0

Investor Presentation

May 2019

A Peru Focused Oil CompanyDelivering production growth and high impact exploration

Ticker TSXV: TAL AIM: PTAL

1

Summary

■ London AIM and TSX-V listed Peruvian oil and gas company

■ Strong balance sheet with no debt, crude prices off Brent, favorable fiscal regime

■ Achieved first production in June 2018 under budget and ahead of schedule

■ Currently producing >3,000 bopd from two wells

■ Third oil producer spud April 21st to reach 5,000 bopd by June, already at TD

■ Low cost production with >10,000 bopdby early 2020

■ Bretaña Field - Potential to increase 2P recovery factor from 12% to 24%

■ Block 107 - four leads that, combined with Osheki prospect, have an unriskedhigh estimate of prospective resources of 4.6 billion barrels of oil

■ Management and technical team with in depth expertise and proven track record in Peru

Company Overview

Significant Progress

to Date

Substantial Upside

Potential

Management

Experience

A balanced portfolio with ongoing production growth & high impact exploration

Ecuador Colombia

Brazil

Pacific

Ocean

Oil PipeGas PipeGas Pipe (construction)

Petrotal Blocks

River System

BLOCK 95

BLOCK 107

Bol

ivi

a

Blocks under Contract

Area under TEAAvailable BlocksArea Approved for TEA- ContractArea under Evaluation for TEA – Contract

Area for TEA

TEA = Technical Evaluation Agreement

LEGEND Bol

ivia

Lima

Lima –Pucallpa Road

Liquids Pipe

Tarma

Cerro

de

Pasco

Tingo

María

Huanuco

Pucallpa

Yurimaguas

BLOCK 133

Saramuro

2

Peru: Country Overview

■ Stable & Growing Pro-Business Country

– 5.9% average GDP growth over the past decade

• Projected 3.8% average over next two years

– Democratic, investment grade government with stable /

positive outlook: A3 (Moody’s) / BBB+ (S&P and Fitch)

– Standardized contracts signed into law by supreme decree

– Excellent fiscal/royalty terms and tax regime

• Royalty 5-20% based on production (est. 8.25% at peak)

• Corporate tax 32% (>$310mm in NOL’s to offset tax

liability for next 4-5 years)

■ Established Oil & Gas Industry

– Domestic production of 127kbopd with domestic

consumption of 259kbopd (2017, Source:BP)

– Established infrastructure with capacity and transparent

pricing

– Operators include Pluspetrol, CNPC, Repsol, Hunt, CEPSA,

Perenco, Ecopetrol, Anadarko, Tullow, Shell, GeoPark

– Oilfield services: Baker Hughes, Parker Drilling, Halliburton,

Schlumberger, Weatherford, ENI / Petrex

Talara Refinery: Key Market for Bretaña Oil

Peru Oil Consumption

~$3B expansion & upgrade, expected completion 2020

Source: BP Statistical Review of World Energy (2018)

50

100

150

200

250

300

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

kb

op

d

Peru oil consumption (kbopd)

3

Portfolio Overview

Bretaña (Block 95) (100% WI)

■ 17.9 MMBO 1P reserves(1) from OOIP of 199 MMBO (9% RF)

■ 39.4 MMBO 2P reserves(1) from OOIP of 330 MMBO (12% RF)

■ 78.7 MMBO 3P reserves(1) from OOIP of 500 MMBO (16% RF)

■ 2P reserves NPV-10 increased by ~90% to $535 million

– Mostly due to optimizing operations, with additional potential

savings identified

■ Initial five oil producers will target approximately 25 MMBO of 2P reserves(1)

■ Production estimated to reach 5,000 bopd by mid 2019, and exceed 10,000 bopd in early 2020

Block 107/133 (100% WI)

■ 534 MMBOE(2) at Osheki prospect located in the Ucayali basin

– On trend with several large fields

■ Several leads to be de-risked by Osheki that combined could contain 4.6 BBO(3) of unrisked prospective recoverable resources

■ Farmout process underway – targeting first exploration well in early 2020

1) NSAI Assessment, effective date of December 31, 2018, gross including oil used in the field in each category

2) Mean Prospective estimate NSAI Resource Assessment, effective date of June 30, 2018

3) Forecast only. Actual results may differ due to a number of factors. See “Disclaimers – Forward-Looking Information”.

A balanced portfolio with ongoing production growth & high impact exploration

4

Bretaña, Single Location Next to River Minimizes Costs

5

■ Large oil field with recent first production

– 100% oil production with nominal gas

– First production as of June 2018, ahead of schedule and

under budget

– Second oil producer initial rate of 2,250 bopd, on time and

on budget (IP 20 days 2,400 bopd)

– Third oil producing well expected online in June 2019

– 2P development targeting plateau >10,000 bopd from

11 oil producing wells by 2020

– While 3P development approaches 20,000 bopd with 18

oil wells in a 3P case

– Export routes and commercial contracts in place

■ Development plan in phases

– Increases plant capacity

• 6,000 bopd by YE 2018

• 12,000 bopd by YE 2019

• 24,000 bopd by YE 2020

– As production targets are met*

• YE 2018 production of 2,000 bopd

• YE 2019 production of 10,000 bopd

• YE 2020 production of 20,000 bopd*

Bretaña: Large Oil Field Under Development

BN 95-2-2-2XD

*Assumes ongoing drilling and increased recovery beyond 2P case

6

Bretaña Processing Capacity Phases for 2P Case

LTT5KBOPD & 9KBWPD

CPF220KBOPD & 80KBWPD

CPF1 10KBOPD & 40KBWPD

CPF320KBOPD & 120KBWPD

7

Bretaña’s Existing Two Wells FastTrack LTT Production

8

■ Seven wells now define structure and continuity of reservoir

– Consistent correlations across the field

– No variation in petrophysical properties

■ Latest 2XD well net pay of 18.7 meters, as per prognosis(1)

– Net-to-Gross (NTG) pay estimate of 78%

– NSAI’s NTG pay estimates for the 1P, 2P, and 3P categories

are 50%, 68%, and 86%, respectively

– The higher the NTG the larger the OOIP

■ Modern 3D seismic acquired in 2014

– Simple 4 way closing anticline

– Good velocity control for depth conversion

■ Consistent oil-water contact (OWC) across the structure

– Consistent OWC supported by petrophysics and pressure data

Bretaña Field: Limited Number of Wells Needed(2)

1) Internal estimate of net pay and NTG

2) Company plans to install ESP’s in all its horizontal oil wells, starting with the BN95-3H well

First Five Well Will Allow Us to Prove Up +22 MMBO of Reserves

9

Optimum Bretaña Production Plan

0

2,000

4,000

6,000

8,000

10,000

12,000

01-Apr 01-May 01-Jun 01-Jul 01-Aug 01-Sep 01-Oct 01-Nov 01-Dec

BOPD

LTT OIL

2WD

CPF1

1XD+2XD

3H

1XD+2XD+3H

4H+1XD

All Wells

4H+1XD

1WD(wo)+1XD+2XD+3H

3WD

2XD-ST+4H+1XD

Commissioning

Third Week NovExpected Well Completion

2XD: mid-April

3H: mid-June

2WD: mid-July

1WD(wo): August

4H: October

2XD-ST: mid-November

3WD: mid-December

1XD(wo): December

Production Facilities Capacity

LTT: 6 MBOPD x 9 MBWPD (until Jul-2019)

LTT+2WD: 6 MBOPD x 20 MBWPD (Jul to Nov-2019)

CPF1: 12 MBOPD x 40 MBWPD (from Dec-2019)

Plan to Exit 2019 at >10,000 BOPD

10

3H Well: Continue Executing and Optimizing Timeline

11

Schematic Structural Cross Section Bretaña Field

Envidia Prospect with 5.6 MMBO(2)

of Mean Prospective Resources

OOIP NSAI (1)

1P 199 MMBO

2P 329 MMBO

3P 500 MMBO

PetroTal’s Internal Updated Estimate of Bretaña’s OOIP is ~367 MMBO

Bretaña’s OOIP (*)

(*) OOIP = Original Oil In Place

1) NSAI Assessment, effective date of December 31, 2018, gross including oil used in the field in each category

2) Mean Prospective estimate NSAI Resource Assessment, effective date of June 30, 2018.

Bretaña Oilfield is ~15 km long

12

Bretaña Detailed Structural Cross Section

NW SE

3H BN-2XD BN 1WD(current wáter

disposal well)

BN-1XD B SUR 1X

OWC

-2609 m

717 m 785 m 6437 m487 m

Cross Section Shows Continuity of Vivian Formation and Excellent Oil Sands in 1WD Well

12

13

Bretaña’s Analog Fields Point at Higher Recoveries

■ Bretaña estimated 2P recovery factor of 12% is based on data set of three wells & one core

■ Every analog field in region has achieved >12% recovery factor (ranging from 19.1% to 41.6%(1))

■ NSAI has already increased the 1P recovery factor by 23%, from 7.4% to 9.1%(2)

■ These analog fields benefitted from horizontal reservoir barriers that slowed down the water coning – also seen in Bretaña’s core

■ Management believes that Bretaña has similar reservoir barriers and could deliver >24% Recovery Factor

Reservoir Transmissibility

Analog Table(1,2)Bretaña

#1

Capahuari N.

#2

Shiviyacu

#3

Carmen

#4

Yanayacu

#5

San Jacinto

#6

Jibaro/Jibarito

API (o Gravity) 19.4o 35.2o 20.2o 19.7o 19.0o 12.5o 10.8o

OOIP (MMBO) 330 48 331 45 65 209 414

EUR / 2P (MMBO) 39.4 20.0 120.8 13.5 23.6 46.3 103.2

Recovery (%) 12.0% 41.6% 36.4% 29.9% 36.1% 22.2% 24.9%

1) Perupetro S.A. databank for all analog fields

2) NSAI Reserves Report (December 31, 2018) for Bretaña

3) Reservoir Transmissibility = Permeability x Net Thickness / Oil Viscosity.

Larger font projection layout

14

Netback per Barrel at $65 Brent

With Increased Volumes Unit Lifting and G&A Will be Reduced

0

10

20

30

40

50

60

70

Brent BrentDiscount

Transport Royalty Lifting G&A Netback Target 2019Netback

Target 2020Netback

$/b

bl

4Q20181

,00

0 b

op

d

4,5

00

bo

pd

11

,00

0 b

op

d

15

Export Route Optionality for Bretaña Oil 1. Iquitos Refinery (1,200 bopd): barging distance of 370 km.

Delivery: 3 days.

2. Bayovar Port (20,000 bopd, to reach Talara Refinery, La PampillaRefinery in Lima, or export markets):

a. Barging 460 km to Saramuro, 856Km through the PeruvianNorthern Pipeline (ONP) to Bayovar Port. Delivery: 4 days.

b. Barging 740 km to Yurimaguas and trucking 940Km toBayovar Port. Delivery: 10 days.

3. Conchan Refinery in Lima (1,500 bopd): barging 700 km to Pucallpaand trucking 750 km to Lima. Delivery: 10 days.

4. Talara Refinery (20,000 bopd): barging 460 km to Saramuro, 856km through the Peruvian Northern Pipeline (ONP) to Bayovar Port.Then trucking or barging to Talara Refinery. Ideal market aftermodernization project is complete at the end of 2020.

5. El Milagro Refinery (1,500 bopd): barging distance of 740 km toYurimaguas port and trucking 540 km. Delivery: 8 days.

6. Pucallpa Refinery (2,500 bopd): barging 700 km to Pucallpa.Delivery 7 days.

7. Exports via Perenco’s Manati FSO (20,000 bopd): barging 500 km.Delivery: 5 days.

Will Access ONP Pipeline Once We Reach 5,000 bopd by Mid June 2019

Ecuador Colombia

Brazil

Pacific

Ocean

Oil PipeGas PipeGas Pipe (construction)

Petrotal Blocks

River System

BLOCK 95

BLOCK 107

Bol

ivi

a

Blocks under Contract

Area under TEAAvailable BlocksArea Approved for TEA- ContractArea under Evaluation for TEA – Contract

Area for TEA

TEA = Technical Evaluation Agreement

LEGEND Bol

ivia

Lima

Lima –Pucallpa Road

Liquids Pipe

Tarma

Cerro

de

Pasco

Tingo

María

Huanuco

5

4

2

1

3

7

Pucallpa

Yurimaguas

BLOCK 133

Saramuro

6

Larger font projection layout

16

Accessing Diversified Markets to Guarantee Oil Sales

PetroTal Plans to enter the ONP by June 2019, but will continue adding other markets

17

Potential Resource

■ Osheki Structure is a sub-thrust play similar to Cusiana complex in the Llanos Foothills of Colombia

• Mean Estimate Unrisked prospective resources of 534 MMBO

■ 2-D seismic completed with drilling permits approved

■ De-risked with new 3D Geologic Model supporting Cretaceous reservoirs with oil charge from high quality Permian source rocks

Exploration Strategy

■ Farm out process underway

■ Targeting first exploration well in 2020

1) Mean estimate NSAI Resource Assessment, effective date of June 30, 2018

2) High estimate NSAI Resource Assessment, effective date of June 30, 2018.

High Estimate Unrisked

Prospective Resources (MMBO)

Mean Estimate Unrisked

Prospective Resources (MMBO)

Osheki 1,289 534

Bajo Pozuzo 2,634 1,016

San Juan 192 147

Constitucion 98 78

Lead A 369 39

Total 4,582 1,815

Block 107 - Osheki Prospect Ready to be Drilled

18

Commitment to Sustainable Operations

CSR Team Engaged with Local Communities

• In Block 95 at Bretaña with 2,000 inhabitants, as well as the 18 communities of the PuinahuaDistrict

• In Block 107 with the indigenous Ashaninkaand Yanesha ethnic groups, as well as foreign settlers

Rebuilding Identity of Indigenous

Communities

• Promoting processes to rebuild their identity

• Strengthening indigenous organizations

• Working with a network of NGOs, producers, and local and central government organizations

Investments in Sensitive Areas

• Pacaya-Samiria National Reserve

• San Matías–San Carlos Forest Reserve

• Oxampampa-Ashaninka-Yanesha Biosphere Reserve

Our Strategy

• Sustainability of the projects based on strategic

relationships with the local population and

NGOs

• Being active members of the committees that

manage the reserved or protected areas

• Having a team with experience working in

sensitive areas while caring for the environment

• To be recognized as a conscious user of the

land that is committed to and respected for

contributing to local development.

Four Pillars of CSR: Commitment to Employees, Communities, Environment, and Ethics

▪ 5 full time CSR

employees

▪ CSR team with ~75

years of combined

experience

▪ Annual budget of

~$900K

▪ CSR is part of the Key

Performance Indicators

of all employees and

management

▪ Commitment at Board

level. HSE & CSR

Committee approves

the guidelines, and the

Board is provided

monthly updates

19

Summary

Bretaña field development plan provides for rapid production and associated cash

flow growth

• Current production > 3,000 bopd

• >5,000 bopd expected by June 2019

• Ramping up to >10,000 bopd in 2020

• Strong netbacks at $65 oil with FCF by mid-2020

A well defined low risk development with significant potential upside

• Based on other in-country analog fields, Bretaña may deliver >24% Recovery Factor

resulting in doubling the current estimate of 39.8 MMBO(1) of 2P reserves

• Five wells target over 22 Mmbo of 2P Reserves

A balanced portfolio with ongoing production growth and high impact exploration

• Osheki Prospect is drill ready targeting unrisked prospective resource 534 MMBO(2)

o Farm out process underway

• Looking at synergistic projects to drive additional value

3

1

2

1) NSAI Assessment, effective date of June 30, 2018

2) Mean estimate NSAI Resource Assessment, effective date of June 30, 2018.

20

Manolo Zuniga

(713) 609-9101

mzuniga@petrotal-corp.com

Greg Smith

(713) 609-9026

gsmith@petrotal-corp.com

PetroTal

Suite 500

11451 Katy Freeway

Houston, TX 77079

Legal Counsel (Canada): Stikeman Elliott LLP

Independent Reservoir Engineering Firm: Netherland Sewell & Associates

Audit Firm: Deloitte (Canada)

Ltd.

21

Appendix

22

Updated 2019 Drilling Schedule for 2P Reserves

3WD-CD well will dispose of formation water and cuttings, allowing for $1 million and 5 days in savings in future wells

Need to Order CSG, WH, 7" TBG, LHWH, TBG, PKR,

PerforationsCsg, WH, LH, Pkr Csg, ESP, LH, AICD's

WH, Csg, Inject

Pump, tbgWH, Tbg, ESP,

Have Ordered Csg, Tbg, AICD Csg , Tbg, AICD

2019

MOB 2XD - Dir Only 3H (500m) 2WD

WO 1WD

(Converto to Prod) 4H (1000m) ST 2XD H 3WD - CD

WO 1XD

(ESP) Total

Well Type MOB H H WD WO H H WD WO

Days 55 53 55 35 15 58 37 35 15 358

Cost $,000 MM $4,700 $9,800 $13,200 $7,600 $1,500 $14,000 $8,700 $8,500 $1,500 $69,500

Wells Drilled 1 2 4 3 1st 5 5

Start Date 21-Dec-18 27-Feb-19 21-Apr-19 15-Jun-19 20-Jul-19 04-Aug-19 01-Oct-19 07-Nov-19 12-Dec-19 27-Dec-19 27-Dec-19

Need to OrderTbg, ESP, LH, AICD,

Csg, WS

WH, Csg, ESP,

AICD's, LH

WH, Csg, ESP, AICD's,

LH

WH, Csg, ESP,

AICD's, LH

WH, Csg, ESP,

AICD's, LH

WH, Csg, ESP, AICD's,

LH

WH, Csg, ESP,

AICD's, LH

Have Ordered

2020

5H w/o Pilot 1000m 6H 7H

Build 4 Cellars &

Pilot Supports 8H 9H 10H 11H Total

Well Type H H H MOB H H H H

Days 45 45 45 60 45 45 45 45 330

Cost $,000 MM $13,000 $13,000 $13,000 $3,120 $13,000 $13,000 $13,000 $13,000 $94,120

Wells Drilled 6 7 8 9 10 11 12 7

Start Date 27-Dec-19 10-Feb-20 26-Mar-20 10-May-20 09-Jul-20 23-Aug-20 07-Oct-20 21-Nov-20 05-Jan-21 05-Jan-21 05-Jan-21

23

Board of Directors and Senior Management

Manolo Zúñiga - Chief Executive Officer and Director

• Native Peruvian with >30 years of experience in petroleum

engineering

• Started career with Occidental in Bakersfield & Block 192 in Peru

• Founder and former CEO of BPZ Energy

• Helped shape policies promoting oil investments in Peru,

including the current long-term test regulation

Mark McComiskey (Independent)

• Founding Partner of Vanwall Capital, LLC. and was a Managing

Partner of Prostar Capital Ltd

• Former Principal of Clayton, Dubilier & Rice, Inc. He was an

associate at the law firm of Debevoise & Plimpton, LLP

• Holds a J.D., magna cum laude, from Harvard Law School and an

A.B. degree, magna cum laude, in Economics from Harvard

College

Gary Guidry

• President & CEO of Gran Tierra with >35 years as a Professional

Engineer with APEGA

• Former President & CEO of Caracal Energy, Orion O&G,

Tanganyika Oil

• Senior operational roles at Occidental in Nigeria / West Africa,

Yemen and Venezuela

Ryan Ellson

• >15 years experience as a Chartered Accountant

• CFO of Gran Tierra

• Former Head of Finance at Glencore E&P Canada and VP Finance

at Caracal Energy

Douglas Urch (Independent)

• Chartered Professional Accountant with >35 years experience in

international oil & gas

• Executive VP & CFO of Bankers Petroleum, former VP & CFO of

Rally Energy

Gavin Wilson

• Investment Manager for Meridian

• Former founder & manager of RAB Energy & RAB Octane listed

investment funds

Senior Management

Greg Smith - Executive Vice President & Chief Financial Officer

• >20 years oil and gas experience, both US and international

• Served as CFO for PetroTal LLC prior to leading the amalgamation

with Sterling Resources and assets in Peru

• Executive level finance and investor relations experience at Energy

XXI and BPZ Energy

• Significant transaction and capital markets experience

Estuardo Alvarez-Calderon – VP E&P

• >35 years of oil and gas experience with focus on exploration and

new discoveries, and bringing those fields to initial production

• Various senior roles across the Americas for Occidental

• Former VP of Exploration and Production at BPZ Energy

24

Disclaimers Forward-Looking Information

Certain information included in this presentation constitutes forward-looking information under applicable securities legislation. Forward-looking information typically containsstatements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project” or similar words suggesting future outcomes or statementsregarding an outlook. Forward-looking information in this presentation may include, but is not limited, statements about: the Company’s corporate strategy; potentialdevelopment opportunities and drilling locations; expectations and assumptions concerning the success of future drilling, development, transportation and marketing activities;access to diversified markets; intention of engaging joint venture partners to drill the Osheki prospect; future debt and equity financings and use of proceeds; the performance ofexisting wells; the performance of new wells; decline rates; recovery factors; the successful application of technology and the geological characteristics of properties; capitalprogram and capital budgets; future production levels; cash flow; debt; primary and secondary recovery potentials and implementation thereof; potential acquisitions; regulatoryprocesses; drilling, completion and operating costs; commodity prices and netbacks; realization of anticipated benefits of acquisitions; NPV-10 valuations; and CSR activitiesand commitments. Statements relating to “reserves” and “prospective resources” are also deemed to be forward looking statements, as they involve the implied assessment,based on certain estimates and assumptions, that the reserves or prospective resources described exist in the quantities predicted or estimated and that the reserves orprospective resources can be profitably produced in the future.

The forward-looking information is based on certain key expectations and assumptions made by the Company, including, but not limited to, expectations and assumptionsconcerning the ability of existing infrastructure to deliver production and the anticipated capital expenditures associated therewith, reservoir characteristics, recovery factor,exploration upside, prevailing commodity prices and the actual prices received for PetroTal’s products, the availability and performance of drilling rigs, facilities, pipelines, otheroilfield services and skilled labour, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the accuracy of PetroTal’s geologicalinterpretation of its drilling and land opportunities, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, theperformance of new wells, the Company’s growth strategy, general economic conditions, availability of required equipment and services and prevailing commodity prices.Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placedon the forward-looking statements because the Company can give no assurance that they will prove to be correct. Readers are cautioned that the foregoing list is not exhaustiveof all factors and assumptions which have been used.

Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materiallyfrom those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g.,operational risks in development, exploration, production and transportation; delays or changes in plans with respect to exploration or development projects or capitalexpenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety,environmental and regulatory risks), commodity price and exchange rate fluctuations, legal, political and economic instability in Peru, access to transportation routes andmarkets for the Company’s production, changes in legislation affecting the oil and gas industry, and uncertainties resulting from potential delays or changes in plans withrespect to exploration or development projects or capital expenditures. Please refer to the risk factors identified in the Company’s annual information form and management’sdiscussion and analysis for the year ended December 31, 2018 which are available on SEDAR at www.sedar.com. Forward-looking information is 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 proposedmanagement and described in the forward-looking information. The forward-looking information contained in this presentation is made as of the date hereof and the proposedmanagement undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unlessrequired by applicable securities laws. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement.

Financial Outlook

This presentation contains future-oriented financial information and financial outlook information (collectively, “FOFI”) about PetroTal’s prospective results of operations,production, cash flow, netbacks, NPV-10, operating costs, royalties, corporate tax and components thereof, all of which are subject to the same assumptions, risk factors,limitations and qualifications as set forth in the above paragraphs and the assumption outlined in the Non-GAAP measures section below. FOFI contained in this presentationwas made as of the date of this presentation and was provided for the purpose of providing further information about PetroTal’s anticipated future business operations. PetroTaldisclaims any intention or obligation to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unlessrequired pursuant to applicable law. Readers are cautioned that the FOFI contained in this presentation should not be used for purposes other than for which it is disclosedherein.

25

Disclaimers (continued) Oil and Gas Advisories

Reserves Disclosure. The reserve estimates contained herein were derived from a reserves assessment and evaluation prepared by Netherland Sewell & Associates, Inc.(“NSAI”), a qualified independent reserves evaluator, with an effective date of December 31, 2018 (the “NSAI Reserves Report”). The NSAI Reserves Report has been preparedin accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and theCanadian Oil and Gas Evaluation Handbook (the “COGE Handbook”). The reserve estimates contained herein are estimates only and there is no guarantee that the estimatedreserves will be recovered. Volumes of reserves have been presented based on a company interest. Readers should give attention to the estimates of individual classes ofreserves and appreciate the differing probabilities of recovery associated with each category as explained herein. The estimates of reserves for individual properties may notreflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

Resources Disclosure. The prospective resource estimates contained herein were derived from a resource assessment and evaluation prepared by NSAI, a qualifiedindependent reserves evaluator, with an effective date of June 30, 2018 (the “NSAI Resources Report”). The NSAI Resources Report has been prepared in accordance withdefinitions, standards and procedures contained in NI 51-101 and the COGE Handbook. Prospective resources are the quantities of petroleum estimated, as of a given date, tobe potentially recoverable from undiscovered accumulations by application of future development projects. All of the prospective resources have been classified as light oil witha gravity of 46 degrees API. There is uncertainty that it will be commercially viable to produce any portion of the resources in the event that it is discovered. “UnriskedProspective Resources” are 100% of the volumes estimated to be recoverable from the field in the event that it is discovered and developed. NSAI has determined that a 16%chance of discovery is appropriate for the prospective resources based on an assessment of a number of criteria. The estimates of prospective resources provided in thispresentation are estimates only and there is no guarantee that the estimated prospective resources will be discovered. If discovered, there is no certainty that it will becommercially viable to produce any portion of the prospective resources evaluated. Not only are such prospective resources estimates based on that information which iscurrently available, but such estimates are also subject to uncertainties inherent in the application of judgmental factors in interpreting such information. Prospective resourcesshould not be confused with those quantities that are associated with contingent resources or reserves due to the additional risks involved. Because of the uncertainty ofcommerciality and the lack of sufficient exploration drilling, the prospective resources estimated herein cannot be classified as contingent resources or reserves. The quantitiesthat might actually be recovered, should they be discovered and developed, may differ significantly from the estimates herein. The prospective resources estimates that arereferred to herein are risked as to chance of discovery. Risks that could impact the chance of discovery include, without limitation, geological uncertainty, political and socialissues, and availability of capital. In general, the significant factors that may change the prospective resources estimates include further delineation drilling, which could changethe estimates either positively or negatively, future technology improvements, which would positively affect the estimates, and additional processing capacity that could affectthe volumes recoverable or type of production. Additional facility design work, development plans, reservoir studies and delineation drilling is expected to be completed byPetroTal in accordance with its long-term resource development plan.

Oil and Gas Metrics. This presentation contains metrics commonly used in the oil and natural gas industry, such as netback and NPV-10. “Netback” equals total petroleum salesless quality discount, lifting costs, transportation costs and royalty payments calculated on a bbl basis. “NPV-10” or similar expressions represents the net present value (net ofcapex) of net income discounted at 10%, with net income reflecting the indicated oil, liquids and natural gas prices and IP rate, less internal estimates of operating costs androyalties. It should not be assumed that the future net revenues estimated by PetroTal’s independent reserves evaluators represent the fair market value of the reserves, norshould it be assumed that PetroTal’s internally estimated value of its undeveloped land holdings or any estimates referred to herein from third parties represent the fair marketvalue of the lands. These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented byother companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and toprovide shareholders with measures to compare Tamarack’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derivedfrom the metrics presented in this presentation, should not be relied upon for investment or other purposes.

Reserve Categories. Reserves are classified according to the degree of certainty associated with the estimates. Proved reserves (1P) are those reserves that can be estimatedwith 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 (2P) arethose 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 thanthe sum of the estimated proved plus probable reserves. Possible reserves (3P) are those additional reserves that are less certain to be recovered than probable reserves. It isunlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Resource Categories. Prospective resources are classified according to the degree of certainty associated with the estimates. The following classification of prospectiveresources used in the presentation: Low Estimate (or 1C) means there is at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed thelow estimate. Best Estimate (or 2C) means there is at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. HighEstimate (or 3C) means there is at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

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Disclaimers (continued) BOE Disclosure. The term barrels of oil equivalent (“BOE”) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel(6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent avalue equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil.

Analogous Information. Certain information in this document may constitute "analogous information" as defined in NI 51-101, including, but not limited to, information relatingto areas, wells and/or operations that are in geographical proximity to or on-trend with lands held by PetroTal and production information related to wells that are believed to beon trend with PetroTal's properties. Such information has been obtained from government sources, regulatory agencies or other industry participants. Management of PetroTalbelieves the information may be relevant to help define the reservoir characteristics in which PetroTal may hold an interest and such information has been presented to helpdemonstrate the basis for PetroTal's business plans and strategies.

However, to PetroTal’s knowledge, such analogous information has not been prepared in accordance with NI 51-101 and the COGE Handbook and PetroTal is unable to confirmthat the analogous information was prepared by a qualified reserves evaluator or auditor. PetroTal has no way of verifying the accuracy of such information. There is no certaintythat the results of the analogous information or inferred thereby will be achieved by PetroTal and such information should not be construed as an estimate of future productionlevels. Such information is also not an estimate of the reserves or resources attributable to lands held or to be held by PetroTal and there is no certainty that the reservoir dataand economics information for the lands held or to be held by PetroTal will be similar to the information presented herein. The reader is cautioned that the data relied upon byPetroTal may be in error and/or may not be analogous to such lands to be held by PetroTal.

Initial Production Rates. Any references in this document to test rates, flow rates, initial and/or final raw test or production rates, early production, test volumes and/or "flush"production rates are useful in confirming the presence of hydrocarbons, however, such rates are not necessarily indicative of long-term performance or of ultimate recovery.Such rates may also include recovered "load" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregateproduction for PetroTal. In addition, the resource play which may be subject to high initial decline rates. Such rates may be estimated based on other third party estimates orlimited data available at this time and are not determinative of the rates at which such wells will continue production and decline thereafter.

OOIP Disclosure. The term original-oil-in-place (“OOIP”) is equivalent to total petroleum initially-in-place (“TPIIP”). TPIIP, as defined in the COGE Handbook, is that quantity ofpetroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in knownaccumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is nocertainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of suchundiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce anyportion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered.

US Disclaimer. This presentation is not an offer of the securities for sale in the United States. The securities have not been registered under the U.S. Securities Act of 1933, asamended, and may not be offered or sold in the United States absent registration or an exemption from registration. This presentation shall not constitute an offer to sell or thesolicitation of an offer to buy nor shall there be any sale of the securities in any state in which such offer, solicitation or sale would be unlawful.

All figures in US dollars unless otherwise denoted.

Abbreviations bbl barrel API an indication of the specific gravity of crude oil measured on the American Petroleum Institute gravity scale. Liquid

petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil

bopd barrel of oil per day LTT Long term test

MMBO million barrels of oil Mcf million cubic feet

NGL natural gas liquids Bcf/

d

billion cubic feet per day

BNBOE billion barrels of oil equivalent IRR internal rate of return

NGL natural gas liquids WI working interest

NPV net present value EUR estimated ultimate recovery