TRANSGLOBE ENERGY CORPORATE PRESENTATION MAY 2018 TSX:TGL NASDAQ:TGA

Transcription

1 TRANSGLOBE ENERGY CORPORATE PRESENTATION MAY 2018 TSX:TGL NASDAQ:TGA

2 CAUTIONARY STATEMENT The information provided in this presentation is provided as of May, 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" 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 24 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

3 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 11.8 MBopd in Q MMbl 2P Gross Reserves (16.1 MMbl 1P Gross) (12/31/17) 1 Re-entry to Canada in December 2016 Averaged 2.6 MBoepd in Q MMboe 2P Gross Reserves (11.4 MMboe 1P Gross) (12/31/17) 1,2 Management focus is on cash flow and building shareholder value over the long term Stock price recovery has lagged oil price recovery TransGlobe is well positioned with a strong balance sheet, steady production, strong working relationship with Egypt and increasing cash flows from both business units, to take advantage of the delayed market sentiment on oil and gas. 1. Based on GLJ evaluation effective 12/31/17. See Cautionary Statements "Oil and Gas Information" 2. 6 Mcf = 1 Boe 3

4 VALUE PROPOSITION AND GO-FORWARD PLAN 2 Enterprise Value to 2018E mid-point production of $8,987/boepd and $2.92/boe on a 2P reserve basis 1,2,3 Diversified production base ~ Mboepd (2018 guidance) High working interest, oil-focused operated assets torqued to commodity price recovery ~94% Oil & Liquids Egypt Near Term Catalysts (2018) Western Desert exploration in NWS and SG, (4 exploration wells) beginning in Q2 Medium Term Catalysts (2019+) WB acceleration Western Desert development and further exploration in NWS and SG Acquisition, in Egypt or region Canada Near Term Catalysts (2018) Cash flow growth of Canadian assets New generation of Cardium completion results Drilling of 6 horizontal oil wells Medium Term Catalysts (2019+) 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 ($2.09/share x 72.2 MM shares) plus Current Liabilities plus Debt less A/R, Cash and current estimated market value of crude inventory all as at 03/31/18 2. Reserves are per GLJ evaluations as of 12/31/17 and are gross working interest before royalties, with natural gas, converted on a basis of 6 Mcf = 1 Boe. See Cautionary Statements Oil and Gas Information". 3. See Cautionary Statements Forward-Looking Statements and Information. 4

5 2018 Q1 FINANCIAL HIGHLIGHTS Sales volumes averaged 11,753 boepd* and production volumes averaged 14,375 boepd* Positive funds flow from operations of $3.9 MM ($0.05/share) vs. positive funds flow of $2.5 MM ($0.03/share) in Q Operating expense averaged ~$10.27/Bbl in in Egypt and ~$9.32/Boe* in Canada G&A costs averaged $3.09/Boe* on a produced barrel basis Spent $4.6 MM on capital expenditures in Q Ended quarter with $31.1 MM in cash and cash equivalents and $45.3 MM in working capital (excludes fair market value of crude held in inventory) Inventoried entitlement oil of ~1.0 MM Bbls at quarter end, an increase of ~0.2 MM Bbls from Q Q1 '18 Q1 '17 Change % Production and Sales Egypt Oil Sold Bpd 9,155 11,044-17% Egypt Oil Produced Bpd 11,777 13,948-16% Canada Oil Bpd % Natural Gas Mcfd 6,176 7,075-13% NGLs Bpd 894 1,037-14% Revenue Egypt Oil $/Bbl $56.20 $ % Canada Oil $/Bbl $57.15 $ % Natural Gas $/Mcf $1.70 $ % NGLs $/Bbl $27.72 $ % Operating Expenses Egypt $/Bbl $10.27 $ % Canada (1) $/Boe (2) $9.32 $ % G&A Expenses Gross $MM $4.0 $4.4-9% Sold Boe $/Boe $3.77 $3.57 6% Produced Boe $/Boe $3.09 $2.95 5% Egypt Crude Oil Inventory Ending Balance MMBbls % Equivalent Months (3) Months % Funds Flow from Operations $MM $3.9 $2.5 56% Net Income $MM -$10.1 -$12.9 -$22 (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. * 6 Mcf to 1 Boe 5

6 2018 STRATEGY, FOCUS AREAS AND GUIDANCE Strategy To materially grow the Company s annual cash flow through exploitation, development, small e exploration and acquisitions. Focusing our acquisition efforts where we can leverage our operational and technical strengths in under-developed assets in under-loved situations / locations with a geographic focus North/South of Egypt Focus and Guidance 2018 production guidance of 14.2 to 15.6 Mboepd 1 Egypt 12.0 to 13.0 Mbopd in 2018 (12.8 Mbopd in 2017) Canada 2.2 to 2.6 Mboepd in 2018 (2.7 Mboepd 1 in 2017) Continued focus on increasing frequency of entitlement crude sales in Egypt Goal is to reduce inventoried crude oil from 2017 year-end level of ~800,000 Bbls to less than 500,000 Bbls 1 by year end 2018 Capital plan funded from cash flow budgeting run at $55 Brent capital budget of $41.3 MM (before capitalized G&A) Egypt $29.1 MM Canada $12.2 MM (C$15.3 MM) List the Company on the AIM exchange by summer and establish an executive office in London to increase investor interest and business development opportunities 1. See Cautionary Statements "Forward-Looking Information and Statements" and "Oil and Gas Information". 6

7 2018 OPERATIONAL PLAN 1 TransGlobe 2018 Capital ($MM) EGYPT 8 well development program 5 in West Bakr, 2 in NW Gharib and 1 in West Gharib Maintain Eastern Desert production Test 4 independent structures on South Ghazalat and NW Sitra South Alamein contract extension CANADA Execute 2018 Cardium oil drilling program consisting of ~6 (net) horizontal wells Develop multi-year development plans representing stable and predictable production growth 1. See Cautionary Statements "Forward Looking Information and Statements" and "FOFI and Other Financial Measures". 7 Gross Well Count Development Exploration (Drilling) Total Concession Wells* Other Wells Other Development Exploration Total West Gharib West Bakr NW Gharib NW Sitra South Ghazalat South Alamein** Egypt $12.3 $5.1 $11.3 $0.4 $ Canada $11.2 $1.1 $ Total $23.4 $6.2 $11.3 $0.4 $ Splits (%) 71% 29% 100% 74% 26% 100% * Wells include new wells, completions, workovers, recompletions and equipping. ** Under review due to access restrictions

8 BALANCE SHEET SUMMARY TransGlobe has a strong balance sheet with a cash position of ~US$31.1 March 31 st 2017 Simple capital structure US$75 MM Prepayment Agreement from Mercuria Energy Trading S.A. ($60 MM drawn at 03/31/18) C$30 MM Reserves-based lending facility (C$10.7 MM drawn) (USD MM) Shares Outstanding (05/09/18) ~72.2 Market Capitalization (05/09/18) - $2.14/share $155 Debt (03/31/18) (Prepay Agreement + Canadian RBL) 1 $67 Working Capital (03/31/18) 2 Excluding Crude Inventory $30 Estimated Market Value of Inventoried Crude Oil of ~1.0 MMbbls 3 (03/31/18) $57 Enterprise Value 4,5 $ Includes Prepay Agreement of $60MM and Canadian RBL of C$10.7 ($8.3MM) 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 Q1 sales and inventoried crude oil as at 03/31/18 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" 8

9 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 Egypt Total Proved (1P) Proved Plus Probable (2P) Canada Egypt Total Proved Plus Probable (2P) Total Proved Plus Probable Plus Possible (3P) 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 below. 3. Gross reserves are working interest reserves before royalties 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. 9

10 2017 YEAR END NET PRESENT VALUE OF FUTURE NET REVENUE 1 Before Deducting Future Income Taxes Discounted At Effective December 31, % 5% 10% 15% 20% (MM$) Proved Canada Egypt Total Proved Proved Plus Probable Canada Egypt Total Proved Plus Probable 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 10

11 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 Apr-17 Jun-17 Aug-17 Oct-17 Dec-17 Feb-18 Apr-18 Q GUIDANCE MARCH 2018 APRIL 2018 Egypt ~11,777 MBopd ~ MBopd ~11,739 MBopd ~12,026 MBopd Canada ~2,598* MBoepd ~ * MBoepd ~2,509 MBoepd* ~2,505 Mboepd* Total Company ~14,375* MBoepd * MBoepd ~14,248 Mboepd* ~14,531 Mboepd* 1. See Cautionary Statements "Forward-Looking Information and Statements" and "Oil and Gas Information * 6 Mcf = 1 Boe. 11

12 INVESTMENT HIGHLIGHTS - EGYPT Million gross acres of land 6 PSCs in Egypt (100% WI) Q production 11.8 MBopd Gross 2P reserves of 26.6 Mmbbl (12/31/17) 1 New developments in NWG 2018 Exploration & Development focus In Western Desert, complete 4 exploration wells (2 wells in NWS, 2 wells in SG) In Eastern Desert, sustain/develop producing concessions 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. 12

13 WEST GHARIB/WEST BAKR/NWG: 100% WI - OPERATED Eastern Desert Production Q average rate 11.8 Mbopd 2018 production guidance of 12.0 to 13.0 Mbopd 1. See Cautionary Statements "Forward-Looking Information and Statements" Plan 1 Drill 8 development wells (5 WB, 2 NWG & 1 WG) WB development/optimization includes 5 dev wells, 8 recompletions and pump optimization WB K&H station upgrades; Phase 2 commissioned in May to double process capacity. Phase 3 operational prior to year end. NWG development/appraisal, implement water flood in NWG 38 pool WG development/optimization including 1 dev well, recompletions and pump optimization

14 EASTERN DESERT DEVELOPMENT K-SOUTH PLAN Existing Wells Future Locations Negotiated access from the military in late 2015 Drilled K-47, K-48 and K-51 during 2016/17 Completed in Upper Asl AI sands Drilled K-46 in Q Total net pay 111 ft.*, (Asl A&B) including 15ft. Asl B over water Completed Asl A&B, producing 120 Bopd at current pumping rates Drilled K-45 in Q 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 in early May * See Cautionary Statements Oil and Gas Information 14

15 M-MESEDA ASL A TOP STRUCTURE & WELL LOCATIONS Existing Wells 2018 Drilling Agreement with GPC to drill 2 wells each, inside the 250m boundary M-19 M-North & M-South Waiting on surface approvals Drill Q2/Q Possible twin/recomplete M-19 in Asl A Currently an Asl D oil well producing 350 Bopd 65 ft.* of net oil pay behind pipe in Asl A GPC * See Cautionary Statements Oil and Gas Information TG West Bakr 15

16 NWG DL #1 NW Gharib Development Lease-4 NWG-DL #1 (Red Bed oil) NWG-3X: ~640 Bopd NWG-27A-1ST-1 NW Gharib Development Lease-1 NWG-38A: ~240 Bopd NWG-38A-1: ~230 Bopd NWG-26AST-1 NWG-27A NWG-38A-2: ~450 Bopd 2018 plan: NWG-16X NWG-3X Possible Up-dip Producer NWG-38A-2 NWG-38A-1 NWG-38A C.I.=100ft NWG 38 pool: initiate water flood for pressure maintenance and increase recoveries East Arta Lease Possible Injector Legend Develop. Loc. Oil Well P&A Injector planned for Q Injection facilities work underway 16

17 NWG DL #2, NWG DL #3 AND ARTA NWG-1X NW Gharib Development Lease-2 NWG-DL #2 (Red Bed oil) NWG-1X: Producing ~40 Bopd Arta-54 Arta-48 NWG-1A Complete NWG-1A in Q NWG-DL #3 (Nukhul oil) C.I.=100ft NWG-5B: Producing ~90 Bopd Complete NWG-5X in Q Arta Lease NWG-5B East Arta Lease Possible development drilling Evaluate HZ multi-stage dev potential Arta (West Gharib) Nukhul/RB NWG-5X NW Gharib Development Lease-3 Legend Develop. Loc. Oil Well P&A Arta-48 to be stimulated in Q Arta-54 currently drilling (second well drilled inside the 400m boundary) 17

18 EGYPT ASSETS: WESTERN DESERT Three operated 100% WI concessions (1.03 million acres) Acquired 1000 km 2 of seismic over South Ghazalat and NW Sitra ( ) Prospect inventory completed and 4 locations being prepared for drilling in 2018 South Alamein contract extension applied for 18

19 NWS: CRETACEOUS PROSPECTS Proposed Drill Locations Locations De-Risked W/ Success NWS-12X Cretaceous/Jurassic Structure Map: Top Bahariya CI: 50ft 5KM NWS-09X - Cretaceous

20 CANADIAN ASSET PORTFOLIO (AVG WI ~88%) Canadian Lands Crown Rights Freehold Rights 2017 Drills P+P Locations Other Locations 2018 drilling Locations Land Position: 71,877 net acres (82,145 gross acres) Production: 2.6 MBoepd 1 (Q1/18) (62% liquids-weighted) 2P Reserves: 19.3 MMBoe 2,3 (65% liquids-weighted) Producing Gross Locations 4 Wells Boepd 1 2P Cardium Ellerslie/Mannville 61 1, Other *Of Total which 85 are HZ wells 120* 2, Average production for Q 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/ See Cautionary Statements "Forward-Looking Information and Statements". 4. Booked drilling locations based on GLJ evaluation effective 12/31/17 * 6 Mcf = 1 Boe 20 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 6 HZ well drill program planned for 2018 from single pad (one two miler) Production can be increased materially through development of existing locations 3

21 CANADA: ONE YEAR IN REVIEW Acquired December 2016 for $60 MM (C$80 MM) 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 Q to evaluate the development model Under budget at $2.0 MM/well (C$2.5 MM), lower FDC/well Increased well performance (more frac s) vs. historical wells ( ) Negotiated reduced FH royalties on nine undrilled spacing units Acquired additional Crown land in Harmattan Area Year End 2017 Increase in NPV10, despite removing 3.1 MM Boe (2P) of undeveloped Mannville Gas, primarily due to low gas prices Proved (1P) NPV 10% of $94 MM 1 up 81% from 2016 ($52 MM) 2 Proved plus Probable (2P) NPV 10% of $134 MM 1 up 57% from 2016 ($85 MM) 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 21

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23 SUMMARY Well Positioned to Grow 2018 production guidance of Mboepd* (95% oil & liq) 1 Inventory of low-risk development growth in Egypt and Canada, plus high-impact exploration in Egypt High working interest in largely operated assets Scalable growth in a rising commodity price environment (torque to oil) Progressing with plans to list on the AIM in near term Actively seeking acquisitions in Egypt and region and land acquisition in Canada Strong balance sheet Share price has lagged oil price recovery 1. See Cautionary Statements Oil and Gas Information * 6 Mcf = 1 Boe 23

24 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; the Company's beliefs related to the AIM market; the Company's intention to establish an office in London and the expected timing thereof; 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 markets access to investors; the AIM markets 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 advance an AIM admission filing; failure to achieve the perceived benefits of the AIM market; failure to establish an executive office in London on the time anticipated or at all; no assurances are given that an application to list will be made or that any TransGlobe security will be listed on 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 and 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. 24

25 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 "2018 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. 25

26 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 Standards of Disclosure for Oil and Gas Activities ("NI ") 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, 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 and COGEH and using D&M's forecast prices and costs as at December 31, 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 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 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 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 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. 26

27 CAUTIONARY STATEMENTS 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 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. 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 27

28 APPENDIX

29 Netback ($/boe) Netback ($/bbl) Netback ($/bbl) COMPANY INDICATIVE NETBACKS US$ AECO/ MMBTU $25 $20 $15 $10 $5 $0 $60 $40 $20 $8 $6 $4 $2 $0 $0 $3.66 $7.90 Egypt (US$) $12.14 $16.37 $20.61 $40 $50 $60 $70 $80 Brent $21.21 Canada - Oil (US$) $28.87 $36.03 $43.44 $50.73 $40 $50 $60 $70 $80 $0.83 $2.02 WTI Canada - Gas/NGLs (US$) $2.95 $4.77 $6.58 $40 $50 $60 $70 $80 WTI $1.00 $1.20 $1.40 $1.60 $1.80 Egypt Assumptions: Using anticipated 2018 Egypt production profile Ras Gharib price differential estimate of $9.00 per bbl applied consistently at all price points Concession differentials of 4%/5%/3% applied to WG/WB/NWG respectively Opex estimated at ~$9.50/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$10.15/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 29

30 $1,000 s (A/R) / 10 s Bbls (Inventory) Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 OIL MARKETING TransGlobe began marketing its own entitlement oil in January 2015 Marketing improved liquidity and decreased credit risk - 30 day payment in US$ from date of cargo sailing Marketed 12.5 cargo liftings in the last 41 months Signed long term marketing agreement (in conjunction with Prepayment Agreement) with Mercuria on Feb 10/17 Ongoing discussions with EGPC to improve lifting frequency Egypt Accounts receivable and Inventory 300, , , , , Months 50, Accounts Receivable Crude Inventory Equivalent Months of Production in Inventory Months in AR 30

31 YEAR-END RESERVES SUMMARY 1,2, Reserves Summary 1P 2P 3P 2016 Year End Reserves (MMBoe) Adds/Revisions Production Year End Reserves (MMBoe) Change vs Year End 2016 (%) -8.0% -8.0% -5.0% Production Replacement Ratio (%) (ex A&D, economic factors) Year End Reserves (mmbl) 2017 Year End Reserves (mmbl) 62% 30% 45% 1P 2P 3P Reserve Category 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 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 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 Tables may not total due to rounding * 6 Mcf = 1 Boe.

32 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 boep/d (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. 32

33 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 Edward Ok - VP Finance and CFO Lloyd W. Herrick - VP and COO Brett Norris - VP Exploration 33

34 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 34

35 For additional information contact us at: Phone: +1 (403) Or visit: