A Lundin Group Company

Internationally Focused Upstream CompanyInternational Petroleum Corp.

NC00059 02.18

March 2018

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3 p

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International Petroleum Corp.Corporate Strategy

Deliver operational excellence

Maintain financial resilience under low oil prices

Maximize the value of our resource base

Grow through M&A

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International Petroleum Corp.Resource Growth(1)

January 2017 June 2017 January 2018

MM

boe

>4x

0

50

100

150

200

2P

2C

2C

2P

29.4

17.5

129.1

63.4

192.52P + 2C

1) See MD&A and MCR

Malaysia, 9.1 Netherlands, 1.8

France, 17.6Canada Gas, 73.2

57%

21%

14%1%

7%

Canada Oil, 27.4

Quadrupled 2P reserves to 129.1 MMboe

Increased reserves life index (RLI) from 8 to 11 years

IPC Net 2P Reserves129.1 MMboe

More than tripled Contingent Resource base

Bertam Infill wells, 1.4

France other, 11.8

France Villeperdue West, 4.2

Canada Oil , 7.4

Canada Gas Drilling, 38.6

IPC Net 2C Contingent Resources63.4 MMboe

11.8 %

18.6%

6.6%

2.2%60.8%

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International Petroleum Corp.2018 Guidance - Production

20,00010,300 boepd

30,000

40,000

10,000

02017

>3x

Netherlands

Canada Gas

Canada Oil

Oil

Gas

France

Malaysia

Production Forecast by Country

IPC Production Guidance 2018

Production guidance for 2018: 30,000 to 34,000 boepd net

Key Considerations Assumes provisions for FPSO downtime and ESP outage Infill well performance Contribution from Q4 drilling in Canada expected Q1 2019

2018 Guidance Range

2018Guidance

Net

Pro

duct

ion

(boe

pd)

Q1 Q2 Q3 Q4

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International Petroleum Corp.Operating Costs(1)

2017 Guidance 2017 Actual 2018 Guidance

USD/

boe

-14%

0

5

10

15

2018.8

16.1

12.6

-22%

1) Non-IFRS measure, see MD&A 5

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International Petroleum Corp.Operating Cash Flow(1)

2017 Actual

2) Based upon mid-point 2018 production guidance

2018 Guidance(2)

Mill

ion

USD

0

50

100

150

200

250

138

201

161

233 70 USD/bbl

60 USD/bbl

50 USD/bbl

1) Non-IFRS measure, see MD&A 6

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International Petroleum Corp.2018 Guidance - Capital Expenditure

2018 Budget: 32.2 MUSD

Malaysia

France

Netherlands

Canada

Netherlands – 1.5 MUSD

- Development well (E17)- Maintenance capital

France – 5.7 MUSD

- Paris Basin - Vert-La-Gravelle - Well reactivations - Maintenance capital

Canada – 10.8 MUSD

- Oil drilling and preparation- Maintenance capital

Malaysia – 14.2 MUSD

- Infill wells (carryover from 2017)

2018 Capital Expenditure Guidance: 32.2 MUSD

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International Petroleum Corp.2P Reserves and Net Asset Value(1)

2P Reserves ValuesNPV8

Net Debt NAV NAVper Share

MUS

D

0

200

400

600

800

1,000

1,200 1,151

608Canada

543International

796 9.1 USD/share

355(2)

2) Net debt as at January 5, 2018 (Non-IFRS measure, see MD&A) 1) As at December 31, 2017, after giving effect to the Suffield acquisition, see MD&A and MCR

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International Petroleum Corp.Net Asset Value Per Share vs Share Price(1)

1) See MD&A and MCR

10NAV per share(1)

9

8

7

6

3

2

1

5

0

10

9

8

7

6

3

4

2

1

5

0MayApr Jun Jul Aug

2017 2018Sep Oct Nov Dec Jan Feb

US

D p

er s

har

e

US

D p

er share

01/01/17

01/01/18

~55%discountto NAV

~26%discountto NAV

USD 4.8

USD 9.1

Listing

25.5 M shares purchasedand cancelled at 3.53 USD/share

Canada acquisitionannouncedMalaysia infill and

France 3D seismicannounced

17.5 MMboe CR announced France 3D seismic

completed

Canada acquisitioncompleted

Infill wellsonline

Infill drillingstarts in Malaysia

+89%

USD share price

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International Petroleum Corp.Organic Growth

Canada

Malaysia » 2 infill wells

» Easy Coulee

» South Gibson

» Gas Optimisation

» 2019 oil drilling

» Enhanced oil recovery expansion

» 2020 oil drilling

» Phase 3 Infill wells» I35 prospect

» Villeperdue seismic acquisition

» Vert-La-Gravelle» Villeperdue North

» Merisier

» Villeperdue WestFrance

Executed /on Production

ProjectExecution

in 2018

Future OpportunitiesSanctioned 2 Bertam infills–> drilled and online in early 2018Sanctioned 79km2 3D seismic in France–> acquisition completed in October

2017

Execute first tranche of Glauconiticinfill wells in Canada

2018

Future Opportunities

Mature inventory of Suffield drilling locations to have optionality in 2019Mature next tranche of wellsat BertamVilleperdue West seismic processing,interpretation and development studiesMature Vert-La-Gravelle project to final investment decision (FID)

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IPC - CanadaDiverse Portfolio of Opportunities

2P Oil Reserves (1)

DevelopedDeveloped

Non Producing

Undeveloped

2P Gas Reserves (1)

Developed

Developed Non Producing

Undeveloped

Unrisked Best EstimateContingent Resources (1)

EOR: Water Flood & ASP

Oil Drilling

Gas Drilling

Near term priority on oil development drilling and gas optimisation

N2N enhanced oil recovery project being matured in 2018

Deep inventory of opportunities creates optionality in 2019 and beyond

27.4MMboe

73.2MMboe

46.0MMboe

1) As at January 5, 2018, see MD&A and MCR

45 undeveloped oil drilling locations in 2P reserves base117 undeveloped oil drilling locations in 2C resource base2,540 shallow gas drilling locations

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IPC - Canada2018 Overview

Suffield Development Activity 2018Q1 Q2 Q3 Q4

Mature 2019 opportunities

Environment survey, location scouting

Application for development and appraisals

Drilling operations

CFB SuffieldSuffield

YYY

UUDakota

Jenner

Lundy Lane

West Gibson

Chieftain Hill

Deberg

Gibson Lake

South Gibson Lake

Falcon

N2N

Ram Hill

East Easy Coulee

EasyCoulee

Mature GlauconiticDrillingTargets

Mature GlauconiticDrillingTargets

Mature GlauconiticDrillingTargets

2018 Drilling

Mature ASP Flood Commission & Drilling

North Dieppe

2018 Drilling

South Dieppe

2018 production outlook Underpinned by base decline rates Contribution from 4Q 2018 drilling expected 1Q 2019 Baseline production optimization activities included Screening ongoing to unlock further potential

2018 development programme 10.8 MUSD development programme Targeting drilling commencement in Q4 2018 1 well in Easy Coulee field 5 wells in South Gibson Lake field - 4 horizontal producers - 1 geo-pilot Mature opportunity set for expanded drilling in 2019

~8 USD/boeBase Operating Costs(1)

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One of four focus areas for 2018 development studies

5 wells in base plan – more locations being evaluated for 2019 drilling

~1,000 m dual lateral horizontal wellsOpen hole completionProgressive cavity pumpsMinimal facility work

IPC - CanadaSouth Gibson Lake Development

0 KM 10YYY

UUDakota

Jenner

Lundy Lane

West Gibson

Chieftain Hill

Deberg

Gibson Lake

South Gibson Lake

Falcon

South Dieppe

North Dieppe

N2NRam Hill

East Easy Coulee

South Gibson Lake

Proposed 2018 drilling locations

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IPC - MalaysiaAsset Overview

Hydrocarbon Type2P Reserves Net (1), MMboe

Malaysia

Oil9.1

Malaysia

0 400KMBertam Field – Operated by IPC Light oil offshore development (75% working interest) 2 infill wells online Q1 2018 Good reservoir performance and >99% facility uptime in 2017 Favourable PSC terms and tax pools Secured permanent flagging status for the Bertam FPSO

Management focus Maintain high production uptime Infill drilling and facilities enhancements Near field opportunity review

–

4

8

12

16

20

MM

boe

1) As at December 31, 2017, see MD&A and MCR

+16%+13%

Bertam Field

Bertam Facilities

20162012 2017

+43%

2P Reserves

2P + 2Cgrowth

Cumulative Production2C

Additional infill wells

14

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Cumulative Production to YE 20172P Reserves2C Contingent ResourcesBest Estimate Prospective Resources (Unrisked) / (risked)

MMboe(1)Net Working Interest Basis

7.69.11.4

5.8 / 1.2

Infill A172017 Infill Campaign

2016 Infill A15

Infill A16

Future Infill Opportunities

IPC - MalaysiaDevelopment Upside

2016 - A15 well

2017 - A16/17 wells

2018 and beyond

Successfully executed extended reach development wellWell continues to produce clean oil

Two additional contingent resources identifiedand being matured in 2018 - A-14 near field prospect - I-35 prospect

Completed safely and on schedule Savings of over 3 MUSD vs budgetBoth wells on stream, production rates in line with expectations

1) See MD&A and MCR

I-35A-14

Prospect Areas

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IPC – FranceAsset Overview

1) As at December 31, 2017, see MD&A and MCR

Villeperdue West, 4.2

Merisier, 2.6Paris BasinTriassicOpportunities, 7.1

Aquitaine, 2.1

France2C Contingent Resources

16.0 MMboe(1)

27%

16%44%

13%

–

10

20

30

40

50

60

2002 2016 2017

MM

boe

+123%2P+2CGrowth

+2%+54%

2P ReservesCumulative Production2C

12 contingent resource opportunities 2C:2P ratio 0.9

~40% of resource base being matured via studies in 2018 Villeperdue 3D seimic interpretation and development plan Merisier integrated reservoir study

Horizontal wells at Vert-La-Gravelle have potential to unlock other Triassic opportunities

France

Paris Basin

Aquitaine Basin

Hydrocarbon Type Oil2P Reserves Net (1), MMboe 17.6

France

16

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Vert-La-Gravelle Facility

IPC - FranceVert-La-Gravelle Development Plan Optimisation

VGR-13H

VGR-12H

VGR-10

VGR-9H

VGR-11H

Highest ranked project in Paris Basin portfolio

Vertical well concept sanctioned in 2013 and 2 of 7 wells drilled in 2014/2015

Additional 5 wells were put on hold

Infrastructure in place – total investment to date 23 MEUR

Similar geology to other Triassic reservoirs in IPC’s contingent resource base

Maturation plan

Optimised plan considers three horizontal producers supported by two water injectors Final investment proposal in 2018

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Ville

perd

ueOi

l Fie

ld

3D Seismic Coverage

France

Paris BasinIPC - FranceVilleperdue West Development

3D seismic acquired in 2017Close to existing infrastructureMaterial project for IPC Targeting 4 MMbbl contingent resources(1)

G&G and development studies in 2018

Seismic Localisation - Inline 350

Inline 350

Good contrast:promising zone

undeveloped

Good contrast:producing zone

Top Reservoir

Base Reservoir

1) As at December 31, 2017, see MD&A and MCR18

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22% reduction in per barrel operating costs146 MUSD and 12.6 USD/ boe in 2018

International Petroleum Corp.2018 Highlights

30,000 to 34,000 boe/d

Opportunistic approach to further acquisitions

Capital programme of 32.2 MUSDCompletion of infill drilling in Malaysia and new development drilling in Canada

129.1 MMboe proved and probable (2P) reserves63.4 MMboe contingent (2C) resourcesRLI increased from 8 to 11 years with more than tripled production

Organic Growth

Strong cash flow generation Operating cash flow netback 14 to 20 USD/boe (Brent 50 to 70 USD/bbl)

Resource Base (2)

Production Guidance

Operating costs (1)

Operating Cash Flow (1)

Business Development

Secured permanent flagging statusFPSO Bertam

89% increase in 2P reserves value per shareShareholder Value (2)

1) Non-IFRS measure, see MD&A 2) As at December 31, 2017, after giving effect to the Suffield acquisition, see MD&A and MCR19

AppendixCanada

20

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IPC - CanadaShallow Gas Optimisation

Active well and reservoir management required to unlock potential

Many small interventions => material impact on production

Res

ervo

ir P

ress

ure

Flow

Reservoir PressureFlow

Time

Well able to lift waterwithout intervention

Installsiphon string

Swabbing programmeto remove water

Initialproduction

Removesiphon string

SuffieldWell Stock

~10,800 shallow gas wells

Tubing string installed

With siphon string installed

Cased only - Available for swabbing - Some interventions required

~750

~450

~9,600

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IPC - CanadaSwabbing Programme

WellsActivities

Require interventions to return to swabbing programme - Technical and commercial analysis ongoing

~5,500 wells currently not in swabbing programme

~3,500 wells currently in swabbing programme- Average of 1.6 swabs per well in 2018

2018 Forecast 1.3 MCAD in 2018 programme from <0.2 CAD/Mcf breakeven

Opportunity foradditional swabs in 2018

Swabbing Rig

Swabbing Tool

~400

~5,500

~3,500

~5,500

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IPC - CanadaGas Optimisation Programme

Wells

Inactive siphon string wells with no/low flow - Candidates for removal to restart production

Siphon strings in place- Monitoring ongoing for optimal intervention timing

Active programme to efficiently manage wells

~80

~125

~370

2018 budget 0.6 MCAD - Targets portion of activities shown

Coil tubing clean outs- Wash of well bore to remove mud/debris

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IPC - CanadaFurther Optimisation Potential

Shut inWells

Mudplugs

Water HandlingUpgrades

Workovers

Wells currently closed in

Candidates for workover and reactivation

Gas production lines currently blocked orrestricted due to plugging

Optimisation, debottlenecking and increasing water handling capacity

Significant potential under review

Limited investments in prior years

Many small additions = material impact

Gas

Gas

Gas

Oil

Note: Activities shown are not included in 2018 forecasts

Oil

Oil

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UU pool Technology proven in Suffield area Pilot commenced in 2007 Surfactant injection stopped in 2013

YYY pool Same geologic formation and fluid as UU Chemical injection commenced 2015 but has been sub-optimal Good response observed during 2H 2017

N2N expansion Analagous to UU and YYY pools Facility in place (22 MCAD capital), only commissioning and tie-in work remains Development plan review and optimisation a focus area in 2018

IPC - CanadaEnhanced Oil Recovery

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

UU Pool Performance

2013 2014 2015 2016 2017 2018

YYY Pool Performance

N2N Facilities

Pre ASP ASP Injection AP Injection

Pre ASP

Sub OptimalASP

SurfactantStopped

ASP

AP – Alkaline Polymer ASP – Alkaline Surfactant Polymer

0 KM 20Medicine Hat

25

AppendixPrice Forecasts

26

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Year End 2017 ReservesPrice Forecast(1)

McDaniel & Associates price forecasts used for all assets for end 2017 reserves valuation

Year End 2016Year End 2017

85

Price Forecast Brent

75

65

552018 2019 2020 2021 2022 2023

63.5

61.3

63.4

70.1

74.275.6

62.0

69.0

74.0

77.0

79.080.0

1) See MD&A and MCR27

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Calgary

Edmonton

Hardisty

Cutbank

CalgaryVancouver

Billings

Trans Mountain

EnbridgeKeystone

Keystone XL

Bow

Riv

er

Express

Major Oil Pipeline

Great Falls

Calumet

Billings

CHS (Laurel)Phillips 66ExxonMobil

Suffield

Alberta

Saskatchewan

British Columbia

WTI

WCS

Oil Sale Premium

Quality and Diluent

Field ex Transportation

Transportation(1)

Field

Discount to Brent

Field (CAD/bbl)

WTI

WCS

Oil Sale Premium

Quality and Diluent

Field ex Transportation

Transportation

Well Head

Discount to Brent

Field (CAD/bbl)

47.0

32.0

+2.0

-3.1

30.9

-3.4

27.5

45%

34.3

56.0

38.5

+2.3

-5.1

35.7

-3.4

32.3

46%

40.3

65.0

42.5

+2.5

-7.1

37.9

-3.4

34.5

51%

43.1

50 60 70Brent Price

USD/bbl

1) Transportation included in operating costs

Canadian Crude OilSuffield

Suffield heavy oil is mixed with diluent and sent through the Bow River pipeline to refineries in Billings and Great Falls

Suffield oil is priced as a netback to WTIand includes transportation, quality anddiluent components to the price

28

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IPC - CanadaGas Market

Majority of Suffield gas priced on the Alberta/Saskatchewan border at Empress

Benefits from relative higher price comparedto AECO

0

1

2

3

4

5

6

7

8

9

10

11

01 02 03 04 05 08 09 10 11 12 15 16

January 2018 February 201817 18 19 22 23 24 25 26 29 30 31 01 02 05 06 07 08 09 12 13 14 15 16 19

Empress PremiumAECO CAD/McfEmpress CAD/McfCMD Gas Price CAD/Mcf

Redcliff

Medicine Hat

Suffield

ALTA Ga s Pip

elin

e

NOVA Sales Line

NOVA Mainline to TCPL

0 KM 20

Suffield/Alderson Assets

NG Pipelines

NG Facilities

Empress

NOVA line to TCPL

NOVA Sales Line

Empress (ALTA)

NOVA

Swing NOVA/Empress

Albe

rtaSa

skat

chew

an

1-27 Oil Battery

TransCanadaMain Line

EmpressPrice Point

Empress Pricing~92% production

AECO Pricing~8% production

29

AppendixFinancials

30

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2018 ForecastOperating Cash Flow Netback(1) [USD/boe]

Brent oil price USD/bbl 70

Cash Margin Netback

Cash Taxes

Operating Cash Flow Netback

13.8

0.0

13.8

17.3

-0.1

17.2

60 (Base)

2018Forecast

50

20.1

-0.2

19.9

(1) Non-IFRS measure, see MD&A and Reader Advisory

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2018 ForecastOil Sensitivity to WTI/WCS Differential

29.3

16.4

15.4

30.2

17.2

16.2

31.1

18.1

17.1

Total Revenue (USD/boe)

Operating Cash Flow (1) (USD/boe)

EBITDA (1) (USD/boe)

Brent price (USD/bbl)WTI/WCS Differential (USD/bbl)

Low Case60.0022.50

Base Case60.0017.50

High Case60.0012.50

(1) Non-IFRS measure, see MD&A

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2018 ForecastGas Sensitivities to Realised Canadian Gas Price

29.6

16.7

15.7

30.2

17.2

16.2

30.7

17.8

16.8

Total Revenue (USD/boe)

Operating Cash Flow (1) (USD/boe)

EBITDA (1) (USD/boe)

Brent price (USD/bbl)WTI/WCS Differential (USD/bbl)Gas price (CAD/mcf)

Low Case60.0017.502.15

Base Case60.0017.502.40

High Case60.0017.502.65

(1) Non-IFRS measure, see MD&A

33

International Petroleum Corp.Acquisition Credit Facilities

Suffield acquisition was funded with 3 credit facilities:

International RBL

Canadian Borrowing Base

Canadian Second Lien

Malaysia, France and

Netherlands assets

Canada assets

Canada assets (2nd ranking)

200 MUSD

250 MCAD

60 MCAD

185 MUSD

195 MCAD

60 MCAD

Security Facility AmountOutstanding as of

5 Jan 2018

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International Petroleum Corp.Acquisition Credit Facilities

Net debt(1) as of January 5, 2018 was approximately 355 MUSD

Leverage Net debt(1,2) to EBITDA(1,3) below 2.0x(2)

2018 free cash flow used to fund budgeted capital expenditure and repay debt Expect to reduce leverage through 2018

Average margin for 2018 ~3.50%

(1) Non-IFRS measure, see MD&A (2) As at January 5, 2018, after giving effect to the Suffield acquisition (3) Based on 2018 Capital Markets Day guidance

35

AppendixNetherlands

36

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5 p

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4.17

IPC - NetherlandsAsset Overview

Hydrocarbon Type Gas2P Reserves Net (1), MMboe 1.8

Netherlands

Portfolio of mature gas fields Non-operated onshore and offshore gas Infrastructure provides additional revenue stream

NETHERLANDS

Offshore

Onshore

AMSTERDAM

The Hague

Rotterdam

Leeuwarden

0 KM 50

Hydrocarbon fields/discoveries

Non-operated

Oil

Gas

IPC Licences

Follega

Zuidwal

F15d

L7

L4a

L1fK3d

E17b

Slootdorp

Gorredijk

F6a

Oosterend

Lemsterland

K4b K5a K6

E16aK3b

Q16a

Leeuwarden

L1e

E17a F15a

–

2

4

6

8

10

12

14

MM

boe

2002 2016 2017

+40%Growth

+38%

+4%

2P ReservesCumulative Production2C

1) As at December 31, 2017, see MD&A and MCR37

AppendixLundin Group

38

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2.16

The Lundin Group of CompaniesA History of Value Creation

value creation to date14 Billion USD estimated

Denison Mines

Lundin MiningNGEx ResourcesFilo Mining

Lucara Diamonds

golddia

monds

so

lar power

base metals

uran

ium

NGEx ResourcesLundin Gold

Lundin Petroleum

BlackPearl ResourcesAfrica Oil

ShaMaran Petroleum Africa Energy

IPC

Etrion Corporation

39

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International Petroleum Corp.Board of Directors & Management Team

Ashley HeppenstallFormer CEO of Lundin Petroleum

CEO of IPCChairman

Mike NicholsonCEO CFO

Mike NicholsonCEO of ShamaranPetroleum

Chris BruijnzeelsFormer Managing Director,Lundin Norway

Torstein Sanness

Christophe Nerguararian

VP OperationsDaniel Fitzgerald

VP Reservoir Development

Ryan AdairVP Corporate Planning and Investor Relations

Rebecca Gordon

Lukas LundinBoard Member ofLundin Mining

Donald Charter

Board of Directors

Legal Counsel andCorporate Secretary

Jeff Fountain

Management Team

40

Reader AdvisoryForward Looking StatementsThis presentation contains statements and information which constitute “forward-looking statements” or “forward-looking information” (within the meaning of applicable securities legislation). Such statements and information (together, “forward-looking statements”) relate to future events, including the Corporation’s future performance, business prospects or opportunities. Actual results may differ materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this presentation are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this presentation, unless otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws.

All statements other than statements of historical fact may be forward-looking statements. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “forecast”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, “budget” and similar expressions) are not statements of historical fact and may be “forward-looking statements”. Forward-looking statements include, but are not limited to, statements with respect to: our intention to continue to implement our strategies to build long-term shareholder value; the benefits of the Suffield acquisition; IPC’s intention to review future potential growth opportunities; our belief that our resource base will provide feedstock to add to reserves in the future; the ability of our high quality portfolio of assets to provide a solid foundation for organic and inorganic growth; the integra-tion of the Suffield-related operations into IPC; potential future growth opportunities in North America; organic growth opportunities in France; results of infill drilling in Malaysia; results of 3D seismic survey in France; future development potential of the Suffield operations; the expecta-tion that the anticipated 2018 capital expenditures will provide future development and growth opportunities in 2019 and beyond; potential acquisition opportunities; estimates of reserves; estimates of contingent resources and prospective resources; future production levels including 2018 production guidance; 2018 operating cost forecast; 2018 capital expenditure budget including future capital expenditures and their allocation to exploration and development activities; future drilling and other exploration and development activities. Statements relating to “reserves”; “contingent resources” 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 and resources described exist in the quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well produc-tion rates and reserve and contingent resource volumes; operating costs; the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the benefits of acquisitions; the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; the availability and cost of financing, labour and services; and the ability to market crude oil, natural gas and natural gas liquids successfully.

Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to be correct. Since for-ward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks as-sociated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; the ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive.

Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the MCR, the management’s discussion and analysis (MD&A) for the three months and year ended December 31, 2017 (See “Cautionary Statement Regarding Forward-Looking Information” therein), the Corporation’s Non-Offering Prospectus dated April 17, 2017 (See “Risk Factors” and “Forward-Looking Information” therein) and other reports on file with applicable securities regulatory authorities, which may be accessed through the SEDAR website (www.sedar.com) or IPC’s website (www.international-petroleum.com).

Non-IFRS MeasuresReferences are made in this presentation to “operating cash flow” (OCF), “Earnings Before Interest, Tax, Depreciation and Amortization” (EBITDA), “operating costs” and “net debt”/”net cash”, which are not generally accepted accounting measures under International Financial Report-ing Standards (IFRS) and do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of OCF, EBITDA, operating costs and net debt/net cash that may be used by other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS.

Management believes that OCF, EBITDA, operating costs and net debt/net cash are useful supplemental measures that may assist shareholders and investors in assessing the cash generated by and the financial performance and position of the Corporation. Management also uses non-IFRS measures internally in order to facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Corporation’s ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures are important supplemental measures of operating performance because they highlight trends in the core business that may not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for assessment of the Corpora-tion’s operating performance and financial condition on a basis that is more consistent and comparable between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties frequently use non-IFRS measures in the evaluation of issuers.

The definition and reconciliation of each non-IFRS measure is presented in IPC’s MD&A (See “Non-IFRS Measures” therein).

Disclosure of Oil and Gas Information This presentation contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas assets. Gross reserves / resources are the working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests. Net reserves / resources are the working interest (operating or non-operating) share after deduction of royalty obligations, plus royalty interests in reserves/resources. Unless otherwise indicated, reserves / resource volumes are presented on a gross basis.

Reserve estimates, contingent resource estimates, prospective resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in France, Malaysia and the Netherlands are effective as of December 31, 2017 and were prepared by IPC and audited by ERC Equipoise Ltd. (ERCE), an independent qualified reserves auditor, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook), and using McDaniel’s January 1, 2018 price forecasts as referred to below.

Reserves estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of January 5, 2018, being the completion date for the acquisition of this assets by IPC, and were evaluated by McDaniel & Associates Consultants Ltd. (McDaniel), an independent qualified reserves evaluator, in accordance with NI 51-101 and the COGE Handbook, and using McDaniel’s January 1, 2018 price forecasts. The volumes are reported and aggregated by IPC in this presentation as being as at December 31, 2017.

The price forecasts used in the reserve audit / evaluation are available on the website of McDaniel (www.mcdan.com), and are contained in the MCR referred to below.

The reserve life index (RLI) is calculated by dividing the 2P reserves of 129.1 MMboe as at December 31, 2017, after giving effect to the Suffield acquisition in Canada, by the mid-point of the 2018 production guidance of 30,000 to 34,000 boepd.

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Reader Advisory“2P reserves” means IPC’s gross proved plus probable reserves. “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.

Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies are conditions that must be satisfied for a portion of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be resolved within a reasonable timeframe. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or characterized by their economic status.

There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a classification of estimated resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will be actually recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.

Contingent resources are further classified based on project maturity. The project maturity subclasses include development pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources are classified as development unclarified. Development unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable. Of the Corporation’s 63.4 MMboe best estimate contingent resources (unrisked), 17.4 MMboe are light and medium crude oil, 7.4 MMboe are heavy crude oil and 38.6 MMboe are conventional natural gas.

References to “unrisked” contingent resources volumes means that the reported volumes of contingent resources have not been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Therefore unrisked reported volumes of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such resources.

The contingent resources reported in this presentation are estimates only. The estimates are based upon a number of factors and assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this presentation.

Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Chance of discovery is the estimated probability that exploration activities will confirm the existence of a significant accumulation of potentially recoverable petroleum. There is no certainty that any portion of the prospective resources estimated in the report audited by ERCE and summarized in this document will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources audited. Estimates of the prospective resources should be regarded only as estimates that may change as additional information becomes available. Not only are such prospective resources estimates based on that information which is currently available, but such estimates are also subject to uncertainties inherent in the application of judgmental factors in interpreting such information. Prospective resources should not be confused with those quantities that are associated with contingent resources or reserves due to the additional risks involved. Because of the uncertainty of commerciality and the lack of sufficient exploration drilling, the prospective resources esti-mated in the report audited by ERCE and summarized in this document cannot be classified as contingent resources or reserves. The quantities that might actually be recovered, should they be discovered and developed, may differ significantly from the estimates in the report audited by ERCE and summarized in this document.

2P reserves, contingent resources and prospective resources audited by ERCE and evaluated by McDaniel have been aggregated in this presentation by IPC. Estimates of reserves, resources and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This presentation contains estimates of the net present value of the future net revenue from IPC’s reserves. The estimated values of future net revenue disclosed in this presentation do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.

The reserves and resources information and data provided in this presentation presents only a portion of the disclosure required under NI 51-101. All of the required information will be contained in the Corporation’s Annual Information Form for the year ended December 31, 2017, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2018. Further information with respect to IPC’s 2P reserves, contingent resources, prospective resources and estimates of future net revenue, including assumptions relating to the calculation of net present value and other relevant information related to the contingent resources disclosed, is disclosed in the material change report (MCR) dated and filed on February 26, 2018 by IPC and available under IPC’s profile on www.sedar.com and on IPC’s website at www.international-petroleum.com.

This presentation includes oil and gas metrics including “cash margin netback”, “operating cash flow netback”, “cash taxes”, “EBITDA netback” and “profit netback”. Such metrics do not have a standardized meaning under IFRS or otherwise, and as such may not be reliable. This infor-mation should not be used to make comparisons.

“Cash margin netback” is calculated on a per boe basis as oil and gas sales, less operating, tariff/transportation and production tax expenses. Netback is a common metric used in the oil and gas industry and is used by management to measure operating results on a per boe basis to bet-ter analyze performance against prior periods on a comparable basis.

“Operating cash flow netback” is calculated as cash margin netback less cash taxes. Operating cash flow netback is used to measure operating results on a per boe basis of cash flow.

“Cash taxes” is calculated as taxes payable in cash, and not only for accounting purposes. Cash taxes is used to measure cash flow.

“EBITDA netback” is calculated as cash margin netback less general and administration expenses. EBITDA netback is used by management to measure operating results on a per boe basis.

“Profit netback” is calculated as cash margin netback less depletion/depreciation, general and administration expenses and financial items. Profit netback is used by management to measure operating results on a per boe basis.

BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel (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. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.

CurrencyAll dollar amounts in this presentation are expressed in United States dollars, except where otherwise noted. References herein to USD mean United States dollars. References herein to CAD mean Canadian dollars.

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