TRANSGLOBE ENERGY CORPORATE PRESENTATION NOVEMBER 2017 TSX:TGL/NASDAQ:TGA

TRANSGLOBE ENERGY CORPORATE PRESENTATION NOVEMBER 2017 TSX:TGL/NASDAQ:TGA

CAUTIONARY STATEMENT The information provided in this presentation is provided as of January 31, 2017 for informational purposes only, is not complete, is based (in part) on information prepared for internal evaluation purposes and may not contain certain material information about TransGlobe Energy Corporation ("TransGlobe", "TGL" or the "Company"), including important disclosures and risk factors associated with the information disclosed in this presentation. This presentation does not constitute an offer to sell or a solicitation of an offer to buy any security in Canada, the United States or any other jurisdiction. The content of this presentation has not been approved or disapproved by any securities commission or regulatory authority in Canada, the United States or any other jurisdiction, and TransGlobe expressly disclaims any duty to make disclosure or any filings with any securities commission or regulatory authority, beyond that imposed by applicable laws. See "Cautionary Statements" beginning on slide 21 for other important disclosures regarding forward looking information, future orientated financial information and other financial matters, oil and gas information and other important information. 2

ABOUT TRANSGLOBE Over 20 years of history as an International Oil and Gas Company Strong track record with proven abilities in development drilling and reservoir management Operations in Egypt began in 2004 Averaged 12.3 MBopd in Q3-2017 29.3 MMbl 2P Gross Reserves (18.3 MMbl 1P Gross) (12/31/16) 1 Re-entry to Canada in December 2016 Averaged 2.6 MBoed in Q3-2017 20.7 MMboe 2P Gross Reserves (9.0 MMboe 1P Gross) (12/31/16) 1 Management focus is on cash flow and building shareholder value over the long term Stock price recovery has lagged oil price recovery Have continuously operated in 3 jurisdictions over the past 20 years Drilled over 400 gross wells in Canada, Egypt and Yemen Produced over 50 million WI barrels equivalent during past 20 years in Canada, Egypt and Yemen Extensive development (Canada and Egypt) and exploration portfolio (Egypt) 1. Based on D&M evaluation effective 12/31/16. See Cautionary Statements "Oil and Gas Information". 3

VALUE PROPOSITION AND GO-FORWARD PLAN 2 Enterprise Value to 2P reserves of ~$2.12/boe 1,2,3 Enterprise Value to 2017E mid-point production of ~$6,890 boepd Diversified production base ~16,000 boepd (mid-point of guidance) High working interest, oil-focused operated assets torqued to commodity price recovery ~ 95% Oil & Liquids Egypt Near Term Catalysts (2017) WB K Field development/acceleration WG optimization/development NWG development Medium Term Catalysts (2018+) WB acceleration NWG full development Western Desert exploration in NWS and SG New acquisition in Egypt or region Canada Near Term Catalysts (2017) Cash flow and growth of Canadian Assets Initial drilling of 3 horizontal oil wells Medium Term Catalysts (2018+) Expand Cardium resource footprint through synergistic acquisitions Ramp-up Cardium HZ drilling program Unlock and develop Ellerslie HZ potential Focused on building a diversified, profitable and growth oriented International Portfolio 1. EV calculated as current Market Capitalization plus Current Liabilities plus Debt less A/R, Cash and Current Estimated market value of crude inventory 2. Based on D&M evaluation effective 12/31/16. 3. See Cautionary Statements "Forward-Looking Statements and Information". 4

2017 Q3 FINANCIAL HIGHLIGHTS Sales volumes averaged 18,020 boepd* and production volumes averaged 14,912 boepd* Positive funds flow from operations of $19.2 MM ($0.27/share) Net loss of $6.9 MM (-$0.09/share), which includes a $10.3 MM non-cash impairment loss and a $3.2 MM unrealized derivative loss on commodity contracts Operating expense averaged $9.36/Bbl in Egypt and $5.26/Boe in Canada G&A costs averaged $2.78/Bbl on a produced barrel basis Spent $10.1 MM on capital expenditures Ended quarter with $26.3 MM in cash and cash equivalents (includes restricted cash) and $58.8 MM in working capital Inventoried entitlement oil of ~1.0 MM Bbls at the end of the quarter, with the next lifting scheduled for November * 6 Mcf to 1 Boe 5 Q3 '17 Q3 '16 Change % Production and Sales Egypt Oil Sold Bpd 15,376 11,485 34% Egypt Oil Produced Bpd 12,268 11,733 5% Canada Oil Bpd 518 n/a n/a Natural Gas Mcfd 6,268 n/a n/a NGLs Bpd 1,081 n/a n/a Revenue Egypt Oil $/Bbl $44.82 $34.43 30% Canada Oil $/Bbl $44.91 n/a n/a Natural Gas $/Mcf $1.65 n/a n/a NGLs $/Bbl $18.90 n/a n/a Operating Expenses Egypt $/Bbl $9.36 $10.36-10% Canada (1) $/Boe (2) $5.26 n/a n/a G&A Expenses Gross $MM $2.54 $4.12-38% Sold Boe $/Boe $2.30 $3.87-41% Produced Boe $/Boe $2.78 $3.79-27% Egypt Crude Oil Inventory Ending Balance MMBbls 0.99 0.73 35% Equivalent Months (3) Months 5.89 4.43 33% Funds Flow from Operations $MM $19.2 $2.3 719% Net Income $MM -$6.9 -$25.4 73% (1) Includes transportation costs (2) Mcf converted at a ratio of 6:1 for purposes of calculating Boe (3) Months production is calculated based on last month in period.

2017 KEY FINANCIAL FOCUS AREAS AND GUIDANCE Full year Capital Budget estimated at ~$41 MM Production for 9 months averaged 16,050 Boed, within the guidance of 15,500 to 16,500 Boepd* Continued focus on increasing frequency of selling our entitlement barrels in Egypt One cargo lifting in September for proceeds of $21.5 MM One additional lifting scheduled for November Sold ~350,000 bbls to EGPC for $14.9 MM during the quarter, to provide funding for Egypt based expenditures Egypt crude oil inventory reduced to just under one million barrels as of September 30 th Awaiting 2018 lifting schedule Heavy differentials have shown improvement in 2017 over 2015-2016. Differentials for Gharib Blend to Brent have been <$10 for the last two quarters Repaid $5.0 MM of the amount outstanding under the $75 MM prepayment agreement * 6 Mcf to 1 Boe 6

BALANCE SHEET SUMMARY TransGlobe has a strong balance sheet with a cash position of ~US$26.2 MM @ September 30 th, 2017 (inclusive of restricted cash) Simple capital structure US$75 MM Prepayment Agreement from Mercuria Energy Trading S.A. C$30 MM Reserve-based lending facility (C$13.9 MM drawn) Repaid $5.0 MM of the amount outstanding under the prepayment agreement Shares Outstanding (30/09/17) ~72.2 MM Market Capitalization (9/11/17) Debt (Prepay Agreement + Canadian RBL) 1 Working Capital (30/09/17) 2 Excluding Crude Inventory Estimated Market Value of Inventoried Crude Oil of 1.00 MMbbls @ $44.82 3 Enterprise Value 4,5 US$109.0 US$79.8 US$45.5 US$44.3 US$99.0 1. Estimated US$ value of Prepay Agreement of US$75MM and $11MM for Canadian RBL 2. Current Assets (including cash and cash equivalents) minus Current Liabilities, excludes crude inventory 3. Estimated value of crude oil inventory is based on average realized price of Gharib blend for Q3 sales and inventoried crude oil as at 30/09/17 4. Enterprise value calculated as Market Capitalization + Long term debt Working capital (Current Assets - Current Liabilities) Market Value of Inventoried Crude Oil 5. See Cautionary Statements "Forward-Looking Statements and Information" 7

Production (boepd) DAILY PRODUCTION 1 20,000 TRANSGLOBE TOTAL DAILY Released Service Rig New Service Rig 15,000 10,000 Canada 5,000 NWG West Bakr West Gharib 0 Oct-16 Dec-16 Feb-17 Apr-17 Jun-17 Aug-17 Oct-17 Q3-2017 YTD 2017 2017 GUIDANCE 1 Egypt 12.3 MBopd 13.3 MBopd ~13.0 13.8 MBopd Canada 2.6* MBoepd 2.7* MBoepd ~2.5 2.7 MBoepd Total Company 14.9* MBoepd 16.0* MBoepd ~15.5 16.5 MBoepd * 6 Mcf to 1 Boe 1. See Cautionary Statements "Forward-Looking Information and Statements" and "Oil and Gas Information". 8

2016 YEAR-END RESERVES SUMMARY 1 2016 Reserves Summary 1P 2P 3P 2015 Year End Reserves (MMbbl) 17.5 28.7 39.9 2016 Adds/Revisions 5.1 5.0 4.6 Canadian Acquisition (MMBoe) 11.7 20.7 25.8 2016 Production (4.4) 2016 Year End Reserves (MMBoe) 29.9 50.0 65.9 Change vs Year End 2015 (%) 71% 74% 65% Production Replacement Ratio (%) pre acquisition 70 60 50 40 30 20 10 0 2015 Year End Reserves (mmbbl) 2016 Year End Reserves (mmbbl) 116% 114% 105% 1P 2P 3P Reserve Category Total proved plus probable ( 2P ) gross reserves increased 74% from year-end 2015 to 50.0 MMboe noting the following: Canadian acquisition added 20.7 MMboe of gross 2P reserves net of production including 46 BCF 2P of conventional natural gas Positive technical additions of 5.0 MMbbls of gross 2P reserves primarily attributed to the Arta Red Bed pool performance/simulation results and performance at West Gharib, West Bakr Replaced 114% of 2016 production (~4.4 MMboe), pre Canadian acquisition At year-end 2016, 2P reserves were comprised of 59% Egypt medium/ heavy oil, 15% Canada conventional natural gas, 16% Canada natural gas liquids and 10% Canada light oil 1. Based on D&M evaluations effective 12/31/15 and 12/31/16. See Cautionary Statements "Oil and Gas Information". 2. 6:1 BOE MCF. 9

INVESTMENT HIGHLIGHTS - EGYPT 1.075 Million gross acres of land 6 PSCs in Egypt (100% WI) Q3-2017 production 12.3 MBopd Gross 2P reserves of 29.3 mmbbl (12/31/16) 1 AT NPV10 of 2P reserves of $260.2 million 1 New developments in NWG 2017 Exploration & Development focus In Eastern Desert, complete NWG exploration program and develop NWG discoveries In Western Desert, acquired 600km 2 3-D seismic in North West Sitra South Alamein (100%) Exploration & Development NW Sitra (100%) Exploration South Ghazalat (100%) Exploration CAIRO West Bakr (100%) NW Gharib (100%) Appraisal Development Growth Underway West Gharib (100%) 1. See Cautionary Statements Oil and Gas Information ; Based on D&M evaluation effective 12/21/16. 10

WEST GHARIB/WEST BAKR/NWG: 100% WI - OPERATED Eastern Desert Production Q3-2017 average rate 12.6 MBopd 2017 YTD average rate 13.3 MBopd 2017 Plan 1 Develop/appraise NWG discoveries Integrate NW Gharib operations into established Joint Venture leveraging operating best practices and utilizing existing infrastructure Received approval on NWG development leases ( DL ) 2, 3 & 4 during September. Initial production Q4-2017/Q1-2018 WB facility optimization and production growth 1. See Cautionary Statements "Forward-Looking Information and Statements" 11

NW GHARIB EXPLORATION & DEVELOPMENT NW Gharib Development Lease-4 DL #1 NWG-3X: Production ~575 Bopd NWG-38A: Production ~550 Bopd NWG-27A-1ST-1 C.I.=100ft NWG-38A-1: Production ~340 Bopd NWG-26AST-1 NWG-27A NWG-3AST-1 is P&A NW Gharib Development Lease-1 NWG-3AST-1 NWG-16X NWG-3X NWG-38A-1 NWG-38A NWG-38A-2 NWG-38A-2 currently drilling DL #4 Received development lease approval Legend Develop. Loc. Oil Well P&A 12

NWG DL - 2 & NWG DL - 3 NW Gharib Development Lease-2 NWG-1X NWG-1A Arta Field C.I.=100ft DL 2 & 3 have received development lease approval NWG-1X: Producing ~90 Bopd NWG-5B: Producing ~210 Bopd 400m boundary exclusion area can now be accessed for additional drilling NWG-5B NWG-5X NW Gharib Development Lease-3 Legend Develop. Loc. Oil Well P&A 13

EGYPT ASSETS: WESTERN DESERT Three operated 100% WI concessions (1.03 million acres) Map & evaluate the South Ghazalat 3-D (400 km 2 ) NW Sitra 3-D seismic acquisition program completed Q1-2017 (600 km 2 ) Finalize prospect inventory for 2018 drilling @ NW Sitra, and S. Ghazalat 14

Working Interest Production (boe/d) Producing Well Count TRANSGLOBE CANADIAN ASSET PORTFOLIO Canadian Lands Historic Production 7,000 6,000 5,000 4,000 3,000 2,000 1,000-180 160 140 120 100 80 60 40 20 0 Land Position: 77,000 net acres (87,000 gross acres) Production: 2.6 MBoepd 1 (Q3/17) (58% liquids-weighted) 2P Reserves: 20.7 MMBoe 2,3 (41% liquids-weighted) Producing Gross Locations 4 Wells Boepd 2P Unbooked Cardium 37 751 22 46 Ellerslie/Mannville 61 1,419 25 54 Other 22 612 2 Total 120* 2,782 49 100 *Of which 82 are HZ wells 1. Average production for January 2017. 2. See Cautionary Statements Oil and Gas Information ; All reserves and net present value estimates in respect of the Canadian acquisition based on D&M evaluation effective 12/31/16. 3. See Cautionary Statements "Forward-Looking Information and Statements". 4. Booked drilling locations based on D&M evaluation effective 12/31/16. Potential unbookeddrilling opportunities based on TransGlobe internal estimate prepared in accordance with the COGE Handbook by a non-independentqualified reserves evaluator. See Cautionary Statements "Oil and Gas Information". 15 Oil (bbl/d) Natural Gas Liquids (bbl/d) Gas (boe/d) Producing Well Count (Gross) Zero wells drilled on acquired lands over past 3 years Last Cardium HZ drilled in 2013 2017 drilling program (3 HZ) completed in Q3 Production can be increased materially through development of existing locations 3

CARDIUM LOCATIONS HARMATTAN CORE AREA Crown Rights Freehold Rights 2017 Drills Proved Locations Probable Locations Other locations 39 Cardium (mile-long) HZ wells on TransGlobe lands 36 drilled in 2012-2013 Average fracs = 18 per well Industry standard is now 30+ per well 17 PUD s, 5 probable locations assigned 1 3 Cardium HZ wells drilled July/August 2017 and completed September/October with 40 stage (15 t/stage) on 1 mile HZ s New wells placed into production mid-october Acquired 1,600 acres of Cardium rights at Crown Land sales 1. See Cautionary Statements Oil and Gas Information ; Booked drilling locations based on D&M 12/31/2016 evaluation. 16

INITIAL WELL RESULTS *Early days as wells still recovering frac fluids and cleaning up. Wells also experiencing temporary down time during this initial period due to servicing and tie-in activities 02/15-14: 11 Days production data. Avg. 244 Boe/d. Well flowed to surface from Oct. 16 26 th prior to loading up. Presently undergoing installation of production wellhead, rods and pump. Water cut currently <5%. 03/16-14: 12 Days production data. Avg. 207 Boe/d, Oct. 26 Nov 5 th. Water cut currently ~10%. 02/1-11: 13 Days production data. Avg. 122 Boe/d, Oct. 22 Nov 3 rd. Pressure communication was observed in an offset well during completion. Water cut currently ~ 40%. P10 P90 * There are no assurances that the early time production presented is representative of long term performances 17

SUMMARY Well Positioned to Grow Production base of ~16,000 Boepd* Inventory of low-risk development growth in Canada and Egypt, plus highimpact exploration in Egypt High working interest in largely operated assets Scalable growth in a rising commodity price environment Actively seeking acquisitions in Egypt and region Share price has lagged oil price recovery * 6 Mcf to 1 Boe 18

CAUTIONARY STATEMENTS Forward-Looking Information and Statements Certain information regarding TransGlobe set forth in this document contains forward-looking information or statements (collectively, "forward-looking statements") that involve substantial known and unknown risks and uncertainties. The use of any of the words "plan", "expect", prospective, "project", "intend", "believe", "should", "anticipate", "estimate" or other similar words, or statements that certain events or conditions "may" or "will" occur are intended to identify forward-looking statements. Such statements represent TransGlobe's internal projections, estimates or beliefs concerning, among other things, future growth, commodity price forecasts, diversification, results of operations, reserves (including estimated recoveries), plans for and results of drilling activities, production, future capital and other expenditures, business prospects and opportunities and other matters. These statements are only predictions and actual events or results may differ materially. Although the Company s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause TransGlobe's actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, TransGlobe. In particular, forward-looking statements contained in this document include, but are not limited to plans for and results of the prepayment agreement and repayment of the convertible debentures; terms of the prepayment agreement and marketing agreement; anticipated drilling and completion plans; exploration and development activities and estimated costs of the foregoing; 2017 production; TransGlobe's plans for future acquisitions; potential results and production from future developments; capital expenditure estimates; reserves estimates (including estimated recoveries); the anticipated benefits of third party processing arrangements; anticipated trends in drilling and completion costs and related savings; expected reduction of geological risk exposure; anticipated decline rates and the resulting benefits; and realization of the anticipated benefits of diversification. Statements relating to "reserves" and "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation; loss of markets; economic and political instability, volatility of commodity prices, currency and interest rate fluctuations, imprecision of reserve and resource estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; the impact of general economic conditions; industry conditions including changes in laws and regulations including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; risks related to obtaining required approvals of regulatory authorities; risks associated with negotiating with governments; changes in income tax laws, tax rates and/or incentive programs relating to the oil industry; changes to pipeline capacity; ability to access sufficient capital from internal and external sources; failure of counterparties to perform under the terms of their contracts; incorrect assessment of the value of acquisitions; and other factors, many of which are beyond the control of the Company. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could effect TransGlobe's operations and financial results are included in reports on file with Canadian and United States securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or the EDGAR website at and www.sec.gov/edgar.shtml. Although the forward-looking statements contained in this document are based upon assumptions which management believes to be reasonable, the Company cannot guarantee that actual results will be consistent with these forward-looking statements. With respect to forward-looking statements contained in this document, TransGlobe has made assumptions regarding, among other things: current commodity prices and royalty regimes; availability of skilled labour; future growth; timing and amount of capital expenditures; future currency, exchange and interest rates; future commodity prices; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; receipt of partner, regulatory and community approvals; royalty rates; future operating costs; effects of regulation by governmental agencies; uninterrupted access to areas of TransGlobe's operations and infrastructure; recoverability of reserves and future production rates; timing of drilling and completion of wells; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company and Mercuria to successfully market and receive payment for its oil and natural gas product; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; that TransGlobe will benefit from diversification; that TransGlobe 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 TransGlobe's conduct and results of operations will be consistent with its expectations; that TransGlobe will have the ability to develop its oil and gas properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that TransGlobe will be able to fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; and other matters. Management has included the above summary of assumptions and risks related to forward-looking information provided in this document in order to provide investors with a more complete perspective on TransGlobe's current and future operations and such information may not be appropriate for other purposes. TransGlobe's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits TransGlobe will derive. These forward-looking statements are made as of the date of this document and TransGlobe disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified by this cautionary statement. 19

CAUTIONARY STATEMENTS FOFI and Other Financial Matters This document also contains future oriented financial information ("FOFI") within the meaning of applicable securities laws, including but not limited to the information regarding future capital expenditures, estimated working capital, internal rates of return, net present value, payout, recycle ratio, and finding and development costs set forth on slides "2017 Operational Plan", "Canada Type Curve Economics C$" and "Balance Sheet Summary". The FOFI has been prepared by TransGlobe s management to provide an outlook of the Company's activities and results. The FOFI has been prepared based on a number of assumptions including those set forth in the presentation, the assumptions discussed above and assumptions with respect to the costs and expenditures to be incurred by the Company, capital equipment and operating costs, foreign exchange rates, taxation rates for the Company, general and administrative expenses and the prices to be paid for the Company's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results will likely vary from the amounts set forth in the analysis presented in this presentation, and such variation may be material. The Company and its management believe that the FOFI has been prepared on a reasonable basis, reflecting the best estimates and judgments, and represent, to the best of management's knowledge and opinion, TransGlobe's expected expenditures and results of operations. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, TransGlobe undertakes no obligation to update such FOFI and forward-looking statements and information. 20

CAUTIONARY STATEMENTS Oil and Gas Information The estimates of TransGlobe's December 31, 2016 reserves set forth in this presentation have been prepared by DeGolyer and MacNaughton Canada Limited ("D&M"), an independent qualified reserves evaluator, as of December 31, 2016 in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluations Handbook (the "COGE Handbook" or "COGEH") and using D&M's forecast prices and costs as at December 31, 2016. The estimates of TransGlobe's December 31, 2015 reserves set forth in this presentation have been prepared by D&M as of December 31, 2015 in accordance with NI 51-101 and COGEH and using D&M's forecast prices and costs as at December 21, 2015. All of TransGlobe's reserves disclosed herein are heavy crude oil/medium crude oil/light crude oil, conventional natural gas or natural gas liquids. Light crude oil is crude oil with a relative density greater than 31.1 degrees API gravity, medium crude oil is crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity, and heavy crude oil is crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity. "Proved" or "1P" 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. "Probable" or "2P" 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. Estimates of the net present value of the future net revenue from TransGlobe's reserves do not represent the fair market value of such reserves. The estimates of reserves and future net revenue from individual properties or wells may not reflect the same confidence level as estimates of reserves and future net revenue for all properties and wells, due to the effects of aggregation. In this presentation NPV10 represents the net present value of net income discounted at 10%. The NPV estimates are net estimates and are prepared after the deduction of royalties and abandonment and reclamation costs. This presentation contains certain oil and gas metrics, including F&D, recycle ratios, production replacement ratio, reserve life index and internal rates of return ("IRR"), which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. A summary of the calculations of such metrics are as follows: F&D is calculated as exploration and development costs incurred in the year adjusted for the change in estimated future development costs. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Recycle ratio is calculated by dividing the netback by the proved and proved plus probable finding and development cost on a per Bbl basis Reserve life index is calculated as 2P reserves divided by production at 3,100 Boepd, Sept 2016 Production replacement ratio is calculated as reserve additions (excluding the Canadian acquisition) during the year divided by the annual production. IRR is calculated as the discount factor applied to future cash flows at which the NPV is calculated to be zero Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Bbl of production "BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (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. 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. The recovery and reserve estimates of reserves provided in this document are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. 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 royalties, development costs, production costs, well abandonment costs and estimated future capital expenditures for wells to which reserves have been assigned. Certain information in this document may constitute "analogous information" as defined in NI 51-101. Such information includes production estimates, drilling results, test rates, reserves estimates and other information retrieved from the continuous disclosure record of certain industry participants from www.sedar.com, AccuMap or other publically available sources. Management of TransGlobe believes the information is relevant as it may help to define the reservoir characteristics and production profile of lands in which TransGlobe may hold an interest. TransGlobe is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor and is unable to confirm that the analogous information was prepared in accordance with NI 51-101. Such information is not an estimate of the production, reserves or resources attributable to lands held or to be held by TransGlobe and there is no certainty that the production, reserves or resources data and economic information for the lands held or to be held by TransGlobe will be similar to the information presented herein. The reader is cautioned that the data relied upon by TransGlobe may be in error and/or may not be analogous to such lands held or to be held by TransGlobe. Certain other information contained in this presentation has been prepared by third-party sources, which information has not been independently audited or verified by TransGlobe. No representation or warranty, express or implied, is made by TransGlobe as to the accuracy or completeness of the information contained in this document, and nothing contained in this presentation is, or shall be relied upon as, a promise or representation by TransGlobe. 21

CAUTIONARY STATEMENTS This presentation discloses drilling locations that have associated proved and/or probable reserves based on D&M 12/31/2016 evaluation prepared in accordance with NI 51-101 and the COGE Handbook and using D&M pricing forecasts as at 12/31/2016. 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. Unbooked locations have been identified by management 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 is ultimately dependent upon the availability of capital, 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. Certain type curves referred to in this document represent estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves disclosed herein are management-generated type curves based on a combination of historical performance of older wells and management's expectation of what might be achieved from future wells. The type curves represent what management thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. Defined Terms MM PSCs WI Bbl Bopd or bopd MMBbl Mcf MMcf MMBoe Boepd 1P PDP PU 2P millions of dollars production sharing contracts. working interest barrels barrels of oil per day million barrels thousand cubic feet million cubic feet million barrels of oil equivalent barrels of oil equivalent per day proved reserves proved developed producing reserves proved undeveloped reserves proved plus probable reserves 22

APPENDIX

Netback ($/boe) Netback ($/bbl) Netback ($/bbl) 2017 NETBACK GUIDANCE $25 $20 $15 $10 $5 $0 $60 $40 $20 $0 $10 $8 $6 $4 $2 $0 Egypt (US$) $22.14 $17.65 $13.16 $8.67 $4.18 $40 $50 $60 $70 $80 Brent Canada - Oil (US$) $53.50 $45.50 $37.50 $29.50 $21.50 $40 $50 $60 $70 $80 WTI Canada - Gas/NGLs (US$) $9.41 $7.24 $5.07 $2.89 $0.72 $40 $50 $60 $70 $80 WTI Egypt Assumptions: Using anticipated 2017 Egypt production profile Ras Gharib price differential estimate of $10.00 per bbl applied consistently at all price points Opex estimated at ~$9.30/bbl Maximum cost recovery resulting from accumulated cost pools Canada Assumptions: Using anticipated 2017 Canada production profile Edmonton Light to Harmattan discount = C$2.83/bbl Opex estimated at C$8.00/boe Aeco gas price C$1.25/mmbtu for $40 WTI and increases C$0.50/mmbtu for every $10/bbl WTI Edmonton Light = $3.25 off of WTI NGL mixture price = 40% of Edmonton Light Takes into consideration Canadian tax pools 24

Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 $1,000 s (A/R) / 10 s Bbls (Inventory) OIL MARKETING TransGlobe began marketing its own entitlement oil in January 2015 Marketing improved liquidity and decreased credit risk - 30 day payment in US$ from date of cargo sailing Marketed 10.5 cargo liftings in the last 33 months 1 additional scheduled for 2017 Signed long term marketing agreement (in conjunction with Prepayment Agreement) with Mercuria on Feb 10/17 On-going discussions with EGPC to improve lifting frequency Egypt Accounts receivable and Inventory 300,000 12 250,000 10 200,000 150,000 8 6 Months 100,000 4 50,000 2 0 0 Accounts Receivable Crude Inventory Equivalent Months of Production in Inventory Months in AR 25

NET PRESENT VALUE OF FUTURE NET REVENUE 1 Before Deducting Future Income Taxes Discounted At After Deducting Future Income Taxes Discounted At Effective December 31, 2016 0% 5% 10% 15% 20% 0% 5% 10% 15% 20% (MM$) Proved Canada 119.0 75.5 52.3 38.5 29.7 118.4 75.3 52.2 38.5 29.6 Egypt 2 207.6 181.1 160.5 144.2 130.9 207.6 181.1 160.6 144.2 130.9 Total Proved 326.6 256.6 212.8 182.7 160.6 326.0 256.4 212.8 182.7 160.6 Proved Plus Probable Canada 240.8 134.5 85.5 58.9 42.8 207.2 120.0 78.2 54.8 40.4 Egypt 2 372.1 307.3 260.2 225.0 197.8 372.1 307.3 260.2 225.0 197.8 Total Proved Plus Probable 613.0 441.8 345.7 283.9 240.6 579.3 427.3 338.4 279.8 238.2 Proved Plus Probable Plus Possible Canada 368.5 185.1 114.3 78.6 57.6 300.3 157.3 99.8 69.9 51.9 Egypt 2 521.8 408.7 333.2 280.3 241.4 521.8 408.7 333.2 280.3 241.4 Total Proved Plus Probable Plus Possible 890.4 593.8 447.5 358.8 299.0 822.1 566.0 433.0 350.1 293.3 1. Based on D&M evaluation effective 12/31/16 2. Egyptian taxes are paid from the Governments share of production, therefore the Company s share is always after tax 26

CANADA: CORNERSTONE ACQUISITION Acquired Canadian Cardium Light Oil and Liquids-Rich Gas Production Dec 20 th, 2016 Stable geopolitical environment with favourable tax structure and attractive royalty regime Purchase price of ~US$60 Million (C$80 Million) September 2016 average production of ~3,100 Boepd (57% oil and NGLs) Acquisition metrics C$25,806/Boed Acquisition Adds Low-Risk Development Upside Well defined Cardium drilling locations provide for significant production and cash flow growth for the foreseeable future Access to surplus infrastructure capacity to accommodate production growth Current asset decline rate of ~12% provides stable production platform 149 gross potential drilling opportunities identified on acquired assets (49 booked, 100 unbooked) 1 Significant liquids-rich Ellerslie gas opportunity exists on acquired lands Acquisition Adds Material Reserves and Significantly Increases Reserve Life and NAV Identifiable growth supported by offsetting production in proven plays Gross 2P Reserves of 20.7 Mmboe 2 Reserve life index of 18.3 years 2 After Tax 2P NPV10 of US$78.2MM 2 Acquisition metrics C$3.76/2P Boe 1. Booked drilling locations based on D&M evaluation effective 12/31/16. Potential unbooked drilling opportunities based on TransGlobe internal estimate prepared in accordance with the COGE Handbook by a nonindependent qualified reserves evaluator. See Cautionary Statements "Oil and Gas Information". 2. See Cautionary Statements Oil and Gas Information. All reserves and net present value estimates in respect of the Harmattan assets based on D&M evaluation effective 12/31/16 27

CARDIUM PRIMER The Cardium formation has produced hydrocarbons in central Alberta for over 60 years; and is one of the most prolific hydrocarbon resource deposits in the Western Canada Sedimentary Basin Although conventionally produced since the 1950 s recent advances in horizontal drilling and multi-stage fracking have allowed producers to drill economic wells in increasingly tighter portions of the play In areas where the Cardium is developed it is often found stacked with multiple other potentially producible formations such as the Viking and Ellerslie There are currently ~10,000 producing wells (of which ~3,900 are horizontal wells) September total Cardium production in Alberta was ~207,289 boep/d (not including NGL yields) 1 71,295 bbl/d oil 136 Mmcf/d gas Wells depths in the range of 2,000 to 2,300 metres Approximate location of acquired lands West Central Alberta Stratigraphic Chart with highlighted target formations present on acquired lands. Additional potential and production from the deeper Elkton and Wabamun 1. Production estimates for the month of September, 2016 based on Accumap data. Values reported are raw production and values and do not include Natural Gas Liquid yields or associated Natural Gas shrinkage. 28

EXECUTIVES AND DIRECTORS Robert G. Jennings - Director, Chairman Ross G. Clarkson - Director, President and CEO Lloyd W. Herrick - Director, VP and COO Fred J. Dyment - Director Susan MacKenzie Director David Cook - Director Bob MacDougall Director Matthew Brister Director Steve Sinclair - Director Randy C. Neely - VP, Finance and CFO Brett Norris - VP, Exploration 29

ANALYST COVERAGE Rita Guindy, Arqaam Capital, Cairo, Egypt Jenny Xenos, Canaccord Genuity, Calgary, Canada Caroline Berzi, CI Capital, Giza, Egypt Darren B. Engels, GMP First Energy, Calgary, Canada Al Stanton, RBC Capital Markets, London, UK Gavin Wylie, Scotia Capital Inc., Calgary, Canada 30

For additional information contact us at: Phone: +1 (403) 264 9888 Email: investor.relations@trans-globe.com Or visit: www.trans-globe.com