Forward Looking Statements

Transcription

1 January 2015

2 Forward Looking 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 2015 and beyond, and related production expectations, costs and cash flow, expenses, our plans for constructing and expanding the facilities, the volume of ARC's oil and gas reserves and the volume of ARC's gas and oil 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 Resources. 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 2015 Guidance, which is updated and 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 bbl when converting natural gas to barrels of oil equivalent ("boes"). Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf per 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.

3 Value Proposition Clear Line of Sight to Long-term Value Creation

4 Value Creation Culture Culture Focused on Organizational Learning Drives Ongoing Success Technology Efficiency Opportunity Applying New Technology: Focus on Operational Efficiency: Building for the Long-Term: Longer Laterals Optimize Frac Spacing Optimize Proppant Rates Horizontal Water Floods Managing Operating Costs Low Decline Rate Pad Drilling Efficiencies Facility Ownership Significant Land Base Multi-layer Potential Large Drilling Inventory Montney Liquids Potential Montney Pilot Projects EOR Projects

5 Corporate Profile Corporate Summary Production (Q3 2014) Reserves (2P Gross YE 2013) (1) 115,530 boe/d 634 mmboe Reserve Life Index (2P) (1) 15.5 years (2) Annualized Dividend / Dividend Yield $1.20 per share / 5.4% (3) Annualized Returns (4) Since Inception 5 Year Trailing Market Summary Ticker Symbol 16% 7% TSX: ARX Average Daily Volume 1.7 million (5) Shares Outstanding 337 million Enterprise Value $8.5 billion (6) Total Net Debt $1.2 billion (6) Net Debt to Funds from Operations 1.0 times (7) Member of TSX 60 (1) See Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this Presentation. (2) Based on 2014 production guidance midpoint of 112,000 boe/d. (3) Dividend yield as at January 29, (4) Annualized total return to January 29, 2015, including December 2014 dividend, and assuming DRIP participation. (5) Daily average trading volume for the trailing six month period ended January 29, (6) Market Capitalization as at January 29, 2015 and net debt as at September 30, (7) Based on annualized Funds from Operations for three months ended September 30, 2014.

6 Unique Strategy Risk Managed Value Creation is Central to ARC s Strategy Targeting net debt to funds from operations between x >200% Reserve Replacement through the drill bit for the past 6 consecutive years One of the longest RLI compared to peers at 15.5 years Highly skilled team of 560 employees with proven ability to execute

7 High Quality Long Life Assets 200% or Greater Reserve Replacement Over the Past 6 Years 700% Annual Reserve Replacement 600% Development Acquisitions 500% 400% 300% 200% 100% 0%

8 $ per boe/d $ per boe/d Operational Excellence Capital Efficiencies Managing Declines and Driving Down Costs $40,000 $30,000 All In Capital Efficiencies $/boe/d (1) 3 Year Avg. Capital Efficiencies $/boe/d (2) $40,000 $30,000 ARC Competitors $20,000 $20,000 $10,000 $10,000 $ F $- All In Capital Drill & Completion (1) 2013 Costs include Infrastructure spending, related production did not come on-stream until 2014 (2) Source: Scotiabank GBM Statsbook May 2014 Competitors group includes BNP, BTE, CPG, ERF, LTS, PGF, POU, PWT, TET, TOU, PEY, VET.

9 ARC Dawson Gas ARC NE BC Oil & Gas ARC Dawson Gas ARC NE BC Oil & Gas Operational Excellence Cost Management Low Cost Producers Deliver Superior Returns Over Time Focused assets, characterized by high working interest, operatorship and ARC owned/operated facilities, provides control over costs and operations $30 3 Year FD&A $/boe (1)(2) 2013 Operating Costs $/boe (3) $20 $25 $15 $20 Group Average Group Average $15 $10 $10 $5 $5 $- ARC $- ARC Peer group includes: ARX, BNP, BTE, CPG, ERF, PEY, PGF, PWT, TOU, VET (1) Three year 2P FD&A includes future development capital ( FDC ) source: Peters & Co Reserves Comparison April 3, (2) See ARC s press release issued on February 5, 2014 relating to its 2013 year end reserves for information relating to ARC s finding and development costs. (3) Operating costs from Canoils and company reports.

10 $ millions Net Debt to Funds from Operations Financial Flexibility Balance Sheet Strength Targeting Net Debt to Funds from Operations Between x $1,400 Net Debt to FFO 2.0 $1,200 $1, $ $600 $ $200 $ Q (1) Net Debt Funds From Operations Net Debt to FFO 2014F (2) - (1) Q Net Debt to FFO was calculated based on annualized Q FFO and net debt at September 30, (2) 2014 Net Debt and 2014F FFO based on consensus of 11 Analysts as of October 2014.

11 boe/d Forecast Forecast Risk Managed Value Creation 15% Compound Annual Production Growth (CAGR) Since Inception 140, , ,000 80,000 60,000 40,000 20,000 0 Non-Montney Liquids Montney Liquids Non-Montney Gas Montney Gas

12 Cumulative Total Dividends $ Millions Payout Ratio Sustainable Dividend Committed to the Dividend While Delivering Profitable Growth 16% annualized total return since inception, ~$5.3 billion of dividends ($31.08/share) $5,500 $5,000 $4,500 Cumulative Dividends and Historic Payout Ratio 120% 100% $4,000 $3,500 80% $3,000 $2,500 $2,000 $1,500 $1,000 60% 40% 20% $500 $ YTD % Cumulative Dividend Payout Ratio * Payout Ratio is calculated as dividends before DRIP and SDP as a percentage of Funds from Operations. * Annualized total return to January 29, 2015, including December dividend, and assuming DRIP participation

13 Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Growth in Per Share Production and Cash Flow Delivering Value with Profitable Growth and Income 38% increase in production per share and 69% increase in Funds from Operations per share over five year period Production per Share (1) 6% CAGR Q Q Funds From Operations per Share (2) 11% CAGR Q Q $ $ $ $0.40 (1) Boe/d per 1,000 shares based on basic weighted average shares. (2) Funds from Operations per share based on basic weighted average shares.

14 ARC s Proven Development Model Inventory of Opportunities at all Stages

15 Asset Overview

16 Operations Overview Western Canadian Producer Strategic Optionality BRITISH COLUMBIA ALBERTA SASKATCHEWAN MANITOBA NE British Columbia Northern Alberta Pembina Redwater Southern Alberta SE Sask and Manitoba

17 Focused Production and Reserves Montney Comprises ~ 70% of Production and 2P Reserves 40,000 30,000 20,000 10,000 - Production (boe/d) Q P Reserves (Mmboe) YE 2013 (1) Montney 80,000 boe/d (70%) Base 35,000 boe/d (30%) Montney 457 mmboe (72%) Base 177 mmboe (28%) Natural Gas Oil & Liquids (1) 2P Gross Reserves as at December 31, 2013.

18 F F Complimentary Asset Base Montney Growth Assets Underpinned by Free Cash Flow Generating Base Assets Invested ~$2.3 billion of capital in Montney growth assets during F Base assets generated ~$1.6 billion of free cash flow during the period F Base production decline due to divest of ~8,300 boe/d of non-core production since 2009 Base Assets Free Cash Flow Montney Growth Assets Free Cash Flow $MM 1,000 Mboe/d 80 $MM 1,000 Mboe/d Field Netback Free Cash Flow -200 Capital Expenditures Production boe/d (20) (1) 2014 Forecast based on actuals for first nine months of 2014 and forecast for Q based on forward price curve.

19 Montney Assets

20 Why the Montney Total Recoverable Resource Ranks High Amongst North American Resource Plays Massive thickness Large areal extent (>500km) Superior lithology and fracability High permeability Over pressured Higher recovery factors Repeatable performance Dry gas, liquids rich gas and oil opportunities Montney Barnett Eagleford Marcellus Haynesville

21 PETRONAS CNQ ARX ECA BIR 7 GENS CR CIOC POU RDS DCK TOU PPY NVA ATH AAV TET BNP Montney Acres (000's) Significant Montney Land Position 3 rd Largest Montney Landholder With Over 620,000 Net Acres 1,400 Top Montney 000 acres Acreage Holder (1) 1,200 1, ~70% of ARC s Montney land is undeveloped, providing significant future opportunity (1) Source: RBC Energy Insights: The Montney Tracking an Elephant August 12, 2014

22 Lower Montney Upper Montney Multiple Layers to Develop Attachie Septimus Sunrise Tower Parkland Dawson Pouce Coupe Montney A Montney B Montney C Montney D Montney E Existing Horizontal Wells, Development Potential Horizontal Wells Existing Horizontal Wells, Pilots

23 Forecast ARC in the Montney 40% Annual Montney Growth over 5 Year Period ( ) ~40% CAGR F 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, ARC enters Ante Creek ~30% CAGR F 2003 ARC acquires Dawson Field 2005 ARC drills first Montney Hz Building ARC s Montney land base 2010 / 08 ARC acquires Storm 2010 / 04 Dawson Gas Plant Phase Ante Creek Gas 2011 Plant Dawson Gas Plant: Phase Parkland Gas 2013 Plant: Phase 1 Construction begins on Parkland Phase 1 - Montney Liquids Montney Gas

24 NE BC Montney Reserves & Resources NE BC Montney TPIIP 55 Tcf of Gas and 2.2 Billion Barrels of Oil Corporate P+P Reserves of 634 mmboe 2.2 Tcf 4.5 Tcf P+P RESERVES ECONOMIC CONTINGENT RESOURCE (Best Estimate) OIL 11.3 mmbbls NGL 27.6 mmbbls OIL 10.7 mmbbls NGL mmbbls 3.9 Tcf PROSPECTIVE RESOURCE (Best Estimate) NGL mmbbls 30.4 Tcf DISCOVERED PETROLEUM INITIALLY IN PLACE OIL 1.7 Billion Barrels 55 Tcf TOTAL PETROLEUM INITIALLY IN PLACE OIL 2.2 Billion Barrels GAS LIQUIDS *Total Petroleum Initially in Place (TPIIP) and Discovered Petroleum Initially in Place (DPIIP) estimates are determined using a 0% porosity cut-off for gas. Based on the July 2014 updated Resource Other Than Reserves guidelines in the Canadian Oil and Gas Evaluation Handbook (COGEH), the use of 0% is not viewed as acceptable practice. (1) Independent Resources Evaluation conducted by GLJ effective December 31, (2) See Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this presentation.

25 Montney Development Economics Strong Rates of Return Across the Montney Portfolio Half Cycle Economics Cdn$85/bbl Oil and Cdn$3/GJ Gas Parkland Tower Dawson Sunrise Ante Creek 50% IRR 4.2x Recycle <$1.00/mcf Breakeven 50% IRR 4.3x Recycle $40/bbl Breakeven 65% IRR 4.2x Recycle $1.40/mcf Breakeven 50% IRR 5.1x Recycle $1.60/mcf Breakeven 50% IRR 3.1x Recycle $40/bbl Breakeven * All economics run at FLAT price forecasts with Cdn$85/bbl Edm MSW and Cdn $3/GJ AECO * Breakeven prices are Cdn$ per barrel or mcf as indicated. Breakeven is defined as the price at which NPV10 is equal to zero.

26 Montney Infrastructure Optionality Well Positioned For Market Access Area is currently well served with three major pipelines providing access to North American Markets: ARC Lands TransCanada Canada & US Alliance Chicago Spectra - Westcoast Multiple pipelines planned to support the proposed West Coast LNG Projects ARC s primary properties are situated in the heart of the region to be serviced by the pipelines Source: RBC Capital Markets

27 Dawson Gas World Class Resource, Unlimited Potential *Breakeven Cdn$ per bbl or mcf price as indicated defined as price at which NPV10 is equal to zero. *IRR Half cycle after tax rate of return based on C$85/bbl Edm MSW and C$3/GJ AECO *Free Cash Flow Defined as Revenue royalties op costs - transportation costs capital expenditures (before land and net acquisitions). *F&D 2013 Finding and Development Cost before changes in future development capital. *Significant Resource - TPIIP as per 2013 year end GLJ report based on 0% porosity cut-off see See Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this presentation.

28 Dawson Asset Details Excellent Free Cash Flow ARC 1-34 Compressor Station (45 mmcfd) ARC Proposed Gas Plant (90 mmcfd & 7,500 bbls/d liquids) ARC 5-35 Gas Plant (120 mmcfd) Net production (boe/d) Q ,000 Liquids (bbls/d) 920 Gas (mmcf/d) 162 Production split % (liquids/gas) ~97% gas Land (Montney net sections) 133 Working Interest ~96% Reserves (2P mmboe) 174 Liquids (mmbbls) 5.0 Gas (bcf) 1,013 Reserve Life Index 17 Year Forecast # HZ wells drilled

29 Dawson Development Potential Additional Development Layer Below Core Acreage Upper Montney Lower Montney Dawson Upper Montney A Booked Reserves* Lower Montney Booked Reserves* Dawson core development has been focused on Upper Montney A; 55% of lands currently have no reserves booked in this layer ARC drilled our first Lower Montney in Improved completion techniques show promising results for unlocking this additional layer at Dawson Currently 0.75 Hz wells drilled per section *Sections with 2P Reserves booked as of YE2013

30 $ per Frac Fracs/well Lateral Length (metres) Frac Spacing (metres) Operational Excellence Dawson Continual Learning in Frac Design = Lower Costs + Improved Economics Lower Cost per Frac, Increasing Frac Intensity $300, Longer Laterals, Tighter Frac Spacing 2, $250, , $200, , $150, , $100, , $50, , $ F 0 1, F 0 Completion Cost per frac Avg # Fracs per Well Avg Well Length (lateral) Avg Frac Spacing Frac Design 100T Slickwater Fracs with Open Hole Packers/Ball Drop system 80m 80m 2,050m

31 Production Rate (Mcf/d) Dawson Gas Type Curve Growth Frac Technology Advancements = Improvements in Well Performance Type curve growth over time due to improvements in well design, focused on completions and tighter frac spacing 7,000 6, Type Curve Completions Frac spacing (m) Fracs per well Avg. tonnage per frac (T) Cost per frac ($000) ,000 4, /2014 Type Curve Frac type Fluid system Plug & perf Polymer H20/CO2 Plug & perf Slickwater Hybrid Openhole packers Slickwater Openhole packers Slickwater Key Metrics ,000 DCET Capex/well ($MM) , Type Curve Internal 2P Reserves (Bcfe) , Type Curve 2008 Type Curve Months Type curves are internal estimates based on analog wells and reservoir modelling IP (1 mo) (MMcfd) IP (12 mo) (MMcfd) Half Cycle Economics C$85/bbl and C$3/GJ IRR (%AT) 31% 42% 55% 65%

32 Gas Rate (Mcf/d) Dawson Development Economics 65% Rate of Return at Flat $3/GJ AECO and C$85/bbl 7,000 6,000 5,000 4,000 Key Metrics DCET Capex per well ($MM) 5.5 Reserve estimate (Bcf) 7.4 IP (1 mo) (MMcf/d) 6.2 IP (12 mo) (MMcf/d) 5.4 Half Cycle Economics (Cdn$85bbl) C$4/GJ C$3/GJ IRR (% AT) 110% 65% Recycle Ratio ,000 2,000 1, Months All economics run at FLAT price forecasts with C$85/bbl Edm MSW and $3/GJ AECO Liquid yield assumptions: Condensate 3 bbl/mmcf, NGL 2 bbl/mmcf Assumed Cycle Time (from spud to on production): 4 months Type curve is an internal estimate based on analog wells and reservoir modeling

33 $ millions mmcfe/d Dawson A Cash Flow Machine Low Reinvestment Ratio to Maintain Significant Free Cash Flow Grown production from ~ 50 Mmcfe/d in 2009 to 165 Mmcfe/d by mid 2012 At Cdn$3 gas ~30% Reinvestment Ratio to sustain cash flow and generate ~$100 million of free cash flow annually for >15 years based on current booked reserves Approximately nine wells required to sustain production at 165 mmcf/d Field Netback ($mm) Capex ($mm) Net Cash Flow Production (mmcfe/d) Forecast (40) -150 $3.79 $3.79 $3.44 $2.27 $ F AECO (Cdn$/GJ) (80) (1) 2014 Forecast based on actuals for first nine months of 2014 and forecast for Q based on forward price curve.

34 Dawson Infrastructure New Facility Planned For 2017 On-stream New Dawson Phase III Gas Plant 90 mmscfd with 7,500 bbls/day of liquids handling New site ideally situated in the Lower Montney/Liquids Rich play Designed to handle inlets of 45 bbl/mmscf of NGL s and over 40 bbl/mmscf of Condensate Low emission design complete with acid gas injection Gas plant is targeted to be commissioned in 2017 Total gas processing capacity in Dawson will be 255 mmscfd and over 8,500 bbls/day of liquids handling in 2017

35 Parkland/Tower Reaping Acquisition Benefits *Breakeven Cdn$ per bbl or mcf price as indicated defined as price at which NPV10 is equal to zero. *IRR Half cycle after tax rate of return based on C$85/bbl Edm MSW and C$3/GJ AECO *Free Cash Flow Defined as Revenue royalties op costs - transportation costs capital expenditures (before land and net acquisitions). *F&D 2013 Finding and Development Cost before changes in future development capital.

36 Parkland/Tower Asset Details Material Value Creation in 2014 Net production (boe/d) Q Parkland Tower 18,200 6,880 Liquids (bbls/d) 3,700 4,940 Gas (mmcf/d) Land (net sections) Working Interest ~84% ~92% Reserves (2P mmboe) Liquids (mmbbls) Gas (bcf) Reserve Life Index Year Forecast Tower Parkland # Hz Wells Drilled # Hz Wells Drilled

37 Parkland/Tower Development Potential Incremental Reserves Potential with Multilayer Development Upper Montney Upper Montney A Booked Reserves* Upper Montney supports two layers of development at Parkland and Tower Lower Montney Upper Montney A+ Booked Reserves* At year end 2013, ~55% of WI lands had reserves booked to Upper Montney A Currently piloting Lower Montney potential Lower Montney Booked Reserves* *Sections with 2P Reserves booked as of YE2013 Current well density is 3 Hz wells per section in Parkland and 0.6 Hz wells per section in Tower

38 $ per Frac Fracs/well Lateral Length (metres) Frac Spacing (metres) Operational Excellence Tower Optimal Frac Design and Significant Efficiency Gains in Tight Oil Play 60% Decrease in Cost/Frac, 2X Increase in Frac Intensity $160,000 $140,000 $120,000 $100,000 $80,000 $60,000 $40,000 $20, ,500 2,000 1,500 1, Applying Learnings in Well Length and Frac Spacing $ F F 0 Completion Cost per frac Avg # Frac per Well Avg Well Length (lateral) Avg Frac Spacing Frac Design 45T Slickwater Fracs with Plug and Perf 25m 25m Proposed 2,300m

39 Production Rate (boe/d) Tower Completions Advancement Advanced Completion Design = Improved Performance 1,200 Completions , Type Curve 2015 Type Curve Frac spacing (m) Fracs per well Avg. tonnage per frac Cost per frac ($000) Frac type Plug & perf Plug & perf Fluid system Hybrid Slickwater 400 Key Metrics DCET Capex/well ($MM) Months Internal 2P Reserves (MBOE) IP (1 mo) (boed) IP (12 mo) (boed) Half Cycle Economics C$85/bbl and C$3/GJ IRR (%AT) 28% 50% Type curves are internal estimates based on analog wells and reservoir modelling

40 BOE/d Tower Development Economics 50% Rate of Return at Flat $3/GJ AECO and C$85/bbl Key Metrics DCET Capex per well ($MM) 6.5 2P Reserve Estimate (Mboe) 600 IP (1 mo) (boe/d) 1000 IP (12 mo) (boe/d) 400 Half Cycle Economics (C$3/GJ) Cdn$95/bbl Cdn$85bbl IRR (% AT) 60% 50% 600 Recycle Ratio Months Oil COND NGL Gas All economics run at FLAT price forecasts with C$85/bbl Edm MSW and $3/GJ AECO Liquid yield assumptions: Condensate 15 bbl/mmcf, NGL 37 bbl/mmcf Reserves estimate breakdown: 200 mbbls oil, 100 mbbls NGL/Condensate and 1.8 bcf natural gas Assumed Cycle Time (from spud to on production): 5 months Type curve is an internal estimate based on analog wells and reservoir modeling

41 Tower 2014 Wells New Completions Delivering Breakthrough Performance Total Production (boe/d) Oil Production (bbl/d) Pad 5-14 Pad (2014) 8-15 Pad (2014) Old completion design New completion design 2015 Type curve 2015 Type curve 2014 Type curve 2014 Type curve *Smoothed data using 6 day moving average Type curves are internal estimates based on analog wells and reservoir modeling

42 Tower Cumulative Production New Wells are Exceeding Type Curve Total Production (boe) Oil Production (bbl) 2015 Type curve 2015 Type curve 2014 Type curve 2014 Type curve Pad 5-14 Pad (2014) 8-15 Pad (2014) Old completion design New completion design *Smoothed data using 6 day moving average Type curves are internal estimates based on analog wells and reservoir modeling

43 $ per Frac Fracs/well Lateral Length (metres) Frac Spacing (metres) Operational Excellence Parkland Learnings from Dawson = Advanced Frac Design and Improved Results at Parkland $300,000 Optimizing # Fracs, Lowering Costs 35 Optimizing Well Length and Frac Spacing 2, $250,000 $200,000 $150,000 $100,000 $50, ,000 1,950 1,900 1,850 1,800 1,750 1,700 1, $ F 0 1, F 40 Completion Cost per frac Avg # Frac per Well Frac Design 100T Slickwater Fracs with Open Hole Packers/Ball Drop system Avg Well Length (lateral) Avg Frac Spacing 70m 70m 2,000m

44 Production Rate (Boe/d) Parkland Development Economics Targeting Liquids With Step Out From Core Completions Frac spacing (m) ,200 1, Type Curve (Dry Gas) 2013 Type Curve (Dry Gas) 2014 Type Curve (Dry Gas / Liquids Rich Gas) 2015 Budget (Liquids Rich Gas) Fracs per well Avg. tonnage per frac (T) Cost per frac ($000) Frac type Plug & perf Plug and perf Perf+Plug/OH OH Packers Fluid system Polymer H20/CO2 Slickwater Hybrid Slickwater Slickwater 600 Key Metrics DCET Capex/well ($MM) Internal 2P Reserves (Bcfe) IP (1 mo) (Boed) Months on Production IP (12 mo) (Boed) Half Cycle Economics C$85/bbl and C$3/GJ Type curves are internal estimates based on analog wells and reservoir modelling IRR (%AT) 31% 54% 48% 50%

45 BOE/d Parkland Development Economics 50% Rate of Return at Flat $3/GJ AECO and C$85/bbl Key Metrics DCET Capex per well ($MM) 5.7 2P Reserve Estimate (Bcfe) 5.8 IP (1 mo) (boe/d) 1080 IP (12 mo) (boe/d) 645 Half Cycle Economics (Cdn$85bb) C$4/GJ C$3/GJ IRR (% AT) 70% 50% Recycle Ratio Months COND NGL Gas All economics run at FLAT price forecasts with C$85/bbl Edm MSW and $3/GJ AECO Liquid yield assumptions: Condensate 16 bbl/mmcf, NGL 22 bbl/mmcf Reserves estimate breakdown: 180 mbbls NGL/Condensate and 4.7 bcf (sales) natural gas Assumed Cycle Time (from spud to on production): 5 months Type curve is an internal estimate based on analog wells and reservoir modeling

46 Sunrise Long-term Growth Opportunity *Breakeven Cdn$ per bbl or mcf price as indicated defined as price at which NPV10 is equal to zero. *IRR Half cycle after tax rate of return based on C$85/bbl Edm MSW and C$3/GJ AECO. *Free Cash Flow Defined as Revenue royalties op costs - transportation costs capital expenditures (before land and net acquisitions). *F&D 2013 Finding and Development Cost before changes in future development capital. *Significant Resource - TPIIP as per 2013 year end GLJ report based on 0% porosity cut-off see See Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this presentation.

47 Sunrise/Sunset Asset Details Sunrise/Sunset Moving Forward with Full Scale Development Sunrise has progressed from pilot to full scale development Net production (boe/d) Q ,050 Liquids (bbls/d) 0 Gas (mmcf/d) 42.3 Land (net Montney sections) 32 Working Interest ~89% Reserves (2P mmboe) 113 Liquids (mmbbls) 3.3 Gas (bcf) Reserve Life Index Year Forecast Sunrise/ Sunset # Hz Wells Drilled

48 Sunrise Development Potential Proven Productivity from Four Layered Development Upper Montney Lower Montney Upper Montney A Booked Reserves* Upper Montney A+ Booked Reserves* Upper Montney B Booked Reserves* Lower Montney Booked Reserves* Known reserves exist in Upper Montney A drilling program has proved Upper Montney A+ productivity With four layered development at Sunrise, ARC s 24 net sections are equivalent to 96 net sections of single layer development Current well density of 1 Hz well per section *Sections with 2P Reserves booked as of YE2013

49 $ per Frac Fracs/well Lateral Length (metres) Frac Spacing (metres) Operational Excellence Sunrise Incorporating Learnings into Early Development = Excellent Initial Results $250,000 Doubling Fracs/well over 3 years 35 2,500 Efficient Lateral Lengths 140 $200, , $150, , $100, , $50, $ F Completion Cost per frac Avg # Frac per Well Frac Design 100T Slickwater Fracs with Open Hole Packers/Ball Drop system F Avg Well Length (lateral) Avg Frac Spacing

50 Gas Rate (Mcfd) Sunrise Outperforming Expectations 2014 Drilling Results Prove Four Layer Development Model 10,000 9,000 8,000 7,000 6, Type Curve (11.7 Bcf Raw) 08-24Hz (MTYA) C09-13Hz (Lower (Upper MTYA) MTYA+) B02-25Hz (MTYB) - see note C02-25Hz (MTYD) - see note 5,000 4,000 3,000 2,000 1, ,000 Days On Production C02-25Hz (MTYD): 2010 Completion - 130m interfrac spacing --> proposing reducing interfrac spacing going forward B02-25Hz (MTYB): 115m interfrac spacing Type curve is an internal estimate based on analog wells and reservoir modelling

51 Gas Rate (Mcfd) Sunrise Continuous Improvements Enhanced Well Design = Type Curve Improvement 7,000 Completions ,000 5, Type Curve (11.5 Bcf) 2013/14 Type Curve (11 Bcf) 2012 Type Curve (9.7 Bcf) 2011 Type Curve (7 Bcf) Frac spacing (m) # Fracs per well Avg. tonnage per frac (T) Cost per frac ($000) ,000 Fluid system Hybrid / Slickwater Slickwater Slickwater 3,000 Key Metrics DCET Capex/well ($MM) ,000 Internal 2P Reserves (Bcfe) IP (1 mo) (MMcfd) ,000 IP (12 mo) (MMcfd) ,000 Days On Half Cycle Economics C$85/bbl and C$3/GJ IRR (%AT) 33% 50% 50% Type curves are internal estimates based on analog wells and reservoir modelling

52 Gas Rate, mcf/d Sunrise Development Economics 50% Rate of Return Flat at $3/GJ AECO and C$85/bbl 7,000 Key Metrics DCET Capex per well ($MM) 6.0 6,000 5,000 2P Reserve Estimate (Bcf) 11.5 IP (1 mo) (MMcf/d) 6.2 IP (12 mo) (MMcf/d) 5.4 Half Cycle Economics (Cdn$85bbl) C$4/GJ C$3/GJ 4,000 IRR (% AT) 75% 50% Recycle Ratio ,000 2,000 1, Months All economics run at FLAT price forecasts with C$85/bbl Edm MSW and $3/GJ AECO Liquid yield assumptions: Condensate 1 bbl/mmcf, NGL 0.6 bbl/mmcf Assumed Cycle Time (from spud to on production): 4 months Type curve is an internal estimate based on analog wells and reservoir modeling

53 Montney Pilot Projects Significant Future Potential

54 Montney Pilots Proving Future Value Before Full Scale Development West Attachie: Pilot Production on-stream since Q Attachie Red Creek Parkland: Lower Montney well on-stream Q East Attachie: Monitoring Pilot Production since 2012 Septimus Tower Parkland Pouce Coupe Pouce Coupe: Lower Montney pilot production on-stream late 2013 Septimus: Pilot Production on-stream since Q Sunset Sunrise Dawson Dawson: Two Lower Montney wells drilled in Q Sundown Upper Montney Pilot Wells Lower Montney Pilot Wells

55 Ante Creek A Montney Success Story *Breakeven Cdn$ per bbl or mcf price as indicated defined as price at which NPV10 is equal to zero. *IRR Half cycle after tax rate of return based on C$85/bbl Edm MSW and C$3/GJ AECO. *Free Cash Flow Defined as Revenue royalties op costs - transportation costs capital expenditures (before land and net acquisitions). *F&D 2013 Finding and Development Cost before changes in future development capital.

56 Ante Creek Asset Details Significant Cash Flow with Substantial Growth Opportunity Net production (boe/d) Q ,800 Liquids (bbls/d) 9,300 Gas (mmcf/d) 51 Production split % (liquids/gas) ~52/48 Land (Montney net sections) 351 Working Interest ~99% Reserves (2P mmboe) 50.9 Liquids (mmbbls) 24.6 Gas (bcf) 158 Reserve Life Index 9 Year Forecast # Hz Wells Drilled

57 Ante Creek Significant Drilling Inventory Large Land Base and Down-spacing = Significant Drilling Inventory Booked reserves exist on ~30% of ARC held mineral rights Significant opportunity to prove up this large land base with delineation drilling Continue to step out from existing drilled lands to prove up new core areas for pad drilling Current well density of 0.45 wells per section Montney Booked Reserves* *Sections with 2P Reserves booked as of YE2013

58 Lateral Length (metres) Drill Days $ per Frac Frac Spacing (metres) Operational Excellence Ante Creek Reducing Business Cycle Times with Optimized Frac Design 2,500 Drilling Longer Laterals in Fewer Days 20 Lower Cost/Frac, Optimizing Frac Intensity $180, $160, , $140, ,500 1, $120,000 $100,000 $80,000 $60,000 $40,000 $20, F 12 $ F 0 Avg Well Length (lateral) Avg drill days Completion Cost per Frac Avg Frac Spacing Frac Design 20T, Nitrified Foam Fracs with Open Hole Packers and Ball Drops 80m 80m 2000 m

59 Production Rate (boe/d) Ante Creek Delivering Results Type Curve Consistency Moving Out of the Core Ante Creek Normalized Type Curves for Montney Horizontal Wells Completions Frac spacing (m) # Fracs per well Avg. tonnage per frac (T) Cost per frac ($000) Frac Type Fluid System Ball & Seat Oiljel/ Water Ball & Seat Oil/ N2 Foam/ Crosslink Ball & Seat Oil/ N2 Foam Ball & Seat N2 Foam Key Metrics DCET Capex/well ($MM) Internal 2P Reserves (Mboe) IP (1 mo) (Boepd) IP (12 mo) (Boepd) Months Half Cycle Economics C$85/bbl and C$3/GJ IRR (%AT) 45% 50% 50% 50% Type curves are internal estimates based on analog wells and reservoir modeling

60 BOE/d Ante Creek Development Economics 50% Rate of Return at Flat $3/GJ AECO and C$85/bbl Key Metrics DCET Capex per well ($MM) 4.2 2P Reserve Estimate (Mboe) 290 IP (1 mo) (boe/d) 375 IP (12 mo) (boe/d) Half Cycle Economics (C$3/GJ) Cdn$95/bbl Cdn$85bbl IRR (% AT) 64% 50% Recycle Ratio Months Oil COND NGL Gas All economics run at FLAT price forecasts with C$85/bbl Edm MSW and $3/GJ AECO Liquid yield assumptions: Condensate 9 bbl/mmcf, NGL 24 bbl/mmcf Reserves estimate breakdown: 124 mbbls oil, 31 mbbls NGL/Condensate and 0.9 bcf natural gas Assumed Cycle Time (from spud to on production): 4 months Decline curve is and internal estimate based on analog wells and reservoir modeling

61 Pembina Revitalizing a Mature Oil Field *Breakeven Cdn$ per bbl or mcf price as indicated defined as price at which NPV10 is equal to zero. *IRR Half cycle after tax rate of return based on C$85/bbl Edm MSW and C$3/GJ AECO. *Free Cash Flow Defined as Revenue royalties op costs - transportation costs capital expenditures (before land and net acquisitions). *F&D 2013 Finding and Development Cost before changes in future development capital.

62 SE Saskatchewan/Manitoba Solid Long Life Assets *Breakeven Cdn$ per bbl or mcf price as indicated defined as price at which NPV10 is equal to zero. *IRR Half cycle after tax rate of return based on C$85/bbl Edm MSW and C$3/GJ AECO. *Free Cash Flow Defined as Revenue royalties op costs - transportation costs capital expenditures (before land and net acquisitions). *F&D 2013 Finding and Development Cost before changes in future development capital.

63 Financial Strategy

64 Financial Strategy Financial Flexibility Provides Optionality

65 Priority Sustainability Balancing Inflows and Outflows for Long-Term Sustainability Objective to fully fund ARC's Dividend and Sustaining Capital from Funds from Operations ( FFO ) over the long-term Profitable Growth Capital will be funded from remaining FFO and other sources $6,000 5 Year Total Inflows & Outflows ($millions) FFO DRIP/SDP Debt Divests Equity $4,000 Other DRIP/SDP Growth Capital 3 Sustaining Capital 2 $2,000 FFO Dividends 1 $0 *Sustaining and growth capex is before land and net acquisitions Inflows Outlows

66 $ Billions Multiple Sources of Debt Significant Available Credit Capacity of ~$1.1 Billion $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 $2.1 Billion Total Credit Capacity ($1.1 Billion Available) Master Shelf LT Notes Credit Facility Capacity Drawn Available Bank Credit Facility $1 Billion credit facility plus $40 million working capital facility 12 banks including the five largest Canadian banks Long-term notes Private Placement market Notes are rated NAIC 2 Prudential Master Shelf Currently have US$238 million drawn out of capacity of US$350 million As of September 30, 2014 Assumes USDCAD of $ Credit facility in graph includes $40 million working capital facility Working Capital Deficit not included

67 Summary

68 Value Proposition Clear Line of Sight to Long-term Value Creation

69 Forecast Looking Beyond 2016 Diverse Portfolio Provides Strategic Optionality ARC has a well balanced inventory of value creating opportunities which may be pursued beyond , , ,000 80,000 Project Options Dawson Phase 3 Pouce Commercialization Ante Creek Expansion Sunrise Phase 2 60,000 40,000 20,000 0 Non-Montney Liquids Montney Liquids Non-Montney Gas Montney Gas Attachie Commercialization Septimus Commercialization Parkland/Tower Phase 2 Pembina Waterflood and EOR Redwater and/ or SE Saskatchewan EOR

70 APPENDIX

71 Crude Oil Marketing 96% Condensate, Light and Medium Crude Oil Maintain control into liquid market hubs to ensure flexibility and optimize price Secured firm transportation pipeline agreements to support future development Purchasers 36% 23% Sweet Sour C5+ Heavy BR North/South Processing & Infrastructure 41% Financial Institution Production Producer & Physical Marketer Pembina P/L Edmonton Hardisty Regina Cromer 3% 12% 19% 29% 18% 18% Midale Fosterton/BR Sweet Sour LSB C5+

72 Natural Gas Commodity Marketing Diversified Sales Point and Purchasers of ARC s Natural Gas Sales are typically 70%/30% monthly/daily dependent upon operations and market environment Secured adequate take-away to support development until 2019 Destination 7% 70% 23% Station 2 Chicago AECO Purchasers 2% 56% 42% Processing & Infrastructure Financial Institution Producer & Physical Marketer

73 Capacity (bbl/d) NGL Commodity Marketing NGL Pipeline & Fractionation Capacity Secured ARC s NGL Exposure NGL revenue (~5,000 bbl/d) makes up approximately 4% of ARC s revenue Ensuring NGL production moves to market protects ARC s oil & gas production Planned Capacity Expansions Infrastructure players have announced pipeline take-away and fractionation expansions to alleviate congestion ARC has committed to long-term transportation and fractionation contracts to support future development NGL Mix 3% 250,000 Existing Fractionation Capacity & Expansions 44% 28% 200, ,000 Existing Capacity Capacity Expansions 100,000 25% 50,000 C2 C3 C4 C5 0 Pembina Redwater Dow Fort Keyera Fort Plains Fort Saskatchewan Saskatchewan Saskatchewan Aux Sable (Chicago) Source: Company Reports and RBC Capital Markets

74 Hedge Positions November 5, 2014 Active Hedging Program Supports Business Plan Crude Oil (2) WTI: (US$/bbl) Summary of Hedge Positions as at November 5, 2014 (1) Remainder of US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d Ceiling $ ,000 $ ,975 $ - - $ - - $ - - Floor $ ,000 $ ,975 $ - - $ - - $ - - Sold Floor $ ,000 $ ,984 $ - - $ - - $ - - Crude Oil MSW (Differential to WTI) (3) (US$/bbl) bbl/d (US$/bbl) bbl/d (US$/bbl) bbl/d (US$/bbl) bbl/d (US$/bbl) bbl/d Swap ($5.66) 2,663 $ - - $ - - $ - - $ - - Natural Gas (4) - Nymex: (US$/mmbtu) US$/ Mmbtu mmbtu/d US$/ mmbtu mmbtu/d US$/ mmbtu mmbtu/d US$/ mmbtu mmbtu/d US$/ mmbtu mmbtu/d Ceiling $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 Floor $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 Natural Gas Basis (5) : (US$/mmbtu) AECO/ Nymex mmbtu/d AECO/ Nymex mmbtu/d AECO/ Nymex mmbtu/d AECO/ Nymex mmbtu/d AECO/ Nymex mmbtu/d Swap (% of NYMEX) 89.8% 190, % 135, % 130, % 50, % 9,918 Foreign Exchange (000s): C$/US$ C$/US$ US$ C$/US$ US$ C$/US$ US$ C$/US$ US$ C$/US$ US$ Ceiling , , Floor , , ) The prices and volumes in this table represent averages for several contracts representing different periods. The average price 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 Note 8 Financial Instruments and Market Risk Management in the financial statements for the three and nine months ended September 30, ) The crude oil prices in this table are referenced to WTI. For 2014, all floor positions settle against the monthly average WTI price. Positions establishing the ceiling have been sold against the monthly average WTI price. 3) MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton, calculated on a monthly weighted average basis. 4) The natural gas prices in this table are referenced to NYMEX at Henry Hub. 5) ARC sells the majority of its natural gas production based on AECO pricing. To reduce the risk of weak basis pricing (AECO relative to NYMEX) ARC has hedged a portion of production by tying ARC's price to a percentage of the NYMEX natural gas price.

75 Reserves and Resources Disclosure All reserves and resources volumes for the BC Montney and elsewhere in this presentation are, unless indicated otherwise, as at December 31, 2013 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 zero percent porosity cut-off for gas and a 3% cutoff for oil. This means that all gas bearing rock has been incorporated into the calculations. Reserves volumes for the BC Montney and elsewhere in this presentation are, unless indicated otherwise, Proved plus Probable, while the resource categories for the BC Montney in this presentation are best estimates. All reserves and resources volumes for the 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. TPIIP and DPIIP include 0.7 Tcf of solution gas associated with Tower oil. The liquid yields are based on average yield over the producing life of the property. The oil DPIIP is a stock tank barrel. All DPIIP and TPIIP other than cumulative production, reserves, Economic Contingent Resources and Prospective Resources have been categorized as unrecoverable. The amount of natural gas and liquids ultimately recovered from ARC s BC Montney resource will be primarily a function of the future price of both commodities.

76 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. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible 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 discovered petroleum initially in place 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. Forecast

77 Definitions of Oil and Gas Reserves and Resources Economic Contingent Resources ( ECR are those contingent resources which are currently economically recoverable. 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 undiscovered petroleum initially in place 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 Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources as follows: Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. Best Estimate: This 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 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. Forecast It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

78 This presentation contains forward-looking 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 Forward Looking Statements at the beginning of the presentation and also to the November 5, 2014 news release titled ARC Resources Ltd. Announces an $875 Million Capital Program For 2015 and Sets The Stage for Continued Profitable Growth Beyond 2015 which may be found 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 please visit our website Or contact: Investor Relations ir@arcresources.com T F Toll Free ARC Resources Ltd. 1200, Avenue S.W. Calgary, AB T2P 0H7