Corporate Presentation August 2018 AIM & TSX:TGL NASDAQ:TGA
Cautionary Statement The information provided in this presentation is provided as of August, 2018 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, TGA 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, the United Kingdom 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, the United Kingdom 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 29 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
Overview Focused on building a diversified, profitable and growth oriented international portfolio Significant operational experience Founded 20+ years ago Established production in Egypt and Canada FY 2018 production guidance 14.2-14.8 Mboepd (see cautionary statements in appendix to presentation) Strong balance sheet and cash flow generation 1H funds flow of $37.4MM Unique opportunity to grow in Egypt and surrounding region Management team actively seeking acquisition opportunities Growth underpinned by resource base Gross 2P reserves of 45.9MMboe (Based on GLJ evaluation dated 12/31/17. See Cautionary Statements "Oil and Gas Information ) 3
Health, Safety, Environment & Social Responsibility Performance HSESR is a fundamental component of how TransGlobe Operates 25 20 15 10 5 2013-2018 Road Traffic Accidents ( RTA ) 2013-2018 Total Recordable Cases ( TRC ) 2013-2018 RTA's 2013-2018 TRC's 30 21 25 19 25 19 14 20 16 16 11 15 12 6 10 4 6 5 0 2013 2014 2015 2016 2017 2018 0 2013 2014 2015 2016 2017 2018 - TGL implemented a formal HSES management system in 2014 in accordance with IFC guidelines - TGL formed an independent HSE board committee in 2015 (combined with Reserves and HSES committee in 2016) - TGL has made significant progress on several HSES key performance indicators - The gains in HSES were achieved during a period of low oil prices and reduced investment, while maintaining production and completing a robust exploration program in both the eastern and western desert areas of Egypt - Canadian operations have been incident free since acquisition in 2016 4
$US/Share 1H Results: Strong cashflow from existing asset base 14,076 boepd Production $37.4MM Funds flow $10.5MM Capex $1.7MM 1 Net debt 6 5 4 SHARE PRICE Announced intention to list on AIM Admission to AIM 3 $0.035/sh 2 Dividend declared 2 1 0 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 1. Long term debt (including the current portion) plus working capital 2. Dividend declared of $0.035 USD/share * 72,205,369 shares outstanding 5
A unique position in Egypt Focused on building a diversified, profitable and growth oriented international portfolio Best-in-class operator in Egypt with 20+ years Int l experience Strong relationship with government 100% Working interest and operator Ability to market 100% of entitlement crude Virtually zero receivables Poised for organic growth via infill drilling and exploration Uniquely networked to identify M&A opportunities 6
Near-Term Strategy Inventory of low-risk development growth in Egypt and Canada, plus exploration in Egypt Drilling to maintain production base Egypt 8 development wells in 2018 (YTD 7 oilwells drilled) Canada 6 Hz development wells in 2018 (YTD 2 hz oilwells drilled) Exploration potential Egypt 2 Exploration wells in 2H in Western Desert Canada 1 Hz appraisal well in Harmattan South Cardium trend Pursuing value-accretive growth opportunities Actively seeking acquisitions in Egypt and region, and Canadian land acquisitions Excellent in-country relationship screening for M&A opportunities in Egypt and region Uniquely positioned for M&A among peer group - capable of a deal in the 100MM+ range without being significantly leveraged Seeking the under-loved and under-developed opportunities (akin to West Gharib, West Bakr and Harmattan) 7
Near-Term Value Milestones - Egypt Egypt Near-Term Catalysts (2018) 8 well development program - 4 in West Bakr, 2 in NW Gharib and 2 in West Gharib Western Desert exploration in NWS and SG - 2 exploration wells in Q3 & Q4 Test one additional prospect in South Ghazalat and one in NW Sitra South Alamein contract extension (drilling subject to approvals) Medium-Term Catalysts (2019+) Accelerate Eastern Desert work program to develop producing concessions Subject to negotiation with and approval from the Egyptian government - Consolidate and extend Eastern Desert existing (3) concessions into one concession to improve efficiencies and increase reserve recovery from known oil pools through enhanced recovery techniques (Hz multi stage fracs, Infill drilling, Tertiary recovery) Western Desert exploration Acquisition in Egypt or region Maintain Eastern Desert production and progress Western Desert exploration program 8
USD $MM Near-Term Value Milestones - Canada Canada Delivering value Acquired December 2016 for US$60 million 2P NPV10 increased 57% Near-Term Catalysts (2018) Cash flow growth of Canadian assets New generation of Cardium completion results Evaluate newly acquired (2018) Cardium trend lands in South Harmattan Drilling of 6 net horizontal oil wells (5 one mile and 1 two mile horizontal wells) Medium-Term Catalysts (2019+) Expand Cardium resource footprint through synergistic acquisitions Ramp-up Cardium Hz drilling program Unlock and develop Ellerslie Hz potential 160 140 120 100 80 60 40 20 0 Before Tax NPV10 57% YOY Growth YE 2016 YE 2017 Total Proved Total Probable 16 net sections of Crown lands with Cardium potential acquired in 2018 Develop multi-year development plans representing stable and predictable production growth 9
Egyptian Asset Portfolio
Egypt Q2-2018 production 11,912 bopd Gross 2P reserves of 26.6 MMbbls (12/31/17) 1 New developments in NWG 1.075 Million gross acres of land 6 PSCs in Egypt (100% WI) 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 GLJ evaluation effective 12/21/17 11
West Gharib/West Bakr/NWG: 100% WI - Operated Eastern Desert Production Q2-2018 average rate 11.9 Mbopd 2018 production guidance of 12.0 to 12.4 Mbopd 2018 Plan 1 Drill 8 development wells (4 WB, 2 NWG & 2 WG) WB development/optimization includes 4 dev wells, 8 recompletions and pump optimization WB K&H station upgrades: Phase 2 expansion to double capacity operational; Phase 3 expansion early 2019 NWG development/appraisal, implement water flood in NWG 38 pool WG development/optimization including 2 dev wells, recompletions and pump optimization 1. See Cautionary Statements "Forward-Looking Information and Statements" 12
Eastern Desert Development K-South Plan Existing Wells Tentative Future Locations Negotiated additional access from the military in late 2015 Drilled K-47, K-48 and K-51 during 2016/17 Completed in Upper Asl A sands Drilled K-46 in Q1-2018 Total net pay 111 ft., (Asl A&B) including 15 ft. Asl B over water Asl B produced briefly and watered out. Scheduled for recompletion in the Asl A Drilled K-45 in Q2-2018 Total net pay 195 ft., (Asl A&B) including 77 ft. of Asl B Completed in Asl B on initial production rate of 300+ Bopd 13
M-Meseda ASL A Top Structure & Well Locations M-North M-South M-19 Existing Wells 2018 Drilling Agreement with GPC to drill 2 wells each, inside the 250m boundary M-North drilled & cased Total net pay 132 ft of Asl A On production late August M-South drilling Q3 Possible twin/recomplete M-19 in Asl A Currently an Asl D oil well producing 250 Bopd 65 ft. of net oil pay behind pipe in Asl A GPC TG West Bakr 14
NWG DL #1, DL #2, NWG DL #3 and ARTA NWG-DL #1 (Red Bed oil) NWG-3X: ~440 Bopd NWG-38A: ~190 Bopd NWG-38A-1: SI to maintain pool pressure NWG-38A-2: ~440 Bopd 2018 plan: NWG 38 pool: initiate water flood for pressure maintenance and increase recoveries Injector drilled and found oil, SI for fracture stimulation New injector planned for Q3-2018, drilling Injection facilities work underway NWG-DL #2 (Red Bed oil) NWG-1X: Producing ~40 Bopd Frac d NWG-1A IP30 70 bopd NWG-DL #3 (Nukhul oil) NWG-5B: Producing ~50 Bopd Frac d NWG-5X IP30 300 bopd Rapid rise in WC to ~ 90%, investigating Evaluate Hz multi-stage dev potential Arta (West Gharib) Nukhul/RB Arta-48 frac d in May IP30 200 bopd, currently ~180 bopd Arta-54 frac d late June IP 205 bopd, currently ~80 bopd NWG-26AST-1 NWG-27A-1ST-1 NWG-27A NW Gharib Development Lease-4 NW Gharib Developmen t Lease-1 NWG-38A-1 NWG-16X Possible Up-dip Producer NWG-38A NWG-3X NWG-38A-2 NWG-38A-INJ East Arta Lease Poss. Injector Legend Develop. Loc. Oil Well P&A C.I.=100ft 15
Egypt Assets: Western Desert Three operated 100% WI concessions (~1 million acres) Acquired 1000 km 2 of seismic over South Ghazalat and NW Sitra (2015-2017) Prospect inventory completed and 4 locations being drilled in 2018 7 month contract extension for South Alamein received June 2018 16
Canadian Asset Portfolio
Canadian Asset Portfolio (Average WI ~88%) Canadian Lands Crown Rights Freehold Rights 2017 Drills P+P Locations Other Locations 2018 drilling Locations Calgary Land Position: 77,673 net acres (86,918 gross acres) Production: 1.9 Mboepd 1 (Q2/18) (55% liquids-weighted) 2P Reserves: 19.3 MMboe 2,3 (65% liquids-weighted) Producing Gross Locations 4 Wells Boepd 1 2P Cardium 40 761 30 Ellerslie/Mannville 53 950 17 Other 21 459 0 Total 114* 2,170 47 *Of which 85 are HZ wells 6 (5 net) HZ well drill program planned for 2018 from single pad at 16-8-31-3W5 (one two miler) Drilling commenced early September, targeting production by year end Production can be increased materially through development of existing locations 3 1. Average production for six months ended June 30 2018. The figures above were impacted by a one month shut-in for May 2018 2. See Cautionary Statements Oil and Gas Information ; All reserves and net present value estimates in respect of the Canadian acquisition based on GLJ evaluation effective 12/31/17 3. See Cautionary Statements "Forward-Looking Information and Statements" 4. Booked drilling locations based on GLJ evaluation effective 12/31/17 * 6 Mcf = 1 Boe 18
2018 Land Acquisition 16 sections of land were acquired (10,121 acres) at 100% WI 8 section lease 8 section license Average acquisition cost of $153/ha A single 1 mile Hz well is planned to test the Cardium trend in the new Harmattan South area in Q4 Further development with same scenario as Harmattan with 4 hz wells per section Success could add between 30 and 40 additional potential drilling locations (one mile hz each) Harmattan Harmattan South Calgary 19
Initial Well Results 1 Type Well Economics @60$WTI NPV10 $1.8MM US ROR 61% Wells shut in for 3 rd party gas plant maintenance 1. GLJ 2P Typecurve based on 187 Hz Cardium wells drilled within the greater Harmattan area between 2011-2013, modified to take into account increased frac density since that time frame * There are no assurances that the early time production presented is representative of long term performances 20
Finances & Reserves
Revised 2018 Capital Program Concession TransGlobe Net Operational Capital ($MM) WI Well Count - Budget WI Well Count -Revised Development Exploration (Wells) (Wells) Total Revised Wells Maint Proj Other Wells Bonus Seismic Dev Expl Total Dev Expl Total Canada 11.1-0.5 0.6 - - - $ 12.2 $ 16.4 6-6 6-6 West Gharib 2.6 0.1 0.3 - - - - $ 3.0 $ 5.2 1-1 2-2 West Bakr 7.3 1.4 1.7 - - 0.1 - $ 10.4 $ 12.1 5-5 4-4 NW Gharib 2.4 0.8-0.1 - - - $ 3.3 $ 3.2 2-2 2-2 South Alamein - - - 2.8 - - $ 2.8 $ 0.1-1 1 - - - South Ghazalat - - - 3.3 0.2 - $ 3.5 $ 1.8-2 2-2 2 NW Sitra - - - 5.2 0.2 - $ 5.4 $ 4.9-2 2-2 2 TG Egypt - - - 0.7 - - - $ 0.7 $ 0.4 - - - - - - 2018 Operations Total $23.4 $2.3 $2.5 $1.4 $11.3 $0.5 $0.0 $41.3 $44.1 14 5 19 14 4 18 22
Balance Sheet Summary TransGlobe has a strong balance sheet with a cash position of ~US$38.1MM @ June 30, 2018 Simple capital structure US$75MM Prepayment Agreement from Mercuria Energy Trading S.A. ($55MM drawn at 06/30/18) C$30MM Reserves-based lending facility (C$10.8MM drawn) (USD MM) Shares Outstanding (08/10/18) ~72.2 Market Capitalization (08/10/18) - $3.19/share $230.3 Debt (06/30/18) (Prepay Agreement + Canadian RBL) 1 $62.2 Working Capital (06/30/18) 2 Excluding Crude Inventory $52.6 Estimated Market Value of Inventoried Crude Oil of ~0.5 MMbbls 3 (06/30/18) $30.3 Enterprise Value 4,5 $209.6 1. Includes Prepay Agreement of $55MM and Canadian RBL of C$10.8 ($8.2MM) 2. Current Assets (including cash and cash equivalents) minus Current Liabilities, excludes inventoried crude oil 3. Estimated value of inventoried crude oil is based on average realized price of Gharib blend for Q2 sales and inventoried crude oil as at 06/30/18 4. Enterprise value calculated as Market Capitalization + Long term debt Working capital (Current Assets (excluding book value of crude inventory)- Current Liabilities) Market Value of Inventoried crude oil 5. See Cautionary Statements "Forward-Looking Statements and Information" 23
2017 Year-End Reserves Summary Based On Forecast Prices and Costs 1,2,3 Light & Medium Crude Oil Heavy Crude Oil Conventional Natural Gas Natural Gas Liquids BOE 4 Effective December 31, 2017 Gross (MMbbl) Gross (MMbbl) Gross (Bcf) Gross (MMbbl) Gross (MMboe) Proved (1P) Canada 4.1-22.9 3.5 11.4 Egypt 2.3 13.9 - - 16.1 Total Proved (1P) 6.3 13.9 22.9 3.5 27.5 Proved Plus Probable (2P) Canada 6.3-40.3 6.2 19.3 Egypt 3.8 22.8 - - 26.6 Total Proved Plus Probable (2P) 10.1 22.8 40.3 6.2 45.9 Total Proved Plus Probable Plus Possible (3P) 5 13.2 31.2 57.5 8.5 62.5 Based on GLJ evaluation 12/31/17. See Cautionary Statements "Oil and Gas Information 1. Tables may not total due to rounding 2. The pricing assumptions used in the GLJ report with respect to the net present value of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth in the GLJ report 3. Gross reserves are working interest reserves before royalties 4. 6 Mcf = 1 Boe 5. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves 24
Summary
Summary Well Positioned to Grow 2018 production guidance of 14.2 14.8 Mboepd* (95% oil & liquids) Inventory of low-risk development growth in Egypt and Canada Organic growth through exploration in Egypt and Canada High working interest in largely operated assets Scalable growth in a rising commodity price environment (torqued to oil) Listed on the AIM Jun 29, 2018 opening London office in September Actively seeking acquisitions in Egypt and region and land acquisition in Canada Strong balance sheet Re-instated dividend of US$0.035 per common share August 2018, to be assessed semiannually * 6 Mcf = 1 Boe 26
Appendix
Cautionary Statements Forward-Looking Information and Statements Certain statements included in this presentation constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "may", "will", "would" or similar words suggesting future outcomes or statements regarding an outlook. In particular, forward-looking information and statements contained in this document include, but are not limited to, anticipated drilling, completion and testing plans, including, the anticipated timing thereof, prospects being targeted by the Company, formations expected to be encountered during drilling, and rig mobilization plans; estimated net oil pay; expectation that current production rates will be optimized upon completion of a water injection scheme and stabilized reservoir pressures; the Company's anticipation that completion of the Phase 2 and 3 of the K-field facility expansion will double/triple the current fluid handling capacity respectively; the expected effect of the planned turnaround at the main natural gas processing plant in the Harmattan area on the Company's production; expected future production from certain of the Company's drilling locations; TransGlobe's plans to drill additional wells, including the types of wells, anticipated number of locations and the timing of drilling thereof; the timing of rig movement and mobilization and drilling activity; anticipated production and ultimate recoveries from wells; the Company s planned drilling program in each of Egypt and Canada; TransGlobe's plans to continue exploration, development and completion programs in respect of various discoveries; future requirements necessary to determine well performance and estimated recoveries; and other matters. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. 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 addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things, anticipated production volumes; the timing of drilling wells and mobilizing drilling rigs; the number of wells to be drilled; the Company's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business; future capital expenditures to be made by the Company; future sources of funding for the Company's capital programs; geological and engineering estimates in respect of the Company's reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities; current commodity prices and royalty regimes; availability of skilled labour; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; future operating costs; uninterrupted access to areas of TransGlobe's operations and infrastructure; recoverability of reserves and future production rates; 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 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 TransGlobe's reserves and resource volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; the AIM market s access to investors; the AIM market s improvement to TransGlobe's corporate profile; the perceived benefits of the AIM market; and other matters. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward-looking statements or information include, among other things, operating and/or drilling costs are higher than anticipated; unforeseen changes in the rate of production from TransGlobe's oil and gas properties; changes in price of crude oil and natural gas; adverse technical factors associated with exploration, development, production or transportation of TransGlobe's crude oil reserves; changes or disruptions in the political or fiscal regimes in TransGlobe's areas of activity; changes in tax, energy or other laws or regulations; changes in significant capital expenditures; delays or disruptions in production due to shortages of skilled manpower equipment or materials; economic fluctuations; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; obtaining required approvals of regulatory authorities; volatility in market prices for oil; fluctuations in foreign exchange or interest rates; environmental risks; ability to access sufficient capital from internal and external sources; failure to negotiate the terms of contracts with counterparties; failure of counterparties to perform under the terms of their contracts; uncertainty in obtaining required approvals from TransGlobe's nominated advisor; uncertainty in obtaining required approvals from the London Stock Exchange; failure to achieve the perceived benefits of the AIM market; general economic and financial conditions of the AIM market; and other factors beyond the Company's control. Readers are cautioned that the foregoing list of factors is not exhaustive. Please consult TransGlobe s public filings at www.sedar.com and www.sec.gov/edgar.shtml for further, more detailed information concerning these matters, including additional risks related to TransGlobe's business. The forward-looking statements or information contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this presentation are expressly qualified by this cautionary statement. 29
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 the slide "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 forwardlooking statements and information. 29
Cautionary Statements Oil and Gas Information The estimates of TransGlobe's December 31, 2017 reserves set forth in this presentation have been prepared by GLJ Petroleum Consultants ( GLJ"), an independent qualified reserves evaluator, as of December 31, 2017 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 GLJ's forecast prices and costs as at December 31, 2017. The estimates of TransGlobe's December 31, 2016 reserves were prepared by DeGolyer and MacNaughton Canada Limited ("D&M"), an independent qualified reserves evaluator, in accordance with NI 51-101 and COGEH and using D&M's forecast prices and costs as at December 31, 2016. 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, net pay, 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 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. References in this presentation to production test rates, are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for TransGlobe. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, TransGlobe cautions that the production test results should be considered to be preliminary. 30
Cautionary Statements This presentation includes estimates of net pay which are considered to be anticipated results or information that indicate the potential value or quantities of resources under National Instrument 51-101. Such estimates have been prepared by management of TransGlobe and have not been prepared or reviewed by an independent qualified reserves evaluator or auditor. The risks associated with these estimates include, but are not limited to, the risk that TransGlobe's exploration and development drilling and related activities may provide different results; the risk that TransGlobe may encounter unexpected drilling results; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas; delays in anticipated timing of drilling and completion of wells; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and the risk that if any resources are discovered that it will not be commercially viable to produce any portion thereof. There is no certainty that TransGlobe will achieve the estimated. 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. This presentation discloses drilling locations that have associated proved and/or probable reserves based on GLJ s 12/31/2017 evaluation prepared in accordance with NI 51-101 and the COGE Handbook and using GLJ pricing forecasts as at 12/31/2017. 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. Mr. Brett Norris, M.Sc., P Geo, - Vice President Exploration for TransGlobe Energy Corporation, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, June 2009, of the London Stock Exchange, has reviewed and approved the technical information contained in this presentation. Mr. Norris obtained a Master s of Science Degree in Geology from the University of Western Ontario. He is a Registered Professional Geoscientist in the province of Alberta and has over 30 years experience in oil and gas. 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 (or 3 rd party) generated type curves based on a combination of historical performance of older wells and management (or 3 rd party s) expectation of what might be achieved from future wells. The type curves represent what management (or 3 rd party) thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells management (or 3 rd party) 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 31
Production (boepd) Daily Production 1 20,000 TRANSGLOBE TOTAL DAILY Canada shut in for planned facility turnaround 15,000 10,000 Canada 5,000 NWG West Bakr West Gharib 0 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Q2 2018 2018 GUIDANCE JUNE 2018 JULY 2018 Egypt ~11,916 MBopd ~12.0 12.4 MBopd ~12,304 MBopd ~12,312 MBopd Canada ~1,907 Mboepd* ~2.2-2.4 Mboepd* ~2,564 MBoepd* ~2,383 Mboepd* Total Company ~13,822 Mboepd* 14.2-14.8 Mboepd* ~14,868 Mboepd* ~14,695 Mboepd* 1. See Cautionary Statements "Forward-Looking Information and Statements" and "Oil and Gas Information * 6 Mcf = 1 Boe 32
2017 Year End Net Present Value of Future Net Revenue 1 Before Deducting Future Income Taxes Discounted At Effective December 31, 2017 (MM$) 0% 5% 10% 15% 20% Proved Canada 190.8 129.4 94.0 71.9 57.3 Egypt 2 175.9 155.2 139.3 126.8 116.7 Total Proved 366.7 284.6 233.3 198.8 174.0 Proved Plus Probable Canada 344.9 202.8 133.5 95.3 72.1 Egypt 2 297.0 250.1 216.3 190.9 171.3 Total Proved Plus Probable 641.9 452.9 349.8 286.2 243.4 1. Based on GLJ evaluation effective 12/31/17 2. Egyptian taxes are paid from the Government s share of production, therefore the Company s share is always after-tax 33
Canada: 2017 in Review Acquired December 2016 for $60MM (C$80MM) Closed December 20 th, 2016 Took over field operations Feb 1 st, 2017 ATB Facility in place Q2 2017, paid out VTB loan Production averaged 2.7 Mboepd* in 2017 Drilled 3 Cardium Hz multi-stage frac oil wells in Q3-2017 to evaluate the development model Under budget at $2.0MM/well (C$2.5MM), lower FDC/well Increased well performance (more frac s) vs. historical wells (2012-2014) Negotiated reduced FH royalties on nine undrilled spacing units Acquired additional Crown land in Harmattan Area Year End 2017 Increase in NPV10, despite removing 3.1MMboe (2P) of undeveloped Mannville Gas, primarily due to low gas prices Proved (1P) NPV 10% of $94MM 1 up 81% from 2016 ($52MM) 2 Proved plus Probable (2P) NPV10 of $134MM 1 up 57% from 2016 ($85MM) 2 1. Based on GLJ evaluation 12/31/17. See Cautionary Statements "Oil and Gas Information 2. Based on D&M evaluation effective 12/31/16. See Cautionary Statements "Oil and Gas Information * 6 Mcf = 1 Boe 34
Netback ($/boe)1 Netback ($/bbl) Netback ($/bbl) Company Indicative Netbacks $25 $20 $15 $10 $5 $0 $60 $40 $20 $0 $8 $6 $4 $2 $0 Egypt (US$) $19.87 $15.63 $11.39 $7.15 $2.92 $40 $50 $60 $70 $80 Brent Canada - Oil (US$) $49.35 $42.31 $35.29 $28.41 $21.12 $40 $50 $60 $70 $80 WTI Canada - Gas/NGLs (US$) $6.42 $4.66 $2.89 $1.79 $0.71 $0.95 $40 $1.15 $50 $1.35 $60 $1.55 $70 $1.75 $80 AECO Egypt Assumptions: Using anticipated 2018 Egypt production profile Ras Gharib price differential estimate of $10.50 per bbl applied consistently at all price points Concession differentials of 4%/5%/3% applied to WG/WB/NWG respectively Opex estimated at ~$9.60/bbl Maximum cost recovery resulting from accumulated cost pools Canada Assumptions: Using anticipated 2018 Canada production profile Edmonton Light to Harmattan discount = C$2.50/bbl Opex estimated at C$10.25/boe Aeco gas price C$1.25/mmbtu for $40 WTI and increases C$0.25/mmbtu for every $10/bbl WTI Edmonton Light = $5.50 off of WTI NGL mixture price = 45% of Edmonton Light Takes into consideration Canadian tax pools 1. 6 Mcf = 1 Boe 35
Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 AR ( 000s)/ Inventory (10 s bbls) Oil Marketing TransGlobe began marketing its own entitlement oil in January 2015 Marketing improved liquidity and decreased credit risk - 30 day payment in US$ from date of cargo sailing Marketed 15.5 cargo liftings in the last 45 months Signed long-term marketing agreement (in conjunction with Prepayment Agreement) with Mercuria Energy Trading S.A. in February 2017 Ongoing discussions with EGPC to improve lifting frequency Egypt Accounts Receivable and Inventory 300,000 250,000 200,000 Lowest A/R & days inventory in Company history 12 10 8 150,000 100,000 6 4 Months 50,000 2 0 0 Accounts Receivable Crude Inventory Equivalent Months of Production in Inventory Months in AR 36
Year-end Reserves Summary 1,2,3 Total proved plus probable ( 2P ) gross reserves of 45.9 MMboe at year end 2017: 2P Reserves 8% lower YOY primarily due to production of ~5.7 MMboe during 2017 (~4.7 MMbbls Egypt & ~ 1.0 MMboe Canada) 2P Positive Adds/Revisions of 1.6 MMboes of gross 2P reserves primarily attributed to; - Egypt of +1.2 MMbbls due to improved performance - Egypt of + 1.0 MMbbls attributed to NW Gharib discoveries - Canada of +2.6 MMboes attributed to undeveloped Cardium oil and extensions - Offset by -3.1 MMboes attributed to undeveloped Mannville gas which was deemed uneconomic at current natural gas price forecasts Replaced 62% and 30% of 2017 production (~5.7 MMboe) on a respective 1P and 2P gross reserve basis 2017 Reserves Summary 1P 2P 3P 2016 Year End Reserves (MMboe) 29.9 50.0 65.9 2017 Adds/Revisions 3.2 1.6 2.4 2017 Production -5.7 2017 Year End Reserves (MMboe) 27.5 45.9 62.5 Change vs Year End 2016 (%) -8.0% -8.0% -5.0% Production Replacement Ratio (%) (ex A&D, economic factors) 62% 30% 45% 70 60 50 40 30 20 10 0 1P 2P 3P 2016 Year End Reserves (mmbl) 2017 Year End Reserves (mmbl) 1. Based on D&M evaluation effective 12/31/16 and GLJ evaluation 12/31/17. See Cautionary Statements "Oil and Gas Information 2. Reserves are Gross working interest reserves before royalties. 3. Tables may not total due to rounding * 6 Mcf = 1 Boe 37
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) December 2017 total Cardium production in Alberta was ~209,000 boepd (not including NGL yields) 1 75,000 bbl/d oil 804 MMcf/d gas Well 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 December, 2017 based on Accumap data. Values reported are raw production and values and do not include Natural Gas Liquid yields or associated Natural Gas shrinkage. 38
Executives and Directors Robert G. Jennings Director, Chairman Ross G. Clarkson Director, and CEO Randy Neely Director, and President Fred J. Dyment Director Susan MacKenzie Director David Cook - Director Bob MacDougall Director Matthew Brister Director Steve Sinclair Director Lloyd W. Herrick VP and COO Edward Ok VP Finance and CFO Brett Norris VP Exploration 39
Analyst Coverage Rita Guindy Arqaam Capital, Cairo, Egypt Jenny Xenos Canaccord Genuity, Calgary, Canada Caroline Berzi CI Capital, Giza, Egypt Stephane G. Foucaud GMP First Energy, London, UK Al Stanton RBC Capital Markets, London, UK Gavin Wylie Scotia Capital Inc., Calgary, Canada 40
For additional information contact us at: Phone: +1 (403) 264 9888 Email: investor.relations@trans-globe.com Or visit: www.trans-globe.com