November 2018 FOCUSED INVESTOR PRESENTATION

Transcription

1 November 218 FOCUSED INVESTOR PRESENTATION 1

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3 Investor Relations Contacts & Advisory Statements Investor Relations Bevin Wirzba Martha Wilmot Senior Vice President, Business Development & Capital Markets Investor Relations Analyst General Investor Enquiries 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 218 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 218 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 217 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. Corporate Profile Corporate Summary Production (Q3 218) 135,41 boe/day Reserves (2P Gross YE 217) (1) 836 MMboe Reserve Life Index (2P) (1)(2) 17.4 years Monthly Dividend Annualized Returns since Inception ARC is a Canadian oil and gas producer in its 23rd year of delivering on its disciplined, returns-focused value proposition. Montney Growth Assets BC AB $.5 per share (3) 1% Market Summary Ticker Symbol TSX: ARX Average Daily Volume (4) 2.4 million Shares Outstanding 353 million Enterprise Value (5)(6) $4.4 billion Net Debt (5)(6) $667.8 million Net Debt to Funds from Operations (6)(7).8 times Oil and Liquids Dry Gas Member of TSX 6 (1) (2) (3) (4) (5) (6) (7) Refer to Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this presentation. Based on original 218 production guidance midpoint of 132, boe/day. Annualized total return to November 9, 218, including September dividend, and assuming reinvestment of dividends in ARC shares. Daily average trading volume for the trailing six month period ended November 9, 218. Market Capitalization as at November 9, 218 and Net Debt as at September 3, 218. Refer to the Capital Management note in ARC s financial statements. Based on annualized Funds from Operations for the nine months ended September 3, 218 and Net Debt as at September 3, /12/218 Condensate-rich Gas 1

4 Sustainable Dividend-paying E&P Company ARC s Business Model Supports Profitable Future Growth Portfolio Balance Sheet Capital Efficiencies and Declines 219 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. 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 1% Plan does not require outside financing, asset sales, or inventory upgrades 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 Dawson Phase I Dawson Phase II Ante Creek Phase I Parkland Tower Phase I Sunrise Phase I Parkland Tower Battery Upgrade Dawson Phase III Sunrise Phase II 29 Non-core Dispositions Q4 219 Q2 22 Q2 22 Q2 221 ~$575 Million Facility Investment $36 Million Facility Investment 54 MMcf/day of Natural Gas Capacity 17.5 Mbbl/day of Liquids Capacity 165 MMcf/day of Natural Gas Capacity 3 Mbbl/day of Liquids Capacity 11/12/218 2

5 ARC Delivered through Its Transformation ARC s Plan Remains Focused on Profitability, Sustainability, and Creating Optionality for the Long Term Monthly dividend of $.5 per share Brought on Dawson Phase III Sustained Montney businesses Execute capital program of $775 million Sold Saskatchewan assets Eliminated DRIP and SDP plans 118,671 boe per day Rebuilt liquids production from divestments Achieved success in Lower Montney and Attachie 122,937 boe per day Built 3, bbl per day battery at Attachie West Progressed Sunrise Phase II (6 MMcf per day in service by year-end) Parkland-Dawson interconnect in service Divested non-core assets including Redwater 131, to 133, boe per day Maintain Share Count Cash Flow per Share Growth Is Critical Bring on Sunrise Phase II to full capacity 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 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 $21 million Bring on Sunrise Phase II to full capacity Bring on Ante Creek expansion in Q2 Progress next major capital project Sustaining capital Average $4 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 $35 million Production CAGRs Total: >1% Condensate: >4% NGLs: >25% Natural gas: >1% Crude oil: <5% decline Maintain Share Count Consider Development, Share Buybacks, and Increasing Dividend 11/12/218 3

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 29 Q % F 46% Physical Market Access and Financial Risk Management Multiple Direct Sales Points across North America for liquids and natural gas production ~$.8 billion of realized cash gains on risk management contracts since & 219 Guidance Investing in Infrastructure to Grow Liquids Production and Deliver Per Share Growth over the Long Term Production 218 Guidance 218 Revised Guidance (1) 218 YTD Actuals 219 Guidance (2) Crude oil (bbl/day) 25, - 26,5 23, - 24, 24,595 18, - 22, Condensate (bbl/day) 6,5-7,5 7, - 7,5 6,884 7,5-8,5 Crude oil and condensate (bbl/day) 31,5-34, 3, - 31,5 31,479 25,5-3,5 Natural gas (MMcf/day) NGLs (bbl/day) 6, - 6,5 6,5-7, 6,84 6, - 6,5 Total production (boe/day) 13, - 134, 131, - 133, 131, , - 142, Expenses ($/boe) Operating Transportation G&A expenses before share-based compensation plans G&A - share-based compensation plans (3) Interest Current income tax (per cent of funds from operations) (4) Capital expenditures before land purchases and net property acquisitions (dispositions) ($ millions) Land purchases and net property acquisitions (dispositions) ($ millions) N/A N/A (194.3) N/A Weighted average shares (millions) (1) Following the disposition of ARC s non-core Redwater assets in the third quarter of 218, and to more accurately reflect full-year 218 expectations, guidance for production, operating expenses, transportation expenses, G&A expenses before share-based compensation plans, and current income tax, was revised in the third quarter of 218. (2) 219 Budget amounts reflect the anticipated impact that IFRS 16 Leases will have on ARC s operating expenses, G&A expenses, and interest expenses. Refer to the Changes in Accounting Policies note in ARC s financial statements. (3) Comprises expenses recognized under the Restricted Share Unit and Performance Share Unit Plans, Share Option Plan, and Long-term Restricted Share Award Plan, and excludes compensation under the Deferred Share Unit Plan. In periods where substantial share price fluctuation occurs, G&A expenses are subject to greater volatility. (4) The current income tax estimate varies depending on the level of commodity prices. 11/12/218 4

7 Creating a Sustainable Dividend-paying E&P Company ARC s continued focus on maintaining a strong balance sheet, targeting a 25 per cent payout ratio, improving capital efficiencies to preserve operating netbacks, targeting decline rates below 3 per cent, and delivering superior full-cycle corporate returns will support profitable future growth Maintaining Balance Sheet Strength Targeting a Payout Ratio (1) of 25 Per Cent $ millions 1,4 1,2 1, Net Debt to Funds from Operations Net Debt (LHS) Funds From Operations (LHS) Net Debt to Funds from Operations (RHS) Ratio Cumulative Dividends ($ billions) Cumulative Dividends and Historic Payout Ratio 218 YTD Payout Ratio of 26% YTD Cumulative Dividend (LHS) Payout Ratio (before DRIP and SDP) (RHS) 12% 1% 8% 6% 4% 2% % Payout Ratio Improving Capital Efficiencies to Preserve Operating Netbacks Delivering Full-cycle Asset Return on Invested Capital and Corporate Return on Average Capital Employed (2) 6 6, Operating Netback ($/boe) Preserve Operating Netbacks Improve Capital Efficiencies F 219F 5, 4, 3, 2, 1, Capital Efficiency ($/boe/day) After-tax Rate of Return Single-well Economics (Half-cycle) Proportional Facility and Appropriate Timing Included: Project Economics (Full-cycle) Corporate Costs ROACE of 1% since Inception Operating Netback (LHS) Capital Efficiency (RHS) ARC s Funding Model ARC s current funding model includes the reinvestment of proceeds from 216 and 218 non-core dispositions, allowing ARC to fund infrastructure and profitably grow the business Post Dawson Phase IV, ARC expects to have the ability to satisfy its dividend obligations, sustain the business, and fund growth capital entirely from funds from operations Total Forecasted Inflows & Outflows (3)(4) Future Inflows & Outflows 217 to 22 (3)(4) ARC can sustain the business at US$5/bbl WTI and Cdn$1.5/GJ AECO Net A&D Proceeds and Excess Funds from Operations Funds from Operations ~4% Gas ~$4MM/year Dawson Phase III Sunrise Phase II Dawson Phase I & II Upgrade Dawson Phase IV Ante Creek Expansion Attachie West Phase I Funds from Operations ~$4MM/year Discretionary Growth Projects ARC can fund the dividend and sustaining and growth capital at US$6/bbl WTI and US$3./MMBtu NYMEX Funds from Operations ~6% Oil & Liquids ~$21MM/year Capital Efficiencies $1,/boe/day Capital Efficiencies $15,/boe/day ~$21MM/year Sources of Cash Dividend Sustaining Capital Growth Capital Sources of Cash Dividend Sustaining Capital Growth Capital (1) Payout Ratio is calculated as dividends before DRIP and SDP as a percentage of Funds from Operations. (2) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to Non-GAAP Measures in the Advisory Statements to this presentation. (3) 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. Growth capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. (4) Sustaining capital refers to capital expenditures to maintain production from existing facilities up to current levels. Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. 11/12/218 5

8 219 Budget of $775 Million Advances Projects to Deliver Near-term Annual Production of 135, to 142, boe per day and Multi-year Growth BC Attachie Attachie $184MM 6 wells (5 Hz +1 Injection) 3, boe/day Attachie West Phase I is sanctioned to come onstream in Q2 221 AB Red Creek Sunrise Tower $24MM 34, boe/day Initial 6 MMcf/day at Phase II facility on-stream, production will ramp up once final transportation arrangements come into effect in 219 Pouce Coupe Septimus Parkland Sunset Sunrise Dawson Sundown Ante Creek Parkland/Tower $128MM 13 wells 32, boe/day Sustain production at current facility capacity and develop Lower Montney via interconnect to Dawson Dawson $299MM 39 wells 42, boe/day Phase IV facility sanctioned to come on stream in Q2 22; development is focused on liquids-rich Lower Montney $4MM Sustaining Capital (1) $375MM Growth Capital (1) Ante Creek $95MM 12 wells 16, boe/day Expansion at Ante Creek 1-36 facility to add 15 MMcf/day of gas and 2,5 bbl/day of oil in Q2 22 Pembina Pembina $31MM 7 wells 1, 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. 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) 217 Natural Gas (MMcf/day) Total (boe/day) 18 3, Parkland-Dawson Interconnect Sunrise Phase II Sanctioned Q Dawson Phase I & II Upgrade 2, 1, Dawson Phase IV 7,5 3, Ante Creek Expansion 2,5 Attachie West Phase I 1, 4, 3, 9 25,5 15 5, 6 24, Sanctioned 11/12/218 Development Processing Capacity Available 6

9 Physical Marketing Activities Crude Oil & Liquids ARC s Crude Oil & Liquids Sales Mix Crude Oil & Condensate Benchmark Pricing 41% 39% 2% Oil Condensate NGLs 8% of ARC s liquids production is made up of oil and condensate US$/barrel Mixed Sweet Blend WTI Condensate Western Canadian Select Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 68% of ARC s 218 YTD overall sales revenue derived from crude oil and liquids production Natural Gas Integrated physical marketing and financial risk management strategies enable ARC to effectively execute on its long-term plans Market Access Firm transportation pipeline agreements to support existing production and future development beyond 221 Market Diversification Portfolio approach to physical diversification into consuming regions reduces single price hub risk Station 2 $1.12 $.14 $.98 Westcoast /NWP Natural Gas Flows & Sales Points (218 YTD Pricing in US$/MMBtu) AECO $1.1 $.15 Initial Tie-in of ARC s Production: 8% through the TransCanada NGTL system 2% through the Enbridge Westcoast system ARC s Corporate Natural Gas Price $3.34 $3.24 $2.96 $3.2 $3.7 $.78 $.74 $.87 $.88 $.39 $.32 $1.5 $.56 $.72 $.63 $2.17 $2.18 $1.63 $1.28 $ Cdn$/Mcf Sumas $2.4 $.14 $.35 $1.55 Malin $2.29 $.15 $.52 $1.62 GTN Pricing Hub Hub Market Price (1) Field-to-Hub Transportation Cost (2) Hub-to-Hub Transportation Cost (3) Market Netback $.95 Northern Border Alliance GLGT Via Northern Border Ventura Chicago $2.9 $2.87 $.15 $.15 $.51 $.64 $2.24 $2.8 Henry Hub TCPL Mainline < 5% of expected overall sales revenue exposed to AECO and Station 2 for the remainder of 218 (1) 218 YTD monthly index pricing, or daily index in the absence of a monthly index. (2) Uses a three-year average published toll including abandonment costs. (3) As per published pipeline data. Dawn $2.9 $.15 $.79 $ Q1 218 Q2 218 Q YTD Realized Gains on Risk Management Contracts Diversification Activities Average Price before Diversification Activities ARC Natural Gas Diversification (4)(5) 4% 4% 4% 4% 4% 7% 7% 19% 22% 3% 26% 18% 15% 5% 6% 9% 12% 15% 23% 25% 34% 23% 14% % Bal 218 Cal 219 Cal 22 Hedged AECO Floating Station 2 Floating Midwest US Floating Dawn Floating Henry Hub Floating Pac-NW US Floating (4) Based on production assumptions for sanctioned projects. (5) Hedged includes all physical and financial fixed price swaps and collars at AECO, Station 2, and Henry Hub. 11/12/ % 75% % of Total Production

10 Optionality in the Montney BC AB Significant Resource Potential Total petroleum initially-in-place (1) identified across ARC s NE BC and Pouce Coupe assets includes: 1.5 billion barrels of tight oil 16. Tcf of shale gas 1,m Lower Montney 1 kpa/m Line Oil and Liquids Red Creek 2,m Attachie Tower Pouce Coupe Septimus Parkland Sunset Dawson Sunrise 3,m 1,m Sundown Geographic Optionality Ante Creek Proximity of ARC Montney land base enables: Capital and operating efficiencies Application of learnings across areas ARC holds ~1,12 net Montney sections (~732, acres) Majority of lands 1% owned-and-operated, located across two jurisdictions (Alberta and BC) Dry Gas 2,m Egress Optionality Dual-connected ARC facilities allow for takeaway optionality in well-served area with three major pipelines providing access to North American markets Condensate-rich Gas Commodity Optionality ARC can target crude oil, liquids-rich natural gas or natural gas, depending on commodity price levels ARC designs its infrastructure to allow for optionality Montney Erosional Edge Multi-layer Optionality (1) Strategic capital invested in the Lower Montney has increased overall depth of portfolio Year-end 217 results comply with current Canadian Oil and Gas Evaluation Handbook guidelines. Resources Evaluation volumes provided are the risked Best Estimate case. Year-end 217 total petroleum initially-in-place estimates utilize a one per cent porosity cut-off based on Best Estimate case. 11/12/218 8

11 Multiple Layers to Develop Significant Future Delineation Opportunities with the Development of Efficient and Sustainable Resource Base Attachie Septimus Sunrise Tower Parkland Dawson Pouce Coupe Upper Montney Montney A Montney B Montney C Lower Montney Montney D Montney E Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells Proven Development Model Inventory at All Stages Allows for Self-funding and Strong Full-cycle Returns across Portfolio Growth for Future Phase Exploration Appraisal / Piloting Development Phase Develop to Commercialize Invest in Infrastructure Geographic and Commodity Diversity Free Cash Flow Phase Optimization Maintenance Development to Sustain Cash Flow Pembina Dawson Phase I & II Ante Creek Sunrise Phase I Parkland/Tower Phase I & II Net Cash Flow + Dawson Phase III Attachie West (Pilot) Sunrise Phase II Dawson Phase IV Ante Creek (South Expansion) Attachie West Phase I Dawson Phase V Attachie West Phase II Parkland/Tower Phase III Pouce Coupe Septimus Attachie East Sundown 219 Budget $775 million Growth & Development Capital (1) $375 million Sustaining Capital (1) $4 million (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. 11/12/218 9

12 Competing Continentally ARC s Efficient Cost Structure Competes with the Best Producers across North America ARC Tower Oil Single Well Economics Capital/Well Canadian 2P Finding & Development Cdn$4.8MM Cdn$7.91/boe ARC Sunrise Gas Single Well Economics Capital/Well Cdn$5.2MM Canadian 2P Finding & Development Cdn$.45/Mcfe Permian Oil Single Well Economics (1)(2)(3) Capital/Well ~Cdn$8.7MM US 1P Finding & Development ~Cdn$8./boe Appalachian Gas Single Well Economics (1)(4)(5) Capital/Well ~Cdn$9.MM US 1P Finding & Development ~Cdn$.5/Mcfe 75. ARC Tower Oil vs. Permian Oil 217 Netback Comparison (1)(2)(3) (Cdn$/boe) ARC Sunrise Gas vs. Appalachian Gas 217 Netback Comparison (1)(4)(5) (Cdn$/Mcfe) $66.3 WTI (Cdn$) $ NYMEX Henry $4.4 Hub (Cdn$) $4.4 Cdn$/boe ARC s cash costs are 8% lower Cdn$/Mcfe ARC s cash costs are 53% lower 15.. ARC s netback is 5% higher Permian Average ARC Tower Oil Appalachian Average ARC Sunrise Gas 8% Liquids 5% Liquids (.5) 85% Gas 1% Gas Price Differential & Basis on Gas and Liquids Mineral Production Tax & Royalties Gathering, Compression, Processing & Transport Lease Operating Expense Netback (1) Financial data from company 1-K SEC filings. Capital cost assumptions from Scotiabank The Playbook (September 217). (2) Assumes exchange rate of Cdn$/US$ and US royalty rate of 25%. (3) Permian average includes: CPE, FANG, LPI, PE, PXD, RSPP. (4) Assumes exchange rate of Cdn$/US$ and US royalty rate of 18%. (5) Appalachian average includes: AR, COG, EQT, GPOR, RRC, SWN. Map from RBC Capital Markets..5 ARC s netback is 4% higher 11/12/218 1

13 NE BC Montney Reserves and Risked Resources (1) Tremendous Development Potential from NE BC Montney Assets with TPIIP of 16. Tcf of Shale Gas and 1.5 Billion Barrels of Oil Shale Gas Tight Oil, Condensate & NGLs.9 Tcf CUMULATIVE PRODUCTION Oil 7.8 MMbbl Condensate & NGLs 21 MMbbl ECONOMIC CONTINGENT RESOURCE 7.1 Tcf 3.5 Tcf 4. Tcf TOTAL PROVED + PROBABLE RESERVES DEVELOPMENT PENDING RISKED Oil 31 MMbbl Condensate & NGLs 62 MMbbl Oil 33 MMbbl Condensate & NGLs 9 MMbbl ECONOMIC CONTINGENT RESOURCE Oil 147 MMbbl Condensate & NGLs 191 MMbbl 3.1 Tcf DEVELOPMENT UNCLARIFIED RISKED Oil 115 MMbbl Condensate & NGLs 1 MMbbl.7 Tcf DEVELOPMENT NOT VIABLE RISKED Oil 1.2 MMbbl Condensate & NGLs 63 MMbbl 6.4 Tcf PROSPECTIVE RESOURCE RISKED Oil 76 MMbbl Condensate & NGLs 475 MMbbl (1) Independent Resources Evaluation conducted by GLJ effective December 31, 217. Contingent Resource and Prospective Resource quoted are Best Estimate case. For reserves and resources disclosure, please refer to ARC s February 8, 218 news release entitled, ARC Resources Ltd. Announces Record 32 Per Cent Replacement of Produced Reserves through Development Activities. Early Stages of Property Development (1) Large Identified Opportunity for Future Value Creation 1, GLJ has recognized >3, future gross drilling locations across ARC s NE BC and Pouce Coupe Montney assets 75 Number of Locations 5 25 Dawson Parkland / Tower Sunrise / Sunset Attachie Other Montney Ante Creek Total HZ Wells Drilled to YE 217 2P Booked Undeveloped Locations Development Pending ECR Booked Locations Development Unclarified ECR Booked Locations Pembina area has ~6 future drilling opportunities in the Cardium (1) Subject to change based on technology and economic environment. 11/12/218 11

14 Montney Development Economics Strong Rates of Return across the Montney Portfolio Half-cycle Economics (1)(2)(3) US$6/bbl WTI Cdn$2./GJ AECO Attachie West Upper Montney 5% 8% to 11% 8% to 11% (dependent on liquids ratio) (dependent on liquids ratio) 4.x 4.2 to 4.3x 3.3 to 4.9x ~US$3/bbl Cdn$.1/Mcf to Cdn$.3/Mcf Liquids / Natural Gas 59% / 41% 83% / 17% Liquids / Natural Gas 19-35% / 65-81% 76-8% / 2-24% IRR Recycle Ratio Breakeven Production Split 6 Mcf : 1 barrel (4) 2 Mcf : 1 barrel (5) (dependent on liquids ratio) (1) (2) (3) (4) (5) Dawson ParklandDawson Lower Montney Upper Montney Ante Creek Tower Sunrise Upper Montney Upper Montney Upper Montney 85% to 11% 7% 13% (dependent on area) 5.6x 3.2 to 3.4x 5.3x ~US$14/bbl ~US$14/bbl ~Cdn$1./Mcf Liquids / Natural Gas 43% / 57% 72% / 28% Liquids / Natural Gas 45% / 55% 73% / 27% Liquids / Natural Gas 1% / 99% 2% / 98% Cdn$.1 to Cdn$1.15/Mcf Liquids / Natural Gas 1% / 9% 26% / 74% IRR (half-cycle after-tax rate of return) run at US$6/bbl WTI and Cdn$2./GJ AECO flat pricing. Breakeven prices are US$ 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 NPV1 is equal to zero. Recycle ratio is calculated using first 12 months of undiscounted netback divided by F&D. Utilizes the standard 6 Mcf:1 barrel ratio when converting natural gas to boe. Utilizes a 2 Mcf:1 barrel ratio when converting natural gas to boe. Greater Dawson Area Lower Montney Investments 217 Appraisal Activities and Subsequent 218 Investments Unlocked Significant Opportunity to Grow Liquids Production Pouce Coupe Tower Parkland Total Lower Montney Wells Drilled/Planned wells wells Dawson 22 ~2 wells Sunrise 217 to Q3 218 Lower Montney Drilled and Completed Wells Wells Planned for 218 Wells Planned for 219 Parkland-Dawson Interconnect Note: Only Lower Montney wells are displayed. 11/12/218 12

15 Parkland-Dawson Proven Lower Montney Results Impressive Liquids Results Drove Decision to Interconnect Parkland and Dawson Fields Parkland-Dawson Lower Montney Wellhead Liquids Production 14 Cumulative Liquids Production (Thousand Stock Tank Barrels) Mbbl of liquids 95 MMcf of gas in 235 days 1 Mbbl of liquids 49 MMcf of gas in 28 days Producing Days Parkland F11-4 Parkland 1-31 Dawson 3-15 Dawson C3-15 Dawson F9-21 Dawson D16-13 Dawson H3-15 Dawson K3-15 Medium Liquids High Liquids 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 Cumulative Oil & Condensate Production (Mbbl) Mbbl of liquids 45 MMcf of gas in 2 days 1 Mbbl of liquids 643 MMcf of gas in 44 days Attachie Estimated Ultimate Recovery at YE 217 Condensate: 386 Mbbl NGLs: 1 Mbbl Gas: 2.7 Bcf Total: 846 Mboe ,5 1,2 Days on Production Attachie Attachie B13-26 Attachie Attachie Pad Average Attachie West 219 Type Curve Tower 7-12 West Pad Average Parkland F /12/218 13

16 Cost Management Low-cost Producers Deliver Superior Returns over Time Focused assets, characterized by high working interest, operatorship and owned-and-operated facilities, provide control over costs and operations 2 Three-year FD&A Costs ( ) (1)(2)(3) ($/boe) 15 H1 218 Operating Costs (4)(5) ($/boe) $/boe 12 8 Group Average $/boe 9 6 Group Average 4 ARC Sunrise Gas ARC ARC NE BC Oil & Gas ARC Dawson Gas 3 ARC Sunrise Gas ARC Dawson Gas ARC NE BC Oil & Gas ARC (1) Three-year 2P FD&A Costs ( ) includes future development capital. Source: Peters & Co. 217 Reserves Comparison E&P Producers April 4, 218. (2) Refer to ARC s February 8, 218 news release entitled, ARC Resources Ltd. Announces Record 32 Per Cent Replacement of Produced Reserves through Development Activities for information pertaining to ARC s finding and development costs. (3) Three-year 2P FD&A Costs ( ) peer group includes: BNP, BTE, CPG, PEY, POU, TOU, VET, VII, WCP. (4) H1 218 Operating Expenses from company reports and represent data for the six months ended June 3, 218. (5) H1 218 Operating Expenses peer group includes: BNP, BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP. Continuous Improvement in Safety Performance Strong Health and Safety Performance Supports Capital Efficiency Improvements; Over 4.5 Years LTI-free for Employees ARC s strong safety performance and capital efficiencies are the result of well-planned and executed operations Improvements in safety performance are the result of ARC employees being focused on safety and alignment with strong service providers ARC Contractor Total Recordable Incident Frequency % Reduction in TRIF Strong Safety Performance = Strong Business Performance YTD TRIF (Total Recordable Incident Frequency) = # of Recordable Injuries x 2, # Hours Worked Recordable Injury (Lost Time, Restricted Work Case or Medical Aid) 11/12/218 14

17 Environmental, Social & Governance Performance Responsible Development Has Shaped the Company We Are Today and Underpins Sustainable Future Growth GHG emission intensity reduced by 43 per cent since 27 Targeting to further reduce GHG emission intensity by 25 per cent by 221 Strong safety culture demonstrates ARC s commitment to creating an injury-free workplace for employees and contractors Superior financial returns achieved through: Risk management Good governance practices Maintenance of high ethical standards Wealth distribution Local hiring practices Community investment For more information and to view our 218 Sustainability Report, visit 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 /12/218 15

18 PORTFOLIO OVERVIEW ARC s Attachie West Phase I Business Profitably Investing in First Major Phase of Development While Planning for Subsequent Phases Natural Gas Processing Capacity: 6 MMcf/day Condensate-handling Capacity: 1, bbl/day NGLs-handling Capacity: 4, bbl/day,, 35, 3, 25,,, 2, 15,,, 1, 5, 231F 23F 229F 228F 227F 226F 225F 224F 223F 222F 221F 22F 219F $ -1,,,) Field Netback (1) Capital Expenditures Facility Expenditures Net Cash Flow Production,,),,) -15, -2, -25, -3, -35, Facility and Infrastructure Pre-drill 22 Wells (1) -5, Drill 15 Wells per Year 45% of Field Netback Required to Sustain Business (1) Economics run at US$6/bbl WTI and Cdn$2./GJ AECO flat pricing. 11/12/218 16

19 Attachie Attachie West Phase I Sanctioned Attachie West is a leading development opportunity within ARC s portfolio due to its: Condensate-rich production profile Significantly over-pressured reservoir Extensive, contiguous land position suited for multi-layer development pad Attachie West Update Attachie West Phase I sanctioned; expected to be on-stream in Q MMcf/day of gas processing 1 Mbbl/day of condensate-handling 4 Mbbl/day of NGLs-handling Commercial demonstration pad wells have cumulatively produced 36 Mbbl of condensate and 1,5 MMcf of raw natural gas over 18 days of production pad Battery upgrade completed in Q2 218 has increased Attachie s liquids processing capacity to 3 Mbbl/day of condensate ARC has secured takeaway on TCPL s North Montney Mainline, expected to be on-stream in late 219 ARC Wells ARC Attachie West Production Pilots ARC Attachie West 217 Multi-well Pad ARC Attachie East Delineation Wells ARC Wells Drilled in 217 Multi-layer Development Potential Journey to Commercial Development Single-well Appraisals Commercial Demonstration Pad Commercial Development Upper Montney 214 to 217 Applying Learnings 217 to 218 Sanctioning Decision Q2 221 Lower Montney Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells Asset Details Net Production (boe/day) Q ,36 Liquids (bbl/day) 2,74 Gas (MMcf/day) 1 Land (Montney Net Sections) 36 Working Interest ~99% 2P Reserves (MMboe) 3 Liquids (MMbbl) 14.7 Gas (Bcf) 93 Reserve Life Index (Years) (1) 28 PDP Reserves (MMboe) 2 Liquids (MMbbl) 1. Gas (Bcf) 7 Reserve Life Index (Years) (1) 2 (1) Reserve Life Index based on 218 guided production. 11/12/218 17

20 Dawson Asset Details Focus on Liquids with Infrastructure Enhancements at Dawson Phase I & II and Dawson Phase IV Net Production (boe/day) Q3 218 ARC 13-7 ARC 13-7 Phase III Gas Plant Phase IV Gas Plant (9 MMcf/day & (9 MMcf/day & 7.5 Mbbl/day) 1.5 Mbbl/day) ARC 1-34 Compressor Station (45 MMcf/day) ARC 5-35 Phase I & II Gas Plants (12 MMcf/day) Upgrade (3 Mbbl/day) TCPL 47,59 Liquids (bbl/day) 4,66 Gas (MMcf/day) 258 Production Split % (Liquids / Gas) ~9% Gas Land (Montney Net Sections) 137 Working Interest ~1% 2P Reserves (MMboe) 255 Liquids (MMbbl) 31.7 Gas (Bcf) 1,34 Reserve Life Index (Years) (1) 16 PDP Reserves (MMboe) 58 Liquids (MMbbl) 5.9 Gas (Bcf) 31 Reserve Life Index (Years) (1) ARC Gas Plants & Compressor Stations ARC Wells Competitor Wells (1) Year # Hz Wells Drilled Budget 219 Budget Reserve Life Index based on 218 guided production. Dawson Development Potential Liquids-rich Development Layer Below Core Acreage Upper Montney Drilling Inventory 8 Upper Montney A Booked Reserves Lower Montney Wells Wells Drilled to YE Drilling 217 Opportunities at YE 217 Lower Montney Booked Reserves Development Unclarified ECR Locations Development Pending ECR Locations 2P Booked Locations Wells Drilled Existing Horizontal Wells, Development Potential Horizontal Wells ARC Montney Lands ARC Montney Lands with 2P Reserves Booked as of YE /12/218 18

21 Parkland/Tower Asset Details Profitable with Commodity Optionality: Oil, Condensate and Natural Gas; Parkland-Dawson Interconnect Commissioned in Q3 218 Tower Net Production (boe/day) Q3 218 Parkland Tower 7,12 23,53 Liquids (bbl/day) 1,59 11,41 Gas (MMcf/day) Land (Montney Net Sections) Working Interest ~9% ~94% Parkland/Tower 2P Reserves (MMboe) ARC 8-13 Compressor (2 MMcf/day) (1) 39.2 Gas (Bcf) 571 Reserve Life Index (Years) (1) 12 Parkland/Tower PDP Reserves (MMboe) ARC 3-9 Gas Plants (9 MMcf/day & 1 Mbbl/day) Parkland ARC Gas Plants ARC Wells Competitor Wells Parkland Tower Boundary 134 Liquids (MMbbl) 4 Liquids (MMbbl) 11.4 Gas (Bcf) 17 Reserve Life Index (Years) (1) 4 Year Budget 219 Budget Parkland # Hz Wells Drilled Tower # Hz Wells Drilled Reserve Life Index based on 218 guided production. Parkland/Tower Development Potential Incremental Reserves Potential With Multi-layer Development Tower Parkland Drilling Inventory Upper Montney Upper Montney A Booked Reserves 1, Wells 75 Upper Montney A+ Booked Reserves 5 Lower Montney 25 Wells Drilled to YE Drilling 217 Opportunities at YE 217 Development Unclarified ECR Locations Lower Montney Booked Reservess Development Pending ECR Locations 2P Booked Locations Wells Drilled Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells 11/12/218 ARC Montney Lands ARC Montney Lands with 2P Reserves Booked as of YE

22 Sunrise/Sunset Asset Details Sunrise Phase II Completed Ahead of Schedule, Under Budget, and with an Excellent Safety Record Net Production (boe/day) Q ,56 Liquids (bbl/day) 13 Gas (MMcf/day) 129 Land (Montney Net Sections) 32 Working Interest Sunset ~89% 2P Reserves (MMboe) 22 Liquids (MMbbl) Sunrise ARC Gas Plant (6 MMcf/day) & Phase II Gas Plant (1) (18 MMcf/day) 2.3 Gas (Bcf) 1,33 27 Reserve Life Index (Years) (2) PDP Reserves (MMboe) 41 Liquids (MMbbl).2 Gas (Bcf) Reserve Life Index (Years) ARC Gas Plants ARC Wells Competitor Wells (1) (2) 245 Year An initial 6 MMcf/day of gas processing capacity will be operational in the fourth quarter of 218. Production is expected to ramp up to the facility s maximum processing and sales capacity of 18 MMcf/day in 219, once final transportation arrangements have come into effect. Included within the 18 MMcf/day of production is 6 MMcf/day of existing production that is currently flowing through a third-party facility and will be moved to Sunrise Phase II in June 219. Reserve Life Index based on 218 guided production. # Hz Wells Drilled 5 (2) Budget 219 Budget 5 23 Sunrise Development Potential Proven Productivity from Four-layered Development, Piloting Six-layered Development Drilling Inventory 6 Upper Montney Upper Montney A Booked Reserves 4 Wells Upper Montney A+ Booked Reserves 2 Lower Montney Upper Montney B Booked Reserves Wells Drilled to YE Drilling 217 Opportunities at YE 217 Development Unclarified ECR Locations Lower Montney Booked Reserves Development Pending ECR Locations 2P Booked Locations Wells Drilled Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells 11/12/218 ARC Montney Lands ARC Montney Lands with 2P Reserves Booked as of YE 217 2

23 Ante Creek Asset Details Significant Cash Flow with Substantial Growth Opportunities Including Facility Expansion Planned for Q2 22 Net Production (boe/day) Q ,64 Liquids (bbl/day) 8,27 Gas (MMcf/day) 5 Production Split % (Liquids / Gas) ARC 2-26 Gas Plant (2 MMcf/day) ARC 1-7 Gas Plant (3 MMcf/day & 12.5 Mbbl/day) 5% / 5% Land (Montney Net Sections) 329 Working Interest ~1% 2P Reserves (MMboe) 54 Liquids (MMbbl) 25.9 Gas (Bcf) 17 Reserve Life Index (Years) (1) 9 PDP Reserves (MMboe) ARC 1-36 Gas Plant (1 MMcf/day) Expansion (15 MMcf/day & 2.5 Mbbl/day) Liquids (MMbbl) 1.5 Gas (Bcf) 63 Reserve Life Index (Years) Year ARC Gas Plants ARC Wells (1) 21 3 (1) Budget 219 Budget # Hz Wells Drilled Reserve Life Index based on 218 guided production. Ante Creek Development Potential Large Land Base and Down-spacing = Significant Drilling Inventory Drilling Inventory (1) Wells 2 1 Wells Drilled to YE Drilling Opportunities 217 at YE 217 Wells Drilled 2P Booked Locations ARC Montney Lands ARC Montney Lands with 2P Reserves Booked as of YE /12/218 (1) ECR locations not shown as no independent resource study has been conducted for Ante Creek. 21

24 Pembina Asset Details High Working Interest of Light Oil Production, Competitive Operating Netbacks and Free Cash Flow Generation Net Production (boe/day) Q ,65 Liquids (bbl/day) 8,76 Gas (MMcf/day) 11 Land (Cardium Net Sections) 219 Working Interest ~89% 2P Cardium Reserves (MMboe) Berrymoor Lindale NPCU Buck Creek 68 Liquids (MMbbl) 58.3 Gas (Bcf) Reserve Life Index 62 (Years) (1) 19 PDP Cardium Reserves (MMboe) Liquids (MMbbl) MIPA PCU Gas (Bcf) Reserve Life Index SPCU Year ARC Working Interest Lands (1) (2) 42 # Hz Wells Drilled 38 (Years) (1) Budget 219 Budget 15 (2) 7 Reserve Life Index based on 218 guided production. ARC drilled and completed a five-well pad in Pembina in Q3 218, and expects to bring the wells on production in Q /12/218 22

25 ARC s HISTORY ARC s History and Future Strong Foundation for Continued Success In over 22 years, ARC has successfully achieved the following: 1% Return on Average Capital Employed (1) $6.3 Billion of Distributions / Dividends & 1% Annualized Total Return (2) Stayed within Target of 1. to 1.5x Net Debt to Funds from Operations Transitioned Its Asset Base to World-class Montney Looking ahead, ARC will: Preserve Strong Balance Sheet and Maintain Financial Flexibility (1) (2) Fund New Capital Projects Includes Redeployment of Proceeds from Non-core Divestments Manage Risk Through Physical and Financial Diversification Activities Provide Total Shareholder Return to Investors with Per Share Growth and Dividend Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to Non-GAAP Measures in the Advisory Statements of this presentation. Annualized total return to November 9, 218, including September dividend, and assuming reinvestment of dividends in ARC shares. 11/12/218 23

26 Consistent and Sustainable Strategy Delivering on Our Strategy of Risk-managed Value Creation 1,6 1,2 Net Debt to Funds from Operations Net Debt (LHS) Funds From Operations (LHS) Net Debt to Funds from Operations (RHS) Operating Costs $ millions Montney Growth Assets Ratio Financial Flexibility and Market Access RISK- MANAGED VALUE CREATION HSE and Operational Excellence $/boe Employee Engagement YTD Oil and Liquids High-quality, Long-life Assets Top Talent and Strong Leadership Culture 1% 75% 5% ARC Industry Average (Baed on Gallup's Research) Dry Gas 25% ARC holds ~1,12 net Montney sections (~732, net acres) Condensate-rich Gas % Transformation of Our Business Montney Transformation Has Allowed ARC to Manage a Profitable Business through Commodity Price Cycles 16, Production Profile 1,4 Net Debt to Funds from Operations 3. boe/day 12, 8, 4, Non-Montney Crude Oil & Liquids (bbl/day) Montney Crude Oil & Liquids (bbl/day) Non-Montney Natural Gas (boe/day) Montney Natural Gas (boe/day) Forecast 1,2 1, $ millions Ratio. Q Q Q Q Q3 2 Q2 21 Q1 22 Q4 22 Q3 23 Q2 24 Q1 25 Q4 25 Q3 26 Q2 27 Q1 28 Q4 28 Q3 29 Q2 21 Q1 211 Q4 211 Q3 212 Q2 213 Q1 214 Q4 214 Q3 215 Q2 216 Q1 217 Q4 217 Q3 218 Q Net Debt Funds From Operations Net Debt to Funds from Operations % 2% 15% 1% 5% % (5%) Return on Average Capital Employed (1) 1% ROACE since Inception Cumulative Dividends ($ billions) Cumulative Dividends and Historic Payout Ratio (2) 218 YTD Payout Ratio of 26% 12% 1% 8% 6% 4% 2% Payout Ratio (1%) ROACE Trailing Three-year ROACE (1) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to Non-GAAP Measures in the Advisory Statements to this presentation Cumulative Dividend (LHS) Payout Ratio (before DRIP and SDP) (RHS) YTD calculated as dividends before DRIP and percentage of Funds from Operations. (2) Payout Ratio is SDP as a % 11/12/218 24

27 Record Produced Reserves Replacement in 217 Greater than 2% Reserves Replacement for 1 th Consecutive Year 217 development reserves adds largest in company history, with 32 per cent of produced reserves replaced Montney assets have been the centerpiece to ARC s strategy of organic reserves and resource growth Finding and development costs of $6.41/boe for proved plus probable reserves and $14.98/boe for proved producing reserves (1) 16 Annual Produced Reserves Replacement (2) Growth through Acquisition Organic Growth 12 MMboe 8 4 (4) Reserves Replacement - Development Reserves Replacement - Net Acquisitions & Dispositions Reserves Replacement - Total Production (1) Excludes future development capital. (2) 1997 to 22 reserves data is based on company interest established reserves (proved plus 5 per cent of probable reserves). 23 to 217 reserves data is based on gross interest proved plus probable reserves. Key Reserve Information 836 MMboe 2P Reserves at Year-end 217 Reserves at year-end, December 31, 217 Proved Producing 23 MMboe Total Proved 56 MMboe Proved plus Probable 836 MMboe Crude and Tight Oil 131 MMbbl NGLs 73 MMbbl Natural Gas 3.8 Tcf 2P Reserve Life Index (1) 17 years 2P Reserves (MMboe) Natural Gas Liquids 1% CAGR YE 217 2P Reserves Probable 39% Natural Gas Natural Gas 75.7% 75.7% PUD 29% 16% 9% 76% 16% 9% 75% PDP 27% PNP 5% Crude and Tight Crude Oil and 15.6% Tight Oil 15.6% NGLs 8.7% NGLs 8.7% (1) Based on 218 production guidance midpoint of 132, boe per day. 11/12/218 25

28 Risk Management Program Program Executed with a Long-term View The fair value of ARC s risk management contracts at September 3, 218 was a net asset of $71.3 million $ millions Crude Oil Natural Gas Foreign Exchange & Power Total Realized Gains (Losses) on Risk Management Contracts (1)(2)(3) (5) (1) WTI US$/bbl AECO Cdn$/GJ F 219F 22F 221F 222F 223F $62 $8 $95 $94 $98 $93 $49 $43 $51 $68 $72 $67 $64 $61 $59 $3.91 $3.79 $3.44 $2.27 $3. $4.19 $2.63 $1.98 $2.3 $1.46 $1.54 $1.54 $1.68 $1.71 $1.93 (1) 218 Forecast values based on actuals for the nine months ended September 3, 218 and forecast for October through December 218 based on the forward price curve as at September 3, 218 and net of credit adjustment. 219 to 223 Forecast values based on the forward price curve as at September 3, 218 and net of credit adjustment. (2) Realized pricing is based on annual average settlements and forecasted pricing is the annual average prices based on the forward price curve as at September 3, 218. (3) See ARC s financial statements and notes and MD&A for additional details on risk management program results as well as current risk management contract positions. Risk Management Contract Positions at November 8, 218 Q Crude Oil WTI (2) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day Ceiling , , Floor 5. 4, 5. 2, Sold Floor 4. 4, 4. 2, Swap 54. 2, , Crude Oil Cdn$ WTI (3) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Ceiling , 88. 1, , Floor 65. 2, 8. 1, , Sold Floor , , Swap , , Total Crude Oil Volumes (bbl/day) 2, 15, 5, Crude Oil - MSW (Differential to WTI) (4) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day Swap (3.38) 7, Natural Gas - NYMEX Henry Hub (5) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day Ceiling , , , , , - - Floor 3. 8, , , , , - - Sold Floor 2.5 8, , , , Swap 4. 9, 4. 4, Natural Gas AECO (6) Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Ceiling , 3.6 3, Floor , 3.8 3, Swap , , , Total Natural Gas Volumes (MMBtu/day) 27, ,435 16,869 5, 25, - Natural Gas - AECO Basis (Percentage of NYMEX) AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day Sold Swap , , Natural Gas - AECO Basis (Differential to NYMEX) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day Sold Swap (.84) 86,739 (.88) 12,959 (.82) 98,361 (.97) 34, Total AECO Basis Volumes (MMBtu/day) 176,739 16,959 98,361 34, Natural Gas Other Basis (Differential to NYMEX) (7) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/day Sold Swap 2, 6, 1, 12, 1, 67,479 Foreign Exchange Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Average Rate Forward (8) Sold USD Call (9) (1) The prices and volumes in this table represent averages for contracts representing different periods. The average price for the portfolio of options above does not have the same payoff profile as the individual option contracts. Viewing the average price group of options purely for indicative purposes. All positions several listed of a is are financially settled against the benchmark prices disclosed in the Financial Instruments and Market Risk Management note in ARC s financial statements as at and for the three and nine months ended September 3, 218. Crude oil prices referenced to WTI. (2) (3) Crude oil prices referenced to WTI, multiplied by the WM/Reuters Intra-day Cdn$/US$ Foreign Exchange Spot Rate as of Noon Eastern Standard Time. (4) MSW differential refers to the discount between WTI and the mixed sweet crude stream price at Edmonton, calculated on a monthly weighted average basis in US$. (5) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement. (6) Natural gas prices referenced to AECO 7A Monthly Index (7) ARC has entered into basis swaps at locations other than AECO. (8) Cdn$/US$ referenced to WM/Reuters Intra-day Cdn$/US$ Foreign Exchange Spot Rate as of Noon Eastern Standard Time. (9) Cdn$/US$ referenced to the 1:: AM Eastern Standard Time NY cut. 11/12/218 26

29 Recognitions and Rankings MSCI Global Sustainability Index Jantzi Social Index FTSE Russell s FTSE4Good Index Series CDP Participant for nine consecutive years Joined the 3% Club in 218 Globe and Mail Board Games (Ranked 26 out of 242 companies with a score of 9/1) Brendan Wood International (Ranked #1 in peer group for Confidence in Corporate Strategy in 218) 216 Canadian Coalition for Good Governance: Best Disclosure of Corporate Governance and Executive Compensation Practices 217 & 218 IR Magazine Awards: Best IR in Energy Sector, Grand Prix for Mid-Cap, Best Financial Reporting, Best Use of Technology, Best Investor Relations Officer, Best IR by a CEO (218 only) 218 IR Magazine Global Awards: Best IR in Energy Sector APPENDIX 11/12/218 27

30 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, 217 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. 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. 11/12/218 28

31 Definitions of Oil and Gas Reserves and Resources Undiscovered Petroleum Initially-in-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of UPIIP is referred to as "prospective resources" and the remainder as "unrecoverable". Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 5 per cent probability that the quantities actually recovered will equal or exceed the best estimate. Forecast This presentation contains forward-looking information and statements that may be identified by words like outlook, estimates and similar expressions. These forward-looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. Reference is made to the section titled Forwardlooking Statements at the beginning of the presentation and also to the February 8, 218 news release entitled, ARC Resources Ltd. Reports Record Annual Production and Record Increase to Oil and Gas Reserves which may be found on ARC s website at or on SEDAR at and which are hereby incorporated by reference in this presentation and which outline a number of assumptions, risks and uncertainties associated with forward-looking statements. Actual results could differ materially as a result of changes to ARC s plans, the impact of changes in commodity prices, general economic, market and business conditions as well as production, development and operating performance and other risks associated with oil and gas operations. For further information about ARC Resources Ltd. please visit our website Or contact: Investor Relations ir@arcresources.com T F Toll Free ARC Resources Ltd. 12, 38 4 Avenue SW Calgary, AB T2P H7 11/12/218 29

32 Notes 11/12/218 3

33 FINANCIAL AND OPERATIONAL HIGHLIGHTS ($ millions, except per share amounts) FINANCIAL Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Sales of crude oil, natural gas, condensate, NGLs and other income (1) Per share, basic (1) Per share, diluted (1) Net income (loss) 45.1 (45.9) Per share, basic.13 (.13) Per share, diluted.13 (.13) Funds from operations (2) Per share, basic Per share, diluted Dividends declared Per share (3) Total assets 5, ,59.8 6, ,224. 6,115. 6, , ,99.5 Total liabilities 2, , , , , , , ,55.7 Net debt outstanding (2) Weighted average shares, basic Weighted average shares, diluted Shares outstanding, end of period CAPITAL EXPENDITURES Geological and geophysical Drilling and completions Plant and facilities Administrative assets Total capital expenditures Undeveloped land Total capital expenditures, including undeveloped land purchases Acquisitions Dispositions (96.2) (.7) (98.3) (72.1) Total capital expenditures, land purchases and net acquisitions and dispositions (525.6) OPERATING Production Crude oil (bbl/day) 23,867 24,893 25,37 24,641 25,2 23,813 24,3 29,885 Condensate (bbl/day) 8,158 6,96 5,55 6,989 6,815 4,253 4,54 3,767 Natural gas (MMcf/day) NGLs (bbl/day) 7,687 6,38 6,332 6,38 6,91 4,691 3,893 4,22 Total (boe/day) 135,41 127, ,16 133,49 129, ,41 115, ,611 Average realized prices, prior to risk management contracts (1) Crude oil ($/bbl) Condensate ($/bbl) Natural gas ($/Mcf) NGLs ($/bbl) Oil equivalent ($/boe) TRADING STATISTICS (5) ($, based on intra-day trading) High Low Close Average daily volume (thousands) 1,246 1,15 1,46 1,114 1,8 1,269 1, (1) Comparatives prior to 217 have not been restated for IFRS Revenue from Contracts with Customers. Refer to the Changes in Accounting Policies note in ARC s financial statements. (2) Refer to the "Capital Management" note in ARC s financial statements and to the sections entitled, "Funds from Operations" and Capitalization, Financial Resources and Liquidity contained within ARC s MD&A. (3) Dividends per share are based on the number of shares outstanding at each dividend record date. (4) Trading statistics denote trading activity on the Toronto Stock Exchange only.

34 CORPORATE AND SHAREHOLDER INFORMATION DIRECTORS Harold N. Kvisle Chairman Myron M. Stadnyk President and Chief Executive Officer David R. Collyer (1) (2) John P. Dielwart (2) (3) Fred J. Dyment (3) (4) James C. Houck (2) (3) Kathleen O Neill (4) (5) Herbert C. Pinder Jr. (1) (4) William G. Sembo (1) (5) Nancy L. Smith (3) (5) (1) Member of Human Resources and Compensation Committee (2) Member of Safety, Reserves and Operational Excellence Committee (3) Member of Risk Committee (4) Member of Policy and Board Governance Committee (5) Member of Audit Committee OFFICERS Myron M. Stadnyk President and Chief Executive Officer Terry M. Anderson Senior Vice President and Chief Operating Officer P. Van R. Dafoe Senior Vice President and Chief Financial Officer Bevin M. Wirzba Senior Vice President, Business Development and Capital Markets Chris D. Baldwin Vice President, Geosciences Ryan V. Berrett Vice President, Marketing Kris J. Bibby Vice President, Finance Sean R. A. Calder Vice President, Production Lara M. Conrad Vice President, Engineering and Planning Armin Jahangiri Vice President, Operations Lisa A. Olsen Vice President, Human Resources Grant A. Zawalsky Corporate Secretary EXECUTIVE OFFICE ARC Resources Ltd. 12, 38 4th Avenue SW Calgary, Alberta T2P H7 T TOLL FREE F W TRANSFER AGENT Computershare Trust Company of Canada 6, 53 8th Avenue SW Calgary, Alberta T2P 3S8 T AUDITORS PricewaterhouseCoopers LLP Calgary, Alberta ENGINEERING CONSULTANTS GLJ Petroleum Consultants Ltd. Calgary, Alberta LEGAL COUNSEL Burnet Duckworth & Palmer LLP Calgary, Alberta CORPORATE CALENDAR February 7, 219 Year-end 218 Results May 1, 219 Q1 219 Results May 2, 219 Annual General Meeting August 1, 219 Q2 219 Results November 7, 219 Q3 219 Results 22 Budget STOCK EXCHANGE LISTING The Toronto Stock Exchange Trading Symbol: ARX INVESTOR INFORMATION Visit our website at or contact: Investor Relations T or TOLL FREE E ir@arcresources.com ARC is listed on the Jantzi Social Index; a common stock index of 6 Canadian companies that pass a set of broadly based environmental, social and governance rating criteria.