Investor Presentation

Transcription

1 Investor Presentation February, 216

2 2/11/216 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 216 and beyond, and related production expectations, costs and cash flow, expenses, our plans for constructing and expanding facilities, the volume of ARC's oil and gas reserves and the volume of ARC's 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 forwardlooking 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 216 Guidance, which is discussed quarterly, ARC does not undertake to update any forward looking information in this document whether as to new information, future events or otherwise except as required by securities laws and regulations. We have adopted the standard of 6 Mcf:1 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. Corporate Profile Corporate Summary Production (Q4 215) Reserves (2P Gross YE 215) (1) 119,243 boe/day 687 MMboe Reserve Life Index (2P) (1) 16 years (2) Monthly Dividend $.5 per share Annualized Returns (3) Since Inception 15% Market Summary Ticker Symbol TSX: ARX Average Daily Volume 2.2 million (4) Shares Outstanding 348 million Enterprise Value $6.9 billion (5) Total Net Debt $985.1 million (5) Net Debt to Funds from Operations 1.3 times (6) Member of TSX 6 (1) See Reserves and Resources Disclosure and Definitions of Oil and Gas Reserves and Resources in the Appendix to this Presentation. (2) Based on 216 production guidance midpoint of 118, boe/day. (3) Annualized total return to February 9, 216, including January dividend, and assuming reinvestment of dividends in ARC shares. (4) Daily average trading volume for the trailing six month period ended February 9, 216. (5) Market Capitalization as at February 9, 216 and Net Debt as at December 31, 215. (6) Based on 215 Funds from Operations and Net Debt as at December 31,

3 2/11/216 Unique Strategy Risk Managed Value Creation is Central to ARC s Strategy ARC delivered on its strategy in 215: Maintained net debt to funds from operations between target of x Completed Sunrise Gas Plant and Tower Oil Battery ahead of schedule Reduced operating costs and maximized efficiencies High-graded asset base as we continue our transition to the Montney Ensured the right people are in the right roles for long-term success 215 Highlights Year of Strong Performance in All Areas of the Business Full Year Review Annual average production of 114,17 boe/d (up 2% from 214) 19% production replacement adding 78.7 MMboe through the drill bit 687 MMboe of 2P Reserves (up 2% from 214) Funds from Operations of $2.27/share Financial Discipline Strong balance sheet and significant liquidity 1.3x Net Debt to Funds from Operations Invested only in highest rate of return projects Adjusted 215 capital program to realities of commodity price environment Proven Execution Completed Sunrise Gas Plant and Tower Battery Expansion New Tower oil wells matching rate of 1, bbl/d New Sunrise wells exceeding type curve Cost Management Decade-low operating costs of $7.15/boe for 215 F&D costs of $6.97/boe (2P reserves) and $8.2/boe (PDP) as a result of strong well performance and reduced capital costs Realized ~25% in savings from service cost reductions and efficiency gains High-grading Asset Portfolio Added ~21 net Montney sections Divested ~4,9 boe/d of non-core production 2

4 .8 x 1.6 x 1.7 x 2.2 x 2.2 x 2.3 x 2.9 x 3. x 3.1 x 3.3 x 3.7 x 3.9 x 4.4 x 4.5 x 4.7 x 4.9 x 5.2 x 5.3 x 5.5 x 5.6 x 5.7 x 6. x 6.1 x 6.6 x 7.2 x 7.5 x 7.8 x 11. x 1.1x 14.3 x 18.x 14.6 x 28.4x 29.4x 35.5x 16.2 x 16.3 x 1.1 x 1.3 x 1.6 x 1.6 x 1.8 x 1.8 x 1.9 x 1.9 x 2.4 x 2.6 x 2.6 x 2.7 x 2.7 x 2.8 x 2.8 x 2.8 x 3.1 x 3.4 x 3.4 x 3.5 x 3.6 x 3.7 x 4. x 4.2 x 4.3 x 4.3 x 4.5 x 5.8 x 6.9 x 7.4 x 8.6 x 13.1x 15.8x 14.6 x $ millions Ratio 2/11/216 Balance Sheet Strength Targeting Net Debt to Funds from Operations x for the Long Term During specific times, debt to FFO will trend towards a ratio of two times Expect debt to FFO to return to target range once normal pricing environment resumes 1,4 Net Debt to Funds from Operations 3. 1, , (1) Net Debt Funds From Operations Net Debt to Funds from Operations. (1) $18M Ante Creek acquisition in December 29 was financed by $24M equity issuance that closed in January E&P Leverage Analysis ARC Has One of the Strongest Balance Sheets in the Sector Canadian Benchmarking: 216E YE Net Debt / 216E Cash Flow (1)(2) Group Average ARC US Benchmarking: 216E YE Net Debt / 216E Cash Flow (1)(3) Group Average ARC Estimates as per RBC Research as of February 3, 216. (1) Assumes 216E WTI of US$4.28/bbl, Henry Hub of US$2.5/Mcfand Cdn$/US$ exchange rate of.72. (2) Includes intermediate and large cap Canadian E&Ps under RBC Research coverage. (3) Includes US E&Ps under RBC Research coverage. 3

5 2/11/216 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 215, ARC recorded a net loss of ~$34 million 25.% 2.% Return on Average Capital Employed ROACE Trailing Three-Year ROACE 15.% 1.% 5.%.% -5.% -1.% Shareholder Value ARC s Share Price Has Demonstrated Less Volatility Than Most of Its Peers 75% Share Price Volality 211 to 215 6% 45% Group Average 3% 15% % ARC Source: Scotiabank The Valuation Book Valuation, Risk, and Performance: Trauma, Prognosis, Recovery, and Implications Fourth Edition (February 216). 4

6 $ millions Decreasing Priority $ millions 2/11/216 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) 1 5 (5) F 217F 218F 219F 22F WTI $62 $8 $95 $94 $98 $93 $49 $41 $46 $5 $52 $54 US$/bbl AECO $3.91 $3.79 $3.44 $2.27 $3. $4.19 $2.63 $2.47 $2.78 $2.99 $3.26 $3.57 Cdn$/GJ 216 to 22 Forecast values based on the forward price curve as at December 31, 215 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 December 31, 215. 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 December 31, 215 include heat rate swaps to December 217 (2 MWh at a heat rate of approximately GJ/MWh) as well as fixed rate swaps to December 216 (5 MWh at approximately $51./MWh). 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 Debt Divests Equity $6, $4, Five Year Total Inflows & Outflows 211 to 215 Other DRIP/SDP Growth Capital 3 $2, FFO Sustaining Capital 2 Dividends 1 $ Inflows Outflows Sustaining and growth capital expenditures are before land and net acquisitions. 5

7 boe/day Forecast Cumulative Dividends ($ billions) Payout Ratio 2/11/216 Committed to a Dividend ARC Has Always Paid a Dividend While Delivering Value 15% annualized total return since inception, ~$5.7 billion of dividends ($32.18/share) Target is to continue to reduce ARC s payout ratio to 25-3% 6 Cumulative Dividends and Historic Payout Ratio 12% 5 1% 4 8% 3 6% 2 4% 1 2% % Cumulative Dividend Payout Ratio (before DRIP and SDP) Payout Ratio is calculated as dividends before DRIP and SDP as a percentage of Funds from Operations. Annualized total return to February 9, 216, including January dividend, and assuming reinvestment of dividends in ARC shares. Risk Managed Value Creation Montney Assets Have Delivered Profitable Growth and Value Quality assets and capital discipline has resulted in ~85% Montney production growth since , Production Profile 12, 1, 8, 6, 4, 2, Non-Montney Liquids (bbl/day) Montney Liquids (bbl/day) Non-Montney Gas (boe/day) Montney Gas (boe/day) 6

8 $/boe Recycle Ratio 2/11/216 Reserve Replacement ~2% Reserves Replacement for 8 th Consecutive Year Montney assets have been the centrepiece to ARC s strategy of organic reserves and resources growth and provide continued upside potential 7% Annual Produced Reserves Replacement Growth through Acquisition Organic Growth 6% 5% 4% 3% 2% 1% % Development Acquisitions Capital Efficiency Strong F&D Performance Growing our Montney Business at Low F&D Costs Low FD&A costs reflect high-quality assets, cost management and allocation of capital to high rate of return projects Three-year Average F&D and FD&A Costs (PDP) (1)(2) (Including FDC) FD&A F&D Recycle Ratio (1) Three-year average F&D and FD&A costs are calculated on proved developed producing gross reserves. (2) Recycle ratio based on three-year average F&D costs, including FDC, and three-year operating netbacks excluding hedging gains and losses. 7

9 Forecast Mcf/day $ per boe 2/11/216 Operating Efficiencies ARC Continues to Drive Down Operating Costs as It Grows in the Montney Total per boe operating costs have decreased ~3% (29 to 215) Montney per boe operating costs have decreased ~3% (29 to 215) Owned and operated facilities allow ARC to realize low operating costs and maximize operational efficiencies 2. Operating Costs ($/boe) Total Non-Montney Montney Growing Our Low Cost Gas Business ~13% CAGR (1) Total Natural Gas Production Forecast ARC divested of certain non-core, non-montney shallow gas assets in 214 and 215 with associated production of approximately 4,8 boe/day 5, 45, 29 3,71 Net Gas Wells Natural Gas Production Net Gas Wells 4, 35, 3, 25, 2, 15, 1, Montney Gas A combined 4,8 boe/day of non-core shallow gas divested in transactions in 214 & 215 Montney Gas 27% CAGR F 5, Non-Montney Gas F (1) Compound annual growth rate. 8

10 2/11/ Revised Budget $39 Million 216 Capital Budget Sustaining the Business Holding NE BC Facilities at Capacity Holding Parkland/Tower, Sunrise and Dawson facilities at capacity for 216 Investing for Future Growth Progressing Construction of Dawson Phase III Expected to be on-stream in late 217 Investment at Attachie Continue to delineate play with two drills at Attachie West and two appraisal wells at Attachie East Sustaining Capital Superb Capital Efficiencies Drive Low Sustaining Capital Requirements ~23, boe/day Non-Montney Corporate/Other (Maintenance, Exploration, Optimization) Ante Creek No capital allocated for drilling $5MM Sunrise ~95, boe/day Parkland/Tower $25MM (Capital Efficiency: ~$1,/boe/day) Dawson 9

11 2/11/216 Proven Development Model Inventory of Opportunities at All Stages Allows for Self-Funding and Full Cycle ROCE Growth for Future Phase Exploration Appraisal / Piloting Geographic and commodity diversity Development Phase Develop to Commercialize Exploit Parkland / Tower Optimization Maintenance Dawson Phases I & II Ante Creek Free Cash Flow Phase Redwater Southeast Saskatchewan Pembina Sunrise Free Cash Flow + Dawson Phase III Lower Montney Pouce Coupe Septimus Blueberry Sundown Attachie 216 Budget $135 million $25 million Growth Capital Total 216 capital budget includes $15 million of corporate capital. Sustaining Capital Montney Assets 1

12 Net Sections Net Sections boe/day MMboe 2/11/216 NE BC Montney Growth Assets ARC s NE BC Montney Assets Strategically Located TCPL Spectra Alliance TCPL Proposed Geographic Optionality Proximity of ARC Montney landbase enables: Capital & operating efficiencies Application of learnings across areas Egress Optionality Dual-connected ARC facilities allow for takeaway optionality in wellserved area with three major pipelines providing access to North American markets Montney Development Montney Development Driving Efficiencies and Competitive Cost Structure $2.8 billion of capital invested in the Montney since 29 to grow low-cost, high-value Montney production 12, 1, 8, 6, 4, 2, 1, Production 114,167 63,538 47% Montney Well Count 755 1% Montney Assets Base Assets ,2 1, Proved + Probable Reserves 379 Montney Landholdings >1, % %

13 Lower Montney Upper Montney $ millions $ millions $ millions $ millions 2/11/216 NE BC Montney Capital Efficiencies Forecasting Future Cost and Efficiency Savings in 216 ARC continues to incorporate efficiencies realized from its 214 and 215 capital programs and expects further service cost reductions in Dawson 1,8m Well (1) Parkland 1,6m Well (1) Down ~4% 5. Down ~4% F F Sunrise 2,m Well (1) Tower 1,5m Well (1) Down ~3% Down ~25% F F (1) Drill/Complete/Equip costs per well. 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 12

14 Number of Locations 2/11/216 NE BC Montney Reserves and Risked Resources NE BC Montney TPIIP 9 Tcf of Shale Gas and 9.7 Billion Barrels of Oil Shale Gas Tight Oil and NGLs ECONOMIC CONTINGENT RESOURCE 5.7 Tcf 2.6 Tcf 2.4 Tcf 3.3 Tcf.5 Tcf TOTAL PROVED + PROBABLE RESERVES DEVELOPMENT PENDING - RISKED DEVELOPMENT UNCLARIFIED - RISKED DEVELOPMENT NOT VIABLE - RISKED Oil 23 MMbbl NGLs 42 MMbbl Oil 33 MMbbl NGLs 37 MMbbl Oil 129 MMbbl NGLs 21 MMbbl NGLs 53 MMbbl ECONOMIC CONTINGENT RESOURCE Oil 162 MMbbl NGLs 238 MMbbl 5.3 Tcf PROSPECTIVE RESOURCE - RISKED Oil 81 MMbbl NGLs 319 MMbbl YE 214 Unrisked ECR included 4.9 Tcf of natural gas, 143 MMbbl of NGLs and 35 MMbbl of crude oil. Independent Resources Evaluation conducted by GLJ effective December 31, 215. Contingent Resource and Prospective Resource quoted are Best Estimate case. For Development Pending NPV calculations and full Resource disclosure please refer to ARC s reserves news release dated February 1, 216 regarding Reserves and Resources. Early Stages of Property Development* Large Identified Opportunity for Future Value Creation Inclusive of internally identified locations in NEBC and Ante Creek, ~5, potential future drilling opportunities exist within the Montney Pembina area has ~ 6 future drilling opportunities in the Cardium 1,25 1, NEBC Montney >3, Future Gross Drilling Locations Recognized by Independent Evaluator Dawson Parkland / Tower Sunrise / Sunset Attachie Other Montney Total HZ Wells Drilled to YE215 Development Pending ECR Booked Locations 2P Booked Undeveloped Locations Development Unclarified ECR Booked Locations Subject to change based on technology and economic environment. 13

15 2/11/216 Montney Development Economics Strong Rates of Return Across the Montney Portfolio Dawson Sunrise Parkland Tower Half Cycle Economics C$45/bbl MSW C$2.5/GJ AECO 75% IRR 4.1x Recycle Ratio $1.25/Mcf Breakeven 45% IRR 4.5x Recycle Ratio $1.6/Mcf Breakeven 45% IRR 3.6x Recycle Ratio $1.2/Mcf Breakeven 25% IRR 2.1x Recycle Ratio $3/bbl Breakeven Economics run at flat price forecasts with Cdn$45/bbl Edmonton Sweet (MSW) and Cdn$2.5/GJ AECO. Breakeven prices are Cdn$ per barrel or Mcf as indicated. Breakeven is defined as the price at which NPV1 is equal to zero. Recycle ratio is calculated using first 12 months of undiscounted netback divided by F&D. 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 215). 15% before-tax IRR assumes US$/Cdn$ is.83, US$.75/MMbtu AECO basis, 2:1 liquids to gas ratio. 14

16 2/11/216 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 $3.6/boe $.65/Mcf Capital Efficiency $5,/boe/day Superior Economics 75% IRR C$45/bbl & C$2.5/GJ Breakeven Price $1.25/Mcf Significant Resource 2.7 Tcf of shale gas resource IRR Half cycle after-tax rate of return based on Cdn$45/bbl Edmonton Sweet (MSW) and Cdn$2.5/GJ AECO. Breakeven pricing is Cdn$ per bbl or Mcf price as indicated, and defined as price at which NPV1 is equal to zero. F&D 215 Finding and Development Cost before changes in future development capital. Significant Resource TPIIP as per 215 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. 15

17 $ millions Mmcfe/day 2/11/216 Dawson Asset Details Poised for Next Stage of Development Net production (boe/d) Q ,72 Liquids (bbl/d) 99 Gas (MMcf/d) 166 Production split % (liquids/gas) ~97% gas Land (Montney net sections) 133 Working Interest ~96% Reserves (2P MMboe) 175 Liquids (MMbbl) 18.4 Gas (Bcf) 938 Reserve Life Index (years) 16 Year # Hz Wells Drilled 216 Budget Dawson A Cash Flow Machine Low Reinvestment Ratio to Maintain Significant Free Cash Flow Field Netback ($ millions) 25 2 Capital Expenditures ($ millions) Free Cash Flow ($ millions) Production (MMcfe/day) (5) (5) (1) (1) $3.79 $3.44 $2.27 $3. $4.19 $2.63 AECO Cdn$/GJ $8 $95 $94 $98 $93 $49 WTI US$/bbl 16

18 Production Rate (Mcf/day) Wells 2/11/216 Dawson Development Potential Additional Development Layer Below Core Acreage Dawson Upper Montney Upper Montney A Booked Reserves* 5 4 Drilling Inventory 3 Lower Montney 2 1 Lower Montney Booked Reserves* *Sections with 2P Reserves booked as of YE215. Wells Drilled to YE215 Drilling Opportunities at YE215 Development Unclarified ECR Locations Development Pending ECR Locations 2P Booked Locations Wells Drilled Dawson Gas Type Curve Growth Continuous Improvement in Well Performance 7, 6, 5, 215/216 Type Curve 213/214 Type Curve Forecast Key Metrics 216 Budget DCET Capex/well ($ millions) 4.2 Internal 2P Reserves (Bcfe) 7.4 IP (1 mo) (MMcf/day) 6.2 4, 3, IP (12 mo) (MMcf/day) 5.4 Half Cycle Economics C$45/bbl & C$2.5/GJ IRR (%AT) 75% 2, 1, Months Type curves are internal estimates based on analog wells and reservoir modeling. Assumed cycle time (from spud to on production): 4 months. 17

19 2/11/216 Dawson Natural Gas Liquids Potential Finding Higher Liquids With Move Away from Dawson Core 15 bbl/mmcf 4 bbl/mmcf Wellhead Condensate 3 bbl/mmcf 3 bbl/mmcf 1 bbl/mmcf 4 bbl/mmcf Wellhead Condensate 25 bbl/mmcf Liquids ratio at Dawson varies across Upper and Lower Montney Majority of development to-date focused on the Upper Montney A, which has lower liquids yields (core is defined by yellow contours on map) New gas plant planned for 217 will support development of Upper Montney outside of core and Lower Montney both have higher liquids yields Upper Montney A liquids yield based upon cold plant design Lower Montney condensate production at wellhead 2 m pay at 6% porosity cut-off 2 bbl/mmcf Dawson Phase III Plant Construction at Dawson Phase III Underway Dawson Phase III Sour Gas Plant with 9 MMcf per day of gas and 7,5 barrels of liquidshandling sales capacity approved by the BC Oil and Gas Commission in September Design and planning of the plant is ongoing, with procurement of long-lead equipment having commenced Total gas processing capacity in Dawson is expected to be 255 MMcf per day and over 8,5 barrels per day of liquids-handling once the plant is built 18

20 2/11/216 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 = 1%, 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 1 years Standalone after-tax economics*: IRR = 2%, Recycle Ratio = 3.1 Cdn$2/GJ AECO (Cdn$4/bbl MSW) Flat Pricing Cdn$3/GJ AECO (Cdn$6/bbl MSW) Flat Pricing Cdn$4/GJ AECO (Cdn$8/bbl MSW) Flat Pricing Economics quoted above run at Cdn$55/bbl Edmonton Sweet (MSW) and Cdn$3/GJ AECO flat pricing. Parkland/Tower Significant Value Creation Strong Economics 45% IRR (Parkland) 25% IRR (Tower) C$45/bbl & C$2.5/GJ Three Layer Development Lower Montney Pilot well on-stream Growth Driver 95% Forecast YoY 216 liquids growth Liquids Growth Doubled oil handling capacity in Q4 215 Exceptional Results 7 wells with over 1, barrels of cumulative oil production in under a year Significant Resources 1.4 MMbbl of tight oil and 2.3Tcf of shale gas (Tower) 3.9 Tcf of shale gas (Parkland) IRR Half cycle after-tax rate of return based on Cdn$45/bbl Edmonton Sweet (MSW) and Cdn$2.5/GJ AECO. Breakeven pricing is Cdn$ per bbl or Mcf price as indicated, and defined as price at which NPV1 is equal to zero. F&D 215 Finding and Development Cost before changes in future development capital. Significant Resource TPIIP as per 215 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. 19

21 Wells 2/11/216 Parkland/Tower Asset Details Significant Value Creation Net production (boe/d) Q4 215 Parkland Tower 15,5 8,7 Liquids (bbl/d) 2,53 6,7 Gas (MMcf/d) Land (net sections) Working Interest ~84% ~92% Reserves (2P MMboe) Liquids (MMbbl) Gas (Bcf) Reserve Life Index (years) 18 7 Year Budget Parkland Tower # Hz Wells Drilled # Hz Wells Drilled Parkland/Tower Development Potential Incremental Reserves Potential with Multilayer Development Upper Montney Upper Montney A Booked Reserves* 75 Drilling Inventory 5 Lower Montney Upper Montney A+ Booked Reserves* 25 Lower Montney Booked Reserves* Wells Drilled to YE215 Drilling Opportunities at YE215 Development Unclarified ECR Locations Development Pending ECR Locations 2P Booked Locations Wells Drilled *Sections with 2P Reserves booked as of YE215. 2

22 Production Production Rate Rate (boe/day) Cumulative boe Cumulative bbl 2/11/216 Tower Cumulative Production Continuous Improvement in Well Performance Cumulative oil production from nine 214 wells had surpassed one million barrels in January , 14, 12, Total Production 5-14 Pad (214) 8-15 Pad (214) 8-24 Pad (215) Pad (215) 1, 8, Oil Production 5-14 Pad (214) 8-15 Pad (214) 8-24 Pad (215) Pad (215) 1, 216 Type Curve 216 Type Curve 6, 8, 6, 215 Type Curve 4, 215 Type Curve 4, 214 Type Curve 2, 214 Type Curve 2, Days On Days On Type curves are based on internal estimates based on analog wells and reservoir modelling. Tower Completions Advancement Advanced Completion Design = Improved Performance 1,4 1,2 1, Type Type Curve Curve 215 Type Curve 215 Type Curve 216 Type Curve 214 Type Curve Key Metrics 216 Budget DCET Capex/well ($ millions) 5.5 Internal 2P Reserves (Mboe) 6 IP (1 mo) (boe/day) 1,2 IP (12 mo) (boe/day) 54 Half Cycle Economics C$45/bbl & C$2.5/GJ IRR (%AT) 25% Months Type curves are internal estimates based on analog wells and reservoir modeling. Assumed cycle time (from spud to on production): 5 months. 216 Budget type curve based on 1,5 m lateral length. 21

23 Depth (m) 2/11/216 Tower Drilling Curves ~25% Reduction in Drill Times = ~3% Cost Savings at Tower Pads 5 1, 1,5 2, 2, Best Well 8-24 Pad Average Pad Average (Horizon 5) Industry Offset 1 Industry Offset 2 3% cost savings and 25% reduction in drilling time over previous Tower pads Realizing reduced drill days and cost savings as a result of reengineering and optimization of drilling operations The efficiencies that have been realized will remain, despite movement in cost structure when commodity prices recover 3, Q3 215 Q ,5 25% Reduction in Overall Drill Times 4, Days From Spud Sunrise Long-term Growth Opportunity Significant Resource 8.3 Tcf of shale gas resource 215 Growth Driver New 6 MMcf/day facility on-stream and at capacity Strong Economics 45% IRR C$45/bbl & C$2.5/GJ Breakeven Price Four Layer Development Currently producing from all four layers Low Cost Gas $1.6/Mcf Op Cost $.5/Mcf F&D $.48/Mcf IRR Half cycle after-tax rate of return based on Cdn$45/bbl Edmonton Sweet (MSW) and Cdn$2.5/GJ AECO. Breakeven pricing is Cdn$ per bbl or Mcf price as indicated, and defined as price at which NPV1 is equal to zero. F&D 215 Finding and Development Cost before changes in future development capital. Significant Resource TPIIP as per 215 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. 22

24 Wells 2/11/216 Sunrise Asset Details Sunrise Has Progressed from Pilot to Full Scale Development Net production (boe/d) Q ,69 Liquids (bbl/d) 15 Gas (MMcf/d) 123 Land (Montney net sections) 32 Working Interest ~89% Reserves (2P MMboe) 169 Liquids (MMbbl) 2.3 Gas (Bcf) Reserve Life Index (years) Year # Hz Wells Drilled 216 Budget Sunrise Development Potential Proven Productivity from Four-Layered Development Upper Montney Upper Montney A Booked Reserves* 4 3 Drilling Inventory Upper Montney A+ Booked Reserves* 2 1 Lower Montney Upper Montney B Booked Reserves* Wells Drilled to YE215 Drilling Opportunities at YE215 Lower Montney Booked Reserves* Development Unclarified ECR Locations Development Pending ECR Locations 2P booked locations Wells drilled to YE215 *Sections with 2P Reserves booked as of YE

25 Gas Rate (Mcf/day) Gas Rate (Mcf/d) 2/11/216 Sunrise Outperforming Expectations Drilling Results Continue to Reaffirm Four-Layer Development Model 1, 9, 8, 7, 215/16 Upper MTY Type Curve (11.7 Bcf) W6 (8-24Hz) Upper MTYA / W6 (A13-3) Upper MTYA (C9-13Hz) Lower MTYA+ 2/ W6 (B2-25Hz) MTYB 2/ W6 (B13-3) MTYB 12/ W6 (B8-24 ) Lower Montney 6, 5, 4, 3, 2, 1, Type curve is an internal estimate based on analog wells and reservoir modelling. Days On C9-13Hz (Lower MTYA): Was restricted after about three months on production due to facility capacity constraints. B8-24 (MTYD2): Going forward, will target tighter interfrac spacing in the Lower Montney than was achieved on the B8-24 well. A13-3 (Upper MTYA): Most recent Upper MTYA result (three wells on pad) strongest deliverability wells to-date at Sunrise (restricted); producing at high pressures. B13-3 (MTYB): Most recent MTYB result (three wells on pad) strongest MTYB results to date at Sunrise (restricted); producing at high pressures. Sunrise Continuous Improvements Enhanced Well Design = Type Curve Improvement 7, 6, 5, Type Curve (11.5 Bcf) 213 Type Curve (11 Bcf) 211 Type Curve (7 Bcf) Key Metrics 216 Type Curve DCET Capex/well ($ millions) 5.4 Internal 2P Reserves (Bcfe) 11.5 IP (1 mo) (MMcf/day) 6.2 4, 3, IP (12 mo) (MMcf/day) 5.4 Half Cycle Economics C$45/bbl & C$2.5/GJ IRR (%AT) 45% 2, 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. 24

26 Gas Rate (Mcf/d) Bottomhole Flowing Pressure (KPAa) 2/11/216 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 = 6%, 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 = 2%, Recycle Ratio = 3.8 Cdn$2/GJ AECO Flat Pricing Cdn$3/GJ AECO Flat Pricing Cdn$4/GJ AECO Flat Pricing Economics quoted above run at Cdn$3/GJ AECO. Sunrise 215 Drilling Performance Strong Performance at Sunrise from 215 Drills 12-3 Pad wells are flowing at higher bottomhole flowing pressures than had been forecast As wells are rate-restricted (i.e., held at a constant production), the decline is seen in the bottomhole flowing pressure as opposed to the gas rate Improved performance can be noted due to the lower decline in the bottomhole flowing pressure 7, Sunrise 12-3 Pad Upper Montney A 35, 6, 5, 4, Gas forecast has been revised upwards to reflect higher bottomhole flowing pressure 3, 25, 2, 3, 2, 1, Actual bottomhole flowing pressure is exceeding forecast 15, 1, 5, Months A12-3 Actual Gas 12-3 Upper A AFE Forecast A12-3 Gas Forecast BHFP With Forecast Model BHFP Actual 25

27 Depth (m) 2/11/216 Sunrise Drilling Curves ~35% Reduction in Drill Times = ~4% Cost Savings on Sunrise Pads 5 1, 1,5 2, 2,5 3, 3, Pad Average (Q1 215) G (Q4 215) H (Q4 215) I (Q4 215) J (Q1 216) Realizing reduced drill days and cost savings during the year from re-engineered well design including an introduction of a new drill fluid system which has allowed for increased ROP and extended bit life Efficiencies that have been realized will remain, despite movement in cost structure when commodity prices recover Using latest technology high efficiency Electric Triple Drilling Rig 4, Q ,5 Q , 35% Reduction in Drill Times Q1 215 to Q , Days From Spud Attachie Asset Details Highly Prospective Asset With Strong Liquids Potential Net production (boe/d) Q Liquids (bbl/d) 26 Gas (MMcf/d) 1.2 Land (Montney net sections) 279 Working Interest ~1% Reserves (2P MMboe) 14 Liquids (MMbbl) 6.2 Gas (Bcf) Reserve Life Index (years) ARC Montney Land ARC Montney Wells Year # Hz Wells Drilled 216 Budget

28 2/11/216 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 13 Mbbl of liquids in 18 months NGLs yield up to 25 bbl/mmcf dependent on plant design; free condensate gas ratio of 5-15 bbl/mmcf Acquired 89 net sections at Attachie in Q2 215, increasing ARC s total Attachie land position to 279 net sections ARC has drilled three wells on newly acquired lands in H2 215 In 216 ARC plans to: Drill 2 delineation wells at West Attachie Drill 2 appraisal wells at East Attachie West Attachie Pilot production onstream since Q2 214 ARC Montney Land ARC Montney Wells ARC 215 Drills 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. 27

29 Forecast boe/day Forecast Forecast Forecast 2/11/216 Looking Beyond 216 Diverse Portfolio Provides Strategic Optionality ARC has a well-balanced inventory of value creating opportunities which may be pursued beyond , 12, Production Profile Project Options Dawson Phase III 1, 8, 6, 4, 2, Forecast Forecast Pouce Commercialization Ante Creek Expansion Sunrise Phase II Attachie Commercialization Septimus Commercialization Parkland/Tower Phase II Dawson Phase IV Non-Montney Liquids (bbl/day) Montney Liquids (bbl/day) Non-Montney Gas (boe/day) Montney Gas (boe/day) Pembina Waterflood and EOR Redwater and/or SE Saskatchewan EOR 28

30 2/11/216 Q4 215 Operational and Financial Performance Strong Production and Financial Results Three Months Ended December 31 Year Ended December 31 (Cdn$ millions, except per share and per boe amounts) Production (boe/d) Natural Gas Oil & Liquids Commodity Revenue Natural Gas Oil & Liquids Funds from operations Per share Dividends Per share 119,243 66% 34% % 61% ,986 61% 39% % 64% ,167 65% 35% 1, % 61% ,387 6% 4% 2, % 66% 1, Capital expenditures, before land and net property acquisitions/dispositions Net debt outstanding , ,255.9 Weighted average number of shares outstanding, diluted (millions) Netback (pre-hedging)

31 2/11/ and 216 Guidance Focused on Value Creation 216 Original Guidance (1) 216 Revised Guidance (1) 215 Guidance (2) 215 Actuals Oil (bbl/day) 34,5-36,5 32, - 34, 33,5-34,5 32,762 Condensate (bbl/day) 3,2-3,6 3, - 3,4 3,4-3,8 3,43 Gas (MMcf/day) NGLs (bbl/day) 4, - 4,5 3,8-4,2 3,7-3,9 3,819 Total (boe/day) 119, - 124, 116, - 12, 113, - 115, 114,167 Operating expenses (3) Transportation expenses G&A expenses before share-based compensation plans G&A - share-based compensation plans (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) (67.7) Weighted average shares, diluted (millions) ) 216 revised production guidance incorporates impact of approximately 1,3 boe per day of divested non-core crude oil assets at the end of 215 and does not take into account the impact of any dispositions that may occur during ) Incorporates impact of approximately 3,6 boe per day of divested non-core assets throughout 215 (75 per cent natural gas), which resulted in annual volume impact of approximately 2,2 boe per day of production. 3) Actual results for the year ended December 31, 215 incorporate an impact of approximately $.4 per boe due to a revision of estimates for prior period operating costs. 4) Comprises expenses recognized under the Restricted Share Unit and Performance Share Unit Plan, Share Option Plan and Long-term Restricted Share Award Plan. In periods where substantial share price fluctuation occurs, ARC's G&A expenses are subject to greater volatility. 5) The 215 and 216 corporate tax estimates vary depending on level of commodity prices. Hedge Positions February 1, 216 Summary of Hedge Positions as at February 1, 216 (1) Crude Oil Cdn$ WTI (2) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Ceiling , , Floor 7. 3, 7. 1, Swap , Crude Oil - MSW (Differential (3) to WTI) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day Swap (3.75) 9, Natural Gas - NYMEX (4) US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day US$/MMbtu MMbtu/day Ceiling , , , 5. 4, - - Floor 4. 15, , 4. 9, 4. 4, - - Swap 4. 4, Natural Gas - AECO (5) Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Ceiling , 3.6 3, Floor , 3.8 3, Swap , , , , , 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) 9.3% 14, 89.3% 15, 84.5% 95, 82.6% 6, 82.5% 1, 1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. All positions are financially settled against the benchmark prices disclosed in Note 9 Financial Instruments and Market Risk Management in the financial statements for the three and twelve months ended December 31, ) 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. 3

32 2/11/216 Significant Liquidity ARC Continues to Maintain Ample Liquidity Long-term Notes $825MM $2.5 Billion Total Cash & Existing Credit Capacity ($1.4 Billion Available) Master Shelf $289MM Cash $167MM Undrawn Master Shelf $195MM Undrawn Credit Facility $1,4MM Bank Credit Facility $1 billion credit facility plus $4 million working capital facility Currently undrawn 12 banks included in syndicate Credit facility matures in 219 Long-term Notes Private Placement market Notes are rated NAIC 2 Prudential Master Shelf US$29 million currently drawn out of capacity of US$35 million As of December 31, 215. Assumes US$/Cdn$ of $ Credit facility in graph includes $4 million working capital facility. Non-Cash Working Capital not included. 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 219 ~5% of Station 2 exposure mitigated in 216 through physical diversification and basis hedges Destination 8% BRITISH COLUMBIA ALBERTA SASKATCHEWAN 7% 18% 7% 23% 74% AECO Station 2 Ventura Purchasers 3% 64% 33% Producer & Physical Marketer Financial Institution Processing & Infrastructure 31

33 Cdn$/barrel 2/11/216 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 BRITISH COLUMBIA ALBERTA SASKATCHEWAN 36% 23% 31% 58% 41% 1% 1% Refining Processing & Infrastructure Production 21% 12% Producer & Physical Marketer Financial Institutions 29% 18% 37% 18% Midale 9% 18% 13% 2% Bow River Sweet Sour LSB C5+ NGLs Commodity Marketing NGLs Pipeline & Fractionation Capacity Secured ARC s NGLs Exposure NGLs revenue (4, 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 Mix 34% 35% 3% 1% Other Propane Butane Condensate 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 (25) Canadian NGLs Pricing Propane Butane Condendate 32

34 2P Reserves (Mmboe) 2/11/216 Key Reserve Information 687 MMboe 2P Reserves at Year-End 215 Reserves at year end, December 31, Proved Producing 222 MMboe - Total Proved 393 MMboe - Proved Plus Probable 687 MMboe - 2P Reserve Life Index 16 years (1) YE 215 2P Reserves Probable 43% PDP 32% 8 7 Natural Gas Liquids 2P Reserves PUD 23% PNP 2% 6 9% CAGR 5 4 Crude and Tight Oil 21% Natural Gas 71% NGLs 8% (1) Based on 216 production guidance midpoint of 118, boe per day. NE BC Montney Schematic Multiple Layers, Multiple Targets, Massive Opportunity Not to scale. 33

35 Cumulative Production Increasing Forecast bbl/d 2/11/216 Growing Oil and Liquids Since 29 ~4% CAGR(1) Total Liquids Production Forecast ARC continues to invest in long-term strategic oil and liquids assets 5, Oil and Liquids Production 45, 4, 35, Dawson, Parkland Tower 3, 25, Ante Creek Montney Liquids 45% CAGR F 2, Cardium 15, 1, 5, SE Saskatchewan, Manitoba, Redwater Non-Montney Liquids F (1) Compound annual growth rate. Tower Wells Deliver Outstanding Results ARC s Tower Wells Are Some of the Best in Western Canada Majority of wells never produce 1, barrels Source: AltaCorp Research (October 215). Days on Production Increasing 34

36 2/11/216 Strategic Montney Infrastructure Building Montney Infrastructure to Support Resource Development Tower Battery November 215 Parkland Gas Plant On-Stream 213 Dawson Gas Plant Phase I: On-Stream 21 Phase II: On-Stream 211 Dawson Phase III Coming 217 Ante Creek Gas Plant Commissioned 212 Sunrise Plant Commissioned August 215 Greater Dawson Montney Pilots Proving Future Value Before Full-Scale Development Septimus Pilot production on-stream since Q2 214 Pouce Coupe Lower Montney pilot production on-stream since late 213 Parkland Lower Montney well on-stream since Q3 214 Dawson Two Lower Montney wells drilled in Q4 214 Upper Montney Pilot Wells Lower Montney Pilot Wells 35

37 2/11/216 Reserves and Resources Disclosure All reserves and resources volumes for NE BC Montney and elsewhere in this presentation are, unless indicated otherwise, as at December 31, 215 as evaluated by GLJ Petroleum Consultants Ltd. in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument Standards for Disclosure for Oil and Gas Activities. TPIIP, DPIIP and UPIIP have been estimated using a one per cent porosity cut-off for shale gas and a three per cent cutoff for tight oil. Reserves volumes for the NE BC Montney and elsewhere in this presentation are, unless indicated otherwise, Proved plus Probable, while the resource categories for NE BC Montney in this presentation are best estimates. NE BC Montney includes land in Pouce Coupe, Alberta. All reserves and resources volumes for NE BC Montney and elsewhere in this presentation are company gross. Gas volumes are sales for reserves and resource and raw gas for DPIIP and TPIIP. The tight oil DPIIP is a stock tank barrel. All DPIIP and TPIIP other than cumulative production, reserves, Economic Contingent Resources and Prospective Resources have been categorized as unrecoverable. The amount of natural gas and liquids ultimately recovered from ARC s NE BC Montney resource will be primarily a function of the future price of both commodities. This presentation contains metrics commonly used in the oil and natural gas industry, such as recycle ratio, finding and development costs, finding and development recycle ratio, finding, development and acquisition costs, operating netbacks, and reserve life index. These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Definitions of Oil and Gas Reserves and Resources Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows: Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. 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. Economic Contingent Resources ( ECR ) are those contingent resources which are currently economically recoverable. Project Maturity Subclass Development Pending is defined as a contingent resource that has been assigned a high chance of development and the resolution of final conditions for development are being actively pursued. Forecast 36

38 2/11/216 Definitions of Oil and Gas Reserves and Resources Project Maturity Subclass Development Unclarified as a contingent resources that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until contingencies can be clearly defined. 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 9 percent probability (P9) 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 5 percent probability (P5) 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 1 percent probability (P1) that the quantities actually recovered will equal or exceed the high estimate. Forecast NE BC Montney Reserves and Risked Resources Amendments to Disclosure of Resource Evaluation Amendments to NI 51-11came into effect July, 215 that require changes to the way resources are disclosed Key changes that impact ARC include: Changes to product types additional product types that now apply to ARC include Shale Gas and Tight Oil Risking is now applied to both the Contingent Resources and Prospective Resources Sub classification is now required for the Contingent Resource ARC s Economic Contingent Resource is now categorized as either Development Pending or Development Unclarified and ARC s Sub Economic Contingent Resource is categorized as Development Not Viable Net Present Value is calculated for the Development Pending category of Contingent Resources 37

39 2/11/216 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 February 1, 216 news release titled ARC Resources Ltd. Announces Strong Fourth Quarter, Record Annual Production and a Significant Increase in Montney Resource Estimates in 215 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. 12, 38 4 Avenue S.W. Calgary, AB T2P H7 38

40 FINANCIAL AND OPERATIONAL HIGHLIGHTS QUARTERLY HISTORICAL REVIEW ($ millions, except per share amounts) FINANCIAL Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Sales of crude oil, natural gas, condensate, NGLs and other income Per share, basic Per share, diluted Funds from operations (1) Per share, basic Per share, diluted Net income (loss) (55.) (235.) (51. ) (1.7 ) Per share, basic (.16) (.69) (.15 ) (.1 ) Per share, diluted (.16) (.69) (.15 ) (.1 ) Dividends declared Per share (2) Total assets 5, ,72.4 6,346. 6, , ,95.5 5, ,949.5 Total liabilities 2, , , ,74.2 2, ,63.5 2, ,58.7 Net debt outstanding (3) , , ,61.9 1,96. 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 (42.2) (2.7) (14.9 ) (11. ) (2.4 ) (5.1 ) (31.8) Total capital expenditures, land purchases and net acquisitions and dispositions OPERATING Production Crude oil (bbl/d) 33,899 29,397 31,958 35,851 37,442 35,871 35,317 37,478 Condensate (bbl/d) 3,631 3,361 3,139 3,591 3,448 3,862 4,462 2,887 Natural gas (MMcf/d) NGLs (bbl/d) 3,523 3,653 3,795 4,314 5,75 5,56 4,179 3,743 Total (boe/d) 119,243 17,261 19,9 12, , ,53 11,165 15,699 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) 2,224 1,736 1,424 1,944 1,886 1,25 1,37 1,248 (1) Refer to the sections entitled "Funds from Operations" and Additional GAAP Measures contained within ARC s MD&A. (2) Dividends per share are based on the number of shares outstanding at each dividend record date. (3) Refer to the sections entitled "Capitalization, Financial Resources and Liquidity" and Additional GAAP Measures contained within ARC s MD&A.

41 CORPORATE & SHAREHOLDER INFORMATION DIRECTORS EXECUTIVE OFFICE Hal Kvisle (3) (4) Chairman ARC Resources Ltd. 12, 38 4th Avenue S.W. Calgary, Alberta T2P H7 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) Kathleen O Neill (1) (5) (6) Herb Pinder (2) (3) (4) William G. Sembo (1) (2) Nancy L. Smith 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 TRANSFER AGENT Computershare Trust Company of Canada 6, 53 8th Avenue S.W. Calgary, Alberta T2P 3S8 T AUDITORS Deloitte LLP Calgary, Alberta ENGINEERING CONSULTANTS Myron M. Stadnyk President and Chief Executive Officer GLJ Petroleum Consultants Ltd. Calgary, Alberta Terry M. Anderson Senior Vice-President and Chief Operating Officer LEGAL COUNSEL P. Van R. Dafoe Senior Vice-President and Chief Financial Officer Burnet Duckworth & Palmer LLP Calgary, Alberta David P. Carey Senior Vice-President, Capital Markets Bevin Wirzba Senior Vice-President, Business Development Kristen (Kris) Bibby Vice-President, Finance Sean Calder Vice-President, Production Lara Conrad Vice-President, Engineering Neil Groeneveld Vice-President, Geosciences and Exploration 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. 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 6 Canadian companies that pass a set of broadly based environmental, social and governance rating criteria. CORPORATE CALENDAR 216 April 28, 216 Q1 216 Results April 29, 216 Annual General Meeting July 28, 216 Q2 216 Results November 9, 216 Q3 216 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