Investor Presentation

Transcription

1 Investor Presentation January, 2016

2 1/4/2016 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, 2016 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 and 2016 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 ("boe"). Boe 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. Value Proposition Clear Line of Sight to Long-term Value Creation Dividend + Profitable Growth = Value Creation CREATING VALUE Growth & Income Cost Management & Capital Discipline Exposure to Early Stage Development of World Class Assets Strategic Optionality Strong Balance Sheet Technical Expertise Responsible Development 1

3 1/4/2016 Unique Strategy Risk Managed Value Creation is Central to ARC s Strategy Targeting net debt to funds from operations between x Operating costs reduced by ~30% since 2009: $10.19/boe in 2009 $7.18/boe in Q >200% Reserve Replacement through the drill bit for the past 7 consecutive years Highly skilled team of 570 employees with proven ability to execute Corporate Profile Corporate Summary Production (Q3 2015) Reserves (2P Gross YE 2014) (1) 107,261 boe/day 673 MMboe Reserve Life Index (2P) (1) 16 years (2) Annualized Dividend $1.20 per share Annualized Returns (3) Since Inception 14% Market Summary Ticker Symbol TSX: ARX Average Daily Volume 2 million (4) Shares Outstanding 347 million Enterprise Value $6.8 billion (5) Total Net Debt $981.1 million (5) Net Debt to Funds from Operations 1.3 times (6) 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 2015 production guidance midpoint of 114,500 boe/day. (3) Annualized total return to December 31, 2015, including November dividend, and assuming reinvestment of dividends in ARC shares. (4) Daily average trading volume for the trailing six month period ended December 31, (5) Market Capitalization as at December 31, 2015 and Net Debt as at September 30, (6) Based on Q Funds from Operations and Net Debt as at September 30,

4 boe/day Forecast 1/4/2016 Risk Managed Value Creation Montney Assets Have Delivered Long-Term Profitable Growth and Value 140,000 Production Profile 120, ,000 80,000 60,000 40,000 20,000 0 Non-Montney Liquids Montney Liquids Non-Montney Gas Montney Gas Reserve Replacement 200% or Greater Reserve Replacement Over the Past Seven Years Montney assets have been the centrepiece to ARC s strategy of organic reserves and resources growth and provide continued upside potential 3

5 Decreasing Priority Cumulative Dividends ($ billions) Payout Ratio 1/4/2016 Committed to a Dividend ARC Has Always Paid a Dividend While Delivering Profitable Growth 14% annualized total return since inception, ~$5.6 billion of dividends ($32.08/share) 6 Cumulative Dividends and Historic Payout Ratio 120% 5 100% 4 80% 3 60% 2 40% 1 20% YTD 2015 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 December 31, 2015, including November dividend, and assuming reinvestment of dividends in ARC shares. 0% Priorities 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, DRIP/SDP proceeds, and equity proceeds Sustaining and growth capital expenditures are before land and net acquisitions. 4

6 $/boe 1/4/2016 Sustaining Capital Superb Capital Efficiencies Drive Low Sustaining Capital Requirements ~120,000 boe/day Forecast Production ~25,000 boe/day Non-Montney Corporate/Other (Maintenance, Exploration, Optimization) Ante Creek ~$450MM Forecast Sustaining Capital $150MM (Capital Efficiency: ~$24,000/boe/day) $50MM Sunrise ~95,000 boe/day Parkland/Tower $250MM (Capital Efficiency: ~$10,000/boe/day) Dawson Operating Efficiencies ARC Continues to Drive Down Operating Costs as It Grows in the Montney Total per boe operating costs have decreased ~20% (2010 to 2015 YTD) Montney per boe operating costs have decreased ~25% (2010 to 2015 YTD) Owned and operated facilities allow ARC to realize low operating costs and maximize operational efficiencies Operating Costs ($/boe) YTD Total Non-Montney Montney 2015 YTD Operating costs represent data for the nine months ended September 30,

7 Mcf/day 1/4/2016 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 Three Year FD&A peer group includes: BNP, BTE, CPG, ERF, PGF, POU, TOU, VET. YTD 2015 Operating Costs peer group includes: BNP, BTE, CPG, ERF, PEY, PGF, POU, PWT, TOU, VET, WCP. (1) Three year 2P FD&A includes future development capital ( FDC ). Source: Peters & Co Reserves Comparison March 31, (2) See ARC s press release issued on February 11, 2015 relating to its 2014 year-end reserves for information relating to ARC s finding and development costs. (3) Operating costs from EssentialEnergy (CanOils) and company reports and represent data for the nine months ended September 30, Growing Our Low Cost Gas Business ~14% CAGR (1) Total Natural Gas Production Forecast ARC divested of certain non-core, non-montney shallow gas assets in 2014 and 2015 with associated production of approximately 4,800 boe/day 500, , ,071 Net Gas Wells Natural Gas Production Net Gas Wells 300, ,000 Montney Gas A combined 4,800 boe/day of non-core shallow gas divested in transactions in 2014 & 2015 Forecast Montney Gas 27% CAGR F 100,000 Non-Montney Gas (F) 2016 (F) (1) Compound annual growth rate. Non-Montney Montney 6

8 1/4/2016 Long-Term Value Creation Clear Line of Sight to Future Value Creation Growing Profitable Production Investing in Strategic Long- Term Infrastructure Advancing Technology Unlocking Value Accretive Acquisitions and Divest of Non- Core Assets 113, ,000 boe/d 119, ,000 boe/d New Sunrise Facility, Tower Liquids Handling Design/Planning and Construction of New Dawson Facility (on-stream late 2017) Advance Attachie, Lower Montney Pilots & Development Continue to Optimize Completions Continuous Efficiency Improvements Added ~200 net Montney sections Divested 3,600 boe/d (75% non-core gas) ~124,000 boe/d Accretive land and tuck-in acquisitions and divest of non-core assets Dawson, Sunrise, Parkland/Tower, Ante Creek, Attachie Potential Ante Creek, Sunrise or Parkland Expansion Montney Assets 7

9 1/4/2016 Our Conviction in the Montney Strengthens Strong Value Creation Continuous improvement in well production performance Multiple layer development drives operational efficiency Diverse product mix allows optionality Huge long-term growth potential in all commodities Continued profitability in today s economic environment Montney Bakken Marcellus & Utica Haynesville Eagleford Montney Growth Assets ARC s Core Montney Properties Three Super Areas Proximity of ARC Montney landbase within Super Areas enables: Capital & Operating Efficiencies Application of Learnings across Areas Greater Flexibility in Transportation and Marketing Agreements 8

10 Lower Montney Upper Montney 1/4/2016 Montney Infrastructure Dual-Connected ARC Facilities Allow for Takeaway Optionality TCPL Spectra Alliance TCPL Proposed Area is currently well served with three major pipelines providing access to North American markets ARC s primary properties are situated in the heart of the region to be serviced by the pipelines Multiple Layers to Develop Significant Future Delineation Opportunities Attachie Septimus Sunrise Tower Parkland Dawson Pouce Coupe Montney A Montney B Montney C Montney D Montney E Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells 9

11 1/4/2016 NE BC Montney Schematic Multiple Layers, Multiple Targets, Massive Opportunity Not to scale. NE BC Montney Reserves & Resources NE BC Montney TPIIP 67.4 Tcf of Gas and 2.3 Billion Barrels of Oil 2014 Resource evaluation conducted by GLJ saw significant growth in Gas TPIIP, which is mainly attributed to newly-acquired land in Pouce Coupe, Sundown and Dawson. 14% 2.5 Tcf (2.2) 11% 4.9 Tcf (4.5) 2P RESERVES ECONOMIC CONTINGENT RESOURCE OIL 14.5 MMbbl (11.2) NGLs 29.5 MMbbl (27.2) OIL 35.2 MMbbl (10.7) NGLs MMbbl (116.5) 15% 40% 37% 5.3 Tcf (3.9) PROSPECTIVE RESOURCE NGLs MMbbl (114.1) 38% 16% 35.4 Tcf (30.4) DISCOVERED PETROLEUM INITIALLY IN PLACE OIL 1.8 billion barrels (1.7) 5% 22% 67.4 Tcf (55.1) TOTAL PETROLEUM INITIALLY IN PLACE OIL 2.3 billion barrels (2.2) 7% GAS (2013 Reserves and Resources are indicated in brackets.) LIQUIDS *Total Petroleum Initially in Place (TPIIP) and Discovered Petroleum Initially in Place (DPIIP) estimates for 2014 were determined using a 1% porosity cut-off for gas; 2013 estimates were determined using a 0% porosity cut-off for gas. Estimates for both 2014 and 2013 were determined using a 3% porosity cut-off for oil. (1) Independent Resources Evaluation conducted by GLJ effective December 31, (2) Economic Contingent Resource, Prospective Resource, DPIIP and TPIIP quoted are all Best Estimate case. 10

12 1/4/2016 Montney Development Economics Strong Rates of Return Across the Montney Portfolio Tower Dawson Sunrise Ante Creek Half Cycle Economics C$55/bbl MSW C$3/GJ AECO 45% IRR 2.6x Recycle Ratio $30/bbl Breakeven 100% IRR 5.2x Recycle Ratio $1.25/Mcf Breakeven 60% IRR 5.6x Recycle Ratio $1.60/Mcf Breakeven 35% IRR 3.2x Recycle Ratio $30/bbl Breakeven Economics run at flat price forecasts with Cdn$55/bbl Edmonton Sweet (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. Recycle ratio is calculated using first 12 months of undiscounted netback divided by F&D. North American Gas Plays Supply Costs Montney is Extremely Competitive Against Other North American Gas Plays Source: RBC Capital Markets Montney Evolution Playing the Long Game October % before-tax IRR assumes US$/Cdn$ is 0.83, US$0.75/MMbtu AECO basis, 20:1 liquids to gas ratio. 11

13 1/4/2016 Tower is Among the Best Oil Plays Strong Oil Economics at Tower Source: CIBC reports, CIBC World Markets Inc. Dawson Heart of the Montney Low Cost Gas Op Cost F&D $3.84/boe $0.65/Mcf Capital Efficiency $5,000/boe/day Superior Economics 100% IRR C$55/bbl & C$3/GJ Breakeven Price $1.25/Mcf Significant Resource 13.7 Tcf of gas resource IRR Half cycle after-tax rate of return based on Cdn$55/bbl Edmonton Sweet (MSW) and Cdn$3/GJ AECO. Breakeven pricing is Cdn$ per bbl or Mcf price as indicated, and defined as price at which NPV10 is equal to zero. F&D 2015 Finding and Development Cost before changes in future development capital. Significant Resource TPIIP as per 2014 year-end GLJ report based on 1% porosity cut-off see See Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this presentation. 12

14 $ millions MMcfe/day Wells 1/4/2016 Dawson Development Potential Additional Development Layer Below Core Acreage Dawson Upper Montney 99 Hz s drilled 600 Drilling Inventory Upper Montney A Booked Reserves* Lower Montney 5 Hz s drilled Lower Montney Booked Reserves* *Sections with 2P Reserves booked as of YE Wells Drilled to YE2014 Drilling Inventory at YE2014 Internally identified future locations ECR locations 2P booked locations Wells drilled to YE2014 Dawson A Cash Flow Machine Low Reinvestment Ratio to Maintain Significant Free Cash Flow Field Netback ($ millions) Capital Expenditures ($ millions) Free Cash Flow ($ millions) Production (MMcfe/day) (50) F 0 (50) (100) (100) $3.79 $3.44 $2.27 $3.00 $4.19 $2.64 AECO Cdn$/GJ $80 $95 $94 $98 $93 $50 WTI US$/bbl 2015 Forecast based on actuals for first nine months of 2015 and forecast for Q based on forward price curve as at October 19,

15 Production Rate (Mcf/day) 1/4/2016 Dawson Gas Type Curve Growth Continuous Improvement in Well Performance 7,000 6,000 5, Type Curve 2013/2014 Type Curve Forecast Key Metrics 2016 Budget DCET Capex/well ($ millions) 4.2 Internal 2P Reserves (Bcfe) 7.4 IP (1 mo) (MMcf/day) 6.2 4,000 3,000 IP (12 mo) (MMcf/day) 5.4 Half Cycle Economics C$55/bbl & C$3/GJ IRR (%AT) 100% 2,000 1, Months Type curves are internal estimates based on analog wells and reservoir modeling. Assumed cycle time (from spud to on production): 4 months. Dawson Natural Gas Liquids Potential Finding Higher Liquids With Move Away from Dawson Core 15 bbl/mmcf 30 bbl/mmcf Wellhead Condensate (after 9 months of production) 30 bbl/mmcf 30 bbl/mmcf 10 bbl/mmcf Upper Montney A liquids yield based upon cold plant design Lower Montney condensate production at wellhead 20 m pay at 6% porosity cut-off 70 bbl/mmcf Wellhead Condensate (after 4 months of production) 25 bbl/mmcf 20 bbl/mmcf Liquid ratio at Dawson varies across Upper and Lower Montney Majority of development to-date focused on the core of the Upper Montney A, which has lower liquids yields (core is defined by yellow contours on map) New gas plant planned for 2017 will support development of Upper Montney outside of core and Lower Montney both have higher liquids yields 14

16 1/4/2016 Dawson Phase III Plant Full Regulatory Approval Obtained in Q Dawson Phase III Sour Gas Plant with 90 MMcf per day of gas and 7,500 barrels of liquidshandling sales capacity approved by the BC Oil and Gas Commission in September Design and planning of the plant is on-going, with procurement of long-lead equipment commenced in Q Total gas processing capacity in Dawson is expected to be 255 MMcf per day and over 8,500 barrels per day of liquids-handling once the plant is built Dawson Phase III Project Economics From Well Economics to Project Economics Well Economics Include drill, completion, wellsite equipment and pipeline from well to gathering system Standalone after-tax economics*: IRR = 100%, Recycle Ratio = 5.2 Project Economics Facility, sales line and all associated capital, including timing of capital spend Well economics as above built in, using appropriate timing and facility constraints Assumes the plant is kept full for 10 years Standalone after-tax economics*: IRR = 20%, Recycle Ratio = 3.1 Economics quoted above run at Cdn$55/bbl Edmonton Sweet (MSW) and Cdn$3/GJ AECO flat pricing. 15

17 Wells 1/4/2016 Parkland/Tower Significant Value Creation Strong Economics 45% IRR (Tower) C$55/bbl & C$3/GJ Three Layer Development Lower Montney Pilot well on-stream Growth Driver 95% Forecast YoY 2016 liquids growth Liquids Growth Doubled oil handling capacity in Q Exceptional Results 7 wells with over 100,000 barrels of cumulative oil production in under a year Breakeven Price $30/bbl (Tower) IRR Half cycle after-tax rate of return based on Cdn$55/bbl Edmonton Sweet (MSW) and Cdn$3/GJ AECO. Breakeven pricing is Cdn$ per bbl or Mcf price as indicated, and defined as price at which NPV10 is equal to zero. F&D 2015 Finding and Development Cost before changes in future development capital. Parkland/Tower Development Potential Incremental Reserves Potential with Multilayer Development Upper Montney Upper Montney A Booked Reserves* Tower 42 Hz s drilled Parkland 70 Hz s drilled Lower Montney Upper Montney A+ Booked Reserves* Tower 18 Hz s drilled Parkland 15 Hz s drilled Lower Montney Booked Reserves* Tower No Hz s drilled Parkland 1 Hz drilled *Sections with 2P Reserves booked as of YE

18 Cumulative Production Increasing Cumulative boe Cumulative bbl 1/4/2016 Tower Cumulative Production Continuous Improvement in Type Curve Cumulative oil production from nine 2014 wells approaching one million barrels Total Production Oil Production 280, , , , , , , , , , Type Curve 2016 Type Curve 100, , , Type Curve 80, Type Curve 100,000 60,000 80,000 60, Type Curve 2014 Type Curve 40,000 40,000 20, Days On 20, Pad (2014) 8-15 Pad (2014) Days On Type curves are based on internal estimates based on analog wells and reservoir modelling. Tower Wells Deliver Outstanding Results ARC s Tower Wells Are Some of the Best in Western Canada Majority of wells never produce 100,000 barrels Source: AltaCorp Research. Days on Production Increasing 17

19 Depth (m) Production Production Rate Rate (boe/day) 1/4/2016 Tower Completions Advancement Advanced Completion Design = Improved Performance 1,400 1,200 1, Type Type Curve Curve 2015 Type Curve 2015 Type Curve 2016 Type Curve 2014 Type Curve Key Metrics 2016 Budget DCET Capex/well ($ millions) 5.5 Internal 2P Reserves (Mboe) 600 IP (1 mo) (boe/day) 1,200 IP (12 mo) (boe/day) 540 Half Cycle Economics C$55/bbl & C$3/GJ IRR (%AT) 45% Months Type curves are internal estimates based on analog wells and reservoir modeling. Assumed cycle time (from spud to on production): 5 months Budget type curve based on 1,500 m lateral length. Tower Drilling Curves ~25% Reduction in Drill Times = ~30% Cost Savings at Tower Pads Best Well 8-24 Pad Average Pad Average (Horizon 50) Industry Offset 1 Industry Offset 2 30% cost savings and 25% reduction in drilling time over previous Tower pads Realizing reduced drill days and cost savings in the last 6 months from re-engineering and optimization of drilling operations The efficiencies that are realized will remain, despite movement in cost structure due to commodity price recovery 3000 Q Q % Reduction in Overall Drill Times Days From Spud 18

20 Wells 1/4/2016 Sunrise Long-term Growth Opportunity Significant Resource 6.6 Tcf of gas resource Strong Economics 60% IRR C$55/bbl & C$3/GJ Four Layer Development Currently producing from all four layers 2015 Growth Driver New 60 MMcf/day facility on-stream and at capacity Breakeven Price Low Cost Gas $1.60/Mcf Op Cost $0.50/Mcf F&D $0.48/Mcf IRR Half cycle after-tax rate of return based on Cdn$55/bbl Edmonton Sweet (MSW) and Cdn$3/GJ AECO. Breakeven pricing is Cdn$ per bbl or Mcf price as indicated, and defined as price at which NPV10 is equal to zero. F&D 2015 Finding and Development Cost before changes in future development capital. Significant Resource TPIIP as per 2014 year-end GLJ report based on 1% porosity cut-off see See Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this presentation. Sunrise Development Potential Proven Productivity from Four-Layered Development 21 Hz s drilled Drilling Inventory Upper Montney A Booked Reserves* Upper Montney Upper Montney A+ Booked Reserves* 12 Hz s drilled Lower Montney Upper Montney B Booked Reserves* Lower Montney Booked Reserves* 11 Hz s drilled 2 Hz s drilled Wells Drilled to YE2014 Drilling Inventory at YE2014 Internally identified future locations ECR locations 2P booked locations Wells drilled to YE2014 *Sections with 2P Reserves booked as of YE

21 Gas Rate (Mcf/day) Gas Rate (Mcfd) 1/4/2016 Sunrise Outperforming Expectations Drilling Results Continue to Reaffirm Four-Layer Development Model 10,000 9,000 8,000 7,000 6, /16 Upper MTY Type Curve (11.7 Bcf) 2013/14 Type Curve (11 Bcf) W6 (08-24Hz) Upper MTYA (C09-13Hz) Upper MTYA+ 02/ W6 (B02-25Hz) MTYB 102/ W6 (B08-24 ) Lower Montney 5,000 4,000 3,000 2,000 1,000 Type curve is an internal estimate based on analog wells and reservoir modelling. Days On ,000 C09-13Hz (Lower MTYA): was restricted after about 3 months on production due to capacity constraints B08-24 (MTYD2): going forward will target tighter interfrac spacing in the Lower Montney than was achieved on the B08-24 well Sunrise Continuous Improvements Enhanced Well Design = Type Curve Improvement 7,000 6,000 5, Type Curve (11.5 Bcf) 2013 Type Curve (11 Bcf) 2011 Type Curve (7 Bcf) Key Metrics 2016 Type Curve DCET Capex/well ($ millions) 5.4 Internal 2P Reserves (Bcfe) 11.5 IP (1 mo) (MMcf/day) 6.2 4,000 3,000 IP (12 mo) (MMcf/day) 5.4 Half Cycle Economics C$55/bbl & C$3/GJ IRR (%AT) 60% 2,000 1, Days On Type curves are internal estimates based on analog wells and reservoir modeling. Assumed cycle time (from spud to on production): 4 months. 20

22 1/4/2016 Sunrise Phase II Project Economics From Well Economics to Project Economics Well Economics Include drill, completion, wellsite equipment and pipeline from well to gathering system Standalone after-tax economics*: IRR = 60%, Recycle Ratio = 5.6 Project Economics Facility, sales line and all associated capital, including timing of capital spend Well economics as above built in, using appropriate timing and facility constraints Standalone after-tax economics*: IRR = 20%, Recycle Ratio = 3.8 Economics quoted above run at Cdn$3/GJ AECO. Strategic Montney Infrastructure Building Montney Infrastructure to Support Resource Development Tower Battery October 2015 Parkland Gas Plant On-Stream 2013 Dawson Gas Plant Phase I: On-Stream 2010 Phase II: On-Stream 2011 Dawson Phase III Coming 2017 Ante Creek Gas Plant Commissioned 2012 Sunrise Plant Commissioned August

23 1/4/2016 Greater Dawson Montney Pilots Proving Future Value Before Full-Scale Development Septimus Pilot production on-stream since Q Pouce Coupe Lower Montney pilot production on-stream since late 2013 Parkland Lower Montney well on-stream since Q Dawson Two Lower Montney wells drilled in Q Upper Montney Pilot Wells Lower Montney Pilot Wells Greater Dawson Lower Montney Fairway Building Understanding of the Lower Montney Fairway Parkland Dawson 1-17 Pouce 1-15 Dawson 8-1 Sunrise C2-25 Sunrise B8-24 Only Lower Montney wells are displayed. 22

24 1/4/2016 Attachie Pilots Continued Evaluation on Liquids-Rich Land Two pilot horizontal wells on western side of lands have produced 1.4 Bcf of gas and 130 Mbbl of liquids in 18 months NGLs yield up to 25 bbl/mmcf dependent on plant design; free condensate gas ratio of bbl/mmcf Acquired 89 net sections at Attachie in Q2 2015, increasing ARC s total Attachie land position to 279 net sections ARC has drilled three wells on newly acquired lands in H West Attachie Pilot production onstream since Q Attachie West Montney Pilot Wells 23

25 1/4/2016 Financial Strategy Financial Discipline Provides Optionality FINANCIAL DISCIPLINE Strong Balance Sheet & Simple Capital Structure Stable and Meaningful Dividend Prudent Funding of Capital Programs Opportunistic Acquisitions and Non-Strategic Divestitures Manage Risk and Preserve Optionality Balance Sheet Strength Targeting Net Debt to Funds from Operations Between x (1) $180M Ante Creek acquisition in December 2009 was financed by $240M equity issuance that closed in January (2) 2015F Net Debt and 2015F FFO based on consensus of 13 Analysts as of November

26 1/4/2016 Profitable Investment Managing a Profitable Business Through Cycles ARC s high-quality assets, excellent capital efficiencies, and low operating costs have resulted in strong returns over the long term ARC has realized earnings of ~$4 billion since inception As a result of commodity price weakness in 2015, ARC has recorded a net loss of ~$290 million year-to-date (at September 30, 2015) Significant Liquidity Q Net Debt and Cash Balance $2.5 Billion Total Cash & Existing Credit Capacity ($1.4 Billion Available) Long-term Notes $800MM Master Shelf $292MM Cash $205MM Undrawn Master Shelf $177MM Undrawn Credit Facility $1,040MM Bank Credit Facility $1 billion credit facility plus $40 million working capital facility Currently undrawn 12 banks included in syndicate Credit facility matures in 2019 Long-term Notes Private Placement market Notes are rated NAIC 2 Prudential Master Shelf US$218 million currently drawn out of capacity of US$350 million As of September 30, Assumes US$/Cdn$ of $ Credit facility in graph includes $40 million working capital facility. Non-Cash Working Capital not included. 25

27 $ millions 1/4/2016 Hedging Program Results Hedging Continues to Smooth Cash Flow Volatility ARC s hedging program continues to provide greater certainty of cash flows and supports the business plan Crude Oil Natural Gas Foreign Exchange & Power Total Realized Hedging Gains (Losses) (50) F 2016F 2017F 2018F 2019F WTI $62 $80 $95 $94 $98 $93 $49 $47 $51 $53 $56 US$/bbl AECO $3.91 $3.79 $3.44 $2.27 $3.00 $4.19 $2.61 $2.35 $2.74 $2.91 $3.04 Cdn$/GJ 2015 Forecast based on actuals for first 11 months of 2015 and forecast for December 2015 based on the forward price curve as at November 30, 2015 and net of credit adjustment to 2019 Forecast values based on the forward price curve as at November 30, 2015 and net of credit adjustment. Realized pricing is based on annual average settlements and forecasted pricing is the annual average prices based on the forward price curve as at November 30, See ARC s Financial Statements and Notes and MD&A for additional details on hedging program results as well as current hedge positions. ARC s power hedge positions at November 30, 2015 include heat rate swaps to December 2017 (20 MWh at a heat rate of approximately GJ/MWh) as well as fixed rate swaps to December 2016 (5 MWh at approximately $51.00/MWh). 26

28 Forecast boe/day Forecast Forecast 1/4/2016 Looking Beyond 2016 Diverse Portfolio Provides Strategic Optionality ARC has a well balanced inventory of value creating opportunities which may be pursued beyond , ,000 Production Profile Project Options Dawson Phase III 100,000 Pouce Commercialization 80,000 60,000 Forecast Ante Creek Expansion Sunrise Phase II 40,000 Attachie Commercialization 20,000 0 Septimus Commercialization Parkland/Tower Phase II Dawson Phase IV Non-Montney Liquids Montney Liquids Non-Montney Gas Montney Gas Pembina Waterflood and EOR Redwater and/or SE Saskatchewan EOR 27

29 1/4/2016 Q Operational and Financial Performance Strong Production and Financial Results Three Months Ended September 30 Nine Months Ended September 30 (Cdn$ millions, except per share and per boe amounts) Production (boe/d) Gas Liquids Commodity Revenue Gas Liquids Funds from operations Per share Dividends Per share 107,261 66% 34% % 58% ,530 61% 39% % 67% ,457 65% 35% % 60% ,501 60% 40% 1, % 67% Capital expenditures, before land and net property acquisitions/dispositions Net debt outstanding , ,152.8 Weighted average number of shares outstanding (millions) Netback (pre-hedging) and 2016 Guidance Focused on Value Creation 2015 Guidance (1)(2) 2015 YTD Actuals 2016 Guidance Oil (bbl/day) 33,500-34,500 32,379 34,500-36,500 Condensate (bbl/day) 3,400-3,800 3,363 3,200-3,600 Gas (MMcf/day) NGLs (bbl/day) 3,700-3,900 3,918 4,000-4,500 Total (boe/day) 113, , , , ,000 Operating expenses (3) Transportation expenses G&A expenses (4) Interest expenses Current Income Tax expense (per cent of Funds from Operations) (5) Capital expenditures before land and net property acquisitions (disposition) ($ millions) Net property and land acquisitions (dispositions) ($ millions) - (30.4) - Weighted average shares, diluted (millions) ) Incorporates impact of approximately 3,600 boe per day of divested non-core assets throughout 2015 (75 per cent natural gas), which has resulted in annual volume impactof approximately2,200 boe per day of production. 2) ARC expects an increase in fourth quarter 2015 production to a range of 118,000 to 122,000 boe per day following commissioning of the new Sunrise gas processing facility and expanded Tower oil battery. 3) Year-to-date actual results incorporates an impact of approximately $0.50 per boe due to a revision of estimates for prior period operating costs. 4) G&A expenses per boe are based on a range of $ $1.70 per boe prior to the recognition of any expense associated with ARC s share-based compensation plans and $ $0.60 per boe associated with ARC s share-based compensation plans. Actual per boe costs for each of these components for the nine months ended September 30, 2015 were $1.57 and $0.21 per boe, respectively. 5) The corporate tax estimate will vary depending on level of commodity prices. 28

30 1/4/2016 Natural Gas Commodity Marketing Diversified Sales Points and Purchasers of ARC s Natural Gas Secured firm transportation pipeline agreements to support existing production and future development until 2019 ~50% of Station 2 exposure mitigated in 2016 through physical diversification and basis hedges Destination 20% BRITISH COLUMBIA ALBERTA SASKATCHEWAN 7% 70% 23% 70% 10% Station 2 Chicago AECO Purchasers 3% 7% 49% 41% Processing & Infrastructure Producer & Physical Marketer Financial Institution End Users Crude Oil Commodity Marketing Focused on Condensate, Light and Medium Crude Oil Secured firm transportation pipeline agreements to support existing production and future development Maintain control into liquid market hubs to ensure flexibility and optimize price Purchasers 10% BRITISH COLUMBIA ALBERTA SASKATCHEWAN 37% 36% 23% 41% 53% Processing & Infrastructure Refining Production Producer & Physical Marketer 1% 12% 13% 17% 19% 18% 18% 29% 34% 17% 18% Midale Bow River Sweet Sour LSB C5+ 29

31 Cdn$/barrel 1/4/2016 NGLs Commodity Marketing NGLs Pipeline & Fractionation Capacity Secured ARC s NGLs Exposure NGLs revenue (4,000 bbl/day) makes up 1% of ARC s revenue Ensuring NGLs production moves to market protects ARC s oil and gas production ARC has committed to long-term transportation and fractionation contracts to support future development NGLs Pricing North American NGLs supply growth continues to put downward pressure on Canadian propane and butane prices ARC has mitigated weakness in propane prices by adjusting gas plant refrigeration systems at facilities to keep propane in the natural gas sales stream - optimizing the value of ARC s production NGLs Mix 1% 125 Canadian NGLs Pricing 37% 28% % C2 C3 C4 C5 (25) Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Propane Butane Condensate Hedge Positions November 4, 2015 Summary of Hedge Positions as at November 4, 2015 (1) Q Crude Oil Cdn$ WTI (2) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Ceiling , , , Floor , , , Swap , , Crude Oil - MSW (Differential (3) to WTI) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day Swap (4.81) 5,000 (3.78) 9, Natural Gas - NYMEX (4) US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day Ceiling , , , , ,000 Floor , , , , ,000 Swap , Natural Gas - AECO (5) Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Swap , Natural Gas - AECO Basis (6) AECO/NYMEX MMbtu/day AECO/NYMEX MMbtu/day AECO/NYMEX MMbtu/day AECO/NYMEX MMbtu/day AECO/NYMEX MMbtu/day Swap (percentage of NYMEX) 89.5% 160, % 140, % 140, % 85, % 40,000 US$ Millions US$ Millions US$ Millions US$ Millions US$ Millions Foreign Exchange Cdn$/US$ Cdn$/US$ Cdn$/US$ Cdn$/US$ Cdn$/US$ Total Total Total Total Total Ceiling Floor ) 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 Note 9 Financial Instruments and Market Risk Management in the financial statements for the three and nine months ended September 30, ) Crude oil prices referenced to WTI, multiplied by the Bank of Canada monthly average noon day rate. 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) Natural gas prices referenced to NYMEX at Henry Hub. 5) Natural gas prices referenced to AECO 7(a) index. 6) 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. 30

32 1/4/2016 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, 2014 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 1% cutoff for oil. 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. 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 31

33 1/4/2016 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. 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. Forecast 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 4, 2015 news release titled ARC Resources Ltd. Announces a $550 Million Capital Program For 2016 Focused on Continued Long-term Value Creation and Balance Sheet Strength 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 32

34 FINANCIAL AND OPERATIONAL HIGHLIGHTS FINANCIAL AND OPERATIONAL HIGHLIGHTS QUARTERLY HISTORICAL REVIEW ($ millions, except per share amounts) FINANCIAL Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Sales of crude oil, natural gas, condensate, NGLs and other income Per share, basic (1) Per share, diluted (1) Funds from operations (2) Per share, basic (1) Per share, diluted (1) Net income (loss) (235.0 ) (51.0 ) (1.7) Per share, basic (1) (0.69 ) (0.15 ) (0.01) Per share, diluted (1) (0.69 ) (0.15 ) (0.01) Dividends declared Per share (1) Total assets 6, , , , , , , ,736.0 Total liabilities 2, , , , , , , ,339.9 Net debt outstanding (3) , , , , ,011.5 Weighted average shares outstanding Weighted average shares outstanding, diluted Shares outstanding, end of period CAPITAL EXPENDITURES Geological and geophysical Drilling and completions Plant and facilities Administrative assets Total capital expenditures Undeveloped land purchased at Crown land sales Total capital expenditures including undeveloped land purchases Acquisitions Dispositions (20.7 ) (14.9 ) (11.0) (2.4 ) (5.1 ) (31.8 ) 0.5 Total capital expenditures, land purchases and net acquisitions and dispositions OPERATING Production Crude oil (bbl/d) 29,397 31,958 35,851 37,442 35,871 35,317 37,478 35,542 Condensate (bbl/d) 3,361 3,139 3,591 3,448 3,862 4,462 2,887 2,580 Natural gas (MMcf/d) NGLs (bbl/d) 3,653 3,795 4,314 5,075 5,056 4,179 3,743 2,868 Total (boe/d) 107, , , , , , , ,883 Average realized prices, prior to hedging Crude oil ($/bbl) Condensate ($/bbl) Natural gas ($/Mcf) NGLs ($/bbl) Oil equivalent ($/boe) TRADING STATISTICS ($, based on intra-day trading) High Low Close Average daily volume (thousands) 1,736 1,424 1,944 1,886 1,205 1,037 1,248 1,030 (1) Per share amounts (with the exception of dividends per share which are based on the number of shares outstanding at each dividend record date) are based on weighted average shares outstanding during the period. (2) Refer to the sections entitled "Funds from Operations" and Additional GAAP Measures contained within ARC s MD&A. (3) Refer to the sections entitled "Capitalization, Financial Resources and Liquidity" and Additional GAAP Measures contained within ARC s MD&A.

35 CORPORATE & SHAREHOLDER INFORMATION DIRECTORS EXECUTIVE OFFICE Hal Kvisle (3) (4) Chairman ARC Resources Ltd. 1200, 308 4th Avenue S.W. Calgary, Alberta T2P 0H7 T Toll Free F W E ir@arcresources.com Myron M. Stadnyk President and Chief Executive Officer John P. Dielwart (5) (6) Fred J. Dyment (2) (4) (6) Timothy J. Hearn (3) (4) (5) James C. Houck (1) (2) (6) TRANSFER AGENT Kathleen O Neill (1) (5) (6) Computershare Trust Company of Canada 600, 530 8th Avenue S.W. Calgary, Alberta T2P 3S8 T Herb Pinder (2) (3) (4) William G. Sembo (1) (2) Mac H. Van Wielingen (3) (4) (6) (1) Member of Audit Committee (2) Member of Reserve Committee (3) Member of Human Resources and Compensation Committee (4) Member of Policy and Board Governance Committee (5) Member of Health, Safety and Environment Committee (6) Member of Risk 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 David P. Carey Senior Vice-President, Capital Markets AUDITORS Deloitte LLP Calgary, Alberta ENGINEERING CONSULTANTS GLJ Petroleum Consultants Ltd. Calgary, Alberta LEGAL COUNSEL Burnet Duckworth & Palmer LLP Calgary, Alberta Bevin Wirzba Senior Vice-President, Business Development Kristen (Kris) Bibby Vice-President, Finance Jay Billesberger Vice-President, Information Technology Sean Calder Vice-President, Production Lara Conrad Vice-President, Engineering ARC is a CAPP member. Members commit to continuous improvement in the responsible management, development and use of our natural resources; protection of our environment; and, the health and safety of our workers and the general public. Neil Groeneveld Vice-President, Geosciences and Exploration Wayne Lentz Vice-President, Strategic Planning Karen Nielsen Vice-President, Operations Lisa Olsen Vice-President, Human Resources Grant Zawalsky Corporate Secretary ARC is listed on the Jantzi Social Index; a common stock index of 60 Canadian companies that pass a set of broadly based environmental, social and governance rating criteria. CORPORATE CALENDAR 2016 February 10, Year-End Results STOCK EXCHANGE LISTING The Toronto Stock Exchange Trading Symbol: ARX INVESTOR INFORMATION Visit our website at or contact: Investor Relations T or Toll Free