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A Lundin Group Company
Internationally Focused Upstream CompanyInternational Petroleum Corp.
NC00059 02.18
March 2018
NCF
0004
2 Q
3 p
02 0
7.17
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
2
NC0
0052
p34
05.
17
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%
3
NCF
0005
0 p
06 0
2.18
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
4
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0050
p35
02.
18
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
NC0
0050
p36
02.
18
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
NC0
0050
p32
02.
18
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
7
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p38
02.
18
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
8
NC0
0054
p04
02.
18
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
9
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0050
p07
02.
18
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)
10
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0045
p05
11.
17
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
11
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02.
18
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)
12
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18
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
13
NCF
0001
3 p
24 0
2.18
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
NCF
0001
3 p
11 0
2.18
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
15
NCF
0001
4 p
06 0
2.18
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
NCF
0001
4 p
22 0
4.17
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
17
NCF
0001
4 p
24 0
4.17
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
NCF
0005
0 p
41 0
2.18
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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18
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
21
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02.
18
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
22
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18
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
23
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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
24
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18
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
NCF
0005
4 p
01 0
2.18
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
NC0
0053
p01
02
.18
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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p04
02.
18
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
31
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02.
18
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
32
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0051
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02.
18
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
34
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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
NCF
0001
5 p
01 0
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
NCF
0000
1 p0
5 1
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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18
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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