ARC Resources Ltd Investor Day. November 12, 2018

Transcription

1 ARC Resources Ltd Investor Day November 12, 2018

2 Agenda 9:30 am 9:35 am Welcome Bevin Wirzba, Senior Vice President, Business Development and Capital Markets 9:35 am 10:00 am Introduction Myron Stadnyk, President and Chief Executive Officer 10:00 am 10:20 am Capital Allocation, Funding Strategy & Commodity Outlook Van Dafoe, Senior Vice President and Chief Financial Officer 10:20 am 10:40 am 2018 Accomplishments & 2019 Budget Terry Anderson, Senior Vice President and Chief Operating Officer 10:40 am 10:55 am Break 10:55 am 11:40 am Attachie West Greater Dawson Area Ante Creek Lara Conrad, Vice President, Engineering and Planning Armin Jahangiri, Vice President, Operations 11:40 am 11:45 am Summary Myron Stadnyk, President and Chief Executive Officer 11:45 am 12:00 pm Questions

3 Introduction

4 ARC Is a Compelling Investment ARC Is a Unique and Differentiated Canadian Upstream E&P Company 50 Canadian Public E&P Companies (1) E Debt-to-Cash Flow <2.0x ARC is the only Montney 7 Enterprise Value >$3 billion pure play company with significant inventory 4 Decline Rate <30% (1) Refers to non-integrated and non-royalty Canadian public exploration companies with a focus on Canadian development.

5 Building Sustainable Businesses in the Montney Businesses Sustain Production and Generate Free Cash Flow at Low Reinvestment Rates Montney Businesses Attachie West Phase I Montney Production Cardium & Non-core Production Dawson Phase IV Ante Creek Expansion Sunrise Phase II Dawson Phase I & II Upgrade Parkland Tower Phase I Sunrise Phase I Parkland Tower Battery Upgrade Dawson Phase III Sunrise Phase II Dawson Phase I Dawson Phase II Ante Creek Phase I 2009 Non-core Dispositions Q Q Q Q ~$575 Million Facility Investment $360 Million Facility Investment 540 MMcf/day of Natural Gas Capacity 17.5 Mbbl/day of Liquids Capacity 165 MMcf/day of Natural Gas Capacity 30 Mbbl/day of Liquids Capacity

6 ARC s Focus Has Improved The Results Are Clear Delivering Industry-leading Returns via per Share Growth and Dividends Disciplined Capital Allocation Sustaining Capital Requirements F Net Well Count 28% Three-year Average F&D Costs Operating Expenses 61% Focus on Efficiency Improvements 2009 Q % F 46% Physical Market Access and Financial Risk Management Multiple Direct Sales Points across North America for liquids and natural gas production ~$0.8 billion of realized cash gains on risk management contracts since 2009

7 Sustainable Dividend-paying E&P Company ARC s Business Model Supports Profitable Future Growth Portfolio Balance Sheet Capital Efficiencies and Declines 2019 Capital Program $775MM Fully Funded Montney land base is focused with inventory for decades of sustainable investment 23-year history of maintaining net debt-to-trailing funds from operations ratio between 1.0 and 1.5 times Improve capital efficiencies and manage corporate decline rates to support sustainable growth and dividend Kicks off three-year program to deliver production growth of greater than 10% Plan does not require outside financing, asset sales, or inventory upgrades

8 ARC Delivered through Its Transformation ARC s Plan Remains Focused on Profitability, Sustainability, and Creating Optionality for the Long Term Monthly dividend of $0.05 per share Brought on Dawson Phase III Sustained Montney businesses Execute capital program of $775 million Sold Saskatchewan assets Rebuilt liquids production from divestments Built 3,000 bbl per day battery at Attachie West Bring on Sunrise Phase II to full capacity Eliminated DRIP and SDP plans Achieved success in Lower Montney and Attachie Progressed Sunrise Phase II (60 MMcf per day in service by year-end) Bring on Dawson Phase I & II liquidshandling upgrade 118,671 boe per day 122,937 boe per day Parkland-Dawson interconnect in service Divested non-core assets including Redwater 131,000 to 133,000 boe per day Progress multiple largescale projects, leading to per share production and cash flow growth Dawson Phase IV Ante Creek expansion Attachie West Phase I Maintain Share Count Cash Flow per Share Growth Is Critical

9 ARC s Three-year Plan Three-year Capital Investment Program Will Result in Meaningful Liquids Production and Cash Flow per Share Growth Years Execute capital program of $775 million Bring on Dawson Phase IV in Q2 Bring on Attachie West Phase I in Q2 Dividend Average $210 million Bring on Sunrise Phase II to full capacity Bring on Ante Creek expansion in Q2 Progress next major capital project Sustaining capital Average $400 million Bring on Dawson Phase I & II liquidshandling upgrade Progress multiple largescale projects, leading to per share production and cash flow growth Dawson Phase IV Ante Creek expansion Attachie West Phase I Progress Attachie West Phase I Growth capital Average $350 million Production CAGRs Total: >10% Condensate: >40% NGLs: >25% Natural gas: >10% Crude oil: <5% decline Maintain Share Count Consider Development, Share Buybacks, and Increasing Dividend

10 Capital Allocation, Funding Strategy & Commodity Outlook

11 ARC s Capital Allocation Principles Founded on Balance Sheet Strength, Based on In-depth Analysis of Project Economics and Impacts to Corporate Profitability Strong Balance Sheet Stable and Meaningful Dividend Detailed Project-level Analysis Full-cycle Profitability Total Corporate Returns FINANCIAL DISCIPLINE

12 How ARC Chooses to Fund Its Business Increasing Cost of Capital ARC s Current Funding Choices Cash and Long-term Debt Have the Lowest Cost of Capital Cash Debt New Equity Asset Sale PDP Non-core Asset Disposition Proceeds Midstream Joint Venture (Includes Operating Expense Dilution) Upstream Joint Venture (Includes Asset Dilution)

13 $ millions ARC Prudently Manages a Strong Balance Sheet F Ratio Targeting a Net Debt to Annualized Funds from Operations Ratio of 1.0 to 1.5 Times over the Long Term Net Debt to Funds from Operations 1, , Net Debt (LHS) Funds From Operations (LHS) Net Debt to Funds from Operations (RHS) ARC exercises rigor in understanding the headwinds and tailwinds that the Company faces in order to preserve its balance sheet and strong financial position

14 ARC Has Pre-funded Its Three-year Growth Plan Disposition Proceeds Have Given ARC the Ability to Temporarily Outspend Cash Inflows Total Forecasted Inflows & Outflows (1)(2)(3) 2017 to 2020 ARC can sustain the business at US$50/bbl WTI and Cdn$1.50/GJ AECO Net A&D Proceeds and Excess Funds from Operations Dawson Phase III Sunrise Phase II Dawson Phase I & II Upgrade Dawson Phase IV Ante Creek Expansion Attachie West Phase I ~$400 million/year Funds from Operations ~$210 million/year Sources of Cash Dividend Sustaining Capital Growth Capital (1) Assumes flat pricing of US$60/bbl WTI and Cdn$2.00/GJ AECO. (2) Funds from operations is after tax. (3) Sustaining and growth capital do not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities. Refer to Other Definitions in the Advisory Statements to this presentation.

15 Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q3 2018F Q4 2018F Q1 2019F Q2 2019F Q3 2019F Q4 2019F MMbbl/day MMbbl/day Crude Oil Outlook Global Crude Oil Fundamentals Remain Supported and Egress Relief Is Anticipated in Late 2019 for the WCSB Global Oil Supply/Demand Balance (1) WCSB Crude Oil Pipeline Takeaway Capacity (2) 2.0 EIA Supply-Demand IEA Supply-Demand Forecast 6.0 Existing Pipelines Visible Rail Enbridge Line 3 Expansion Keystone XL Net Supply for Export (1.0) 3.0 (2.0) F 2020F 2021F Global crude oil balances have recently moderated but still remain susceptible to unexpected supply outages Structural changes in Western Canada egress are expected to help alleviate congestion in H (1) Source: ARC Risk Research, International Energy Agency, US Energy Information Administration. (2) Source: ARC Risk Research, National Energy Board, Canadian Association of Petroleum Producers, Alberta Energy Regulator.

16 Robust Demand for Canadian Condensate Mbbl/day Demand for Diluent Remains Significantly Higher Than Local WCSB Production and Is Supportive of Strong Condensate Pricing WCSB Condensate Supply/Demand Balance (1) F 2020F 2021F 2022F WCSB Condensate Imports Required Total Condensate Demand (1) Source: ARC Risk Research, National Energy Board, Wood Mackenzie, Alberta Energy Regulator.

17 ARC Is Growing Its Liquids Business Growth Projects Target Organic Development of High-value Light Oil and Condensate Production 29% of ARC s 2018 YTD production is made up of crude oil and liquids production 80% of ARC s crude oil and liquids production is made up of oil and condensate 41% $79/bbl ARC s Crude Oil & Liquids Sales Mix (1) 39% $85/bbl 2019 to 2021 Anticipated Production CAGRs Condensate: >40% NGLs: >25% 68% of ARC s 2018 YTD overall sales revenue derived from crude oil and liquids production Oil 20% $35/bbl Condensate NGLs (1) Pricing denotes average realized pricing for the nine months ended September 30, 2018.

18 Globalization of North American Natural Gas Supply North American Natural Gas Market Has Become Increasingly Connected to Global Natural Gas Markets Western Canadian & US Egress and Demand Outlook (1) LNG Canada Phase Bcf/day, ~2024 Intra-AB Demand +1.0 Bcf/day, ~2022 NGTL EGAT Expansions +1.3 Bcf/day, Westcoast T-South Expansion +0.2 Bcf/day, 2020 US Demand +6.0 Bcf/day, ~2022 NGTL WGAT Expansions +0.4 Bcf/day, 2020 US LNG Export Capacity 10 Bcf/day, 2020 Pipeline Exports to Mexico 6-7 Bcf/day, 2022 (1) Source: ARC Risk Research, Alberta Energy Regulator, TransCanada, Enbridge, Shell, Bentek, US Energy Information Administration, Goldman Sachs, Morgan Stanley, Citi, Wood Mackenzie.

19 ARC s Natural Gas Business Cdn$/Mcf % of Total Production ARC Diversifies Its Price Exposure, Leading to Improved Price Realizations Firm transportation pipeline agreements in place for Dawson Phase IV and Attachie West Phase I Less than five per cent exposure to Western Canadian pricing ARC s Corporate Natural Gas Price $3.34 $3.24 $2.96 $3.02 $3.07 $0.78 $0.74 $0.87 $0.88 $0.39 $0.32 $ % 75% ARC Natural Gas Diversification (1)(2) 4% 4% 4% 4% 4% 7% 7% 19% 22% 30% 26% 18% $0.72 $0.56 $0.63 $2.17 $2.18 $1.28 $1.43 $ Q Q Q YTD % 25% 0% 15% 6% 34% 9% 12% 15% 23% 23% 14% Bal 2018 Cal 2019 Cal 2020 Realized Gains on Risk Management Contracts Diversification Activities Average Price before Diversification Activities Hedged Midwest US Floating Dawn Floating AECO Floating Henry Hub Floating Station 2 Floating Pac-NW US Floating (1) Based on production assumptions for sanctioned projects. (2) Hedged includes all physical and financial fixed price swaps and collars at AECO, Station 2, and Henry Hub.

20 ARC s Funding Model Post-Dawson Phase IV, Productive Capacity Will Allow ARC to Self-fund Itself in a Modest Commodity Price Environment Future Inflows & Outflows (1)(2)(3) Discretionary Growth Projects Pay meaningful dividend and grow cash flow per share No external sources of capital or asset sales required Funds from Operations ~$400MM/year Manage net debt to funds from operations ratio at x ~$210MM/year Sources of Cash Dividend Sustaining Capital Growth Capital Continue to implement ARC s physical and financial diversification strategy ARC can fund the dividend and sustaining and growth capital at US$60/bbl WTI and US$3.00/MMBtu NYMEX Consider Development, Share Buybacks, and Increasing Dividend (1) Assumes flat pricing of US$60/bbl WTI and Cdn$2.00/GJ AECO. (2) Funds from operations is after tax. (3) Sustaining and growth capital do not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities. Refer to Other Definitions in the Advisory Statements to this presentation.

21 2018 Accomplishments & 2019 Budget

22 2018 Accomplishments Strong Capital and Operational Performance across ARC s Portfolio Attachie piloting activities Underpins sanctioning of Attachie West Phase I Lower Montney success at Dawson and Parkland Grows liquids production in core operating areas Commissioning of Sunrise Phase II Lowest cost, highest margin gas asset in portfolio Parkland- Dawson interconnect online Allows optimization of liquids production Divested non-core assets Reduced liabilities and lowered operating costs Continued strong safety performance 4.5 years losttime incident free for employees

23 Primary Objectives of ARC s 2019 Budget Investing in Infrastructure to Advance Multi-year Development Projects to Deliver Future Liquids Growth Attachie Initial success at Attachie supports multi-phase development Progress first commercial development at Attachie West Phase I Continue piloting and optimizing drilling and completion design Dawson Shift to Lower Montney driving investment Meaningful liquids production and cash flow per share growth Optimize Phase I & II facilities to increase liquids-handling capacity Advance Phase IV, targeting condensate-rich Lower Montney Ante Creek Improved completions has increased competitiveness Upgrade existing facility to increase solution gas processing and oil-handling capacity

24 2019 Guidance Investing in Multi-year Infrastructure to Grow Liquids Production and Deliver per Share Growth over the Long Term Invest $775 million 31,500 37,000 bbl/day of liquids production MMcf/day of gas production to add facility capacity in NE BC and Alberta to produce 135, ,000 boe/day through investing $300 million in multi-year facility and infrastructure projects and drilling 77 gross operated wells with improved operating costs of $5.30 $5.70/boe while ensuring the safe and responsible execution of the capital program Allowing ARC to: Maintain Balance Sheet Strength Focus on Organic Liquids Growth Create Shareholder Value

25 2019 Budget Outcomes and 2019 to 2021 Outlook Confidence in Future Development Plan to Provide Multi-year Outlook Outlook 2019 to 2021 Dividend Sustaining capital (1) Growth capital (1) Net debt to annualized funds from operations ratio Anticipated production CAGRs Total Condensate NGLs Natural gas Crude oil Annual average of $210 million Annual average of $400 million Annual average of $350 million Less than 1.5 times Greater than 10 per cent Greater than 40 per cent Greater than 25 per cent Greater than 10 per cent Less than 5 per cent decline (1) Sustaining and growth capital do not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities. Refer to Other Definitions in the Advisory Statements to this presentation.

26 2019 Budget of $775 Million Advances Projects to Deliver Near-term Annual Production of 135,000 to 142,000 boe per day and Multi-year Growth BC AB Attachie $184MM 6 wells (5 Hz +1 Injection) 3,000 boe/day Attachie West Phase I is sanctioned to come onstream in Q Parkland/Tower $128MM 13 wells 32,000 boe/day Sustain production at current facility capacity and develop Lower Montney via interconnect to Dawson $400MM Sustaining Capital (1) $375MM Growth Capital (1) Attachie Red Creek Tower Pouce Coupe Septimus Parkland Sunset Sunrise Dawson Sundown Ante Creek Dawson $299MM 39 wells 42,000 boe/day Phase IV facility sanctioned to come on stream in Q2 2020; development is focused on liquids-rich Lower Montney Sunrise $24MM 34,000 boe/day Initial 60 MMcf/day at Phase II facility on-stream, production will ramp up once final transportation arrangements come into effect in 2019 Pembina Ante Creek $95MM 12 wells 16,000 boe/day Expansion at Ante Creek facility to add 15 MMcf/day of gas and 2,500 bbl/day of oil in Q Pembina $31MM 7 wells 10,000 boe/day Manage production declines and maximize free cash flow generation from light oil production (1) Sustaining and growth capital do not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities. Refer to Other Definitions in the Advisory Statements to this presentation. Note: Well counts denote wells drilled in calendar year; number of wells with completion activities in calendar year may vary.

27 Proven Expertise in Facility Development Investment in Infrastructure Results in Operational Flexibility to Maximize Profitability Aligned with Long-term Development 100% ARC Owned-andoperated Aggressive in Advancing Multiple Projects Simultaneously Designed for Optionality Dawson Phase I (2010) Dawson Phase II (2011) Ante Creek Phase I (2012) Parkland/Tower Phase I (2013) Sunrise Phase I (2015) Dawson Phase III (2017) Sunrise Phase II (2018 to 2019) Dawson Phase IV (Estimated Q2 2020) Ante Creek Expansion (Estimated Q2 2020) Attachie West Phase I (Estimated Q2 2021)

28 1 Three-year Infrastructure Investment Plan ARC Will Advance Multiple Projects to Add Significant Processing Capacity; Production Will Grow into Development Processing Capacity Projects Oil and Condensate (bbl/day) NGLs (bbl/day) Natural Gas (MMcf/day) Total (boe/day) Parkland-Dawson Interconnect Sunrise Phase II ,000 Sanctioned Q Dawson Phase I & II Upgrade 2,000 1,000 3,000 Dawson Phase IV 7,500 3, ,500 Ante Creek Expansion 2, ,000 Attachie West Phase I 10,000 4, ,000 Sanctioned Development Processing Capacity Available

29 Asset Overview

30 Montney Fairway Highly-efficient, Low-cost Montney Assets Driving Value BC AB Geographic Optionality Egress Optionality Commodity Optionality 1,000m 2,000m 3,000m Lower Montney 10 kpa/m Line Attachie Tower Parkland Dawson Oil and Liquids Significant Resource Potential Total petroleum initially-in-place (1) identified across ARC s NE BC and Pouce Coupe assets includes: 1,000m 10.5 billion barrels of tight oil 102 Tcf of shale gas ARC is the third largest Montney landholder Ante Creek Dry Gas Multi-layer Optionality 2,000m Condensate-rich Gas (1) Year-end 2017 results comply with current Canadian Oil and Gas Evaluation Handbook guidelines. Resources Evaluation volumes provided are the risked Best Estimate case. Year-end 2017 total petroleum initially-in-place estimates utilize a one per cent porosity cut-off based on Best Estimate case. Excludes Blueberry lands, which were divested in the first quarter of 2018.

31 Attachie West

32 Pembina Attachie West Ready to Invest in World-class Reservoir Significantly Over-pressured Reservoir and Large Contiguous Land Position Foundation for Decades of Future Development BC AB Lower Montney 10 kpa/m Line Attachie 4-20 Battery (3 Mbbl/day) North Montney Mainline Attachie West Phase I 60 MMcf/day & 14 Mbbl/day Q Attachie West Phase I Attachie area includes 8.9 Bbbl liquids and 32 Tcf gas in place (1) (1) Total Petroleum Initially-in-Place for oil and gas.

33 Attachie West Condensate-rich Production Profile Upper Montney Lower Montney Suited for Multi-layered Development, Condensate Is Being Produced from Both the Upper and Lower Montney Horizons Attachie West pad currently averaging CGR of 265 bbl/mmcf (1) Reservoir is significantly over-pressured at 40 to 70% Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells (1) Pad average excludes Lower Montney well.

34 Attachie West Ready for Commercial Development Attachie West Is Delineated and Ready for Development Phase I Upper Montney 13 wells on production in Attachie West Includes multi-well demonstration pad brought on production in 2018 Strong well deliverability observed to-date and stable CGRs Full range of outcomes are profitable Exploitation strategy to be optimized A13-26 B13-26 Single-well Appraisals 2014 to 2017 Commercial Demonstration Pad 2017 to 2018 Commercial Development Q Applying Learnings Sanctioning Decision Attachie West Wells Drilled Attachie West Demonstration Pad

35 Cumulative Oil & Condensate Production (Mbbl) Attachie West Strong Production Results Transferred Learnings between Tower and Attachie Has Resulted in Meaningful Improvements to Type Curves and Well Inventory 225 Cumulative Oil & Condensate Production Mbbl of liquids 450 MMcf of gas in 200 days 100 Mbbl of liquids 643 MMcf of gas in 440 days Attachie Estimated Ultimate Recovery at YE 2017 Condensate: 386 Mbbl NGLs: 10 Mbbl Gas: 2.7 Bcf Total: 846 Mboe ,050 1,200 Days on Production Attachie Attachie B13-26 Attachie Attachie Pad Average Attachie West 2019 Type Curve Tower West Pad Average Parkland F11-04

36 Production Rate (boe/day) Attachie West Phase I Type Curve Expectations Initial Type Curve Developed for Broad Range of Outcomes and Confidently Supports Development 1,000 Attachie West Development (1)(2)(3)(4) 2019 Type Curve Key Metrics 2019 Type Curve 750 DCET Capex/Well ($ millions) 6.3 Internal 2P Reserves (Mboe) 725 IP (1 month) (boe/day) IP (12 months) (boe/day) 555 Half-cycle Economics US$60/bbl WTI & Cdn$2.00/GJ AECO 250 IRR (%, after-tax) Months on Production (1) Type curves are internal estimates based on analog wells and reservoir modeling. (2) Assumed cycle time (from spud to on-production): six months. (3) Average lateral length of 2,000 m for 2019 Type Curve. (4) Chart data based on raw production data; table data based on sales.

37 Attachie West Focused on Efficient Execution Leveraging Technology to Optimize Attachie Fracture Stimulation Design Microseismic Monitoring Fibre-optic Monitoring Fracture Modelling (1) Utilizing technology to optimize design Driving down cost and improving capital efficiencies (1) Source: Schlumberger Canada Limited.

38 Attachie Planning for Multi-phase Development Investment in Additional Infrastructure Earlier in Project Life Cycle Results in Capital Savings and Higher Profitability Access Road Water Infrastructure Temporary Accommodation Sales Pipelines

39 Attachie West Phase I Project Timeline Development Timeline for Q On-stream Date; Licensing up Front for Multiple Phases Investment Decision ` Q Q Q Q Q Q Q Q Q Q Q Front-end Engineering & Design Regulatory Approval Attachie West Phase I Plant Equipment Fabrication Field Construction Commissioning Plant Start-up Well Activity Additional Infrastructure Drilling & Completions Access Road Water Hub Sales Pipelines

40 ARC s Attachie West Phase I Business Outcome 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F 2027F 2028F 2029F 2030F 2031F Profitably Investing in First Major Phase of Development While Planning for Subsequent Phases,000,000,000,000,000,000 Natural Gas Processing Capacity: 60 MMcf/day Condensate-handling Capacity: 10,000 bbl/day NGLs-handling Capacity: 4,000 bbl/day 35,000 30,000 25,000 20,000 15,000 10,000 5,000 $0 0-5,000,000,000),000,000) Field Netback (1) Capital Expenditures Facility Expenditures Net Cash Flow Production -10,000-15,000-20,000-25,000-30,000,000,000) Facility and Infrastructure Pre-drill 22 Wells Drill 15 Wells per Year 45% of Field Netback Required to Sustain Business (1) -35,000 (1) Economics run at US$60/bbl WTI and Cdn$2.00/GJ AECO flat pricing.

41 Attachie Ready to Invest in First Major Phase Key Success Factors to Become ARC s Next Core Growth Platform Significant Acreage Position in Sweet Spot Attachie West Has Been Delineated Development Plan Is Well Underway Profitable Business Low price of entry Large contiguous land block of 306 net sections, ~99% working interest Liquids-rich,overpressured 8.9 Bbbl liquids and 32 Tcf gas in place (1) 156 MMbbl liquids and 1 Tcf gas classified as ECR at YE 2017 (2) 13 wells on production at Attachie West, including multi-well commercial demonstration pad Strong well deliverability Deep inventory Full range of outcomes are profitable Leveraging Tower experience to optimize well designs early in play life Market access via TCPL North Montney Mainline expansion Efficient with 45% of field netback required to sustain business Will generate free cash flow from 2022 onwards Condensate pricing; premium product Attachie West is ready for initial phase of development and huge resource will support multiple additional phases for decades to come (1) Total Petroleum Initially-in-Place for oil and gas. (2) Economic Contingent Resource. Resources Evaluation volumes is the risked Best Estimate case. Liquids is oil, condensate, and NGLs.

42 Greater Dawson Area

43 Greater Dawson Area Integration and Optimization Proximity of Lands Allows for Optimized Infrastructure Utilization and Efficient Multi-layered Development and Area Egress Tower Pembina & Enbridge 8-13 Compressor Phase I & II Gas Plants Parkland-Dawson Interconnect Dawson Parkland TCPL Phase III & IV Gas Plants 1-34 Compressor Phase I & II Gas Plants Q Parkland-Dawson Pipeline Interconnect Q Dawson Phase I & II Liquids Upgrade Q Dawson Phase IV Facility

44 Greater Dawson Area Lower Montney Investments 2017 Appraisal Activities and Subsequent 2018 Investments Unlocked Significant Opportunity to Grow Liquids Production Tower Parkland Pouce Coupe Total Lower Montney Wells Drilled/Planned wells wells Sunrise Dawson 2020 ~20 wells Note: Only Lower Montney wells are displayed to Q Lower Montney Drilled and Completed Wells Wells Planned for 2018 Wells Planned for 2019 Parkland-Dawson Interconnect

45 Cumulative Liquids Production (Thousand Stock Tank Barrels) Parkland-Dawson Proven Lower Montney Results Impressive Liquids Results Drove Decision to Interconnect Parkland and Dawson Fields Parkland-Dawson Lower Montney Wellhead Liquids Production Mbbl of liquids 950 MMcf of gas in 235 days 100 Mbbl of liquids 490 MMcf of gas in 280 days Producing Days Parkland F11-04 Parkland Dawson Dawson C03-15 Dawson F09-21 Dawson D16-13 Dawson H03-15 Dawson K03-15 Medium Liquids High Liquids

46 Production Rate (boe/day) Parkland-Dawson Lower Montney Development High Liquids Yields Driving Strong Economics for Lower Montney Development Parkland-Dawson Lower Montney Development (1)(2)(3) 1,600 1, bbl/mmcf 200 bbl/mmcf Medium Liquids Ratio 2019 Type Curve High Liquids Ratio 2019 Type Curve Key Metrics Medium Liquids Ratio 2019 Type Curve High Liquids Ratio 2019 Type Curve DCET Capex/Well ($ millions) Internal 2P Reserves (Mboe) 1, IP (1 month) (boe/day) 1,340 1,050 IP (12 months) (boe/day) bbl/mmcf Half-cycle Economics US$60/bbl WTI & Cdn$2.00/GJ AECO IRR (%, after-tax) bbl/mmcf Months on Production (1) Type curves are internal estimates based on analog wells and reservoir modeling. (2) Assumed cycle time (from spud to on-production): four months. (3) Lateral length of 2,200 m for Medium Liquids Ratio and High Liquids Ratio 2019 Type Curves.

47 Production Rate (Mcfe/day) Dawson Optimizing Upper Montney Development ARC Is Growing Its Inventory of Liquids-rich Wells outside of the Dawson Core Dawson Upper Montney Development (1)(2)(3)(4) 8,000 6,000 5 bbl/mmcf Dawson Upper Dry Gas 2019 Type Curve Dawson Upper Liquids-rich 2019 Type Curve Key Metrics Dawson Upper Liquids-rich 2019 Type Curve Dawson Upper Dry Gas 2019 Type Curve DCET Capex/Well ($ millions) Internal 2P Reserves (Bcfe) , bbl/mmcf IP (1 month) (Mcfe/day) 7,100 7,300 IP (12 months) (Mcfe/day) 6,300 4,400 2,000 Half-cycle Economics US$60/bbl WTI & Cdn$2.00/GJ AECO IRR (%, after-tax) Months on Production (1) Type curves are internal estimates based on analog wells and reservoir modeling. (2) Assumed cycle time (from spud to on-production): four months. (3) Lateral length of 2,200 m for Dawson Core and Dawson Fringe 2019 Type Curves. (4) Chart data based on raw production data; table data based on sales.

48 Dawson Phase IV Profitable Investment Robust Project Economics across Range of Pricing Scenarios Benefit from Increases in Both Gas and Condensate Pricing Single Well Economics Project Economics ROR of % (1) ROR of ~22% (1) Project Economics US$70/bbl WTI US$60/bbl WTI US$50/bbl WTI Cdn$2.25/GJ AECO 28% 24% 20% Cdn$2.00/GJ AECO 26% 22% 18% Cdn$1.75/GJ AECO 24% 20% 16% Greater Dawson Area includes 71 MMbbl of oil & NGLs and 1.9 Tcf of gas (2P reserves) (1) Economics run at US$60/bbl WTI and Cdn$2.00/GJ AECO flat pricing.

49 Dawson I & II Liquids Upgrade Project Upper Montney Lower Montney Project Leverages Existing Infrastructure and Will Add 3,000 Barrels per Day of Liquids Processing Capacity by Year-end 2019 Existing core infrastructure is key to improving capital efficiencies at Dawson Lower Montney development will benefit from pre-existing infrastructure Surface locations Pad sites Gathering systems Well site facilities Facility upgrades allow for increased condensate-handling capacity Low capital expenditure for incremental cash flow One of the most economic projects in ARC s long-term plan Existing Horizontal Wells, Development Potential Horizontal Wells

50 Dawson IV Expansion Project Flexibility Incorporated into Facility Design and Takes Advantage of Prior Investments in Dawson Phase III Infrastructure Dawson Phase IV Adds 90 MMcf/day of natural gas, 7.5 Mbbl/day of condensate, and 3 Mbbl/day of NGLs processing capacity Project benefits from existing sales lines, acid gas, water infrastructure, and gathering systems On-stream in Q Parkland-Dawson Interconnect Allows for Lower Montney production from Parkland to be processed at Dawson Phase III and IV facilities Pipeline commissioned in Q Dawson Phase IV Expansion Site

51 ARC s Dawson Phase IV Business Outcome 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F 2027F 2028F 2029F 2030F Infrastructure Investment in Greater Dawson Area to Support Broad Shift to Liquids-rich Lower Montney 000, , ,000 Natural Gas Processing Capacity: 90 MMcf/day Condensate-handling Capacity: 7,500 bbl/day NGLs-handling Capacity: 3,000 bbl/day 35,000 30,000 25,000 20,000 15,000 10,000 5, ,000 $0-10,000-15,000 00,000) 00,000) Field Netback (1) Capital Expenditures Facility Expenditures Net Cash Flow Production -20,000-25,000-30,000-35,000 Facility and Infrastructure Pre-drill 14 Wells Drill 8 to 10 Wells per Year 40% of Field Netback Required to Sustain Business (1) (1) Economics run at US$60/bbl WTI and Cdn$2.00/GJ AECO flat pricing.

52 Greater Dawson Area Confidence in Outcomes Key Success Factors Support Investment in Infrastructure to Develop Liquids-rich Lower Montney High Confidence, Liquids-rich Development Efficiencies of Development Opportunity Large Well Inventory Profitable Business Proven liquids-rich Lower Montney development at Dawson and Parkland Upper Montney at Dawson Phase III & IV produces more liquids than core Dawson Condensate pricing; premium product Continuous improvements in well design Large land block allows for optimal well design Flexibility to process higher liquids volumes was built into Dawson Phase III Benefits from existing ARC owned-and-operated infrastructure Dawson-Parkland/Tower complex includes 71 MMbbl and 1.9 Tcf of 2P reserves Multi-layer development Infrastructure connected across plays Robust project economics Efficient with 40% of field netback required to sustain business Enhanced cash flow generation from Greater Dawson Area as a result of Dawson Phase I & II facility upgrade and Dawson Phase IV expansion project

53 Ante Creek

54 Ante Creek Maximizing Free Cash Flow Generation Average Daily Production (Mboe/day) Facility Expansion Capitalizes on Successful Well Design and Capital Efficiency Improvements 20 Ante Creek Production ARC 2-26 Gas Plant Cumulative Production Liquids: ~28 MMbbl Natural gas: ~165 Bcf Total: ~55 MMboe ARC 10-7 Gas Plant 5 0 ARC Gas Plant Expansion 15 MMcf/day & 2.5 Mbbl/day Liquids Production (boe/day) Natural Gas Production (boe/day) Q Ante Creek Facility Expansion

55 Production Rate (boe/day or bbl/day) Ante Creek Enhancing Free Cash Flows Recent Modifications to Well Design Has Enhanced Capital Efficiencies and Overall Profitability of Wells Ante Creek Development (1)(2)(3)(4) Type Curve (boe/day) 2019 Oil Type Curve (bbl/day) Key Metrics 2019 Type Curve DCET Capex/Well ($ millions) 4.6 Internal 2P Reserves (Mboe) 780 IP (1 month) (boe/day) 575 IP (12 months) (boe/day) 630 Half-cycle Economics US$60/bbl WTI & Cdn$2.00/GJ AECO IRR (%, after-tax) Months on Production (1) Type curves are internal estimates based on analog wells and reservoir modeling. (2) Assumed cycle time (from spud to on-production): three months. (3) Lateral length of 2,000 m for 2019 Type Curve. (4) 2019 Type Curve reflects constraints due to operational execution.

56 Ante Creek Excellence in Execution Depth (m) $/tonne/meter Better Efficiency of Execution Has Resulted in Strong Profitability Culture of Learning Strong Operational Efficiencies Optimization of Well Design Improved Profitability Drilling Times $6.00 Normalized Total Well Cost 0 1,000 22% Reduction in Overall Drill Times $5.50 $5.00 $ % Reduction in Costs 2,000 $4.00 $3.50 3,000 4, $3.00 $ $2.00 5, Days $

57 Ante Creek Creating More Oil Production Capacity Facility Expansion Will Add Up to 2,500 Barrels per Day of Light Oil Production by Q Optimize Plant to Handle 2,500 bbl/day of Additional Oil Production Invest in Water Infrastructure Optimization of ARC s Cash Flow Engine Invest Capital to Improve Access

58 Ante Creek Enhancing Free Cash Flow Key Success Factors to Drive Free Cash Flow with Low-risk, Capitally Efficient Well Inventory Strong Cash Flow Asset Excellent Capital Efficiencies Minimal Investment to Increase Cash Flow Profitable Facility Enhancement Known resource; 50% liquids New well designs have improved productivity Low risk and highly profitable well inventory Strong cash flow generating asset In current commodity price environment, one of ARC s highest netback assets ARC owned-and-operated infrastructure Slickwater completions result in stronger capital efficiencies Ability to increase liquids production with minimal investment Robust well economics Facility enhancement project to bring cash flow forward Ante Creek generates significant cash flow for ARC and by increasing capacity, will enhance cash flow generation

59 Summary

60 ARC s Three-year Plan Three-year Capital Investment Program Will Result in Meaningful Liquids Production and Cash Flow per Share Growth Years Execute capital program of $775 million Bring on Dawson Phase IV in Q2 Bring on Attachie West Phase I in Q2 Dividend Average $210 million Bring on Sunrise Phase II to full capacity Bring on Ante Creek expansion in Q2 Progress next major capital project Sustaining capital Average $400 million Bring on Dawson Phase I & II liquidshandling upgrade Progress multiple largescale projects, leading to per share production and cash flow growth Dawson Phase IV Ante Creek expansion Attachie West Phase I Progress Attachie West Phase I Growth capital Average $350 million Production CAGRs Total: >10% Condensate: >40% NGLs: >25% Natural gas: >10% Crude oil: <5% decline Maintain Share Count Consider Development, Share Buybacks, and Increasing Dividend

61 Why Invest in ARC? A Differentiated Investment with Tremendous Opportunity Competitive Cost Structure Profitable Investment Deep Project Inventory Long-term Value Creation Top-tier Assets Owned Infrastructure Industry-leading Operational Efficiencies Market Access Concentrated Asset Base Strong Expertise Balance Sheet Strength Full-cycle Returning Projects Disciplined Execution Managed Pace and Decline Technology Deployment Growth for Future Development Free Cash Flow Per Share Growth Sustainable Dividend Montney and Cardium Project Potential (boe/day) Next Decade Dawson V Septimus I & II Attachie West II Attachie Central I & II Attachie East I & II Ante Creek II Pouce Coupe Parkland/Tower III Sundown Sunrise III Project Options Next Three Years Sanctioned: Dawson I & II Upgrade Ante Creek Expansion Dawson IV Attachie West I Base Production Montney Cardium 2018

62 Appendix

63 Montney Development Economics Strong Rates of Return across the Montney Portfolio Half-cycle Economics (1)(2)(3) US$60/bbl WTI Cdn$2.00/GJ AECO Attachie West Upper Montney Parkland- Dawson Lower Montney Dawson Upper Montney Ante Creek Upper Montney Tower Upper Montney Sunrise Upper Montney IRR 50% 80% to 110% (dependent on liquids ratio) 80% to 110% (dependent on liquids ratio) 130% 85% to 110% (dependent on area) 70% Recycle Ratio 4.0x 4.2 to 4.3x 3.3 to 4.9x 5.6x 3.2 to 3.4x 5.3x Breakeven ~US$30/bbl Cdn$0.10/Mcf to Cdn$0.30/Mcf Cdn$0.10 to Cdn$1.15/Mcf ~US$14/bbl ~US$14/bbl ~Cdn$1.00/Mcf Production Split 6 Mcf : 1 barrel (4) 20 Mcf : 1 barrel (5) Liquids / Natural Gas 59% / 41% 83% / 17% Liquids / Natural Gas 19-35% / 65-81% 76-80% / 20-24% (dependent on liquids ratio) Liquids / Natural Gas 10% / 90% 26% / 74% Liquids / Natural Gas 43% / 57% 72% / 28% Liquids / Natural Gas 45% / 55% 73% / 27% Liquids / Natural Gas 1% / 99% 2% / 98% (1) IRR (half-cycle after-tax rate of return) run at US$60/bbl WTI and Cdn$2.00/GJ AECO flat pricing. (2) Breakeven prices are US$ per barrel WTI or Cdn$ per Mcf AECO as indicated. Breakeven analysis is run on a single commodity and is defined as the price at which NPV10 is equal to zero. (3) Recycle ratio is calculated using first 12 months of undiscounted netback divided by F&D. (4) Utilizes the standard 6 Mcf:1 barrel ratio when converting natural gas to boe. (5) Utilizes a 20 Mcf:1 barrel ratio when converting natural gas to boe.

64 Tower Strong Oil Production Production Rate (boe/day) Delivering High-quality Oil Production Tower Development (1)(2)(3)(4) 1, Transition Type Curve (boe/day) 2019 Core Type Curve (boe/day) 2019 Transition Oil Rate (bbl/day) 2019 Core Oil Rate (bbl/day) Key Metrics Core 2019 Type Curve Transition 2019 Type Curve DCET Capex/Well ($ millions) Internal 2P Reserves (Mboe) IP (1 month) (boe/day) 1, IP (12 months) (boe/day) Half-cycle Economics US$60/bbl WTI & AECO Cdn$2.00/GJ 300 IRR (%, after-tax) Months on Production (1) Type curves are internal estimates based on analog wells and reservoir modeling. (2) Assumed cycle time (from spud to on-production): five months. (3) Lateral length of 1,950 m for 2019 Core Type Curve (vs. 1,750 m in 2018). (4) Chart and table data based on sales production.

65 Production Rate (Mcf/day) Sunrise Multi-layer Development Strong Reservoir, Low Capital and Operating Costs Sunrise Development (1)(2)(3)(4) 8, Type Curve Key Metrics 2019 Type Curve (Average of 3 Layers) 6,000 4,000 2,000 DCET Capex/Well ($ millions) 4.2 Internal 2P Reserves (Bcfe) 11.5 IP (1 month) (Mcf/day) 7,000 IP (12 months) (Mcf/day) 6,800 Half-cycle Economics US$60/bbl WTI & Cdn$2.00/GJ AECO IRR (%, after-tax) 70% Months On Production (1) Type curves are internal estimates based on analog wells and reservoir modeling. (2) Assumed cycle time (from spud to on-production): four months. (3) Average lateral length of 1,950 m for 2019 Type Curve. (4) Chart data based on raw production and table based on sales.

66 Advisory Statements

67 Advisory Statements Forward-looking Information and Statements This presentation contains forward-looking information as to ARC s internal projections, expectations or beliefs relating to future events or future performance and includes information as to our future well inventory in our core areas, our exploration and development drilling and other exploitation plans for 2018 and beyond, and related production expectations, costs and cash flow, expenses, our plans for constructing and expanding facilities, the volume of ARC's oil and gas reserves and the volume of ARC's oil and gas resources in northeast British Columbia Montney ( NE BC Montney ), the recognition of additional reserves and the capital required to do so, the life of ARC's reserves, the volume and product mix of ARC's oil and gas production, future results from operations and operating metrics. These statements represent Management s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of ARC. The projections, estimates and beliefs contained in such forward-looking statements are based on Management's assumptions relating to the production performance of ARC s oil and gas assets, the cost and competition for services, the continuation of ARC s historical experience with expenses and production, changes in the capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of the current regulatory and tax regime in Canada and necessarily involve known and unknown risks and uncertainties, such as changes in oil and gas prices, infrastructure constraints in relation to the development of the Montney in British Columbia, risks associated with the degree of certainty in resource assessments and including the business risks discussed in ARC s annual and quarterly MD&A and other continuous disclosure documents, and related to Management s assumptions, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differ materially from those predicted. Other than the 2018 Guidance, which is discussed quarterly, ARC does not undertake to update any forward-looking information in this document whether as to new information, future events or otherwise except as required by securities laws and regulations. We have adopted the standard of 6 Mcf:1 barrel when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Non-GAAP Measures Throughout this presentation, ARC uses the terms operating netback ( netback ) and return on average capital employed ( ROACE ) to analyze financial and operating performance. These non-gaap measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. Netback ARC calculates netback on a total and per boe basis as sales less royalties, operating and transportation expenses. ARC discloses netbacks both before and after the effect of realized gains or losses on risk management contracts. Realized gains or losses represent the portion of risk management contracts that have settled in cash during the period and disclosing this impact provides Management and investors with transparent measures that reflect how ARC s risk management program can impact its netback. Management feels that its netback is a key industry benchmark and a measure of performance for ARC that provides investors with information that is commonly used by other crude oil and natural gas producers. The measurement on a boe basis assists Management and investors with evaluating operating performance on a comparable basis. Return on Average Capital Employed ARC calculates ROACE, expressed as a percentage, as net income plus interest and total income taxes (recovery) divided by the average of the opening and closing capital employed for the 12 months preceding period end. Capital employed is the total of net debt plus shareholders equity. ROACE since inception is the annual average net income plus interest and total income taxes (recovery) for the years 1996 to 2017 divided by the average of the opening and closing capital employed over the same period. Refer to the "Capital Management" note in ARC s financial statements for additional discussion on net debt. ARC uses ROACE as a measure of operating performance, to measure how effectively Management utilizes the capital it has been provided and to demonstrate to shareholders that capital has been used wisely over the long term. Other Definitions Throughout this presentation, ARC uses the terms sustaining capital and growth capital. These measures do not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities. Sustaining Capital Sustaining capital refers to capital expenditures to maintain production from existing facilities up to current levels. Growth Capital Growth capital refers to capital expenditures that result in increased production levels at existing facilities or increased production from new facilities and infrastructure required to support higher production levels.

68 Reserves and Resources Disclosure All reserves and resources volumes for NE BC Montney and elsewhere in this presentation are, unless indicated otherwise, as at December 31, 2017 as evaluated by GLJ Petroleum Consultants Ltd. in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument Standards for Disclosure for Oil and Gas Activities. TPIIP, DPIIP and UPIIP have been estimated using a one per cent porosity cut-off for shale gas and tight oil. Reserves volumes for the NE BC Montney and elsewhere in this presentation are, unless indicated otherwise, Proved plus Probable, while the resource categories for NE BC Montney in this presentation are Best Estimates. NE BC Montney includes lands in Pouce Coupe, Alberta. All reserves and resources volumes for NE BC Montney and elsewhere in this presentation are company gross. Gas volumes are sales for reserves and resource and raw gas for DPIIP and TPIIP. The tight oil DPIIP is a stock tank barrel. All DPIIP and TPIIP other than cumulative production, reserves, Contingent Resources and Prospective Resources have been categorized as unrecoverable. The amount of natural gas and liquids ultimately recovered from ARC s NE BC Montney resource will be primarily a function of the future price of both commodities. This presentation contains metrics commonly used in the oil and natural gas industry, such as reserve replacement, reserve life index or RLI, recycle ratio, finding and development costs or F&D costs, finding, development and acquisition costs or FD&A costs, operating netback, finding and development recycle ratio or F&D recycle ratio, and finding, development and acquisition recycle ratio or FD&A recycle ratio. These terms do not have any standardized meaning and may not be comparable to similar measures presented by other entities, and therefore should not be used to make such comparisons.

69 Definitions of Oil and Gas Reserves and Resources Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows: 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. Resources encompasses all petroleum quantities that originally existed on or within the earth s crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total Resources" is equivalent to "Total Petroleum Initially-in-Place". Resources are classified in the following categories: Total Petroleum Initially-in-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. Discovered Petroleum Initially-in-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable. 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. Economic Contingent Resources ("ECR") are those Contingent Resources which are currently economically recoverable. Project Maturity Subclass Development Not Viable is defined as a Contingent Resource that is not viable in the conditions prevailing at the effective date of the evaluation, and where no further data acquisition or evaluation is planned and therefore has not been assigned a low chance of development. Project Maturity Subclass Development Pending is defined as a Contingent Resource that has been assigned a high chance of development and the resolution of final conditions for development are being actively pursued. Project Maturity Subclass 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.