic stability has returned to the country leading to a positive impact in business confidence. As a result of this political and economic stability, on November 11, 2016, the International Monetary Fund ("IMF") approved a three-year, USD $12 billion extended arrangement under the Extended Fund Facility ("EFF") with Egypt to support the Egyptian authorities' proposed economic reform.

To date, Egypt has received approximately USD $6 billion in funds from the IMF, with the most recent disbursement occurring in December 2017. The IMF noted that the Egyptian government continued to meet nearly all of its commitments under the program, and that the Egyptian economy was showing encouraging signs of recovery following initial stabilisation.

Although inflation remains high in Egypt, certain economic reform policies have led to Egypt's CPI inflation falling to approximately 21.9% at the end of 2017. However, the IMF has cautioned Egypt not to jeopardize the fight against inflation by easing any economic reforms prematurely. Inflation in Egypt remains highly volatile leading to significant economic impacts over which the Company does not have control, including but not limited to, living costs, operational costs, transportation costs, employment levels, borrowing/lending rates and currency valuation. The Company cannot predict the impact of inflation on 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 by decreasing the Company's profitability, increasing its costs, limiting its access to capital and decreasing the value of its assets.

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 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.

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

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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 significant account receivables 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 receivables balance due from the Egyptian government was 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 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

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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.

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. 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.

Reserves Estimates

The Company's estimated proved and proved plus probable reserves are based on numerous factors and assumptions which may prove incorrect and which may affect the Company

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 document 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 is often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are often 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, GLJ has used forecast prices and costs in estimating the reserves and future net cash flows as set forth in the GLJ 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

Changes to the demand for oil and natural gas products and the rise of petroleum alternatives may negatively affect the Company's financial condition, results of operations and cash flow

Full conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy generation devices could reduce the demand for oil, natural gas and liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen the demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products

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have a similar effect on the demand for oil and gas products. 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 by decreasing the Company's profitability, increasing its costs, limiting its access to capital and decreasing the value of its assets.

Hedging

Hedging activities expose the Company to the risk of financial loss and counter-party risk

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 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.

Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian to United States dollars or other currencies in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to other currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, the Company will not benefit from the fluctuating exchange rate.

Availability of Drilling Equipment and Access

Restrictions on the availability of and access to drilling equipment may impede the Company's exploration and development activities

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

Exploration, Development and Production Risks

The Company's future performance may be affected by the financial, operational, environmental and safety risks associated with the exploration, development and production of oil and natural gas

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 Company's existing reserves, and the production from them, will decline over time as the Company produces from such reserves. A future increase in the Company's reserves will depend on both the ability of the Company to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects. There is no assurance that the Company will be able to continue 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 participation 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 ensure 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, shut‑ins of wells resulting from extreme weather conditions, insufficient storage or transportation capacity or 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 maintains 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.

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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 prepayment provider could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.

Additional Funding Requirements

The Company may require additional financing from time to time to fund the acquisition, exploration and development of properties and its ability to obtain such financing in a timely fashion and on acceptable terms may be negatively impacted by the current economic and global market volatility

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.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The anticipated benefits of acquisitions may not be achieved and the Company may dispose of non-core assets for less than their carrying value on the financial statements as a result of weak market conditions

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.

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

The successful operation of a portion of the Company's properties is dependent on third parties

Other companies operate some of the assets in which the Company has an interest. 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 assets in which the Company has an interest, 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 assets in which the Company has an interest fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations the Company may be required to satisfy such obligations and to seek reimbursement 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 or recovering amounts owing to the Company from such operators for their share of abandonment and reclamation obligations. Any of these factors could have a material adverse effect on the Company's financial and operational results.

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Income Taxes

Taxation authorities may reassess the Company's tax returns

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

Modification to current regulations or implementation of additional regulations may reduce the demand for oil and natural gas and/or increase the Company's costs and/or delay planned operations

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. Recently, the federal government and certain provincial governments have taken steps to initiate protocols and regulations to limit the release of methane from oil and gas operations. Such draft regulations and protocols may require additional expenditures or otherwise negatively impact the Company's operations, which may affect the Company's profitability.

In order to conduct oil and natural gas operations, the Company will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities at the municipal, provincial and federal level. 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, certain federal legislation such as the Competition Act (Canada) and the Investment Canada Act (Canada) could negatively affect the Company's business, financial condition and the market value of its Common Shares or its assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity.

Royalty Regimes

Changes to royalty regimes may negatively impact the Company's cash flows

There can be no assurance that the governments in the jurisdictions in which the Company has assets 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 took effect on January 1, 2017.

Hydraulic Fracturing

Implementation of new regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production volumes, adversely affecting the Company's financial position

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 its reserves.

Disposal of Fluids Used in Operations

Regulations regarding the disposal of fluids used in the Company's operations may increase its costs of compliance or subject it to regulatory penalties or litigation

The safe disposal of the hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is subject to ongoing regulatory review by the federal and provincial governments, including its effect on fresh water supplies and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that may be enacted in response to such review, the implementation of stricter regulations may increase the Company's costs of compliance.

Environmental

Compliance with environmental regulations requires the dedication of a portion of the Company's financial and operational resources

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,

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release or emission of various substances produced in association with 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 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, no assurance can be given that environmental compliance requirements 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.

Carbon Pricing Risk

Taxes on carbon emissions affect the demand for oil and natural gas, the Company's operating expenses and may impair the Company's ability to compete

The majority of countries across the globe have agreed to reduce their carbon emissions in accordance with the Paris Agreement. In Canada, the federal and certain provincial governments have implemented legislation aimed at incentivizing the use of alternatives fuels and in turn reducing carbon emissions. The taxes placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas products and at the same time, increasing the Company's operating expenses, each of which may have a material adverse effect on the Company's profitability and financial condition. Further, the imposition of carbon taxes puts the Company at a disadvantage with its counterparts who operate in jurisdictions where there are less costly carbon regulations.

Liability Management

Liability management programs enacted by regulators in the western provinces may prevent or interfere with the Company's ability to acquire properties or require a substantial cash deposit with the regulator

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 is unable to satisfy its regulatory obligations. These programs involve an assessment of the ratio of a licensee's deemed assets to deemed liabilities. If a licensee's deemed liabilities exceed its deemed assets, a security deposit is generally required. Changes to the required ratio of the Company's deemed assets to deemed liabilities or other changes to the requirements of liability management programs may result in significant increases to the Company's compliance obligations. In addition, the liability management regime may prevent or interfere with the Company's ability to acquire or dispose of assets, 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. The recent Alberta Court of Queen's Bench decision, Redwater Energy Company (Re), found an operational conflict between the Bankruptcy and Insolvency Act and the AER's abandonment and reclamation powers when the licensee is insolvent, which was affirmed by a majority of the Alberta Court of Appeal, and has been appealed by the AER to the Supreme Court of Canada for final determination. In response to the decision, the AER issued interim rules to administer the liability management program until the Government of Alberta can develop new regulatory measures to adequately address environmental liabilities. There remains a great deal of uncertainty as to what new regulatory measures will be developed by the provinces or in concert with the federal government, as the final ruling will become binding in all Canadian jurisdictions.

Climate Change

Compliance with greenhouse gas emissions regulations may result in increased operational costs to the Company

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 signatory to theParis Agreement, which was ratified in Canada on October 3, 2016, the Government of Canada pledged to cut its GHG emissions by 30 per cent from 2005 levels by 2030. One of the pertinent policies announced to date by the Government of Canada to reduce GHG emission is the planned implementation of a nation-wide price on carbon emissions. Provincially, the Government of Alberta has already implemented a carbon levy on almost all sources of GHG emissions, now at a rate of $30 per tonne. The direct or indirect costs of compliance with GHG-related 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 expected that current and future climate change regulations will have the Effect of increasing the Company's operating expenses and in the long-term reducing the demand for oil and gas production resulting in a decrease in the Company's profitability and a reduction in the value of its assets or asset write-offs.

Aboriginal Claims

Aboriginal claims may affect the Company

Aboriginal peoples have claimed aboriginal title and rights in portions of Western Canada. The Company is not aware that any claims have been made in respect of its properties and assets. However, if a claim arose and were to be 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.

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Seasonality and Extreme Weather Conditions

Oil and natural gas operations are subject to seasonal and extreme weather conditions and the Company may experience significant operational delays as a result

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. Roads bans and other restrictions generally result in a reduction of drilling and exploratory activities and may also result in the shut-in of some of the Company's production if not otherwise tied-in. 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. In addition, extreme cold weather, heavy snowfall and heavy rainfall may restrict the Company's ability to access its properties, cause operational difficulties including damage to machinery or contribute to personnel injury because of dangerous working conditions.

Variations in Foreign Exchange Rates and Interest Rates

Variations in foreign exchange rates and interest rates could adversely affect the Company's financial condition

World oil and natural gas prices are quoted in United States dollars. The Canadian dollar to United States dollar and Egyptian pound to United Sates dollar exchange rates, which fluctuate over time, consequently affects the price received by Canadian producers of oil and natural gas. Material increases in the value of the Canadian dollar relative to the United States dollar and Egyptian pound will negatively affect the Company's production revenues. Accordingly, exchange rates between Canada, the United States and Egypt could affect the future value of the Company's reserves as determined by independent evaluators. Although a low value of the Canadian dollar relative to the United States dollar and Egyptian pound may positively affect the price the Company receives for its oil and natural gas production, it could also result in an increase in the price for certain goods used for the Company's operations, which may have a negative impact on the Company's financial results.

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, and Egyptian pound cash balances. The Company prepares its financial statements in United States 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 United States dollars.

To the extent that the Company engages in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which the Company may contract.

An increase in interest rates could result in a significant increase in the amount the Company pays to service debt, resulting in a reduced amount available to fund its exploration and development activities, and if applicable, the cash available for dividends and could negatively impact the market price of the common sharesof the Company.

Litigation

The Company may be involved in litigation in the course of its normal operations and the outcome of the litigation may adversely affect the Company and its reputation

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, relating to personal injuries, including resulting from exposure to hazardous substances, property damage, property taxes, land and access rights, environmental issues, including claims relating to contamination or natural resource damages and contract disputes. The outcome with respect to 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 effect on the Company's financial condition.

Foreign 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.

Cash from Subsidiaries

The Company currently conducts the majority 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.

Market and Trading Price

The trading price of the common shares may be adversely affected by factors related and unrelated to the oil and natural gas industry

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The trading price of securities of oil and natural gas issuers is subject to substantial volatility often based on factors related and 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. In certain jurisdictions, institutions, including government sponsored entities, have determined to decrease their ownership in oil and gas entities which may impact the liquidity of certain securities and may put downward pressure on the trading price of those securities. Similarly, the market price of the common shares of the Company could be subject to significant fluctuations in response to variations in the Company's operating results, financial condition, liquidity and other internal factors. Accordingly, the price at which the common sharesof the Company will trade cannot be accurately predicted.

Commodity 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.

Dividends

The amount of and frequency at which future cash dividends are paid may vary and there is no assurance that the Company will pay dividends in the future

The 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 could be reduced or suspended entirely.

The market value of the common shares may deteriorate if cash dividends are reduced or suspended. Furthermore, the future treatment of dividends for tax purposes will be subject to the nature and composition of dividends paid by the Company and potential legislative and regulatory changes. Dividends may be reduced during periods of lower funds from operations, which result from lower commodity prices and any decision by the Company to finance capital expenditures using funds from operations.

To the extent that external sources of capital, including the issuance of additional common shares, become limited or unavailable, the ability of the Company to make the necessary capital investments to maintain or expand petroleum and natural gas reserves and to invest in assets, as the case may be, will be impaired. To the extent that the Company is required to use funds from operations to finance capital expenditures or property acquisitions, the cash available for dividends may be reduced.

Third Party Credit Risk

The Company is exposed to credit risk of third party operators or partners of properties in which it has an interest

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 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.

Competition

The Company competes with other oil and natural gas companies, some of which have greater financial and operational resources

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.

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Reliance on Key Personnel

Loss of key personnel would negatively impact the Company's operations

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 is 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

Conflicts of interest may arise for the Company's directors and officers who are also involved with other industry participants

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".

Title to Assets

Defects in the title to the Company's properties may result in a financial loss

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 a 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.

Dilution

The Company may issue additional commons shares, thereby diluting current shareholders

The Company may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Company which may be dilutive.

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.

Information Technology Systems and Cyber-Security

Breaches of the Company's cyber-security and loss of, or access to, electronic data may adversely impact its operations and financial position

The Company has become increasingly dependent upon the availability, capacity, reliability and security of its information technology infrastructure and its ability to expand and continually update this infrastructure, to conduct daily operations. The Company depends on various information technology systems to estimate reserve quantities, process and record financial data, manage its land base, manage financial resources, analyze seismic information, administer its contracts with its operators and lessees and communicate with employees and third-party partners.

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 its 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 the Company's efforts to mitigate these emails through education and stringent email filters, these fraudulent activities remain a serious problem that may damage its 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 its business activities or its competitive position. In addition, cyber phishing attempts, in which a malicious party attempts to obtain sensitive information such as usernames, passwords, and credit card details (and money) by disguising as a trustworthy entity in an electronic communication, have become more widespread and sophisticated in recent years. If the Company becomes a victim to a cyber phishing attack it could result in a loss or theft of the Company's financial resources or critical data and information or could result in a loss of control of the Company's technological infrastructure or financial resources. The Company applies technical and process controls in line with industry-accepted standards to protect its information assets and systems; however, these controls may not adequately prevent cyber-security breaches. Disruption of critical information technology services, or breaches of information security, could have a negative effect on the Company's performance and earnings, as well as on its reputation. 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.

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Insurance

Not all risks of conducting oil and natural gas opportunities are insurable and the occurrence of an uninsurable event may have a materially adverse effect on the Company

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.

Management of Growth

The Company may not be able to effectively manage the growth of its business

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 Information

Forward-Looking Information May Prove Inaccurate

Shareholders and prospective investors are cautioned not to place undue reliance on the Company's forward-looking information. By its nature, forward-looking information involves 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 information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Breach of Confidentiality

Breach of confidentiality by a third party could impact the Company's competitive advantage or put it at risk of litigation

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 the Company. Although confidentiality agreements are generally 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.

Actions or Enforcement Judgements

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 (eight out of nine) 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 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.

Cost of New Technologies

The Company's ability to successfully implement new technologies into its operations in a timely and efficient manner will affect its ability to compete

The petroleum industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. Other companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before the Company. There can be no assurance that the Company will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If the Company does implement such technologies, there is no assurance that the Company will do so successfully. One or more of the technologies currently utilized by the Company or implemented in the future may become obsolete. In such case, the Company's business and financial condition and results of operations could be affected adversely and materially. If the Company is unable to utilize the most advanced commercially available technology, or is unsuccessful in implementing certain technologies, its business and financial condition and results of operations could also be adversely affected in a material way.

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Credit Facility Arrangements

Failing to comply with covenants under the Company's credit facility could result in restricted access to capital or being required to repay all amounts owing thereunder

The Company currently has a credit facility and the amount authorized thereunder is dependent on the borrowing base determined by its lenders. The Company is required to comply with covenants under its credit facility which may, in certain cases, include certain financial ratio tests, which from time to time either may 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 Company's credit facility, which could result in the Company being required to repay amounts owing thereunder. The acceleration of the Company's indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the Company's credit facility may impose operating and financial restrictions on the Company that could include restrictions on, the payment of dividends, repurchase or making of other distributions with respect to the Company's securities, incurring of additional indebtedness, provision of guarantees, assumption of loans, making of capital expenditures, entering into of amalgamations, mergers, take-over bids or disposition of assets, among others. Subject to an event of default, the Company's credit facility converts to a demand loan. In the absence of such conversion and upon maturation of the credit facility, the Company has one year from the term date to repay, subject to a credit facility renewal.

The Company's lenders use the Company's reserves, commodity prices, applicable discount rate and other factors to periodically determine the Company's borrowing base. Commodity prices continue to be depressed and have fallen dramatically since 2014, and while prices have recently increased they remain volatile as a result of various factors including actions taken to limit OPEC and non-OPEC production and increasing production by US shale producers. Depressed commodity prices could reduce the Company's borrowing base, reducing the funds available to the Company under the credit facility. This could result in the requirement to repay a portion, or all, of the Company's indebtedness.

If the Company's lenders require repayment of all or a portion of the amounts outstanding under its credit facilities for any reason, including for a default of a covenant or the reduction of a borrowing base, there is no certainty that the Company would be in a position to make such repayment. Even if the Company is able to obtain new financing in order to make any required repayment under its credit facilities, it may not be on commercially reasonable terms or terms that are acceptable to the Company. If the Company is unable to repay amounts owing under credit facilities, the lenders under the credit facilities could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.

Issuance of Debt

Increased debt levels may impair the Company's ability to borrow additional capital on a timely basis to fund opportunities as they arise

From time to time, the Company may enter into transactions to acquire assets or shares of other entities. These transactions may be financed in whole or in part with debt, which may increase the Company's debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, the Company may require additional debt financing that may not be available or, if available, may not be available on favourable terms. Neither the Company's articles nor its by‑laws limit the amount of indebtedness that the Company may incur. The level of the Company's indebtedness from time to time could impair the Company's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Eco-Terrorism Risks

The Company's properties may be subject to terrorist attack

The Company's oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Company's properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. The Company does not have insurance to protect against the risk from terrorism.

Reputational Risk Associated with the Company's Operations

The Company relies on its reputation to continue its operations and to attract and retain investors and employees

Any environmental damage, loss of life, injury or damage to property caused by the Company's operations could damage the Company's reputation in the areas in which the Company operates. Negative sentiment towards the Company could result in a lack of willingness of municipal authorities to grant the necessary licenses or permits for the Company to operate its business and in residents in the areas where the Company is doing business opposing further operations in the area by the Company. If the Company develops a reputation of having an unsafe work site it may impact the ability of the Company to attract and retain the necessary skilled employees and consultants to operate its business. Further, the Company's reputation could be affected by actions and activities of other corporations operating in the oil and gas industry, over which the Company has no control. In addition, environmental damage, loss of life, injury or damage to property caused by the Company's operations caused by the Company's operations could result in negative investor sentiment towards the Company, which may result in limiting the Company's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the common shares.

Changing Investor Sentiment

Changing investor sentiment towards the oil and gas industry may impact the Company's access to, and cost of, capital

A number of factors, including concerns about the effects of the use of fossil fuels on climate change, concerns about the impact of oil and gas operations on the environment, concerns about environmental damage relating to spills of petroleum products during transportation and concerns about indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they are no longer willing to fund or invest in oil and gas properties or companies or are reducing the amount

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thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board, management and employees of the Company. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in the Company or not investing in the Company at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, the Company, may result in limiting the Company's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the common shares.

Expiration of Licenses and Leases

The Company or its working interest partners may fail to meet the requirements of a licence or lease, causing its termination or expiry

The Company's properties are held in the form of licences and leases and working interests in licences and leases. If the Company or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of the Company's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Expansion into New Activities

Expanding the Company's business exposes it to new risks and uncertainties

In the future the Company may acquire or move into new industry-related activities or new geographical areas, may acquire different energy-related assets and as a result may face unexpected risks or alternatively, significantly increase the Company's exposure to one or more existing risk factors, which may in turn result in the Company's future operational and financial conditions being adversely affected.

Additional information on the risks, assumption and uncertainties are found under the heading "Forward-Looking Statements" of this Annual Information Form.

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, 2017. 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, 2017, 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, 2017. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2017, 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, 2017, 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.$
GLJ Petroleum	December 31, 2017	Egypt	—	216.3	—	216.3
Consultants Ltd		Canada	—	133.5	—	133.5
		Total	—	349.8	—	349.8

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:

GLJ Petroleum Consultants Ltd, Calgary, Alberta, dated January 9, 2018.

GLJ PETROLEUM CONSULTANTS LTD
Per:	(signed) "Leonard L. Herchen, P. Eng."
	Leonard L. Herchen, P. Eng.
	Vice President
	GLJ Petroleum Consultants Ltd

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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 6^th day of March, 2018.

Per:	(signed) "Ross Clarkson"	Per:	(signed) "Bob MacDougall"
	Ross Clarkson		Bob MacDougall
	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 6, 2018

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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.

Reporting Responsibilities

• Provide to the Board of Directors proper Committee minutes.

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• 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.

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.

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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.

• 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.

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• 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.