August 2018 FOCUSED INVESTOR PRESENTATION

Transcription

1 August 218 FOCUSED INVESTOR PRESENTATION 1

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3 Investor Relations Contacts & Advisory Statements Investor Relations Bevin Wirzba Martha Wilmot General Investor Enquiries Senior Vice President, Business Development & Capital Markets Investor Relations Analyst 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 the 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. Corporate Profile Corporate Summary Production (Q2 218) Reserves (2P Gross YE 217) (1) Reserve Life Index (2P) (1)(2) Monthly Dividend 127,879 boe/day 836 MMboe 17.4 years $.5 per share ARC is a Canadian oil and gas producer in its 23 rd year of delivering on its disciplined, returns-focused value proposition. Montney Growth Assets BC AB Annualized Returns since Inception (3) 12% Market Summary Ticker Symbol Average Daily Volume (4) Shares Outstanding Enterprise Value (5)(6) Net Debt (5)(6) Net Debt to Funds from Operations (6)(7) Member of TSX 6 TSX: ARX 2.3 million 354 million $6.2 billion $757. million.9 times Oil and Liquids Dry Gas (1) Refer to Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this presentation. (2) Based on original 218 production guidance midpoint of 132, boe/day. (3) Annualized total return to July 31, 218, including June dividend, and assuming reinvestment of dividends in ARC shares. (4) Daily average trading volume for the trailing six month period ended July 31, 218. (5) Market Capitalization as at July 31, 218 and Net Debt as at June 3, 218. (6) Refer to the Capital Management note in ARC s financial statements. (7) Based on annualized Funds from Operations for the six months ended June 3, 218 and Net Debt as at June 3, 218. Condensate-rich Gas 8/1/218 1

4 ARC s Vision To Be an E&P Business that Is Unique and Difficult to Replicate ARC s vision is to increase shareholder value and deliver industry-leading returns via per share growth in funds from operations and dividends Disciplined Capital Allocation Sustaining Capital Requirements Net Gas Well Count 29% Three-year Average F&D Costs Operating Expenses 61% Focus on Efficiency Improvements % % Physical Market Access and Financial Risk Management Multiple Sales Points including US Midwest, US Pacific Northwest, Dawn, AECO, and Station 2 hubs ~$.8 billion of realized cash gains on risk management contracts since 29 ARC s Principles of Business Delivering on Our Strategy of Risk-managed Value Creation through Focused and Disciplined Decision Making Sustainable total return to shareholders $6.3 billion in distributions / dividends since inception High-margin realizations through low cost structure and market access to deliver profits ROACE (1) of 1% since inception Disciplined capital allocation, maintaining balance sheet strength and managing decline rate The right team pursuing excellence in execution and ESG performance Risk-managed Value Creation (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. 8/1/218 2

5 ARC s Plan ARC s Plan Is Fully Funded and Demonstrates Our Ongoing Focus on Profitability, Sustainability and Creating Optionality Monthly dividend of $.5 per share Brought on Dawson Phase III Sustain Montney businesses Maintain consistent investment levels Sold Saskatchewan assets Rebuilt liquids production from divestments Progress Sunrise Phase II (6 MMcf/day in service by year-end) Bring on Sunrise Phase II (additional 12 MMcf/day in service) Eliminated DRIP and SDP plans 118,671 boe per day Achieved success in Lower Montney and Attachie 122,937 boe per day Advance Attachie piloting activities 13, to 134, boe per day Progress multiple largescale projects, leading to per share production and cash flow growth Attachie West Phase I Dawson Phase I & II liquidshandling enhancements Dawson Phase IV Details on time lines and funding requirements will be presented with ARC s 219 budget Maintain Share Count 218 Guidance Focused on Profitability and Long-term Value Creation Production 218 Guidance 218 Revised Guidance 218 YTD Actuals Crude oil (bbl/day) (1) 25, - 27, 25, - 26,5 24,965 Condensate (bbl/day) (2) 6,5-7, 6,5-7,5 6,236 Crude oil and condensate (bbl/day) 31,5-34, 31,5-34, 31,21 Natural gas (MMcf/day) NGLs (bbl/day) 6, - 6,5 6, - 6,5 6,356 Total production (boe/day) 13, - 134, 13, - 134, 129,439 Expenses ($/boe) Operating Transportation G&A expenses before share-based compensation plans G&A - share-based compensation plans (3) Interest Current income tax expense (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 (98.1) Weighted average shares (millions) (1) With the disposition of non-core assets in the first quarter of 218, ARC reduced the high end of its guidance range for crude oil production. (2) With strong initial production results from ARC s commercial demonstration pad at Attachie West and with continued success from the Lower Montney, ARC increased the high end of its guidance range for condensate production. (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. 8/1/218 3

6 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, maintaining 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 YTD Cumulative Dividend (LHS) 218 YTD Payout Ratio of 26% 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 non-core dispositions, allowing ARC to counter-cyclically fund infrastructure and profitably grow the business Looking beyond 219, ARC will be able to satisfy its dividend obligations, sustain the business, and fund growth capital entirely from funds from operations Total Forecasted Inflows & Outflows (3) Future Inflows & Outflows (3) 217 to 219 ARC can sustain the business in a US$5/bbl WTI and Cdn$1.5/GJ AECO price environment Net A&D Proceeds and Excess Funds from Operations Funds from Operations ~4% Gas ~$4MM/year Dawson Phase III Sunrise Phase II Next Major Project Funds from Operations ~$4MM/year Discretionary Growth Projects Funds from Operations ~6% Oil & Liquids ~$21MM/year ~$21MM/year Sources of Cash Dividend Sustaining Capital Capital Efficiencies $1,/boe/day Growth Capital Capital Efficiencies $15,/boe/day Sources of Cash Dividend (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) Sustaining and growth capital expenditures are before land and net property acquisitions and dispositions. Sustaining Capital Growth Capital 8/1/218 4

7 Physical Marketing Activities Crude Oil & Liquids ARC s Crude Oil & Condensate Production Mix Crude Oil & Condensate Benchmark Pricing 69% 11% 19% 1% ~9% of ARC s liquids production is made up of premium light oil and condensate Light ( > 35 API ) Medium ( 25 to 35 API ) Condensate ( > 5 API ) Heavy ( < 25 API ) US$/barrel Mixed Sweet Blend WTI Condensate Western Canadian Select Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jun-18 68% of ARC s H1 218 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 $1.18 $.14 $1.4 Westcoast /NWP Natural Gas Flows & Sales Points (H1 218 Pricing in US$/MMBtu) AECO $1.14 $.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 $3.15 $3.34 $3.24 $2.96 $.78 $.92 $.74 $.39 $.32 $1.5 $.19 $.63 $2.4 $2.17 $2.18 $ Cdn$/Mcf Sumas $2.5 $.14 $.35 $1.56 Malin $2.24 $.15 $.51 $1.58 GTN Pricing Hub Hub Market Price (1) Field-to-Hub Transportation Cost (2) Hub-to-Hub Transportation Cost (3) Market Netback $.99 Northern Border Alliance GLGT Via Northern Border Ventura Chicago $3.2 $2.93 $.15 $.15 $.48 $.59 $2.39 $2.19 Henry Hub TCPL Mainline < 5% of expected overall sales revenue exposed to AECO and Station 2 for the remainder of 218 (1) H1 218 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 Realized Gains on Risk Management Contracts Diversification Activities Average Price before Diversification Activities ARC Natural Gas Diversification (4)(5) 4% 4% 4% 6% 4% 7% 9% 19% 21% (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.. 1% 75% 34% 26% 19% 5% 8% 2% 7% 11% 17% 23% 25% 37% 23% 15% % Bal 218 Cal 219 Cal 22 Hedged AECO Floating Station 2 Floating Midwest US Floating Dawn Floating Henry Hub Floating Pac-NW US Floating 8/1/218 5 % of Total Production

8 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 2,m Red Creek Attachie Tower Pouce Coupe Septimus Parkland Sunset Dawson Sunrise 3,m Sundown 1,m Geographic Optionality Proximity of ARC Montney land base enables: Capital and operating efficiencies Application of learnings across areas ARC holds ~1,16 net Montney sections (~754, acres) Majority of lands 1% owned and operated, located across two jurisdictions (Alberta and BC) Egress Optionality Dual-connected ARC facilities allow for takeaway optionality in well-served area with three major pipelines providing access to North American markets Dry Gas Ante Creek Condensate-rich Gas 2,m 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 Strategic capital invested in the Lower Montney is increasing overall depth of portfolio (1) Year-end 217 results comply with current Canadian Oil and Gas Evaluation Handbook guidelines. Resources Evaluation volumes provided are the 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. 8/1/218 6

9 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 Full-cycle Returns across Portfolio Growth for Future Phase Development Phase Free Cash Flow Phase Exploration Appraisal / Piloting Develop to Commercialize Invest in Infrastructure Geographic and Commodity Diversity Optimization Maintenance Development to Sustain Cash Flow Redwater Pembina Dawson Phase I & II Ante Creek (Central) Sunrise Phase I Parkland/Tower Phase I & II Net Cash Flow + Dawson Phase III Attachie West (Pilot) Sunrise Phase II Dawson Phase IV Attachie West Phase I Ante Creek (South) Parkland/Tower Phase III Dawson Phase V Pouce Coupe Septimus Attachie East Sundown 218 Budget $69 million (1) (1) Includes $25 million of non-core and corporate capital. Growth & Development Capital $275 million Sustaining Capital $39 million 8/1/218 7

10 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 8/1/218 8

11 NE BC Montney Reserves and Risked Resources 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 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 8 Number of Locations Dawson Parkland / Tower Sunrise / Sunset Attachie Other Montney Ante Creek Total HZ Wells Drilled to YE217 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. 8/1/218 9

12 Montney Development Economics Strong Rates of Return across the Montney Portfolio Half-cycle Economics (1)(2)(3) US$5/bbl WTI Cdn$2.5/GJ AECO Sunrise Upper Montney 85% Upper Montney 5.6x 3.4 to 4.4x Cdn$1.1/Mcf Liquids / Natural Gas % / 1% 2% / 98% Breakeven DawsonParkland Lower Montney Upper Montney 7% Recycle Ratio Production Split 6 Mcf : 1 barrel (4) 2 Mcf : 1 barrel (5) Parkland Phase I & II: 13% Phase III & IV: 95% IRR (1) (2) (3) (4) (5) Dawson 6% to 95% Tower Ante Creek Upper Montney Upper Montney 5% to 1% 5% (dependent on liquids ratio) (dependent on area) 5.x 3.4 to 4.1x 2.6 to 3.7x 4.4x Cdn$.95 to $1.15/Mcf Cdn$.9/Mcf ~Cdn$.75/Mcf US$15 to $21/bbl US$19/bbl Liquids / Natural Gas 9% / 91% 26% / 74% Liquids / Natural Gas 19% / 81% 44% / 56% Liquids / Natural Gas 19-3% / 7-81% 43-59% / 41-57% Liquids / Natural Gas 48% / 52% 76% / 24% Liquids / Natural Gas 51% / 49% 77% / 23% (dependent on liquids ratio) IRR (half-cycle after-tax rate of return) run at US$5/bbl WTI and Cdn$2.5/GJ AECO flat pricing. Breakeven prices are US$ 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. Outstanding Lower Montney Results Progressing from Appraisal to Development and Focused on Growing Liquids Production (1) appraisal wells confirmed significant liquids growth opportunity in the Lower Montney Development activities at Dawson and Parkland will underpin condensate production growth at Dawson Phase III, which has liquids-handling capacity of 7,5 bbl/day Dawson-Parkland interconnect is expected to be in service by late 218 and will allow ARC to invest in Lower Montney wells at Dawson and Parkland on the basis of profitability Dual-layer development is being piloted at Sunrise 2-25 pad, and will add significant drilling inventory and improve capital efficiencies in the area to Q2 218 Lower Montney Drilled and Completed Wells Wells Planned for Dawson-Parkland Interconnect (1) Only Lower Montney wells are displayed. 8/1/218 1

13 Dawson-Parkland 217 Lower Montney Results Strong Results from 217 Lower Montney Appraisal Program Set the Stage for 218 Development Activities Dawson-Parkland Lower Montney Wells Natural Gas Production Dawson-Parkland Lower Montney Wells Free Liquids Production 2, 12 Cumulative Natural Gas Production (MMcf) 1,5 1, 5 Cumulative Liquids Production (Thousand Stock Tank Barrels) Producing Days Producing Days Parkland F11-4 Parkland 1-31 Dawson 3-15Hz Parkland F11-4 Parkland 1-31 Dawson 3-15Hz Dawson C3-15 Dawson F9-21 Dawson D16-13 Dawson C3-15 Dawson F9-21 Dawson D16-13 Dawson H3-15 Dawson K3-15 Med Liquid Dawson H3-15 Dawson K3-15 Med Liquid High Liquid High Liquid Tower & Attachie Integrated Learnings Transferring Exploitation Strategies Between Assets Is Resulting in Meaningful Improvements to Type Curves and Well Inventory 2 Cumulative Oil & Condensate Production (Mbbl) Attachie (~1,95 m) Attachie B13-26 (~1,9 m) Tower 7-12 West Pad Average (~2,5 m) Attachie (~2,8 m) Attachie 4-2 (~2, m) ~6-well Inventory: Phase I (Upper Montney) A13-26 B , 1,2 Days on Production (1) Wells were brought on production through third-party processing infrastructure in Q Attachie West Wells Drilled Attachie West Multi-well Pad (1) 8/1/218 11

14 Montney Exploitation Approach Improves Efficiencies ARC Has Advanced Its Understanding of the Full-stack Development Potential for All Project Areas in Order to Execute Efficiently Montney Full-stack Development (1) Efficiencies of full-stack development include: Surface locations and infrastructure already in place Reduced surface footprint Improved logistics Liquids-to-gas ratio can vary by layer Flexibility built into facility design to handle higher liquids content of Lower Montney (1) Represents Sunrise full-stack model. Spacing and completions approach varies by project area. Continuous Improvement in Safety Performance Strong Health and Safety Performance Supports Capital Efficiency Improvements 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) 8/1/218 12

15 Cost Management Low-cost Producers Deliver Superior Returns over Time Focused assets, characterized by high working interest, operatorship and ARC-owned and operated facilities, provide control over costs and operations 2 Three-Year FD&A Costs ( ) (1)(2)(3) ($/boe) Operating Costs (4)(5) ($/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) 217 Operating Expenses from company reports and represent data for the year ended December 31, 217. (5) 217 Operating Expenses peer group includes: BNP, BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP. Dawson Phase IV Cash Flow Model As With Each Project ARC Advances, Dawson Phase IV Will Generate Significant Free Cash Flow and Strong Full-cycle Returns Development Timeline: 218 to 22: Facility and infrastructure spending 219 to 22: Pre-drill ~36 wells to fill facility 221: Drill ~1 wells per year to sustain business Dawson Phase IV Gas Processing Capacity: 9 MMcf/day Liquids-handling Capacity: 7,5 bbl/day On-stream: 22 35, 3, 25, 2, 15, 1, 5, $ ) F 219F 22F 221F 222F 223F 224F 225F 226F 227F 228F 229F -5, -1, ) ) -15, Field Netback Capital Expenditures, excluding Facility Expenditures -2, Facility Expenditures Net Cash Flow -25, Production -3, 8/1/218 13

16 Environmental, Social & Governance Performance ARC s Leadership Culture Is Reflected in Its ESG Practices ARC looks to develop resources in the most efficient manner while creating long-term value for shareholders and supporting the economic and social wellbeing of the communities in which we operate Investment in low-emissions technology driving strong performance in emissions management and intensity Strong safety culture demonstrates ARC s commitment to creating an injury-free workplace for employees and contractors Our operators and contractors live in the communities in which we operate 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) 217 IR Magazine Global Top 5 For more information, 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 Montney and Cardium Project Potential (boe/day) Growth for Future Development Free Cash Flow Per Share Growth Sustainable Dividend Next Decade Sunrise III Septimus I & II Attachie West II Attachie Central I & II Attachie East I & II Pouce Coupe Sundown Project Options Next Five Years Sanctioned: Sunrise II Follow-on Options: Dawson IV Attachie West I Ante Creek II Parkland/Tower III Dawson V 217 Base Production Montney Cardium 8/1/218 14

17 PORTFOLIO OVERVIEW Key Projects Update Advancing Projects across ARC s Portfolio Montney BC Red Creek AB Attachie Septimus Tower Parkland Pouce Coupe Sunset Sunrise Dawson Sundown Ante Creek Key Projects Update Attachie Seven-well appraisal pad brought on production in Q2 218; early production results are encouraging Takeaway capacity on TCPL North Montney Mainline has been contracted Sunrise Dawson Construction of Sunrise Phase II ahead of schedule; will initiate commissioning activities in Q3 218 and facility will be operational by Q4 218 Initial 6 MMcf/day of new processing capacity available by late Q3 218 or early Q4 218 Additional 6 MMcf/day of incremental processing will be available in H1 219; sales will be commodity-price dependent By May 219, 6 MMcf/day of existing volumes currently processed through a third-party facility will be redirected to Sunrise Phase II Lower Montney delivering high liquids yields and has unlocked significant liquids growth potential Moving forward with Phase I & II enhancements to increase liquids-handling capabilities in the core Sanctioned Phase IV, which will add 9 MMcf/day of natural gas and 7,5 bbl/day of liquids-handling; determining specific time lines Cardium Pembina Parkland/Tower Ante Creek Pembina Delineating and developing Lower Montney at Parkland Connected facility to BC Hydro grid, reducing corporate emissions by 6, tonnes of CO 2 equivalent per year Recent well has been ranked as a top-producing oil well in Alberta Plan to drill five-well pad in H2 218 to capitalize on recent improvements in oil prices 8/1/218 15

18 Attachie Planning for the Future Attachie West is a leading development opportunity within ARC s portfolio due to its: Condensate-rich production profile Significantly over-pressured reservoir Extensive, multi-layered contiguous land position Attachie West Update Commercial, seven-well demonstration pad was drilled in Q4 217 and completed in Q1 218 (included one Lower Montney well) Wells were brought on production in Q2 218; ARC exited the quarter producing 3 Mbbl/day of condensate and 9 MMcf/day of natural gas Wells produced at restricted rates during Q2 218 due to infrastructure constraints Encouraged by initial results 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 Multi-layer Development Potential pad Journey to Commercial Development 2-4 pad ARC Wells ARC Attachie West Production Pilots ARC Attachie West 217 Multi-well Pad ARC Attachie East Delineation Wells ARC Wells Drilled in 217 Single-well Appraisals Commercial Demonstration Pad Commercial Development Upper Montney 214 to 217 Applying Learnings 217 to 218 Determine Time Lines & Funding Requirements for Sanctioning Decision 22 to 221 Lower Montney Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells Asset Details Net Production (boe/day) Q2 218 (1) 2,51 Liquids (bbl/day) 1,61 Gas (MMcf/day) 5 Land (Montney Net Sections) 36 Working Interest ~99% 2P Reserves (MMboe) 3 Liquids (MMbbl) 14.7 Gas (Bcf) 93 Reserve Life Index (Years) (2) 28 PDP Reserves (MMboe) 2 Liquids (MMbbl) 1. Gas (Bcf) 7 Reserve Life Index (Years) (2) 2 (1) Exited Q2 218 producing approximately 3, barrels per day of condensate and 9 MMcf per day of natural gas. Wells from commercial demonstration pad were producing at restricted rates in Q2 218 due to infrastructure constraints. (2) Reserve Life Index based on 218 guided production. 8/1/218 16

19 Sunrise/Sunset Asset Details Confidence in Predictability of Results Supports Strong Reserve Bookings and Next Stage of Development Net Production (boe/day) Q ,52 Liquids (bbl/day) 14 Gas (MMcf/day) 134 Land (Montney Net Sections) 32 Sunset ARC Gas Plant (6 MMcf/day) & Phase II Gas Plant (1) (18 MMcf/day) Sunrise ARC Gas Plants ARC Wells Competitor Wells (1) An initial 6 MMcf/day of gas processing capacity is expected to 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 by June 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. (2) Reserve Life Index based on 218 guided production. Working Interest ~89% 2P Reserves (MMboe) 22 Liquids (MMbbl) 2.3 Gas (Bcf) 1,33 Reserve Life Index (Years) (2) 27 PDP Reserves (MMboe) 41 Liquids (MMbbl).2 Gas (Bcf) 246 Reserve Life Index (Years) (2) Year Budget # Hz Wells Drilled Sunrise Development Potential Proven Productivity from Four-layered Development, Piloting Six-layered Development Drilling Inventory Upper Montney Upper Montney A Booked Reserves Upper Montney A+ Booked Reserves Wells Lower Montney Upper Montney B Booked Reserves Wells Drilled to YE 217 Drilling Opportunities at YE 217 Existing Horizontal Wells, Development Lower Montney Booked Reserves Development Unclarified ECR Locations Development Pending ECR Locations 2P Booked Locations Wells Drilled Existing Horizontal Wells, Pilots Potential Horizontal Wells ARC Montney Lands ARC Montney Lands with 2P Reserves booked as of YE 217 8/1/218 17

20 Dawson Asset Details Focus on Liquids with Infrastructure Enhancements at Dawson Phase I & II and Planning for Dawson Phase IV Expansion TCPL ARC 13-7 Phase III Gas Plant (9 MMcf/day & 7.5 Mbbl/day) ARC 1-34 Compressor Station (45 MMcf/day) ARC 5-35 Phase I & II Gas Plants (12 MMcf/day) Net Production (boe/day) Q ,85 Liquids (bbl/day) 4,42 Gas (MMcf/day) 231 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) 4 ARC Gas Plants & Compressor Stations ARC Wells Competitor Wells Year # Hz Wells Drilled 218 Budget (1) Reserve Life Index based on 218 guided production. Dawson Development Potential Liquids-rich Development Layer Below Core Acreage Drilling Inventory Upper Montney Upper Montney A Booked Reserves 8 6 Wells 4 Lower Montney Existing Horizontal Wells, Development Lower Montney Booked Reserves 2 Wells Drilled to YE 217 Drilling Opportunities at YE 217 Development Unclarified ECR Locations Development Pending ECR Locations 2P Booked Locations Wells Drilled Potential Horizontal Wells ARC Montney Lands ARC Montney Lands with 2P Reserves booked as of YE 217 8/1/218 18

21 Parkland/Tower Asset Details Profitable Business with Commodity Optionality: Oil, Condensate and Natural Gas Tower ARC Gas Plants ARC Wells Competitor Wells Parkland Tower Boundary ARC 8-13 Compressor (2 MMcf/day) (1) Reserve Life Index based on 218 guided production. ARC 3-9 Gas Plants (9 MMcf/day & 1 Mbbl/day) Parkland Parkland Tower Net Production (boe/day) Q ,12 17,52 Liquids (bbl/day) 1,94 8,58 Gas (MMcf/day) Land (Montney Net Sections) Working Interest ~9% ~94% Parkland/Tower 2P Reserves (MMboe) 134 Liquids (MMbbl) 39.2 Gas (Bcf) 571 Reserve Life Index (Years) (1) 12 Parkland/Tower PDP Reserves (MMboe) 4 Liquids (MMbbl) 11.4 Gas (Bcf) 17 Reserve Life Index (Years) (1) 4 Parkland Tower Year Budget # Hz Wells Drilled # Hz Wells Drilled Parkland/Tower Development Potential Incremental Reserves Potential With Multi-layer Development Tower Parkland Upper Montney Upper Montney A Booked Reserves 1 75 Drilling Inventory Upper Montney A+ Booked Reserves Wells 5 Lower Montney 25 Wells Drilled to YE 217 Drilling Opportunities at YE 217 Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells Lower Montney Booked Reservess ARC Montney Lands ARC Montney Lands with 2P Reserves booked as of YE 217 Development Unclarified ECR Locations Development Pending ECR Locations 2P Booked Locations Wells Drilled 8/1/218 19

22 Ante Creek Asset Details Significant Cash Flow with Substantial Growth Opportunities ARC 2-26 Gas Plant (2 MMcf/day) ARC 1-7 Gas Plant (3 MMcf/day & 12.5 Mbbl/day) ARC 1-36 Gas Plant (1 MMcf/day) Net Production (boe/day) Q ,19 Liquids (bbl/day) 8,66 Gas (MMcf/day) 45 Production Split % (Liquids / Gas) 54% / 46% Land (Montney Net Sections) 364 Working Interest ~1% 2P Reserves (MMboe) 54 Liquids (MMbbl) 25.9 Gas (Bcf) 17 Reserve Life Index (Years) (1) 9 PDP Reserves (MMboe) 21 Liquids (MMbbl) 1.5 Gas (Bcf) 63 Reserve Life Index (Years) (1) 3 ARC Gas Plants ARC Wells Year # Hz Wells Drilled 218 Budget (1) Reserve Life Index based on 218 guided production. Ante Creek Development Potential Large Land Base and Down-spacing = Significant Drilling Inventory 2 Drilling Inventory (1) Wells 1 Wells Drilled to YE 217 Wells Drilled Drilling Opportunities at YE 217 ARC Montney Lands ARC Montney Lands with 2P Reserves booked as of YE 217 2P Booked Locations (1) ECR locations not shown as no independent resource study has been conducted for Ante Creek. 8/1/218 2

23 Pembina Asset Details High Working Interest of Light Oil Production, Competitive Operating Netbacks and Free Cash Flow Generation Net Production (boe/day) Q ,12 Liquids (bbl/day) 9,23 Gas (MMcf/day) 11 Land (Cardium Net Sections) 219 Working Interest ~89% NPCU Berrymoor Buck Creek Lindale 2P Cardium Reserves (MMboe) 69 Liquids (MMbbl) 58.3 Gas (Bcf) 63 Reserve Life Index (Years) (1) 19 PDP Cardium Reserves (MMboe) 42 MIPA Liquids (MMbbl) 35.4 Gas (Bcf) 38 PCU7 SPCU Reserve Life Index (Years) (1) 11 Year Budget ARC Working Interest Lands # Hz Wells Drilled 8 15 (2) (1) Reserve Life Index based on 218 guided production. (2) ARC plans to drill and complete a five-well pad in Pembina in H2 218, and expects to bring the wells on production in Q /1/218 21

24 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 & 12% 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 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 (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 of this presentation. (2) Annualized total return to July 31, 218, including June dividend, and assuming reinvestment of dividends in ARC shares. 8/1/218 22

25 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 ~1,16 net Montney sections (~754, net acres) Condensate-rich Gas % Transformation of Our Business Montney Transformation Has Allowed ARC to Manage a Profitable Business through Commodity Price Cycles 15, Production Profile 1,4 Net Debt to Funds from Operations 3. boe/day 12, 9, 6, 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 3, 2.5. 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 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 (2) Payout Ratio is calculated as dividends before DRIP and SDP as a percentage of Funds from Operations. % 8/1/218 23

26 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% 76% 9% 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. 8/1/218 24

27 Risk Management Program Program Executed with a Long-term View The fair value of ARC s risk management contracts at June 3, 218 was a net asset of $126.6 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 $66 $61 $58 $56 $58 $3.91 $3.79 $3.44 $2.27 $3. $4.19 $2.63 $1.98 $2.3 $1.49 $1.64 $1.58 $1.65 $1.72 $1.85 (1) 218 Forecast values based on actuals for the six months ended June 3, 218 and forecast for July through December 218 based on the forward price curve as at June 3, 218 and net of credit adjustment. 219 to 223 Forecast values based on the forward price curve as at June 3, 218 and net of credit adjustment. (2) Realized pricing is based on annual average settlements and forecasted pricing is the annual average prices based on the forward price curve as at June 3, 218. (3) See ARC s financial statements and notes and MD&A for additional details on risk management program results as well as current risk management contract positions. Risk Management Contract Positions Summary of Risk Management Contract Positions as at August 1, 218 (1) H Crude Oil WTI (2) US$/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, 75. 5, Sold Floor , 6. 5, 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 (.88) 93,37 (.88) 12,959 (.82) 98,361 (.97) 34, Total AECO Basis Volumes (MMBtu/day) 183,37 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, 9, 11, 8, 34,877 Foreign Exchange (8) 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 (1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. All positions 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 six months ended June 3, 218. (2) Crude oil prices referenced to WTI. (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. 8/1/218 25

28 APPENDIX 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. 8/1/218 26

29 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. 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 8/1/218 27

30 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 8/1/218 28

31 Notes 8/1/218 29

32 8/1/218 3

33 FINANCIAL AND OPERATIONAL HIGHLIGHTS ($ millions, except per share amounts) FINANCIAL Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Sales of crude oil, natural gas, condensate, NGLs and other income (1) Per share, basic (1) Per share, diluted (1) Net income (loss) (45.9) Per share, basic (.13) Per share, diluted (.13) Funds from operations (2) Per share, basic Per share, diluted Dividends declared Per share (3) Total assets 6,59.8 6, ,224. 6,115. 6, , ,99.5 5,968.4 Total liabilities 2, , , , , , ,55.7 2,622.3 Net debt outstanding (2) ,9.4 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 (.7) (98.3) (72.1) (.3) Total capital expenditures, land purchases and net acquisitions and dispositions (525.6) OPERATIONAL Production Crude oil (bbl/d) 24,893 25,37 24,641 25,2 23,813 24,3 29,885 29,642 Condensate (bbl/d) 6,96 5,55 6,989 6,815 4,253 4,54 3,767 3,562 Natural gas (MMcf/d) NGLs (bbl/d) 6,38 6,332 6,38 6,91 4,691 3,893 4,22 4,221 Total (boe/d) 127, ,16 133,49 129, ,41 115, , ,25 Average realized prices, prior to risk management contracts (1) Crude oil ($/bbl) Condensate ($/bbl) Natural gas ($/Mcf) NGLs ($/bbl) Oil equivalent ($/boe) TRADING STATISTICS (4) ($, based on intra-day trading) High Low Close Average daily volume (thousands) 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 Wayne D. Lentz Vice President, Business Analysis 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 218 November 8, 218 Q3 218 Results 219 Budget November 12, 218 Investor Day 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.