2020 corporate presentation a proven track record€¦ · year‐end reserves summary 1,2,3,4,*...

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2020 CORPORATE PRESENTATION

A PROVEN TRACK RECORDFebruary 2020

CAUTIONARY STATEMENT

TransGlobe Energy | Corporate Presentation | February 2020 Slide 2

The information provided in this presentation is provided as of February 7, 2020 for informational purposes only, is not complete, is based (in part) on information preparedfor 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 asolicitation 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 reviewedor approved by any securities commission or regulatory authority in Canada, the United States, the United Kingdom or any other jurisdiction. TransGlobe expressly disclaimsany duty to make disclosure or any filings with any securities commission or regulatory authority, except as required by applicable securities laws. See "CautionaryStatements" beginning on slide 29 for other important disclosures regarding forward looking information, financial outlook and other financial matters, oil and gasinformation 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.

Please see the table entitled “Production Disclosure” at the end of this presentation for the detailed constituent product types and their respective quantities measuredat the first point of sale for all production amounts disclosed in this presentation on a Bopd and Boepd basis.

OVERVIEW


Focused on building a profitable and growth oriented international portfolio

Strong balance sheet and funds flow generationFunds flow for the three and nine months ended 9/30/19 of $9.4 MM and $43.7 MM

Dividend payer$0.035/share paid in April 2019; $0.035/share paid in September 2019; targeting semi‐annual payments

Established operated productionFY 2020 production guidance to 14.5‐15.5 Mboepd*

Strong platform to grow in Egypt and surrounding region Management team actively seeking merger and acquisition opportunities in Egypt and region

Growth underpinned by resource baseGross 2P reserves of 45.3 MMboe*1

Significant operational experience Founded 20+ years ago

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”1 Based on GLJ evaluations effective 12/31/19

VALUATION UPSIDESTRONG PRODUCTION AND CASH FLOW FROM EXISTING ASSET BASE*


• See Cautionary Statements – "Forward‐Looking Statements and Information“1 Includes: $75MM Prepayment Agreement from Mercuria Energy Trading S.A. ($35MM drawn as at 9/30/19); and C$25MM Reserves‐based lending facility (C$9.7MM

drawn as at 9/30/19) 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 Q3 sales/inventoried crude oil as at 9/30/194 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 oil5 Market cap and working interest production as per most recently released company data as at February 7, 20206 Based on GLJ evaluations effective 12/31/19. See Cautionary Statements – "Oil and Gas Information“

Enterprise Value Estimate ($ MM)

Shares Outstanding (2/07/20) – MM shares ~72.5

Market Capitalization (2/07/20) ‐ $1.28/share $92.8

Debt (9/30/19) (Prepay Agreement + Canadian RBL)1 $41.7

Working Capital (9/30/19)2 Excluding Crude Inventory $29.8

Est. Market Value of Crude Inventory3 (~0.9 MMbbls ‐ 9/30/19) $49.3

Enterprise Value4 * $55.4

16.0 MboepdProduction (2019)

$55.4 MMEnterprise Value

$92.8 MMMarket Capitalization

$0.035/shareDividend declared August 12, 2019 paid September 13,

2019; Targeting semi‐annual payments

45.3 MMboe2P Reserves 12/31/19

6

2020 PRODUCTION AND CAPITAL GUIDANCE

Slide 5

In 2020 we are focused on:

• Building on our 2019 success at South Harmattan with 4 development wells to further grow production and cash flow, and proving up the resource base

• Replacing Egypt production and positioning for growth post conclusion of negotiations

• Expanding our portfolio in both the Eastern and Western Desert of Egypt through targeted exploration

‐

5,000

10,000

15,000

20,000

Q1 Q2 Q3 Q4

2020E Production (Boepd)

0

2

4

6

8

10

12

14

Q1 Q2 Q3 Q4

2020E Capital Spend, US$MM

Egypt Canada

TransGlobe Net Capital (US$MM) Gross Well Count

Concession Development Exploration Total New Drills Total Wells

Wells Other1 Wells Capex Devt Expln

West Gharib 4.9 0.7 ‐ 5.6 4 ‐ 4

West Bakr 6.2 1.8 1.2 9.2 4 1 5

NW Gharib 3.1 0.1 2.4 5.6 3 2 5

South Ghazalat 1.5 0.1 1.8 3.3 1 1 2

Egypt 15.7 2.7 5.4 23.7 12 4 16

Canada 11.4 2 ‐ 13.4 4 ‐ 4

Total 27.1 4.7 5.4 37.1 16 4 20

1 Other includes workovers, recompletions and maintenance. Also seismic within exploration categories.

TransGlobe Energy | Corporate Presentation | February 2020

YEAR‐END RESERVES SUMMARY 1,2,3,4,*

Total proved plus probable (“2P”) gross reserves of 45.3 MMboe at year‐end 2019:

• 2019 production of ~5.8 MMboe (~5.0 MMbbls Egypt and ~0.8 MMboe Canada)

• 2P Reserves are 3% higher YOY

• PDP Reserves are 6% higher YOY following the conversion of 1P undeveloped reserves‒ This results in 1P being 5% lower YOY

• 2P Positive Adds/Revisions of 7.0 MMboeof gross 2P reserves‒ drilling additions in both Egypt and Canada‒ improved performance from production optimization in Egypt

• Replaced 119%, 82% and 135% of 2019 production on a PDP, 1P and 2P gross reserves basis, respectively

2019 Reserves Summary PDP 1P 2P 3P

2018 Year End Reserves (MMboe) 17.5 26.9 44.1 61.8

2019 Adds/Revisions 6.8 4.3 7.0 7.3

2019 Production ‐5.8

2019 Year End Reserves (MMboe) 18.5 25.4 45.3 63.3

Change vs Year End 2018 (%) 6.0% ‐5.0% 3.0% 2.0%

Production Replacement Ratio (%) – (ex A&D, economic factors) 119% 82% 135% 158%

NPV 10% Before tax $MM Dec 31/19 $161 $200 $298 $393

NPV 10% After tax $MM Dec 31/19 $161 $198 $288 $376

1 Based on GLJ evaluations effective 12/31/18 and 12/31/19. See Cautionary Statements – "Oil and Gas Information“ 4 NPV’s GLJ evaluation effective 12/31/2019 forecast pricing2 Reserves are Gross working interest reserves before royalties * 6 Mcf = 1 boe3 Tables may not total due to rounding

Slide 6TransGlobe Energy | Corporate Presentation | February 2020

SUSTAINABILITYCOMMITMENT TO A CORE COMPANY VALUE


Governance•Majority independent Board• Board committees chaired by independent directors• Staff education, training and monitoring for compliance with Canadian CFPOA legislation, US FCPA laws, and the UK Bribery Act

Social•US$1.2 billion invested into Egypt• Charitable support and sponsorship of Ras Gharib hospital• Paid over US$2.1 billion in taxes and royalties in Egypt•Operations directly support over 1,000 jobs in the Ras Gharibregion

Environment• Investment in pipeline replacements/ upgrades to reduce reliance on trucked oil• Corporate commitment to carbon disclosure reporting and reduction plan• Potential to access local West Bakr wind farm (250MW) due on‐stream 2021 to power various field needs• Ras Gharib shoreline remediation project

EGYPTIAN ASSET PORTFOLIO

A UNIQUE POSITION IN EGYPT*


Focused on extracting maximum potential from known reservoirs and leveraging position

Targeting inorganic growth opportunities through acquisitions

Best‐in‐class operator in Egypt with 15 years of in‐country operating experience

Strong relationship with government

Ability to market 100% of its Eastern Desert entitlement crude

Poised for growth post consolidation of its Eastern Desert PSCs

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

EGYPT ACREAGE – FOUR 100% WI CONCESSIONSThree development/production concessions in the Eastern Desert• W Bakr, W Gharib and NW Gharib• Negotiating to amend, extend and consolidate the three concessions into a single new concession in 2020*

South Ghazalat development lease• SGZ‐6X well on production in December 2019

* Subject to approval by Egyptian authorities; See Cautionary Statements – "Forward‐Looking Information and Statements"

Cairo

South Ghazalat(Development)

Nile River Delta

Eastern Desert Concessions

(Development)

NW Gharib

NW Gharib

W Gharib

W Gharib

W Gharib

W Bakr

NWGharib

MediterraneanSea

Western Desert Eastern Desert

100 km

Eastern Desert Concession

Development Leases

West Gharib 5

Northwest Gharib 4

West Bakr 2

Western Desert Concession

Development Leases

South Ghazalat 1

N


EASTERN DESERT: THREE 100% WI CONCESSIONS


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

• Older fields, large resource, unloved by prior owners• Rigorous technical work, capital discipline and transfer of proven western oilfield

technologies • Drilled over 250 wells in past 10+ years

Egypt Production:• 2020 guidance of 11.9 – 12.7 Mbopd*• 2020 currently averaging ~12.7 Mbopd (YTD January)

Egypt Reserves:• 1P – 15.6 MMbbl¹ at December 31, 2019• 2P – 26.7 MMbbl¹ at December 31, 2019

Beyond 2020:• Post concession consolidation, advance primary, secondary and tertiary development

programs to increase recoveries and production*

Appraise HW‐2XDiscovery

NWG Exploration

NWG‐3X pool appraisal

Infill drilling and recompletes/optimization

1 Based on GLJ evaluations effective 12/31/19* Midpoint of guidance; see Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”

H‐block Exploration

Arta Phase 1 Development

WEST BAKR CONCESSION – K/M/H FIELD*


Fields discovered and producing since early 1980s

• Acquired in 2011, producing ~3,500 Bopd1

• Currently producing >8,200 Bopd1 (as of January 2020)

2020 Plan:

• Development:‒ Development drilling (HW‐2A, HW‐8, K‐62, K‐64)‒ Recompletions (~10 wells)

• Optimization:‒ Artificial lift upgrades (~12 wells)‒ Completion of K station Phase 3 CPF upgrade‒ Flow line replacement ongoing‒ Additional water disposal (~5 wells)

• Exploration:‒ Test new structure northwest of HW‐2X discovery (HW‐7x well)

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”1 Production is based on field estimates

HW‐7X

HW‐2A

HW‐8

K‐62

K‐64

H‐Block

K‐Block

West Bakr Concession

WEST GHARIB CONCESSION – ARTA LEASE*


Fields discovered and producing since early 1980s

• Acquired in 2007, producing ~3,000 Bopd1

• Currently producing >3,700 Bopd1

2020 Plan:

• Development:‒ Development drilling, Arta Phase 1

‒ 5 Vertical wells2 (Arta‐50, Arta‐75, Arta‐76, NWG‐1D, NWG‐1E)‒ First horizontal multi‐stage stimulated well (Arta‐Hz‐1)

‒ Recompletions (~4 wells)

• Post consolidation, this area will be early focus, application of horizontal drilling – similar to what is done in Canada

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”1 Production is based on field estimates2 Note that two of the vertical wells are on NW Gharib Development Lease‐2

Arta‐50

Arta‐Hz‐1

Arta‐76

NWG‐1D

NWG‐1E

East Arta

NWG‐DL‐3

West Gharib – Arta Lease

NWG‐DL‐2

Arta

Arta‐75

NW GHARIB CONCESSION – DEVELOPMENT LEASE #1*


Acquired NW Gharib through EGPC Bid Round in 2013

• Multiple field discoveries 2014 – 2016

• Infrastructure and knowledge synergies

2020 Plan:

• Development:‒ Development well to NWG‐3X producer (NWG‐3B‐2)

• Optimization:‒ Monitor and enhance NWG‐38A pool water injection

• Exploration:‒ Test two new structures (NWG‐44A and NWG‐46X wells)

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

NWG‐3X

NWG‐3B‐2

NWG‐46X

NWG‐44A

SOUTH GHAZALAT CONCESSION*


S. Ghazalat:

• SGZ‐6X discovery well put on production in late December 2019‒ Initial rate of 800‐1,000 Bopd1

‒ Currently restricted to 250‐350 Bopd1 to manage the reservoir and optimize facilities

2020 Plan:

• Development:‒ Drill SGZ‐6A appraisal well in Q2 2020

• Exploration:‒ Drill new structure in Q2 2020 (SGZ‐7B well)‒ Well will fulfill exploration commitment‒ Seismic mapping ongoing on reprocessed data to identify additional opportunities

SGZ‐6A

SGZ‐6X

SGZ‐7B

* See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”1 Production is based on field estimates

CANADIAN ASSET PORTFOLIO

CANADIAN ASSETS – EXTENDING THE CARDIUM

Slide 17

2020 • Drill and complete 4 Cardium wells in South Harmattan

3 Development wells offsetting 2‐20 1 Step‐out well to test the extension of the South Harmattan

Fairway and continue land (location not finalized)• 2020 Guidance of 2.6 to 2.8Mboed*

Medium‐Term (2020+)• Production Growth at South Harmattan• Production Maintenance at Harmattan Proper• Unlock Ellerslie Hz potential

Reserves• 1P – 9.9 MMboe¹ at December 31, 2019• 2P – 18.6 MMboe¹ at December 31, 2019• ~ 67% light oil and liquids

TGL Rights

2020 drilling Locations

Production Growth at South Harmattan

• See Cautionary Statements – "Forward‐Looking Information and Statements“ and “Oil and Gas Information”1 Based on GLJ evaluations effective 12/31/19


SOUTH HARMATTAN RESOURCE FAIRWAY

Slide 18

HARMATTAN

TGL Cardium Rights

• TransGlobe has accumulated 18.5 sections of Cardium mineral rights ― Each block or section is equivalent to 1 square mile (640 acres or 256

hectares) and may accommodate up to four 1‐mile horizontal wells

• Lands, or mineral rights, are principally leased from the provincial government― Horizontal drilling royalty incentives reduce royalties to 5% until well costs

are recovered

• Company’s 2‐20 well targeted a concept developed by TransGlobe’s technical team in area previously considered to be in a hydrocarbon transition zone― 2‐20 well estimated IP30 of 417 Boepd, IP60 of 341 Boepd― Well de‐risks South Harmattan Cardium resource fairway

• Highly developed area, with access roads, gas pipeline capacity and oil takeaway facilities

• TransGlobe 2020 program includes three 2‐mile horizontal wells offsetting 2‐20 plus one 1‐mile horizontal step out― 40% increase in reservoir footage over 2019 program

• Up to 72, 1‐mile horizontal locations at South Harmattan that may be optimized with additional 2‐mile and 1½‐mile horizontals

• A further 30, 1‐mile horizontal locations available in the core Harmattan area

HARMATTAN

LOCHEND

LOCHEND

~30 km NW of Calgary

2‐20 2‐mile horizontal well

SOUTHHARMATTANFAIRWAY


SOUTH HARMATTAN TYPE WELLS AND 2‐20 FORECAST

Slide 19

• De‐risked South Harmattan resource fairway offers material returns and capital efficiencies

• Rapid redeployment of capital to South Harmattan in 2020 as first step to growing cash flow and reducing uncertainty

• South Harmattan 2‐20 well production and cash flow forecast compares favourably with Company type well estimates for 1‐mile and 2‐mile horizontals in the core Harmattan acreage

• Scope to materially grow self‐funded Canadian free cash flow

Capital F&D Netback *Recycle Ratio Payout IRR NPV10

(MMUSD) ($/boe) ($/boe) X (yrs) (%) (MMUSD)

1 Mile Type Well 2.0 9.58 35.24 3.7 3.7 24 1.02 Mile Type Well 3.1 7.33 34.78 4.7 2.7 31 2.12‐20 3.0 6.85 34.35 5.0 1.9 49 2.9

* Netback in the first yearNOTE: Price forecast is 55 $/bbl WTI and 1.13 $/MMbtu AECO


SUMMARY

SUMMARY

Slide 21

• 2019 exceeded expectations‒ Egyptian well performance was better than expected, resulting in 2 upward revisions to production guidance‒ South Harmattan 2‐20 well surprised to the upside

• 2020 production guidance is cautious given short production history of new wells and Egyptian drilling activity weighted to the second half of the year

• South Harmattan is potentially significant to the Company‒ Provided ability to shift capital to Canada and create near‐term value to shareholders that will help maintain or increase real returns to our shareholders

• Proving the investment thesis in Canada to maximize shareholder value‒ Canadian production guidance of 2,700 Boepd* has potential value of US$49MM, based on Canadian peer group average trading metrics

• Tangible progress toward merging Eastern Desert concession agreements‒ Scheduled to ramp‐up capital program in the second half of 2020


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

APPENDIX

RECONCILIATION OF CHANGES IN RESERVES

Slide 23

The following tables detail reconciliation of the changes in TransGlobe’s gross light and medium crude oil, heavy oil, associated and non‐associated (combined) conventional natural gas and NGL reserves as at December 31, 2019 compared to such reserves as at December 31, 2018.


RECONCILIATION OF CHANGES IN RESERVES


PRODUCTION DISCLOSURE


• Based on an average Canadian peer group valuation, and TransGlobe’s Canadian 2020 production guidance of 2,700 Boepd(midpoint), the Canadian assets have an implied value of US$49 million‒ Relative to TransGlobe’s current trading

value of ~US$5,900/Boepd, there is implied upside of approximately US$33 million to reach the peer average

• Based on TransGlobe’s current valuation metric and 2020 Egyptian production guidance of 12,300 bbl/d (midpoint), the market assigns a value to the Egyptian assets of US$73 million

• TransGlobe continues to develop its acreage positions in both Egypt and Canada, effectively allocating capital across its portfolio‒ Success at South Harmattan has allowed

the Company to design its 2020 drilling program to further de‐risk its land position maximizing shareholder value

$5,926

$29,863

$23,479

$20,625

$14,653 $14,642

$12,737

$10,823

TransGlobe Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7

EV/boe

/d (U

S$ 202

0E)

Source: Canaccord Genuity, Canadian Energy Weekly, February 3, 2020, converted to US$. TransGlobe metrics are based on the mid‐point of 2020 guidance.Peers are Canadian small‐ and mid‐cap oil‐weighted energy companies

COMPARISON TO CANADIAN PEERS

Slide 26

Mean: US$18,117

TransGlobe’s Canadian oil‐weighted peers trade at a significant premium in terms of EV/Boepd


COMPANY INDICATIVE NETBACKS


$2.11

$6.25

$10.39

$14.53

$18.65

$0

$5

$10

$15

$20

$40 $50 $60 $70 $80

Netba

ck ($

/bbl)

Brent

Egypt (US$)

$18.43 $26.94

$35.11 $43.41

$51.66

$0

$20

$40

$60

$40 $50 $60 $70 $80

Netba

ck ($

/bbl)

WTI

Canada ‐ Oil (US$)

$(1.17)$(0.03)

$0.85

$2.39

$3.92

‐$2‐$1$0$1$2$3$4$5

$40 $50 $60 $70 $80

Netba

ck ($

/boe

)

WTI

Canada ‐ Gas/NGLs (US$)

Egypt Assumptions:• Using anticipated 2020 Egypt production profile• Ras Gharib price differential estimate of $12.00 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 in WG and

NWG

Canada Assumptions:• Using anticipated 2020 Canada production profile• Edmonton Light to Harmattan discount = C$2.50/bbl• Opex estimated at ~C$11.35/boe• Aeco gas price C$1.25/mmbtu for $40 WTI and increases C$0.25/mmbtu

for every $10/bbl WTI• Edmonton Light = $9.00 off of WTI• NGL mixture price = 45% of Edmonton Light• Takes into consideration Canadian tax pools

1. 6 Mcf = 1 Boe

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 20 cargo liftings in the last 61 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 (‘00

0s)/ In

ventory (10’s bb

ls)

0

2

4

6

8

10

12

0

50,000

100,000

150,000

200,000

250,000

300,000

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

Aug‐19

Oct‐19

Dec‐19

Egypt Accounts Receivable and Inventory

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

EXECUTIVES AND DIRECTORS


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

CAUTIONARY STATEMENTS


Slide 31

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 presentation include, but are not limited to, statements relating to "reserves" which are, by their nature, forward‐looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves or resources, as applicable, described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future; expected production amounts and decline rates in the future; the expected product types and quantities of such product types; the plans for the Company's 2020 Canadian drilling program and the details thereof; the Company's expectation relating to the performance of the South Harmattan Cardium prospect; and other matters. The recovery and reserve estimates of TransGlobe's reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will be recovered.

• 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 results, volumes and decline rates; 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 in this presentation; 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; 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; 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.



Slide 32

Financial Outlook

• This document also contains financial outlook within the meaning of applicable securities laws, including but not limited to the information regarding future capital expenditures, estimated finding and development costs, netbacks, recycle ratio, payout, internal rates of return, and net present value. The financial outlook has been prepared by TransGlobe's management to provide an outlook of the Company's activities and results. The financial outlook has been prepared based on a number of assumptions including those set forth below in this 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 financial outlook 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 financial outlook 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 financial outlook and forward‐looking statements and information. See "Economic Assumptions" below for a description of the key assumptions underlying the calculation of certain financial outlook disclosed in this presentation.



Slide 33

Oil and Gas Information

• 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.

• Reserves. The estimates of TransGlobe's December 31, 2019 reserves set forth in this presentation have been prepared by GLJ Petroleum Consultants ("GLJ"), an independent qualified reserves evaluator, as of December 31, 2019 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. See TransGlobe's news release dated February 5, 2020 entitled "TransGlobe Energy Corporation Announces its 2020 Capital Budget and 2019 Year‐End Reserves" available at www.trans‐globe.com/news for more details concerning the reserves set forth in this presentation.

• 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 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.

• The recovery and reserve estimates of reserves provided in presentation 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 in this presentation.

• Oil and gas metrics. This presentation contains certain oil and gas metrics, including F&D, netback, recycle ratio, payout, and internal rates of return ("IRR"), which do not have standardized meanings or standard methods of calculation. 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 calculated by the Company and included in this presentation 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. The following describes the method used to determine the metric and explains the meaning of the metric:

• "Finding and development costs" or "F&D costs" are calculated by dividing the sum of the capital expenditures for the year (in dollars) by the additions to reserves within the applicable reserves category.

• Netback is a measure of operating results and is calculated as sales net of royalties, operating expenses, current taxes and selling costs. Management believes that netback is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses.

• Recycle ratio is calculated by dividing the netback by the proved and proved plus probable finding and development costs on a per bbl basis.

• Payout is calculated as the period of time by which all costs of drilling, completions, and tie‐in for a well or wells have been recovered from the sale of production (net of operating costs and royalties) from a well or wells.

• IRR is calculated as the discount factor applied to future cash flows at which the NPV is calculated to be zero.

• See "Economic Assumptions" below for a description of the key assumptions underlying the calculation of certain oil and gas metrics disclosed in this presentation.



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• Analogous information. Certain information in presentation 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 publically available information relating to certain industry participants, including AccuMap and 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 in this presentation. 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.

• Production results. References in this presentation to production results over a 30 and 60 day period 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. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for TransGlobe or any of its wells. A pressure transient analysis or well‐test interpretation has not been carried out in respect of the highlighted well. Accordingly, TransGlobe cautions that the production results for the highlighted well should be considered to be preliminary.

• Third party sources. Certain other information contained in this presentation has been prepared by third‐party sources, including the Canadian Energy Weekly published by Canaccord Genuity on February 3, 2020. Such 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 that publication, and nothing contained in this presentation is, or shall be relied upon as, a promise or representation by TransGlobe as to the accuracy or completeness of that information.

• Drilling locations. This presentation discloses drilling locations that have associated proved and/or probable reserves based on GLJ's 12/31/2019 evaluation prepared in accordance with NI 51‐101 and the COGE Handbook and using GLJ pricing forecasts as at 12/31/2019. Nineteen (one‐mile equivalents) of the drilling locations have been assigned proved reserves and 8.5 (one‐mile equivalents) of the drilling locations have been assigned probable reserves by GLJ in the evaluation. The remainder of the drilling locations disclosed in this presentation are unbooked locations located on the Company's leases which are internal estimates based on an assumption as to the number of wells that potentially could 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 potential future drilling activities based on an 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. The unbooked drilling location disclosure contained in this presentation was prepared in accordance with COGEH by a non‐independent qualified reserves evaluator as defined in NI 51‐101.



Slide 35

• Type curves. TransGlobe has presented certain type curves and well economics for the Harmattan area type wells and the Company's South Harmattan 2‐20 well. The type curves are TransGlobe's internally prepared estimates of theproduction decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves presented are based on production history from analogous Cardium developments located in close proximity to theHarmattan area and the Company's South Harmattan 2‐20 well. Individual wells may be higher or lower but over a larger number of wells, TransGlobe expects the average to come out to the type curve. Over time type curves can and willchange based on achieving more production history on older wells or more recent completion information on newer wells. The type curve disclosure contained in this presentation was prepared in accordance with COGEH by a non‐independent qualified reserves evaluator as defined in NI 51‐101. The following sets out the key inputs underlying the type curves and well economics on slide 19:

Type Curve Inputs1‐Mile Type Well 2‐Mile Type Well

Drill, complete, equip, and tie‐in capital (US$MM) 2.0 3.1EUR (Raw gas) (Bcf) 0.4 0.8EUR (MMBoe) 0.2 0.4Opex ($/boe) 5.35 5.24Hz length (m) 1,500 3,100Frac intensity (T/m) 0.4 0.4

• Economic assumptions. The following sets out the key assumptions underlying the calculation of certain financial outlook and oil and gas metrics disclosed in this presentation:‒ Oil Price ‐ $55 USD/bbl WTI with a $5 USD/bbl differential to Edmonton Light, flat for 8 years then escalating 2%/year

‒ Gas Price ‐ $1.13 USD/MMbtu flat for 8 years then escalating 2%/year

‒ Royalties as per the Alberta Modernized Royalty Framework (5% until revenue reaches C*)

‒ Operating costs of $968 USD/well*month, $5.58 USD/bbl oil, $0.76 USD/Mcf gas



Slide 36

bbls barrelsMbbl thousand barrelsMMbbl million barrelsMbbl/d thousand barrels per dayboe barrels of oil equivalent of natural gas, on the basis of one barrel of oil or NGLs for six thousand cubic feet of natural gasMboepd thousand barrels of oil equivalent per dayMMboe million barrels of oil equivalentBopd barrels of oil per dayMbopd thousand barrels of oil per dayMcf/d thousand cubic feet per dayMMcf/d million cubic feet per dayBcf billion cubic feetNGL Natural Gas LiquidsMM million

Certain Defined Terms• Product types. All of TransGlobe's reserves disclosed in this presentation 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. Conventional natural gas means natural gas that has been generated elsewhere and has migrated as a result of hydrodynamic forces and is trapped in discrete accumulations by seals that may be formed by localized structural, depositional or erosional geological features. Natural gas liquids means those hydrocarbon components that can be recovered from natural gas as a liquid, including ethane, propane, butanes, pentanes plus, and condensates.

• "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. • "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated

proved plus probable reserves. • "Possible" reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the actual remaining quantities recovered will equal or exceed the sum of the estimated

proved + probable + possible reserves. • "Gross Reserves" are the Company's working interest (operating and non‐operating) share before deduction of royalties and without including any royalty interests of the Company. • "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of

drilling a well) to put the reserves on production. • "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut‐in, they must have previously

been on production, and the date of resumption or production must be known with reasonable certainty. • "Developed Non‐Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut‐in, and the date of resumption is unknown. • "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of

production. They must fully meet the requirements of the reserves classifications (proved, probable, possible) to which they are assigned. • The following abbreviations used in this presentation have the meanings set forth below:

"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.


For additional information contact us at:Phone: +1 (403) 264 9888

Email: investor.relations@trans‐globe.com

www.trans‐globe.com

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