Corporate Presentation August 2019 AIM & TSX:TGL NASDAQ:TGA - - PowerPoint PPT Presentation

August 2019

AIM & TSX:TGL NASDAQ:TGA

Corporate Presentation

Cautionary Statement

2 The information provided in this presentation is provided as of August 12, 2019 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 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. All dollar values are expressed in US dollars unless otherwise stated. All production and reserves are company gross working interest share of volumes before deduction of royalty unless otherwise stated.

Overview

3

Significant operational experience

Founded 20+ years ago

Established operated production in Egypt and Canada

Increased FY 2019 production guidance to 15.0‐16.0 Mboepd* from 14.0 to 15.0 Mboepd

Strong balance sheet and funds flow generation

Funds Flow for the three and six months ended 6/30/19 of $19.1 MM and $34.3 MM

Strong position to grow in Egypt and surrounding region

Management team actively seeking acquisition opportunities

Growth underpinned by resource base

Gross 2P reserves of 44.1 MMboe*1

Focused on building a profitable and growth oriented international portfolio

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”

• 1. Based on GLJ evaluations effective and 12/31/18.

Dividend payer

$0.035/share paid in April 2019; $0.035/share to be paid September 2019; targeting semi‐annual payments

Valuation Upside ‐ Strong Production and Cash Flow From Existing Asset Base*

4

16,940 boepd

Production (Q2)

$69.9 MM

Enterprise Value

$107.4 MM

Market Capitalization

$0.035/share

Dividend declared August 12, 2019 to be paid September 13, 2019; Targeting semi‐annual payments

$19.1 MM

Q2 Funds Flow Ended 6/30/19

Enterprise Value Estimate ($ MM)

Shares Outstanding (08/12/19) ~72.5 Market Capitalization (08/12/19) ‐ $1.48/share $107.4 Debt (6/30/19) (Prepay Agreement + Canadian RBL)1 $48.1 Working Capital (6/30/19)2 Excluding Crude Inventory $41.1 Estimated Market Value of Inventoried Crude Oil of ~0.7 MMbbls3 (6/30/19) $44.5 Enterprise Value4 * $69.9

• 1. Includes Prepay Agreement of $40MM and Canadian RBL of C$11.5 ($8.8MM)
• 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 6/30/19

• 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 * See Cautionary Statements – "Forward‐Looking Statements and Information"

• $75MM Prepayment Agreement from Mercuria Energy Trading S.A. ($40MM drawn as

at 6/30/19)

• C$25MM Reserves‐based lending facility (C$11.5MM drawn as at 6/30/19)

$29.1 MM

Q2 oil cargo net proceeds

5

2019 Capital Program*

Wells Other Wells Other Total Dev Expl Total West Gharib ‐ 3.4 ‐ ‐ 3.4 ‐ ‐ ‐ West Bakr 3.4 10.1 1.1 ‐ 14.6 3 1 4 NW Gharib 1.0 0.6 1.0 ‐ 2.6 1 1 2 South Ghazalat ‐ ‐ 1.2 2.3 3.5 ‐ 1 1 Egypt 4.4 14.1 3.3 2.3 24.1 4 3 7 Canada 6.3 0.5 3.2 ‐ 10.0 3 1 4 2019 Operations Total $10.7 $14.6 $6.5 $2.3 $34.1 7 4 11 Exploration Development Concession TransGlobe Net Operational Capital ($MM) WI Well Count (Wells)

* See Cautionary Statements – "Forward‐Looking Information and Statements"

The Company’s capital budget is financed from cash flows from operations and split 75:25 ‐ Development:Exploration Egypt

• Eastern Desert:
• 1 exploration well drilled (oil producer), a second one awaiting completion
• 4 development wells drilled, one for water injection
• In Western Desert, appraise/develop the SGZ‐6X light oil discovery in South Ghazalat

Canada Maintain/grow Canadian light oil production and test acquired lands for commerciality

2018 YE Reserves Summary (MMboe) 1P 2P 3P

Canada 11.0 18.4 24.8 Egypt 15.9 25.7 37.0 Total Company (MMboe) 26.9 44.1 61.8 Total Company NPV @ Dec 31/18 NPV 10% Before tax $MM Dec 31/18 $231 $339 $446 NPV 10% After tax $MM Dec 31/18 $227 $323 $421

1. Based on GLJ evaluation effective 12/31/18. See Cautionary Statements – "Oil and Gas Information“

• 4. NPV’s GLJ evaluation effective 12/31/2018 forecast pricing

2. Reserves are Gross working interest reserves before royalties. * 6 Mcf = 1 Boe 3. Tables may not total due to rounding

Year‐end Reserves Summary1,2,3,4 *

6

Health, Safety, Environment & Social Responsibility Performance

7

2013‐2018 Road Traffic Accidents (“RTA”) 2013‐2018 Total Recordable Cases (“TRC”)

21 19 14 6 11 4 5 10 15 20 25 2013 2014 2015 2016 2017 2018

2013‐2018 RTA's1

25 19 16 12 16 7 5 10 15 20 25 30 2013 2014 2015 2016 2017 2018

2013‐2018 TRC's1

‐ TGL implemented a formal HSES management system in 2014 ‐ TGL formed an independent HSE board committee in 2015 ‐ TGL has made significant progress on several HSES key performance indicators ‐ Canadian operations have been incident free since acquisition in 2016

HSES is a fundamental component of how TransGlobe operates

• 1. HSES Statistics as at Q1 2019

Egyptian Asset Portfolio

A Unique Position in Egypt*

9

Best‐in‐class operator in Egypt with 15 years in country Strong relationship with government 100% working interest and operator Ability to market 100% of it’s Eastern Desert entitlement crude Very low government receivables Focused on extracting maximum potential from known reservoirs and leveraging position Poised for organic growth via infill drilling and exploration Well positioned to expand through acquisitions

* See Cautionary Statements – "Forward‐Looking Information and Statements"

TransGlobe Egypt – Four 100% WI Concessions*

10

• Three development/production concessions in the Eastern Desert

(W. Bakr, W. Gharib and NW Gharib)

• Negotiating to amend, extend and consolidate the three concessions in

single new concession in 2019*

• Subject to approval by Egyptian authorities
• Western Desert
• South Ghazalat development lease approved* for SGZ‐6X discovery (2018)
• 1st oil planned for Q4 2019
• South Alamein exploration lease relinquished in Q2

Cairo

South Ghazalat (Development)

* See Cautionary Statements – "Forward‐Looking Information and Statements"

Nile River Delta

Eastern Desert Concessions (Development)

NW Gharib NW Gharib W Gharib W Gharib W Gharib W Bakr

NW Gharib

Mediterranean Sea

Western Desert Eastern Desert

100 km

Eastern Desert Concession Development Leases

West Gharib 5 Northwest Gharib 4 West Bakr 2

N

Eastern Desert: Three 100% WI Concessions*

11

1. Based on GLJ evaluations effective 12/31/18 * See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”

Eastern Desert acquisitions (2007 & 2011) are a template for the Company’s future strategy:

• Older fields, large resource, unloved by prior
• wners
• Rigorous technical work, capital discipline and

transfer of emerging western oil field technologies

• Drilled over 250 wells in past 10+ years

Production:

• 2019 guidance increased to 12.95 ‐ 13.75 Mbopd

(13.35 Mbopd mid point)*

• 2019 averaging ~ 14.2 Mbopd (YTD July 31st)

Reserves:

• 1P – 15.9 MMbbl¹ at Dec 31, 2018
• 2P – 25.7 MMbbl¹ at Dec 31, 2018

Beyond 2019

• Post concession consolidation, advance primary,

secondary and tertiary development programs to increase recoveries and production*

Exploration Discovery HW‐2X Exploration Well NWG‐38A pool appraisal Infill drilling and workovers/

• ptimization

12

West Bakr Concession – K/M/H‐Field*

West Bakr Concession H Block DL West Bakr Concession K/M Block DL

Fields discovered and producing since early 1980s

• Acquired in 2011, producing ~3,500 bopd
• Currently producing >9,000 bopd

2019 Activity to Date:

Development:

• Three Infill Wells (H/K/M Fields)
• M‐10 Twin producing ~500 bopd1
• H‐30 producing ~70 bopd1
• K‐63 producing ~475 bopd1
• Recompletions (~5 wells; H/K Fields)
• Workovers (~2 wells; K Field)
• Artificial lift upgrades ongoing

Exploration:

• Cased HW‐2X discovery with ~113 ft net oil

pay, producing ~715 bopd1 as at July 2019

2019 Plan:

Development:

• Recompletions (~5 additional wells; H/K Fields)
• Workovers (~5 additional wells; K Field)

Optimization:

• K station Phase 3 CPF upgrade Q3/4
• Flow line replacement ongoing

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”

1 production is based on field estimates

K‐63 M‐10 Twin HW‐2X H‐30

NW Gharib Concession – DL #1*

13

Acquired NW Gharib through EGPC Bid Round in 2013

• Multiple field discoveries

2014 – 2016

• Infrastructure and

knowledge synergies

2019 Activity to Date:

• Drilled NWG‐38A‐8 injector

well in Q1 to establish water injection and pressure support

• Currently injecting ~600

bwpd and is being

• ptimized
• Monitoring other wells
• Drilled and cased NWG

38D‐1 exploration well adjacent to 38A pool in Q2

NW Gharib Development Lease‐4 NW Gharib Development Lease‐1 East Arta Lease

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information” NWG‐38D‐1 NWG‐38A‐8

Northwest Gharib Concession DL‐4 Northwest Gharib Concession DL‐1

2018 Activity:

• S. Ghazalat: drilled two exploration wells (one P&A)
• SGZ‐6X discovery: tested 3,840 Bopd¹ combined from

Upper (~1,400 bopd) and Lower (~2,400 bopd) Bahariya reservoirs

• Declaration of commerciality submitted to EGPC

2019 Activity to Date:

• Development lease submitted and approved by

ministry

• Remaining land relinquished

2019 Plan:

• Install early production facilities and equip SGZ‐6X

discovery well targeting first oil Q4

• Drill one appraisal well Q3/4 & tie‐in
• Seismic re‐processing for merging of data and better

imaging

• Several additional leads identified for follow‐up

South Ghazalat Concession*

14

• 1. 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. * See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”

SGZ‐6X Discovery

• S. Ghazalat

Development Lease Potential appraisal locations Potential additional leads

Canadian Asset Portfolio

Canadian Assets – Window to NA Technology

16

2018 Program

• Drilled 6 Hz Cardium oil wells (5 one mile, 1 two

mile)

• On production in Jan 2019

2019 Program*

• 4 HZ Cardium well drill program (3 development

in Harmattan and 1 outpost in Harmattan South) Production

• 2019 Guidance of 2.05 to 2.25Mboed*
• 250 Boepd of Ethane (C2) diverted and

sold as gas starting in early 2019 Reserves

• 1P – 11.0 Mmboe¹ at Dec 31, 2018
• 2P – 18.4 Mmboe¹ at Dec 31, 2018
• ~ 65% light oil and liquids

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”

• 1. All reserves and net present value estimates based on GLJ evaluation effective 12/31/18, 6 Mcf = 1 Boe

Near‐Term Plans – Canada*

17

Develop multi‐year development plans representing stable and predictable production growth 2019

• Assess 6 wells drilled in late 2018
• On production in early 2019
• Drill and complete 3 Cardium development Hz wells
• Drill and complete 1 Cardium outpost Hz well to evaluate

Cardium lands acquired in Harmattan South during 2018

• Success could add up to 30 ‐ 40 additional potential drilling

locations (one mile Hz wells at four per section)

Medium‐Term (2020+)

• Ramp‐up Cardium Hz drilling program (P+P and other

locations)

• Unlock and develop Ellerslie Hz potential
• Expand Cardium resource footprint through synergistic

land acquisitions

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”

TGL Rights P+P Locations Other Locations 2019 drilling Locations

Summary

Summary *

19

Strong balance sheet and funds flow of $34.3 MM for the six months ended 6/30/19 2019 production guidance increased to 15.0 – 16.0 Mboepd* (95% oil & liquids) Dividend of US$0.035 per common share declared August 12 to be paid September 2019 2019 Plan designed to maximize free cash flow for future value growth opportunities in and outside of Egypt Consolidate and modernize Eastern Desert Concessions in 2019 to unlock large oil in place development projects in Egypt Organic growth through exploration/development in Egypt and Canada High working interest in largely operated assets

* See Cautionary Statements – "Forward‐Looking Information and Statements"

Well Positioned to Grow

Listed on the AIM June 29, 2018 – London office opened in September Actively seeking acquisitions in Egypt and region and land acquisition in Canada

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

• ther 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

• il 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 Phase 3 of the

K‐field facility expansion will increase the current fluid handling capacity by 50%; 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; the perceived benefits of the London executive office; 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; 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.

21

Cautionary Statements

22

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 forward‐ looking statements and information.

Cautionary Statements

23

Oil and Gas Information

• The estimates of TransGlobe's December 31, 2018 reserves set forth in this presentation have been prepared by GLJ Petroleum Consultants (“GLJ"), an independent qualified reserves evaluator, as of December

31, 2018 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, 2018 for 2018. 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

• r 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.

Cautionary Statements

24

• 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 12/31/2018 evaluation prepared in accordance with NI 51‐101 and the COGE Handbook and

using GLJ pricing forecasts as at 12/31/2018. 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. Darrin Drall, B.Sc., Mechanical Engineering – Engineering Manager for Technical Services 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. Drall obtained a Bachelor’s of Science Degree in Mechanical Engineering from the University of Manitoba. He is a member of APEGA, APEGS and SPE 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 3rd party) generated type curves based on a combination of historical performance of older wells and management (or 3rd party’s) expectation of what might be achieved from future

• wells. The type curves represent what management (or 3rd party) thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells management (or 3rd 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 millions of dollars PSCs production sharing contracts. WI working interest Bbl barrels Bopd or bopd barrels of oil per day Bwpd or bwpd barrels of water per day MMBbl million barrels Mcf thousand cubic feet MMcf million cubic feet MMBoe million barrels of oil equivalent Boepd barrels of oil equivalent per day 1P proved reserves PDP proved developed producing reserves PU proved undeveloped reserves 2P proved plus probable reserves

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

2018 Year‐End Reserves Summary*

Based On Forecast Prices and Costs1,2,3

25 Light & Medium Crude Oil Heavy Crude Oil Conventional Natural Gas Natural Gas Liquids Total BOE4 Effective December 31, 2018 Gross (MMbbl) Gross (MMbbl) Gross (Bcf) Gross (MMbbl) Gross (MMboe) Proved (1P) Canada 4.0 ‐ 21.6 3.4 11.0 Egypt 1.9 14.0 ‐ ‐ 15.9 Total Proved (1P) 5.8 14.0 21.6 3.4 26.9 Proved Plus Probable (2P) Canada 6.0 ‐ 38.1 6.0 18.4 Egypt 3.6 22.1 ‐ ‐ 25.7 Total Proved Plus Probable (2P) 9.6 22.1 38.1 6.0 44.1 Total Proved Plus Probable Plus Possible (3P)5 13.4 31.0 55.0 8.3 61.8

*Based on GLJ evaluation 12/31/18. See Cautionary Statements – "Oil and Gas Information“

* Based on GLJ evaluation 12/31/18. See Cautionary Statements – "Oil and Gas Information“ 1. Egyptian taxes are paid from the Governments share of production, therefore the Company’s share is always after tax

2018 Year End Net Present Value of Future Net Revenue*

26

AFTER Deducting Future Income TaxesDiscounted At

Effective December 31, 2018 ($MM)

0% 5% 10% 15% 20%

Proved Canada

154 113 87 69 56

Egypt2

174 155 140 128 118

Total Proved (1P)

328 268 227 197 175

Proved Plus Probable Canada

256 165 117 87 69

Egypt2

277 236 207 184 166

Total Proved Plus Probable (2P)

532 402 323 271 235

Proved Plus Probable Plus Possible Canada

348 210 142 103 80

Egypt2

408 331 279 242 215

Total Proved Plus Probable Plus Possible (3P)

756 541 421 346 295

Company Indicative Netbacks

27

Egypt Assumptions:

• Using anticipated 2019 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 ~$10.35/bbl
• Maximum cost recovery resulting from

accumulated cost pools

1. 6 Mcf = 1 Boe

Canada Assumptions:

• Using anticipated 2019 Canada production

profile

• Edmonton Light to Harmattan discount =

C$2.50/bbl

• Opex estimated at ~C$12.25/boe
• Aeco gas price C$1.25/mmbtu for $40 WTI and

increases C$0.25/mmbtu for every $10/bbl WTI

• Edmonton Light = $6.00 off of WTI
• NGL mixture price = 45% of Edmonton Light
• Takes into consideration Canadian tax pools

$1.86 $6.01 $10.15 $14.29 $17.51 $0 $5 $10 $15 $20 $40 $50 $60 $70 $80 Netback ($/bbl) Brent

Egypt (US$)

$19.84 $27.84 $35.56 $43.37 $51.19 $0 $20 $40 $60 $40 $50 $60 $70 $80 Netback ($/bbl)

WTI Canada ‐ Oil (US$)

$(1.82) $(0.79) $0.24 $1.76 $3.26 ‐$4 ‐$2 $0 $2 $4 $40 $50 $60 $70 $80 Netback ($/boe) WTI

Canada ‐ Gas/NGLs (US$)

C$1.25 C$1.50 C$1.75 C$2.00 C$2.25 C$AECO/MMBTU

OIL MARKETING

28

• TransGlobe began marketing its own entitlement oil in January 2015
• Marketing improved liquidity and decreased credit risk ‐ 30 day payment in US$ from date
• f cargo sailing
• Marketed 18.5 cargo liftings in the last 54 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

AR (‘000s)/ Inventory (10’s bbls) Months

2 4 6 8 10 12 50,000 100,000 150,000 200,000 250,000 300,000 Jun‐11 Aug‐11 Oct‐11 Dec‐11 Feb‐12 Apr‐12 Jun‐12 Aug‐12 Oct‐12 Dec‐12 Feb‐13 Apr‐13 Jun‐13 Aug‐13 Oct‐13 Dec‐13 Feb‐14 Apr‐14 Jun‐14 Aug‐14 Oct‐14 Dec‐14 Feb‐15 Apr‐15 Jun‐15 Aug‐15 Oct‐15 Dec‐15 Feb‐16 Apr‐16 Jun‐16 Aug‐16 Oct‐16 Dec‐16 Feb‐17 Apr‐17 Jun‐17 Aug‐17 Oct‐17 Dec‐17 Feb‐18 Apr‐18 Jun‐18 Aug‐18 Oct‐18 Dec‐18 Feb‐19 Apr‐19 Jun‐19

Egypt Accounts receivable and Inventory

Accounts Receivable Crude Inventory Equivalent Months of Production in Inventory Months in AR

2017 Initial Cardium Well Results*

29

• 2017 Program wells continue to meet or exceed the GLJ Type Curve

Facility Turnaround

• 2017 Cardium wells were designed as one mile horizontal wells with multi stage frac’s (~40 stages/mile)
• Each well costs ~$2.0 MM (for one mile Hz) and is expected to follow a production curve as shown below
• Cardium wells are principally targeting light oil production (~ 90% light oil & liquids)

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”, 6 mcf = 1 Boe

2018 Drilling Program

30

• Facility and weather issues early on in the production life resulted in large discrepancies

between forecast and actual production

• More recently the wells have been trending closer to expected production rates

Executives and Directors

31

• David Cook – Director, Chairman
• Ross G. Clarkson – Director
• Susan MacKenzie – Director
• Steve Sinclair – Director
• Carol Bell – Director
• Edward LaFehr ‐ Director
• Randy Neely – Director, and President & CEO
• Lloyd W. Herrick – Executive Vice President
• Geoff Probert – VP and COO
• Edward Ok – VP Finance and CFO

Analyst Coverage

32

• Rita Guindy

Arqaam Capital, Cairo, Egypt

• Charlie Sharp

Canaccord Genuity, London, UK

• Stephane G. Foucaud

GMP First Energy, London, UK

• Al Stanton

RBC Capital Markets, Edinburgh, UK

• Gavin Wylie

Scotia Capital Inc., Calgary, Canada

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