Capital Markets Day NC00050 p01 02.18 26 February 2018 NC00050 02.18
International Petroleum Corp. Agenda 26 February 2018, 2-5 pm 1. 2. 3. 4. Introduction 2017 Operations Review 2018 Outlook 3a. Overview 3b. Canada 3c. Malaysia 3d. France 3e. Netherlands Q&A Mike Nicholson Daniel Fitzgerald Daniel Fitzgerald Ryan Adair All Break 5. Infrastructure and Marketing Rebecca Gordon 6. Financial Overview Christophe Nerguararian 7. Reserves Valuation Rebecca Gordon NC00050 p02 02.18 8. 9. Closing Remarks Q&A Mike Nicholson All 2
1. Introduction Mike Nicholson CMD, 26 February 2018 3
International Petroleum Corp. Corporate Strategy Deliver operational excellence Maintain financial resilience under low oil prices Maximize the value of our resource base NCF00042 Q3 p02 07.17 Grow through M&A 4
International Petroleum Corp. 2017 Performance IPC Listed 24 th April Share Purchase Offer Production IPC / Lundin Petroleum split announced February, completed April Listed in Stockholm and Toronto Acquired 25.5 million shares at 3.53 USD per share (90 MUSD) Negative dilution to shareholders -22.5% 10,300 boe/d, 3% ahead of original mid point guidance Operating Costs (1) Organic Growth Cash Flow Generation 16.1 USD/boe, 14% below original guidance Delivered 2 infill wells in Malaysia, 3 MUSD ahead of budget Villeperdue 3D seismic acquisition completed Operating cash flow of 138 MUSD (1) 90 MUSD share purchase and 2017 expenditure programme fully funded from cash flow Net cash position of +6 MUSD end 2017 (1) NCF00050 p23 02.18 Transformational Acquisition Announced, closed and transitioned Suffield assets Quadruples reserves and contingent resources, triples production for IPC (1) Fully funded through debt; no equity dilution 1) See MD&A and MCR (as defined in Reader Advisory) 5
International Petroleum Corp. 2018 Highlights Production Guidance Operating costs (1) Organic Growth Resource Base (2) Operating Cash Flow (1) Business Development 30,000 to 34,000 boe/d 22% reduction in per barrel operating costs 146 MUSD and 12.6 USD/ boe in 2018 Capital programme of 32.2 MUSD Completion of infill drilling in Malaysia and new development drilling in Canada 129.1 MMboe proved and probable (2P) reserves 63.4 MMboe contingent (2C) resources RLI increased from 8 to 11 years with more than tripled production Strong cash flow generation Operating cash flow netback 14 to 20 USD/boe (Brent 50 to 70 USD/bbl) Opportunistic approach to further acquisitions FPSO Bertam Secured permanent flagging status NCF00050 p41 02.18 Shareholder Value (2) 89% increase in 2P reserves value per share 1) Non-IFRS measure, see MD&A 2) As at December 31, 2017, after giving effect to the Suffield acquisition, see MD&A and MCR 6
International Petroleum Corp. Production Growth 40,000 34,000 30,000 30,000 >3x boepd 20,000 10,300 boepd 10,000 NC00050 p33 02.18 0 Q1 Q2 Q3 Q4 2017 2018 Guidance 7
International Petroleum Corp. Resource Growth (1) 200 2P + 2C 192.5 63.4 150 2C MMboe 100 >4x 129.1 2P 50 17.5 2C 29.4 2P NC00050 p34 02.18 1) See MD&A and MCR 0 January 2017 June 2017 January 2018 8
International Petroleum Corp. Operating Costs (1) 20 18.8-14% 16.1 15-22% 12.6 USD/boe 10 5 NC00050 p35 02.18 1) Non-IFRS measure, see MD&A 0 2017 Guidance 2017 Actual 2018 Guidance 9
International Petroleum Corp. Operating Cash Flow (1) 250 233 70 USD/bbl 200 201 60 USD/bbl 161 50 USD/bbl Million USD 150 138 100 50 NC00050 p36 02.18 1) Non-IFRS measure, see MD&A 0 2017 Actual 2) Based upon mid-point 2018 production guidance 2018 Guidance (2) 10
International Petroleum Corp. Liquidity Position Fully funded 2017 expenditure and share purchase programme from cash flow 160 152 146 Share Purchase 120 Operating Cash Flow (1) Million USD 80 Development 40 E&A Decommissioning G&A, Financial, WC 0 Opening Cash -100-200 Closing Net Cash 6 (1,2) Suffield Acquisition Net Debt -355 (1,3) NC00050 p37 02.18-300 -400 1) Non-IFRS measure, see MD&A 2) as at December 31, 2017 3) as at January 5, 2018 11
International Petroleum Corp. 2P Reserves and Net Asset Value (1) 1,200 1,151 1,000 608 800 Canada 355 (2) 796 9.1 USD/share MUSD 600 400 543 International 200 NC00050 p38 02.18 0 2P Reserves Values NPV8 1) As at December 31, 2017, after giving effect to the Suffield acquisition, see MD&A and MCR Net Debt NAV NAV per Share 2) Net debt as at January 5, 2018 (Non-IFRS measure, see MD&A) 12
International Petroleum Corp. Net Asset Value Per Share vs Share Price (1) ~26% discount to NAV USD per share 10 9 8 7 6 5 01/01/17 USD 4.8 NAV per share (1) USD share price +89% Malaysia infill and France 3D seismic announced Canada acquisition announced 01/01/18 USD 9.1 Infill drilling starts in Malaysia 10 9 8 7 6 5 4 USD per share ~55% discount to NAV 3 2 1 Listing 25.5 M shares purchased and cancelled at 3.53 USD/share 17.5 MMboe CR announced France 3D seismic completed Canada acquisition completed Infill wells 3 online 2 1 NC00054 p04 02.18 0 1) See MD&A and MCR Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb 2017 2018 0 13
2. 2017 Operations Review Daniel Fitzgerald CMD, 26 February 2018 14
International Petroleum Corp. 2017 Production - Ahead of Guidance 2017 production 10,300 boepd net 3% above original mid-point guidance, upper end of revised guidance (10,000 to 10,500 boepd) Safe and successful shutdown on Bertam completed as planned Strong performance across all assets IPC Quarterly Net Production 2017 NC00052 p02 02.18 Production (boepd) 12,000 8,000 4,000 - Q1 Q2 Q3 Q4 Successful Bertam shutdown completed as scheduled Rig move in Bertam Continental Europe 2017 Guidance High Low France 2017 Production 24% 11% 65% Netherlands Malaysia 15
International Petroleum Corp. 2017 Operating Costs (1) - Ahead of Guidance 2017 Production Original 2017 Guidance Net Production (boepd) 10,300 10,000 Annual operating costs 16.1 USD/boe Original 2017 guidance: 18.8 USD/boe 14% below original guidance 2017 Operating Costs MUSD USD/boe Infrastructure ownership provides additional income FPSO in Malaysia, infrastructure in France and Netherlands 60 68 16.1 18.8 2017 Guidance OPEX NC00052 p03 02.18 1) Non-IFRS measure, see MD&A Operating costs shown is net of self to self lease payments 16
International Petroleum Corp. 2017 Net Capital Expenditure(1) Villeperdue seismic completed as planned Completed October 2017 safely and on budget Bertam infill programme commenced Q4 2017 Completed in Q1 2018, both wells online Safe execution ahead of schedule Savings of over 3 MUSD since budget approval Capital Expenditure (net MUSD) 23 3 12 5 23 10 2017 Guidance Villeperdue Seismic Malaysia Infill Wells Savings on Infills 2017 Projects 2018 2017 Infills Capital Carryover Expenditure Netherlands 2.5 (2.9) MUSD France 8.9 (5.0) MUSD - Pipeline & ESP maintenance - Reservoir studies - Villeperdue seismic (2) - 1 exploration well (Gorredijk) - Facilities projects Malaysia 11.6 (2.1) MUSD NCF00050 p31 02.18 - Infill wells (2) - Debottlenecking project - Reservoir studies (1) 2017 CMD in brackets (2) See MD&A Approved during 2017 17
International Petroleum Corp. 2017 Health, Safety and Environmental Performance HSE Performance No lost time incidents, major accidents or spills Proactive management driven by leadership accountability, with aligned and focused teams Committed to high standards of performance Commited to Goal Zero > No harm to people or the environment Strong safety culture Leadership commitment, competent people, safe work practices and efficient systems and processes NC00052 p26 02.18 18
3. 2018 Outlook CMD, 26 February 2018 19
3a. Overview Daniel Fitzgerald, Ryan Adair CMD, 26 February 2018 20
International Petroleum Corp. 2018 Work Programme Deliver production volumes 2018 production guidance 30,000 to 34,000 boepd Maintain operational and safety performance with high uptime Continue to manage cost base Mature and execute organic growth portfolio Canada Deliver production optimisation scopes Commence oil drilling Q4 2018, 5 oil wells plus 1 pilot hole Mature 2019 infill and enhanced oil recovery opportunities NC00052 p21 11.17 Malaysia Mature next phase of infill drilling Mature near-field upside opportunities France Mature Vert-La-Gravelle to investment decision Interpret Villeperdue seismic and mature development and near-field exploration options 21
International Petroleum Corp. 2018 Guidance - Production 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 Production Forecast by Country France Netherlands 40,000 IPC Production Guidance 2018 Malaysia Net Production (boepd) 30,000 20,000 10,300 boepd >3x Canada Oil Canada Gas 10,000 Oil NCF00050 p06 02.18 0 2017 Q1 Q2 Q3 Q4 2018 Guidance 2018 Guidance Range Gas 22
International Petroleum Corp. Production - Year to Date 2018 Suffield acquisition closed 5 January Two infill wells online in Malaysia Strong performance year to date from all assets IPC Daily Production 40 Suffield acquisition completed 1st Infill well online Rig Move 2nd Infill well online 35 Net Production (thousand boepd) 30 25 20 15 10 Q1 2018 Guidance Range 5 Q1 2018 Guidance Range NC00050 p03 02.18 0 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 January February Daily Production 23
International Petroleum Corp. 2018 Guidance - Operating Costs 2018 guidance 2018 annual operating cost guidance 12.6 USD/boe (1) Base operating cost <10 USD/boe 22% reduction from 2017 levels (USD/boe) Focus on production optimisation and cost reduction Netherlands France Malaysia Canada 150 Net Operating Costs (MUSD) 146 Net Unit Operating Costs (USD/boe) 120 16.1 22% 90 12.6 2.8 Project, tariff and other 60 30 Base 9.8 0 NC00050 p04 02.18 2018 Budget 1) Non-IFRS measure, see MD&A 2017 2018 Budget Operating costs shown are net of self to self lease payments 24
International Petroleum Corp. 2018 Guidance - Capital Expenditure 2018 Budget: 32.2 MUSD Netherlands Canada France 2018 Capital Expenditure Guidance: 32.2 MUSD Malaysia Canada 10.8 MUSD - Oil drilling and preparation - Maintenance capital France 5.7 MUSD Netherlands 1.5 MUSD - Paris Basin - Development well (E17) - Maintenance capital - Vert-La-Gravelle - Well reactivations - Maintenance capital Malaysia 14.2 MUSD NC00050 p32 02.18 - Infill wells (carryover from 2017) 25
International Petroleum Corp. 2P Reserves - Year End 2017 (1) Quadrupled 2P reserves to 129.1 MMboe Increased reserves life index (RLI) from 8 to 11 years Malaysia, 9.1 Netherlands, 1.8 7% France, 17.6 14% Canada Gas, 73.2 1% 57% 21% Canada Oil, 27.4 NC00052 p12 05.17 MMboe 140 120 100 80 60 40 20 0 29.4 Opening balance -3.7 Production +2.8 Revisions /Additions 28.5 Closing balance +100.6 Gas Oil Acquisition 129.1 Gas Oil Closing balance 2P Reserves End 2016 2017 Production France Netherlands Malaysia End 2017 (excluding acquisition) Canada Suffield Acquisition End 2017 Reserves replacement ratio (excluding acquisition) Reserves replacement ratio (including acquisition) 1) See MD&A and MCR MMboe 29.4-3.7 + 0.5 + 0.4 + 1.9 28.5 + 100.6 129.1 76% >2,762% 26
International Petroleum Corp. Year End 2017 - Best Estimate Contingent and Prospective Resources (1) More than tripled Contingent Resource base 99% replacement of international 2C contingent resource base IPC Net 2C Contingent Resources 63.4 MMboe France other, 11.8 18.6% Best Estimate (2C) Contingent Resources Mid 2017 Bertam A16/17 locations mature to reserves MMboe 17.5-1.7 France Villeperdue West, 4.2 Bertam Infill wells, 1.4 Canada Oil, 7.4 6.6% 2.2% 11.8 % 60.8% Bertam 2 additional drilling locations + 1.4 Canada Gas Drilling, 38.6 France Revisions End 2017 (excluding acquisition) +0.2 17.4 80 IPC Net 2C Contingent Resources Canada Suffield Area Assets - Gas Canada Suffield Area Assets - Oil End 2017 Best Estimate Prospective Resources + 38.6 + 7.4 63.4 MMboe Unrisked Risked MMboe (net) 60 40 +46.0 Gas 63.4 Gas Bertam I-35 Prospect (20% CoGS) 5.4 1.1 20 17.5-1.7 +1.4 +0.2 17.4 Oil NC00052 p17 05.17 Bertam A14 Area (35% CoGS) 0.4 0.2 Total 5.8 1.2 1) See MD&A and MCR, for project specific chance of development and risked contingent resources 0 Opening Balance Mid 2017 Bertam Infill Matured Bertam Further Drilling France Revisions End 2017 excl. Acqusition Canada Acquisition Oil Closing Balance End 2017 27
International Petroleum Corp. Organic Growth 2017 Sanctioned 2 Bertam infills > drilled and online in early 2018 Sanctioned 79km 2 3D seismic in France Future Opportunities Project Execution in 2018 Executed / on Production > acquisition completed in October Canada» 2020 oil drilling 2018 Execute first tranche of Glauconitic infill wells in Canada Future Opportunities Malaysia» I35 prospect» 2019 oil drilling» Enhanced oil recovery expansion» Phase 3 Infill wells» Easy Coulee» South Gibson» Gas Optimisation» 2 infill wells Mature inventory of Suffield drilling locations to have optionality in 2019 Mature next tranche of wells at Bertam Villeperdue West seismic processing, France» Villeperdue North» Merisier» Villeperdue West» Vert-La-Gravelle» Villeperdue seismic acquisition interpretation and development studies NC00050 p07 02.18 Mature Vert-La-Gravelle project to final investment decision (FID) 28
3b. Canada Daniel Fitzgerald, Ryan Adair CMD, 26 February 2018 29
IPC - Canada Asset Overview Suffield Acquisition completed on January 5, 2018 Suffield Assets Operated by IPC Conventional onshore oil and gas assets Low decline with resource and development upside Low cost of operations CFB Suffield Alderson 0 KM 20 IPC Licences Redcliff Operated / Shallow Gas Management focus Deliver low cost, stable production and cash flow Increase production from existing well stock through optimisation Execute 2018 drilling programme and mature 2019 targets Mature future development programme Medicine Hat Hydrocarbon fields/discoveries Oil pools Canada Alberta Hydrocarbon Type Oil/Gas CANADA NC00045 p27 02.18 2P Reserves Net (1), MMboe 1) As at January 5, 2018, see MD&A and MCR 100.6 Suffield Ottawa 30
IPC - Canada Transition and Closing Edmonton Alberta Transaction closed on 5 January 2018 Successful transition and operations on Day 1 Integration of IPC Alberta Transferred ~100 experienced staff from Cenovus Offices set-up in Calgary, Redcliff and on site Critical operational and financial systems online Calgary Calgary Calgary Asset Management ~220km Suffield CFB Suffield Alderson Medicine Hat NC00045 p25 02.18 Redcliff Operational Office 31
Local Water handling and Injection (x 6) IPC - Canada Operational Overview Oil Export Main Oil Facilities Connected via main IPL marketing line (1-27 Oil Battery) - Minimises fluid transport cost Sales Gas Export NOVA Mainline to TCPL Suffield - 16,000 bbls/d oil processing capacity - 6 major emulsion/water treatment plants Pipe l ine Underground Well Facilities s Natural Gas Compression Stations in e Ga ALTA - Direct connection to NOVA, TCPL and ALTA gas sales lines Alderson - Wells and manifolds located underground VA NO CFB Suffield le Sa sl - >200MMcf/d capacity - 16 major compression stations - 54 compression units Redcliff NC00045 p26 02.18 IPC Licences Medicine Hat Operated / Shallow Gas Hydrocarbon fields/discoveries 0 KM 20 Oil pools Main Pipelines Oil Gas Facilities Oil Gas 32
IPC - Canada 2018 Work Programme Suffield 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 Alderson CFB Suffield 2018 development programme 10.8 MUSD development programme Targeting drilling commencement in Q4 2018 Mature opportunity set for expanded drilling in 2019 Screening additional project and development activities 0 KM 20 Redcliff Medicine Hat IPC Licences Operated / Shallow Gas Hydrocarbon fields/discoveries Oil pools ~8 USD/boe Base Operating Costs (1) NC00045 p28 02.18 1) Non-IFRS measure, see MD&A 33
IPC - Canada Shallow Gas Optimisation Suffield Well Stock ~10,800 shallow gas wells Active well and reservoir management required to unlock potential Many small interventions => material impact on production Initial production Well able to lift water without intervention Swabbing programme to remove water ~9,600 Cased only - Available for swabbing - Some interventions required Flow Reservoir Pressure Install siphon string Remove siphon string ~450 With siphon string installed Reservoir Pressure Flow ~750 Tubing string installed NC00045 p32 02.18 Time 34
IPC - Canada Swabbing Programme Wells Activities Swabbing Rig ~5,500 ~5,500 wells currently not in swabbing programme Opportunity for additional swabs in 2018 Swabbing Tool ~3,500 ~3,500 wells currently in swabbing programme - Average of 1.6 swabs per well in 2018 ~5,500 2018 Forecast 1.3 MCAD in 2018 programme from <0.2 CAD/Mcf breakeven NC00045 p33 02.18 ~400 Require interventions to return to swabbing programme - Technical and commercial analysis ongoing 35
IPC - Canada Gas Optimisation Programme Wells ~370 Siphon strings in place - Monitoring ongoing for optimal intervention timing Active programme to efficiently manage wells ~80 ~125 Inactive siphon string wells with no/low flow - Candidates for removal to restart production Coil tubing clean outs - Wash of well bore to remove mud/debris 2018 budget 0.6 MCAD - Targets portion of activities shown NC00045 p34 02.18 36
IPC - Canada Further Optimisation Potential Shut in Wells Gas Wells currently closed in Oil Significant potential under review Limited investments in prior years Workovers Gas Candidates for workover and reactivation Many small additions = material impact Oil Mudplugs Gas Gas production lines currently blocked or restricted due to plugging NC00045 p35 02.18 Water Handling Upgrades Oil Optimisation, debottlenecking and increasing water handling capacity Note: Activities shown are not included in 2018 forecasts 37
IPC - Canada Diverse Portfolio of Opportunities 2P Oil Reserves (1) Undeveloped 27.4 MMboe Near term priority on oil development drilling and gas optimisation Developed Non Producing Developed Non Producing Developed Undeveloped N2N enhanced oil recovery project being matured in 2018 2P Gas Reserves (1) 73.2 MMboe Deep inventory of opportunities creates optionality in 2019 and beyond 45 undeveloped oil drilling locations in 2P reserves base 117 undeveloped oil drilling locations in 2C resource base 2,540 shallow gas drilling locations EOR: Water Flood & ASP Oil Drilling Developed Unrisked Best Estimate Contingent Resources (1) 46.0 MMboe NC00045 p05 11.17 1) As at January 5, 2018, see MD&A and MCR Gas Drilling 38
IPC - Canada 2018 Development Overview 2018 oil development drilling 1 well in Easy Coulee field 5 wells in South Gibson Lake field - 4 horizontal producers - 1 geo-pilot Development timing Surveys and location scounting - Q2 Approvals and planning - Q3 Execution - Q4 1st oil - Q1 2019 Opportunity to accelerate with earlier access Dakota Deberg Mature Glauconitic Drilling Targets YYY UU Jenner Ram Hill North Dieppe Lundy Lane South Dieppe N2N Easy Coulee West Gibson Chieftain Hill Mature ASP Flood Commission & Drilling 2018 Drilling East Easy Coulee Mature Glauconitic Drilling Targets Gibson Lake Mature Glauconitic Drilling Targets NC00045 p06 09.17 Suffield Development Activity 2018 Environment survey, location scouting Application for development and appraisals Drilling operations Mature 2019 opportunities Q1 Q2 Q3 Q4 2018 Drilling South Gibson Lake Falcon 39
Dakota YYY UU Ram Hill N2N 0 KM 10 IPC - Canada Jenner North Dieppe East Easy Coulee South Gibson Lake Development Deberg Lundy Lane South Dieppe South Gibson Lake Gibson Lake West Gibson Chieftain Hill South Gibson Lake Falcon 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 wells Open hole completion Progressive cavity pumps Minimal facility work NC00045 p09 02.18 Proposed 2018 drilling locations 40
IPC - Canada Enhanced Oil Recovery UU Pool Performance UU pool Technology proven in Suffield area Pilot commenced in 2007 Surfactant injection stopped in 2013 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Pre ASP ASP Injection AP Injection YYY Pool Performance 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 2013 2014 2015 2016 2017 2018 Pre ASP N2N Facilities Sub Optimal ASP Surfactant Stopped ASP NC00045 p37 02.18 AP Alkaline Polymer ASP Alkaline Surfactant Polymer 41
IPC - Canada Summary Successful transition and operations on Day 1 Significant gas and oil optimisation potential under review Deep inventory of development opportunities Executing first campaign in Q4 2018 first drilling in the field since 2014 Maturing opportunities in 2018 to provide optionality on number of rigs in 2019 NC00045 p38 02.18 42
3c. Malaysia Daniel Fitzgerald, Ryan Adair CMD, 26 February 2018 43
IPC - Malaysia Asset Overview Malaysia Bertam Facilities Bertam 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 marginal 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 20 Bertam Field Additional infill wells NCF00013 p24 02.18 Hydrocarbon Type 2P Reserves Net (1), MMboe 1) As at December 31, 2017, see MD&A and MCR Malaysia Oil 9.1 2C Cumulative Production 2P Reserves MMboe 16 12 8 4 +16% +13% 2012 2016 2017 +43% 2P + 2C growth 44
IPC - Malaysia Bertam Production Operational Performance 2017 uptime average 99.9% (1) Gross Production (bopd) 12,000 10,000 8,000 6,000 4,000 2,000 Shutdown Debottlenecking Rig move Significant shutdown completed safely, on schedule and on budget - Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2017 Pressure debottlenecking activities completed and production improvements realised 100% Bertam Uptime Maintenance & Debottlenecking Rig move 100.0% 99.9% 100.0% 100.0% 100.0% 100.0% 99.5% 99.5% 99.8% 100.0% 88.0% 34.5% NCF00013 p09 04.17 1) Excluding planned outages Planned Shutdown Uptime 0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2017 45
IPC - Malaysia Development Upside 2016 Infill A15 2016 - A15 well Successfully executed extended reach development well Well continues to produce clean oil 2017 Infill Campaign Infill A16 Infill A17 Future Infill Opportunities 2017 - A16/17 wells I-35 A-14 Completed safely and on schedule Savings of over 3 MUSD vs budget Both wells on stream, production rates in line with expectations Prospect Areas NCF00013 p11 02.18 2018 and beyond Two additional contingent resources identified and being matured in 2018 - A-14 near field prospect - I-35 prospect 1) See MD&A and MCR Net Working Interest Basis Cumulative Production to YE 2017 2P Reserves 2C Contingent Resources Best Estimate Prospective Resources (Unrisked) / (risked) MMboe (1) 7.6 9.1 1.4 5.8 / 1.2 46
3d. France Ryan Adair CMD, 26 February 2018 47
IPC - France France Asset Overview Paris Basin Paris and Aquitaine Basins Mature light oil onshore assets 87% of the reserves base is operated Organic growth potential Aquitaine Basin France Management focus Optimise production rates from existing well stock Vert-La-Gravelle project maturation Villeperdue seismic interpretation and development options Villeperdue Facilities 0 KM 400 NCF00014 p08 02.18 France Hydrocarbon Type Oil 2P Reserves Net (1), MMboe 17.6 1) As at December 31, 2017, see MD&A and MCR 48
IPC - France Organic Growth Potential (1) 12 contingent resource opportunities 2C:2P ratio 0.9 France 2C Contingent Resources 16.0 MMboe (1) ~40% of resource base being matured via studies in 2018 Villeperdue 3D seimic interpretation and development plan Merisier integrated reservoir study Aquitaine, 2.1 13% 27% Villeperdue West, 4.2 Horizontal wells at Vert-La-Gravelle have potential to unlock other Triassic opportunities NCF00014 p17 04.17 MMboe 60 50 40 30 20 10 +54% +2% 2002 2016 2017 +123% 2P+2C Growth Paris Basin Triassic Opportunities, 7.1 2C Cumulative Production 2P Reserves 44% 16% Merisier, 2.6 1) As at December 31, 2017, see MD&A and MCR 49
IPC - France Vert-La-Gravelle Development Plan Optimisation VGR-13H 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 VGR-12H VGR-10 VGR-9H VGR-11H Maturation plan Optimised plan considers three horizontal producers supported by two water injectors Final investment proposal in 2018 Vert-La-Gravelle Facility NCF00014 p22 04.17 50
IPC - France Villeperdue West Development France Ville p Oil F erdue ie ld 3D seismic acquired in 2017 Close to existing infrastructure Material project for IPC Paris Basin mic eis 3D S Targeting 4 MMbbl contingent resources G&G and development studies in 2018 (1) ge ra Cove Good contrast: promising zone undeveloped Inline 350 Seismic Localisation - Inline 350 Top Reservoir NCF00014 p24 04.17 Base Reservoir Good contrast: producing zone 1) As at December 31, 2017, see MD&A and MCR 51
3e. Netherlands Daniel Fitzgerald CMD, 26 February 2018 52
IPC - Netherlands Asset Overview Offshore Portfolio of mature gas fields Onshore F6a Non-operated onshore and offshore gas Infrastructure provides additional revenue stream Non-operated F15d E17b E16a K3b K3d Hydrocarbon fields /discoveries L1e L1f Netherlands Hydrocarbon Type 2P Reserves Net (1), MMboe IPC Licences F15a E17a Oil L4a Gas 1.8 K4b K5a Gas L7 K6 Leeuwarden Leeuwarden Zuidwal Oosterend Follega 14 +4% 12 +40% Growth +38% 10 Slootdorp AMSTERDAM MMboe 8 Q16a NCF00015 p01 04.17 NETHERLANDS The Hague 6 2C Cumulative Production 2P Reserves 4 2 2002 1) Gorredijk Lemsterland 2016 Rotterdam 0 KM 50 2017 As at December 31, 2017, see MD&A and MCR 53
4. Q&A CMD, 26 February 2018 54
BREAK CMD, 26 February 2018 55
5. Infrastructure and Marketing Rebecca Gordon CMD, 26 February 2018 56
Infrastructure and Marketing International Differentials Malaysia Bertam at the centre of rising Asian crude demand Medium crude (high distillates yield) Mainly local refiners Average 3 USD/bbl premium to Brent in 2017 Past 5 cargoes averaging 3.90 USD/bbl premium France ~1.10 USD/bbl discount to Brent for France production Netherlands Sold at TTF (European spot gas price) NC00053 p5 02.18 57
IPC - Canada Gas Market Majority of Suffield gas priced on the Alberta/Saskatchewan border at Empress AECO Pricing ~8% production 1-27 Oil Battery NOVA Mainline to TCPL Suffield Empress Pricing ~92% production TransCanada Main Line Benefits from relative higher price compared to AECO Empress Price Point 11 10 9 8 7 6 5 4 3 2 Empress Premium AECO CAD/Mcf Empress CAD/Mcf CMD Gas Price CAD/Mcf NOVA Sales Line Pipeline ALTA Ga s Suffield/Alderson Assets NG Pipelines Empress Alberta Saskatchewan NC00053 p04 02.18 1 0 01 02 03 04 05 08 09 10 11 12 15 16 17 18 19 22 23 24 25 26 29 30 31 01 02 05 06 07 08 09 12 13 14 15 16 19 January 2018 February 2018 0 KM 20 Redcliff Medicine Hat NOVA line to TCPL NOVA Sales Line NG Facilities Empress (ALTA) NOVA Swing NOVA/Empress 58
Canadian Crude Oil British Columbia Alberta Crude Differential Saskatchewan Canadian heavy oil is priced using a netback from WTI marker has been volatile due to a Keystone pipeline spill in November 2017 WTI to WCS discount has ranged between 10 to 30 USD/bbl WCS still at similar price to 2017 Additional capacity proposed online in 2018 and 2019 Vancouver Trans Mountain WCS to Suffield Edmonton Hardisty Bow River Express Suffield Billings Western Canadian Select (WCS) Enbridge Keystone Keystone XL Cushing (WTI) to Hardisty (WCS) Enbridge 70 Western Canadian Select USD v WTI USD Express Keystone 60 50 USD/bbl 40 30 NC00053 p02 02.18 20 10 0 Keystone pipeline spill Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb 2017 2018 WTI USD WCS USD Western Texas Intermediate (WTI) Major Oil Pipeline Cushing 59
Calgary NC00053 p01 02.18 Canadian Crude Oil Suffield 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 WTI and includes transportation, quality and diluent components to the price USD/bbl WTI WCS Oil Sale Premium Quality and Diluent Field ex Transportation Transportation (1) Field Discount to Brent Field (CAD/bbl) 1) Transportation included in operating costs Brent Price 50 60 70 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 Vancouver British Columbia Trans Mountain Major Oil Pipeline Calgary Great Falls Calumet Cutbank Edmonton Hardisty Bow River Billings CHS (Laurel) Phillips 66 ExxonMobil Alberta Express Suffield Billings Keystone Saskatchewan Keystone XL Enbridge 60
6. Financial Overview Christophe Nerguararian CMD, 26 February 2018 61
2018 Forecast Margin Netback (1) [USD/boe] 2018 Forecast Brent oil price USD/bbl 50 60 (Base) 70 2017 Actual 54.2 Revenue Cost of operations - Base - Projects Tariff/transportation expenses Direct production taxes Operating costs Change in inventory position Cash Margin Netback 26.7-9.8-1.0-1.2-0.6-12.6-0.3 13.8 30.2-9.8-1.0-1.2-0.6-12.6-0.3 17.3 33.0-9.8-1.0-1.2-0.6-12.6-0.3 20.1 53.9-13.1-1.1-0.9-1.0-16.1-1.0 36.8 NC00051 p01 02.18 (1) Non-IFRS measure, see MD&A and Reader Advisory 62
2018 Forecast Operating Costs (1) [USD/boe] USD/boe 20 Operating Costs USD/boe 20 16 16 2018 Forecast Operating Costs 12 12 12.6 USD/boe 8 8 4 4 NC00051 p02 02.18 (1) Non-IFRS measure, see MD&A 0 Q1 2018 Q2 2018 Q3 2018 Q4 2018 0 63
2018 Forecast Taxation [USD/boe] 2018 Forecast Brent oil price USD/bbl 50 60 (Base) 70 Current tax charge/(credit) Deferred tax charge/(credit) 0.0-0.3-0.3 0.1 0.5 0.6??? 0.2-0.32 1.2???? 1.4 NC00051 p03 02.18 64
2018 Forecast Operating Cash Flow Netback (1) [USD/boe] 2018 Forecast Brent oil price USD/bbl 50 60 (Base) 70 Cash Margin Netback 13.8 17.3 20.1 Cash Taxes 0.0-0.1-0.2 Operating Cash Flow Netback 13.8 17.2 19.9 NC00051 p04 02.18 (1) Non-IFRS measure, see MD&A and Reader Advisory 65
2018 Forecast EBITDA Netback (1) [USD/boe] 2018 Forecast Brent oil price USD/bbl 50 60 (Base) 70 Cash Margin Netback 13.8 17.3 20.1 General and administration costs -1.1-1.1-1.1 EBITDA Netback 12.7 16.2 19.0 General and administration costs Cash Non-cash LTIP Depreciation -0.7-0.4-1.1-0.1-1.2 NC00051 p05 02.18 (1) Non-IFRS measure, see MD&A and Reader Advisory 66
2018 Forecast Profit Netback (1) [USD/boe] 2018 Forecast Brent oil price USD/bbl 50 60 (Base) 70 Cash Margin Netback 13.8 17.3 20.1 Depletion/Depreciation -9.0-9.0-9.0 G&A -1.2-1.2-1.2 Financial items, net -2.5-2.5-2.5 Profit/loss Before Tax 1.1 4.6 7.4 Tax 0.3-0.6-1.4 Profit/loss After Tax 1.4 4.0 6.0 NC00051 p06 02.18 (1) Non-IFRS measure, see MD&A and Reader Advisory 67
2018 Forecast Oil Sensitivity to WTI/WCS Differential Brent price (USD/bbl) WTI/WCS Differential (USD/bbl) Low Case 60.00 22.50 Base Case 60.00 17.50 High Case 60.00 12.50 Total Revenue (USD/boe) 29.3 30.2 31.1 Operating Cash Flow (1) (USD/boe) 16.4 17.2 18.1 EBITDA (1) (USD/boe) 15.4 16.2 17.1 NC00051 p07 02.18 (1) Non-IFRS measure, see MD&A 68
2018 Forecast Gas Sensitivities to Realised Canadian Gas Price Brent price (USD/bbl) WTI/WCS Differential (USD/bbl) Gas price (CAD/mcf) Low Case 60.00 17.50 2.15 Base Case 60.00 17.50 2.40 High Case 60.00 17.50 2.65 Total Revenue (USD/boe) 29.6 30.2 30.7 Operating Cash Flow (1) (USD/boe) 16.7 17.2 17.8 EBITDA (1) (USD/boe) 15.7 16.2 16.8 NC00051 p08 02.18 (1) Non-IFRS measure, see MD&A 69
2018 Forecast Liquidity and Funding (1) [USD/boe] Forecast 2018 Brent oil price USD/bbl 50 60 (Base) 70 Operating Cash Flow Netback 13.8 17.2 19.9 General and Administration Costs -1.1-1.1-1.1 Cash Financial Items -1.5-1.5-1.5 Cash Flow Available for Investment 11.2 14.6 17.3 MUSD Development Capex 2.7 2.7 2.7 31 Exploration & Appraisal Capex 0.1 0.1 0.1 1 Working Cap. (incl. decommissioning) 1.0 1.0 1.0 3.8 3.8 3.8 Free Cash Flow 7.4 10.8 13.5 NC00051 p09 02.18 (1) Non-IFRS measures, see MD&A and Reader Advisory 70
International Petroleum Corp. Acquisition Credit Facilities Suffield acquisition was funded with 3 credit facilities: Security Facility Amount Outstanding as of 5 Jan 2018 International RBL Malaysia, France and 200 MUSD 185 MUSD Netherlands assets Canadian Borrowing Base Canada assets 250 MCAD 195 MCAD Canadian Second Lien Canada assets (2 nd ranking) 60 MCAD 60 MCAD 71
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% NC00051 p11 02.18 (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 72
7. Reserves Valuation Rebecca Gordon CMD, 26 February 2018 73
Year End 2017 Reserves Price Forecast (1) Price Forecast Brent 85 79.0 80.0 75 74.0 77.0 74.2 75.6 69.0 70.1 65 63.5 63.4 62.0 61.3 55 2018 2019 2020 2021 2022 2023 Year End 2017 Year End 2016 McDaniel & Associates price forecasts used for all assets for end 2017 reserves valuation NCF00054 p01 02.18 1) See MD&A and MCR 74
International Petroleum Corp. Net Asset Values (1) 1,400 1,200-1,000 355 MUSD 800 608 600 1151 400 796 200 543 543 0 IPC Reserves IPC International IPC Canada IPC Reserves Net Debt Net Asset Value NCF00054 p03 02.18 01.01.2017 1) See MD&A and MCR Reserves 01.01.2018 Reserves 01.01.2018 01.01.2018 01.01.2018 75
International Petroleum Corp. Net Asset Value Per Share vs Share Price (1) ~26% discount to NAV USD per share 10 9 8 7 6 5 01/01/17 USD 4.8 NAV per share (1) USD share price +89% Malaysia infill and France 3D seismic announced Canada acquisition announced 01/01/18 USD 9.1 Infill drilling starts in Malaysia 10 9 8 7 6 5 4 USD per share ~55% discount to NAV 3 2 1 Listing 25.5 M shares purchased and cancelled at 3.53 USD/share 17.5 MMboe CR announced France 3D seismic completed Canada acquisition completed Infill wells 3 online 2 1 NC00054 p04 02.18 0 1) See MD&A and MCR Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb 2017 2018 0 76
8. Closing Remarks CMD, 26 February 2018 77
International Petroleum Corp. 2018 Highlights Production Guidance Operating costs (1) Organic Growth Resource Base (2) Operating Cash Flow (1) Business Development 30,000 to 34,000 boe/d 22% reduction in per barrel operating costs 146 MUSD and 12.6 USD/ boe in 2018 Capital programme of 32.2 MUSD Completion of infill drilling in Malaysia and new development drilling in Canada 129.1 MMboe proved and probable (2P) reserves 63.4 MMboe contingent (2C) resources RLI increased from 8 to 11 years with more than tripled production Strong cash flow generation Operating cash flow netback 14 to 20 USD/boe (Brent 50 to 70 USD/bbl) Opportunistic approach to further acquisitions FPSO Bertam Secured permanent flagging status NCF00050 p41 02.18 Shareholder Value (2) 89% increase in 2P reserves value per share 1) Non-IFRS measure, see MD&A 2) As at December 31, 2017, after giving effect to the Suffield acquisition, see MD&A and MCR 78
9. Q&A CMD, 26 February 2018 79
Appendices CMD, 26 February 2018 80
Appendix Summary of Canada Reserves Information (1) Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Undeveloped Light & Medium Crude Oil (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Heavy Crude Oil (MMbbl) Company Gross Working Interest Reserves 13.1 13.4 18.9 27.3 34.5 0.3 5.4 Company Net Reserves 12.6 12.9 17.9 25.7 32.0 0.3 5.1 Conventional Natural Gas (Bscf) Company Gross Working Interest Reserves 331.2 357.2 357.8 439.1 497.8 26.1 0.6 Company Net Reserves 313.9 338.6 339.2 415.8 471.4 24.8 0.6 Natural Gas Liquids (MMbbl) Company Gross Working Interest Reserves 0.0 0.0 0.0 0.1 0.1 0.0 0.0 Company Net Reserves 0.0 0.0 0.0 0.1 0.1 0.0 0.0 Total Oil Equivalent (MMboe) Company Gross Working Interest Reserves 68.3 73.0 78.6 100.6 117.6 4.7 5.6 Company Net Reserves 64.9 69.3 74.5 95.0 110.6 4.4 5.2 Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Uneveloped Net Present Value Before Tax (MUSD) 0% 534.7 580.6 717.0 1,172.1 1,605.9 45.8 136.4 5% 519.6 551.1 620.5 886.7 1,104.3 31.5 69.4 8% 480.9 506.3 554.9 758.4 917.2 25.4 48.6 10% 454.1 476.2 515.0 688.2 820.4 22.1 38.8 15% 393.0 408.6 431.2 552.5 642.2 15.6 22.6 20% 343.2 354.2 367.1 456.9 521.9 11.0 13.0 Net Present Value After Tax (MUSD) 0% 419.3 453.6 570.6 932.4 1,270.0 34.3 117.0 5% 427.9 450.6 506.4 710.2 874.6 22.7 55.8 8% 399.9 417.7 455.1 608.2 726.7 17.8 37.4 10% 379.1 394.3 423.2 552.2 650.4 15.2 28.9 15% 330.0 340.1 355.2 443.9 509.8 10.1 15.2 20% 289.1 295.6 302.9 367.4 415.0 6.6 7.2 NCF00057 p07 02.18 1) See MD&A and MCR 81
Appendix Summary of Malaysia Reserves Information (1) Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Undeveloped Light & Medium Crude Oil (MMbbl) Company Gross Working Interest Reserves 3.2 3.2 3.9 9.1 11.8 0.7 Company Net Reserves 2.8 2.8 3.4 7.8 10.0 0.6 Heavy Crude Oil (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Conventional Natural Gas (Bscf) Company Gross Working Interest Reserves Company Net Reserves Natural Gas Liquids (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Total Oil Equivalent (MMboe) Company Gross Working Interest Reserves 3.2 3.2 3.9 9.1 11.8 0.7 Company Net Reserves 2.8 2.8 3.4 7.8 10.0 0.6 Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Uneveloped Net Present Value Before Tax (MUSD) 0% 120.7 120.7 153.0 391.4 558.0 32.3 5% 114.9 114.9 145.2 351.0 491.0 30.3 8% 111.7 111.7 140.9 330.6 457.8 29.2 10% 109.7 109.7 138.3 318.3 438.1 28.6 15% 105.1 105.1 132.1 291.4 395.6 27.0 20% 100.9 100.9 126.5 268.9 360.9 25.6 Net Present Value After Tax (MUSD) 0% 120.7 120.7 153.0 391.4 536.8 32.3 5% 114.9 114.9 145.2 351.0 473.4 30.3 8% 111.7 111.7 140.9 330.6 442.1 29.2 10% 109.7 109.7 138.3 318.3 423.4 28.6 15% 105.1 105.1 132.1 291.4 383.1 27.0 20% 100.9 100.9 126.5 268.9 350.1 25.6 NCF00057 p08 02.18 1) See MD&A and MCR 82
Appendix Summary of France Reserves Information (1) Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Undeveloped Light & Medium Crude Oil (MMbbl) Company Gross Working Interest Reserves 6.4 6.6 8.8 17.6 25.9 0.2 2.2 Company Net Reserves 5.6 5.8 7.7 15.4 22.8 0.2 1.9 Heavy Crude Oil (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Conventional Natural Gas (Bscf) Company Gross Working Interest Reserves Company Net Reserves Natural Gas Liquids (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Total Oil Equivalent (MMboe) Company Gross Working Interest Reserves 6.4 6.6 8.8 17.6 25.9 0.2 2.2 Company Net Reserves 5.6 5.8 7.7 15.4 22.8 0.2 1.9 Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Uneveloped Net Present Value Before Tax (MUSD) 0% 93.2 94.9 161.0 474.7 1,027.1 1.7 66.1 5% 91.7 92.6 126.4 322.3 554.5 0.9 33.8 8% 86.6 87.2 109.4 260.1 415.9 0.6 22.2 10% 82.7 83.1 99.6 228.0 352.7 0.4 16.5 15% 72.8 72.9 79.6 170.1 250.7 0.1 6.7 20% 63.9 63.8 64.8 132.6 191.4-0.1 1.0 Net Present Value After Tax (MUSD) 0% 60.2 61.5 110.3 334.3 737.7 1.3 48.8 5% 68.5 69.2 93.8 241.2 412.7 0.7 24.6 8% 67.4 67.8 83.6 197.4 312.2 0.4 15.8 10% 65.6 65.9 77.3 174.1 265.7 0.3 11.4 15% 59.7 59.7 63.5 131.3 189.9 0.0 3.8 20% 53.7 53.5 52.8 103.1 145.6-0.1-0.7 NCF00057 p09 02.18 1) See MD&A and MCR 83
Appendix Summary of Netherlands Reserves Information (1) Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Undeveloped Light & Medium Crude Oil (MMbbl) Company Gross Working Interest Reserves 0.0 0.0 0.0 0.0 0.1 0.0 0.0 Company Net Reserves 0.0 0.0 0.0 0.0 0.1 0.0 0.0 Heavy Crude Oil (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Conventional Natural Gas (Bscf) Company Gross Working Interest Reserves 5.8 5.8 10.8 17.9 0.6 0.0 Company Net Reserves 5.8 5.8 10.8 17.9 0.6 0.0 Natural Gas Liquids (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Total Oil Equivalent (MMboe) Company Gross Working Interest Reserves 0.9 1.0 1.0 1.8 3.0 0.1 0.0 Company Net Reserves 0.9 1.0 1.0 1.8 3.0 0.1 0.0 Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Uneveloped Net Present Value Before Tax (MUSD) 0% -23.7-23.0-22.8-2.6 40.8 0.7 0.2 5% -10.2-8.6-8.3 13.0 43.0 1.6 0.2 8% -5.3-3.5-3.2 17.0 41.8 1.8 0.2 10% -2.8-1.0-0.7 18.5 40.6 1.9 0.2 15% 1.3 3.2 3.4 20.2 37.0 1.9 0.2 20% 3.7 5.5 5.7 20.2 33.6 1.8 0.2 Net Present Value After Tax (MUSD) 0% -23.7-23.0-22.8-4.8 29.6 0.7 0.2 5% -10.2-8.6-8.3 11.0 33.9 1.6 0.2 8% -5.3-3.5-3.2 15.0 33.6 1.8 0.2 10% -2.8-1.0-0.7 16.6 32.9 1.9 0.2 15% 1.3 3.2 3.4 18.3 30.3 1.9 0.2 20% 3.7 5.5 5.7 18.5 27.6 1.8 0.2 NC00057 p10 02.18 1) See MD&A and MCR 84
Appendix Summary of IPC International (1) Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Undeveloped Light & Medium Crude Oil (MMbbl) Company Gross Working Interest Reserves 9.7 9.9 12.7 26.7 37.7 0.2 2.9 Company Net Reserves 8.4 8.6 11.1 23.2 32.9 0.2 2.5 Heavy Crude Oil (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Conventional Natural Gas (Bscf) Company Gross Working Interest Reserves 5.2 5.8 5.8 10.8 17.9 0.6 0.0 Company Net Reserves 5.2 5.8 5.8 10.8 17.9 0.6 0.0 Natural Gas Liquids (MMbbl) Company Gross Working Interest Reserves Company Net Reserves Total Oil Equivalent (MMboe) Company Gross Working Interest Reserves 10.5 10.8 13.7 28.5 40.7 0.3 2.9 Company Net Reserves 9.3 9.5 12.0 25.0 35.8 0.3 2.5 Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Uneveloped Net Present Value Before Tax (MUSD) 0% 190.1 192.5 291.2 863.5 1,626.0 2.4 98.6 5% 196.4 198.9 263.3 686.4 1,088.5 2.5 64.3 8% 193.0 195.4 247.1 607.8 915.5 2.4 51.7 10% 189.5 191.8 237.1 564.9 831.4 2.3 45.3 15% 179.1 181.1 215.1 481.6 683.4 2.0 33.9 20% 168.5 170.2 197.0 421.7 585.9 1.7 26.8 Net Present Value After Tax (MUSD) PDP PD 1P 2P 3P PDNP PUD 0% 157.2 159.2 240.5 720.9 1,304.1 2.0 81.3 5% 173.3 175.5 230.7 603.1 920.1 2.3 55.2 8% 173.8 176.1 221.3 543.0 787.8 2.2 45.3 10% 172.5 174.6 214.8 509.0 721.9 2.2 40.2 15% 166.1 168.0 199.0 441.0 603.3 1.9 31.0 20% 158.3 159.9 185.0 390.5 523.3 1.6 25.1 NCF00054 p12 02.18 1) See MD&A and MCR 85
Appendix Summary of IPC Reserves Information (1) Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Undeveloped Light & Medium Crude Oil (MMbbl) Company Gross Working Interest Reserves 9.7 9.9 12.7 26.7 37.7 0.2 2.9 Company Net Reserves 8.4 8.6 11.1 23.2 32.9 0.2 2.5 Heavy Crude Oil (MMbbl) Company Gross Working Interest Reserves 13.1 13.4 18.9 27.3 34.5 0.3 5.4 Company Net Reserves 12.6 12.9 17.9 25.7 32.0 0.3 5.1 Conventional Natural Gas (Bscf) Company Gross Working Interest Reserves 336.4 363.0 363.7 449.9 515.7 26.6 0.7 Company Net Reserves 319.1 344.4 345.1 426.6 489.3 25.3 0.6 Natural Gas Liquids (MMbbl) Company Gross Working Interest Reserves 0.0 0.0 0.0 0.1 0.1 0.0 0.0 Company Net Reserves 0.0 0.0 0.0 0.1 0.1 0.0 0.0 Total Oil Equivalent (MMboe) Company Gross Working Interest Reserves 78.9 83.8 92.3 129.1 158.3 5.0 8.5 Company Net Reserves 74.2 78.9 86.5 120.1 146.4 4.7 7.7 Developed Producing Developed Total Total plus Probable Total plus Probable plus Possible Developed Non Producing Uneveloped Net Present Value Before Tax (MUSD) 0% 724.8 773.1 1,008.1 2,035.6 3,232.0 48.2 235.1 5% 716.0 750.0 883.7 1,573.1 2,192.8 34.0 133.8 8% 673.9 701.8 802.0 1,366.2 1,832.7 27.8 100.3 10% 643.7 668.1 752.1 1,253.1 1,651.8 24.4 84.1 15% 572.1 589.7 646.3 1,034.2 1,325.5 17.6 56.5 20% 511.7 524.4 564.2 878.6 1,107.8 12.6 39.8 Net Present Value After Tax (MUSD) 0% 576.5 612.8 811.1 1,653.4 2,574.1 36.3 198.3 5% 601.2 626.1 737.1 1,313.3 1,794.7 24.9 111.0 8% 573.7 593.8 676.4 1,151.2 1,514.5 20.0 82.7 10% 551.6 568.9 638.0 1,061.2 1,372.2 17.3 69.1 15% 496.0 508.1 554.3 884.8 1,113.1 12.0 46.2 20% 447.4 455.6 487.9 757.9 938.4 8.2 32.4 NCF00057 p11 02.18 1) See MD&A and MCR 86
Reader Advisory Forward Looking Statements This 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 integration 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 expectation 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 production 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 forward-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 associated 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 Measures References 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 Reporting 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 Corporation 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. 2P reserves means IPC s gross proved plus probable reserves. 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