ARC Resources - October 2012 Investor Presentation


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ARC Resources - October 2012 Investor Presentation

  1. 1. ARC ResourcesInvestor PresentationOctober, 2012
  2. 2. FORWARD LOOKING STATEMENTSThis presentation contains forward-looking information as to ARC’s internal projections, expectations or beliefs relating tofuture events or future performance and includes information as to our future well inventory in our core areas, our explorationand development drilling and other exploitation plans for 2012 and beyond, and related production expectations, the volume ofARCs oil and gas reserves and the volume of ARCs gas resources in the NE BC Montney (as defined herein), the recognitionof additional reserves and the capital required to do so, the life of ARCs reserves, the volume and product mix of ARCs oiland gas production, future results from operations and operating metrics. These statements represent management’sexpectations or beliefs concerning, among other things, future operating results and various components thereof or theeconomic performance of ARC Resources. The projections, estimates and beliefs contained in such forward-lookingstatements are based on managements assumptions relating to the production performance of ARC’s oil and gas assets, thecost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes inthe capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of the currentregulatory and tax regime in Canada and necessarily involve known and unknown risks and uncertainties, such as changes inoil and gas prices, infrastructure constraints in relation to the development of the Montney in British Columbia, risks associatedwith the degree of certainty in resource assessments and including the business risks discussed in the annual MD&A andrelated to management’s assumptions, which may cause actual performance and financial results in future periods to differmaterially 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 thosepredicted. Other than the 2012 Guidance which is updated and discussed quarterly, ARC does not undertake to update anyforward looking information in this document whether as to new information, future events or otherwise except as required bysecurities laws and regulations.We have adopted the standard of 6 mcf:1 bbl when converting natural gas to barrels of oil equivalent ("boes"). Boes may bemisleading, particularly if used in isolation. A boe conversion ratio of 6 mcf per barrel is based on an energy equivalencyconversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Giventhat the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energyequivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
  3. 3. CORPORATE OVERVIEWProduction (Q2 2012) 93,997 boed Liquids 36,125 boed Natural gas 347 mmcfd Crude OilReserves (2P Gross) 572 mmboe NE BC/ NW AB Liquids-rich Gas 17 year RLI (1) Dry Gas NORTH ABCurrent monthly dividend $0.10Annualized total return 18% (2) REDWATER 10% (3)Enterprise value ~$8 billion (4) PEMBINAShares outstanding ~307 MM (5) SE SASK/ MANITOBADaily average trading volume 1.5 million shares S AB/ SW SASKNet debt (millions) $665 (0.8 X cash flow)(5)Member of S&P TSX 60 Index(1) Based on 2012 production guidance of 91,000-94,000 boe/d.(2) Annualized total return since inception to September 30, 2012, including September 2012 dividend, and assuming DRIP participation.(3) Annualized total return since September 30, 2007 (last 5 years).(4) Market Capitalization as at September 30, 2012 and net debt as at June 30, 2012 adjusted for August 22 equity offering.(5) As at June 30, 2012, after giving effect to August 22 equity offering and based on trailing 12 month funds from operations.
  4. 4. 2012 CAPITAL PROGRAM FOCUSED ON OIL AND LIQUIDS• $600 million capital program (~150 gross operated wells) with majority of spending in oil and liquids-rich gas plays NE BC - $155MM ~10 gross operated wells NORTHERN AB - $165MM ~90% oil & liquid-rich gas ~30 gross operated wells Parkland/Tower, Attachie ~100% oil & liquid-rich gas Ante Creek, Swan Hills, Prestville PEMBINA - $90MM ~40 gross operated wells ~90% oil Cardium SE SASK/MANITOBA - $100MM ~60 gross operated wells 100% oil Goodlands, Midale (1) The $600 million capital program includes ~$80 million of non-operated and corporate capital spending.
  5. 5. 2012 FOCUS ON OIL AND LIQUIDS• Oil and liquids comprised 38% of second quarter 2012 production while contributing 79% of second quarter revenue• Drilled 77 gross operated wells in first half of 2012 (99% oil and liquids-rich)• Grew crude oil and liquids production 19% to 36,125 boe/d in Q2 2012 (relative to Q2 2011) with significant growth at Ante Creek, Pembina and Goodlands 3% 3% Q4 Revenue 20% 33% 6% Q4 Production Q2 Production Q2 Revenue 62% 3% 70% Crude Oil Condensate NGL’s Natural Gas
  6. 6. VALUE PROPOSITION• We believe that top performing companies all have the following attributes: – Great assets – Operational excellence – Capital discipline – Management that delivers results• At ARC our focus since inception has been on “Risk Managed Value Creation”• It is not a question of growth or income but of how best to create value for our owners• Current dividend of $0.10 per month
  7. 7. PRODUCTION GROWTH Forecast Forecast Forecast
  8. 8. INCOME AND GROWTH ARC HAS DELIVERED BOTH• ARC has a 16 year history of risk managed value creation - Provided a 17.9% annual total return since inception - Paid out $4.5 billion in total dividends - $28.28/share - Grown absolute production from 9,500 boe/d to ~95,000 boe/d, – the Montney provides the opportunity for substantial future growth - Grown debt and dividend adjusted reserves & production by ~ 10% annually Production History 100,000 15% CAGR* 75,000 Gas Liquids Boe/d 50,000 Proved 25,000 Undeveloped 20% 0 2012Q2 1997 2001 2002 2006 2010 1996 1998 1999 2000 2003 2004 2005 2007 2008 2009 2011 * Compound annual growth rate
  9. 9. Corporate StrategyContained in the “Strategy” section is forward-looking information. The reader is cautioned that assumptions used in thepreparations of such information, particularly those pertaining to dividends, production levels, operating costs and drillingresults, although considered reasonable by the Company at the time of preparation, may prove to be incorrect. A number offactors, including, but not limited to: commodity prices, reservoir performance, weather, drilling performance and industryconditions, may cause the actual results achieved to vary from projections, anticipated results or other information providedherein and the variations may be material. Consequently, there is no representation by the Company that actual resultsachieved will be the same in whole or in part as those presented herein.
  10. 10. RISK MANAGED VALUE CREATION Understand our Advantaged Position Leverage our Advantaged Position Make time to Think Strategically Financial Operational Flexibility Excellence RISK MANAGED VALUE CREATION High Quality, Top Talent Long Life and Strong Assets Leadership Culture Be Dynamic and Flexible to Changing Conditions
  11. 11. STRATEGIC OVERVIEW SUMMARY• ARC’s strategy has delivered exceptional results to date – We will continue to provide income and profitable growth to our investors• Where do we go from here? – Continued focus on meaningful oil and gas accumulations – Our strategic initiatives will focus on: • Operational excellence • Developing the Montney – near term growth is forecast as an outcome of the quality of our opportunities • Realization of the value embedded in our assets through the development of our large potential resources through advanced recovery methods or application of new technologies • Opportunistic acquisitions to add to our meaningful resource play presence • Maintaining balance sheet strength and financial flexibility
  12. 12. Asset Overview
  13. 13. ASSET OVERVIEW• ARC’s key assets with the greatest value creation opportunities and highest future reserves contributions are: • Ante Creek – oil resource play • Parkland/Tower/Attachie/Septimus – liquids-rich gas resource play • Pembina Cardium – oil resource play • Goodlands and SE Saskatchewan – oil resource play • Dawson – natural gas resource play • Sunrise/Sunset – natural gas resource play• ARC plans to develop these opportunities, subject to a supportive commodity price environment, over the next five years• Highlights from a few of these key areas will be covered in this presentation
  14. 14. SE Saskatchewan& Manitoba High Quality Oil and Solid Netbacks
  15. 15. SE SASKATCHEWAN/MANITOBAASSET DETAILS Net production (boe/d) 11,500 Reserves (2P mmboe) 45.8 Production split 99% liquids Reserve split (2P) 99% liquids Land (net sections) 248 Reserve Life Index (years) 11 Working Interest ~81%2012 Plans /Accomplishments• Increased total production in this area by 21% relative to Q2 2011 to 11,500 boe/d• Significant production increase coming from Goodlands in Manitoba given active drilling program in 2011 and 2012• Drilled 19 light crude oil wells at Goodlands in the first half of 2012
  16. 16. Boe/d 10,000 12,000 14,000 2,000 4,000 6,000 8,000 0Q1 2005Q2 2005Q3 2005 GasQ4 2005Q1 2006 Oil & liquidsQ2 2006Q3 2006Q4 2006Q1 2007Q2 2007Q3 2007Q4 2007Q1 2008Q2 2008 GROWING OIL AND LIQUIDSQ3 2008Q4 2008Q1 2009Q2 2009Q3 2009Q4 2009Q1 2010Q2 2010 SE SASKATCHEWAN/MANITOBAQ3 2010Q4 2010Q1 2011 weather in Q2 2011 Impact of severe/wet SE Sask/Manitoba >20% growth in liquids production in 2012Q2 2011Q3 2011Q4 2011Q1 2012Q2 2012Q3 2012 ForecastQ4 2012
  17. 17. GOODLANDS DEVELOPMENT ECONOMICS 120.0 Type Curve Production Rate (boepd) 100.0 IP (1mo) boe/d 113 80.0 IP (12mo) boe/d 66 60.0 EUR mboe 55 40.0 20.0 0.0 0 3 6 9 12 15 18 21 24 27 30 33 36 Months F&D ($/boe) 25.7 Economics - Type Curve at C$85/bbl Capital Costs ($K) (Gas not conserved) Drilling & Completions 1,300 IRR (% AT) 80% Equip & Tie-In 100 Total 1,400 Recycle Ratio 2.5• All economics run at FLAT price forecasts
  18. 18. Pembina Revitalizing a Mature Oil Field
  19. 19. PEMBINAASSET DETAILS Net production (boe/d) – Q2 2012 11,500 Cardium production ~80% Production split % (liquids/gas) ~75%/25% Land (Cardium net sections) 132 Working Interest ~78% Reserves (2P mmboe) Cardium 41.6 Reserve Life Index 14.2 2012 Plans/Accomplishments • ARC is the second largest operator in the Pembina area. • 20 Hz Cardium wells drilled in first half of 2012 • Encouraging results on recent Buck Creek horizontals
  20. 20. PEMBINA OIL AND LIQUIDS GROWTHARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD Pembina - 23% Increase in Oil & Liquids Production since 2006 14,000 12,000 10,000 8,000Boe/d Q2 2012 - 8,500 boe/d 6,000 Q1 2006 - 6,900 boe/d oil and liquids oil and liquids 4,000 Forecast 2,000 gas oil & liquids 0 Q1 2006 Q2 2006 Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012 Q4 2012
  21. 21. PEMBINACARDIUM AREA IP AVERAGE (3 MONTH RATE) LOW CARDIUM DC&T COSTS AT ~$2.3 MM/WELL 600.0 Cardium Area IP Average (3 Month Rate)* 500.0 400.0 ARC WellsIP3 boe/d 300.0 Other Wells Industry Median Well ~ 157 boe/d ARC Median Well 200.0 ~ 154 boe/d 100.0 0.0 *Wells from TWNS 47-79 Ranges 5-10W5 *Applied minimum 750 production hours for IP3 cut-off
  22. 22. PEMBINA – HORIZONTAL WELLS DEVELOPMENT ECONOMICS Type Curve IP (1mo) boe/d 237 IP (12mo) boe/d 94 EUR mboe 167 Type Curve F&D ($/boe) 13.77 Economics - Type Curve at C$85/bbl Capital Costs ($k) $4/GJ $3/GJ $2/GJ Drilling & Completion 2,000 IRR (% AT) 55% 53% 50% Equip & Tie-In 300 Total 2,300 Recycle Ratio 3.61 3.54 3.47• All economics run at FLAT price forecasts.• Condensate 4 bbls/MMcf, Propane 20 bbls/MMcf, Butane 15 bbls/MMcf, GOR 1400 scf/bbl.• Assumes two month lag from capital spent to production date, and on-lease tie-in well.
  23. 23. Ante Creek A Montney Oil Success Story
  24. 24. ANTE CREEKASSET DETAILS Net production (boe/d) – Q2 2012 10,500 Liquids (bbls/d) 5,200 Gas (mmcf/d) 33 Production split % (liquids/gas) ~50/50 Land (Montney net sections) 263 Working Interest ~99% Reserves (2P mmboe) 47.2 Liquids (mmbbls) 20.2 Gas (bcf) 162 Reserve Life Index 18.2 2012 Plans/Accomplishments • 30 mmcf/d gas plant commissioned in late February, alleviating capacity constraints • Growth in oil and liquids production in 2012 • Production to increase through 2013 as we “drill to fill” new gas plant
  25. 25. ANTE CREEK HZ WELLS ANTE CREEK - KAYBOB ARC’S HZ ANTE CREEK WELLS HAVE OUTPERFORMED 1200 30 Day Average Daily IP Rate (boe/d) 1000 ARC Gas ARC Liquids Others Gas 800 Others Liquids 600Boe/d ARC Median Well ~ 377 boe/d Industry Median Well 400 ~ 231 boe/d 200 0 (1) All reported wells from 60-20W6 to 69-26W6. (2) Taken within first month of production. (3) ARC wells include only those originally licensed to ARC and do not include wells acquired by ARC. (4) All wells have Oil IP3 > 0.
  26. 26. ANTE CREEK GROWING OIL AND LIQUIDSEXPANDED CAPACITY WILL FACILITATE GROWTH IN 2012/2013 Ante Creek > 60% Increase in Liquids Production during 2012 14,000 12,000 gas oil & liquids 10,000 >60% growth in Q4 2012 liquids production relative to Q4 2011 8,000Boe/d 6,000 4,000 Forecast 2,000 0 Q1 2005 Q2 2005 Q3 2005 Q4 2005 Q1 2006 Q2 2006 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012 Q2 2012 Q3 2012 Q4 2012 Q3 2006 Q4 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Q2 2010 Q3 2010
  27. 27. ANTE CREEK DEVELOPMENT ECONOMICS 450 Type Curve 400 Production Rate (BOE/d) 350 IP (1mo) boe/d 385 300 IP (12mo) boe/d 235 250 200 EUR mboe 265 150 100 50 Type Curve 0 0 3 6 9 12 15 18 21 24 27 30 33 36 Months F&D ($/boe) 15 Economics - Type Curve at C$85/bbl Capital Costs ($K) $4/GJ $3/GJ $2/GJ Drilling & Completions 3,600 IRR (% AT) 45% 35% 25% Equip & Tie-In 400 Total 4,000 Recycle Ratio 2.2 2.0 1.8• All economics run at FLAT price forecasts
  28. 28. British Columbia Montney Gas and Liquids
  29. 29. NE B.C. MONTNEY VAST RESOURCE BASEWe engaged GLJ to provide a resources evaluation of our properties at Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown andBlueberry located in northeastern British Columbia and at Pouce Coupe located in northwestern Alberta (collectively, the "Evaluated Areas" or "NE BCMontney"). The evaluation procedures employed by GLJ are in compliance with standards contained in the Canadian Oil and Gas Evaluation Handbook("COGE Handbook") and the evaluation is based on GLJs January 1, 2012 pricingThe estimates of Economic Contingent Resources (or ECR), DPIIP, TPIIP, UPIIP and Prospective Resources should not be confused with reserves andreaders should review the definitions and notes set forth at the end of this presentation. Actual natural gas resources may be greater than or less thanthe estimates provided herein.There is no certainty that it will be commercially viable to produce any of the resources that are categorized as discovered resources. There is nocertainty that any portion of ARCs resources that have been categorized as undiscovered resources will be discovered. Furthermore, if discovered, thereis no certainty that it will be commercially viable to produce any portion of such undiscovered resources. Unless indicated otherwise in this presentation,all references to ECR volumes are Best Estimate ECR volumes.Continuous development through multi-year exploration and development programs and significant levels of future capital expenditures are required inorder for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potentialfor variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to developthe resources, low gas prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to therequired services at the appropriate cost, and the effectiveness of fraccing technology and applications. The contingencies that prevent the ECR frombeing classified as reserves are due to the early evaluation stage of these potential development opportunities. Additional drilling, completion, and testresults are required before these contingent resources are converted to reserves and a larger component of DPIIP is converted to ECR.Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montneyresource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints,ARCs policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gasprices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.See “Definitions of Oil and Gas Reserves and Resources” in this presentation.
  30. 30. MONTNEY LANDSWORLD CLASS RESOURCE PROGRESS/ • NE BC Montney lands are a major PETRONAS growth engine. Kahta/Lily • Significant opportunity to grow liquids production. TALISMAN/ Attachie SASOL • Total BC Montney Q2 production of Farrell Creek 240 mmcf/d with Dawson Tower contributing approximately 167 Septimus mmcf/d. Parkland • New, 60 mmcf/d gas plant with 130 SHELL Sunset Dawson Groundbirch bbls/mmcf of liquids handling Sunrise capacity planned for Parkland/Tower in late 2013. Sundown ENCANA/ • Ideally positioned with access to MISTUBISHI west coast and other Alberta Cutbank RidgeARC 100% markets.ARC <100%
  31. 31. NE B.C. MONTNEY RESOURCE POTENTIAL• An Independent Resources Evaluation conducted by GLJ effective December 31, 2011 estimates the TPIIP to be 39.6 Tcf using a 3% porosity cut-off and 50.4 Tcf using no cut-off (comparable to US shale gas resource-in-place estimates).• DPIIP estimated to be 21.2 Tcf (54% of TPIIP) using a 3% porosity cut-off and 25.5 Tcf (51% of TPIIP) using no cut-off. 3% Porosity 0% Porosity Resource Categories (1) (2) Cut-Off (Tcf) Cut-Off (Tcf) Total Petroleum Initially In Place (TPIIP) 39.6 50.4 Discovered Petroleum Initially In Place (DPIIP) 21.2 25.5 Undiscovered Petroleum Initially In Place (UPIIP) 18.4 24.9• ARC estimates $54 million of capital would be required to drill and test sufficient wells to convert all of the TPIIP into DPIIP• ARC’s long-term development plans are based upon the estimated TPIIP• The amount of natural gas and NGL’s which is ultimately recovered from ARC’s NE B.C. Montney resource will be primarily a function of the future price of both commodities (1) The resource categories do not include free liquids or associated solution gas in the Tower field. (2) All volumes in table are company gross and raw gas volumes.
  32. 32. NE B.C. MONTNEY RESERVES AND RESOURCES• GLJ’s Best Estimate of the ECR is 4.1 Tcf of gas and 101 Mmbbls• Significant natural gas liquids (“NGL”) resource exists in the Montney in the Attachie, Parkland, Septimus and Tower areas• GLJ’s Best Estimate of the NGL ECR is 101 Mmbbls. In addition, GLJ’s Best Estimate of Prospective NGL Resources is 98 Mmbbls Low High Reserves and Economic Contingent Resources (1)(5)(6) Estimate Best Estimate Estimate Natural Gas (Tcf) Reserves (2) 1.0 1.9 2.4 (3) Economic Contingent Resources 2.5 4.1 5.7 Natural Gas Liquids (mmbbls) (4) Reserves 11.3 21.1 26.6 (3) Economic Contingent Resources 64.2 101.0 133.9 Low High Prospective Resources (1)(6) Estimate Best Estimate Estimate Natural gas (Tcf) 2.9 4.0 5.3 Natural gas liquids (mmbbls) (4) 69.0 98.0 131.2 (1) All DPIIP other than cumulative production, reserves, and ECR and all UPIIP other than Prospective Resources has been categorized as unrecoverable. (2) For reserves, the volume under the heading Low Estimate are proved reserves, the volume under the heading Best Estimate are 2P reserves and the number under the heading High Estimate are 2P plus possible reserves. (3) This volume is an arithmetic sum of multiple estimates of reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of reserves and appreciate the differing probabilities associated with each class. (4) The liquid yields are based on average yield over the producing life of the property. (5) Cumulative production has been 0.2 Tcf on a raw basis. (6) All volumes in table are company gross and sales volumes.
  33. 33. NE B.C. MONTNEY RESERVES AND RESOURCES• Very early stage in reserve booking cycle: • 2P Reserves (1.9 Tcf) plus Cum Prod only 5.3% of TPIIP at 3% cut-off (4.2% at 0% cut-off). • Best Estimate ECR estimated to be 4.1 Tcf resulting in total recovery including 2P reserves and Cum Prod to date of only 15.7% of TPIIP at 3% cut-off (12.3% at 0% cut-off).• ARC estimates the 2P Reserves plus ECR (6.0 Tcf) can support a peak production rate of 800 mmcf/d for 10 years.• Estimated Prospective Resources of 4.0 Tcf (“Best Estimate”) results in a total potential recovery factor of ~20% - 25% of the TPIIP. Recovery factors at that level could support a peak production rate of >1.3 Bcf/d for 10 years.
  34. 34. ARC RESOURCES TOP MONTNEY DRILLER AND PRODUCER• ARC Resources has been one of the top tier drillers and producers in the Montney since completion of its first horizontal well in 2005 - Success of this well led to the recognition that considerably more gas could be accessed than previously thought• As an early play entrant, ARC added significant land and resource in the sweet spot of the fairway through both acquisitions and land sales• Other early entrants recognizing the prospectively of the Montney surrounding ARC lands include, Shell, EnCana, Murphy, CNRL and Talisman Montney Wells Rig Released since 2003 by Montney Gross Operated Raw Gas Production Operator (Mmcf/d) 400 500 350 450 400 300 350 250 300 200 250 150 200 150 100 100 50 50 0 0 PRQ ECA MUR CNQ TLM BIR CR ARX TOU AAV RDS ECA ARX PRQ TT COP BTE MUR CNQ TLM CR DVN BP SU TOU RDS
  36. 36. Parkland/Tower Liquids Rich Gas
  37. 37. PARKLAND/TOWER EVALUATING POTENTIAL AND DEVELOPING EXISTING LANDS Parkland Tower Net production (boe/d) 8,100 330 Tower Liquids (bbls/d) 1,100 150 Gas (mmcf/d) 42 1.0 Land (net sections) 23 56 Working Interest ~84% ~90% Reserves (2P mmboe) 49.7 4.5 Liquids (mmbbls) 8.4 1.4 Gas (bcf) 247.0 19.2 Parkland Reserve Life Index 16 372012 Plans/Accomplishments• Drilled and completed 3 wells in 2011, 2 wells now on production• Drill 8 Hz wells by end of Q3 2012• Complete, test and put on production all wells by year-end 2012• Application submitted to construct two 60 mmcf/d gas plants with 130 bbls/mmcf liquids capacity
  38. 38. PARKLAND CAN A SINGLE WELL DRAIN THE FULL VERTICAL SECTION?• At Parkland, the Upper Montney is considerably thicker than at Dawson. We believe the lower-most sands are not contributing to production – a horizontal well has been drilled into these lower sands to test this theory. 8-25-79-15W6 MA Lower sand and 5 upper sand 1 month Sands Upper production are similar Sands No communication Lower between upper and lower sands to date
  39. 39. PARKLAND DEVELOPMENT ECONOMICS 6,000 Type Curve 5,000 IP (1mo) MMcf/d 5.0 4,000 IP (12mo) MMcf/d 2.6Gas Rate mcf/d 3,000 EUR Bcf 4.8 2,000 1,000 Type Curve 0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 Months F&D ($/boe) 5.5 Economics - Type Curve at C$85/bbl Capital Costs ($k) $4/GJ $3/GJ $2/GJ Drilling & Completion 4,200 IRR (% AT) 65% 40% 15% Equip & Tie-In 500 Total 4,700 Recycle Ratio 3.6 2.8 1.8 • All economics run at FLAT price forecasts. • Condensate 10 bbls/MMcf, Propane 6 bbls/MMcf, Butane 7 bbls/MMcf. • Royalties noted (24%) based on approximate subsequent year royalty rate after. $850 M credit is drawn down. • Assumes one month lag from initial capital spent to production date.
  40. 40. Attachie New Opportunity Undefined Potential
  41. 41. ATTACHIENEW OPPORTUNITY UNDEFINED POTENTIAL • Prospective land base of 117 sections • ARC has drilled three Hz wells to date: • The 4-20 well tested at 10.7 mmcfd and 350 bbls per day of free liquids with 1,300 psia flowing pressure • Tied in two wells to the 4-9 battery and brought production on-stream late in Q2 • Interpreted a 3D seismic program over 300 square kilometers in the first half of 2012 • Two wells planned for the second half of 2012
  42. 42. Dawson
  43. 43. DAWSONASSET DETAILS Net production (boe/d) – Q2 2012 28,000 Liquids (bbls/d) 700 Gas (mmcf/d) 163 45 mmcf/d Compressor Production split % (liquids/gas) ~97% gas Station 120 mmcf/d Land (Montney net sections) 130 Gas Plant Working Interest ~96% Reserves (2P mmboe) 174 Liquids (mmbbls) 5.0 Gas (bcf) 1,012 Reserve Life Index 16.8 2012 Plans/Accomplishments • Inventory of completed gas wells to be tied-in throughout 2012 • Maintain 2012 production flat at 165 mmcf/d
  44. 44. MONTNEY HORIZONTAL WELLS 30 DAY HZ IP RATES GLACIER - TOWN ARC’S DAWSON/PARKLAND WELLS HAVE EXCEEDED EXPECTATIONS 14,000 12,000 10,000Production Rate (mcf/d) ARC Others 8,000 ARC P50 5.2 Mmcf/d 6,000 Other Wells P50 3.3 Mmcf/d 4,000 2,000 0 1 101 201 301 401 501 601 701 801 901 1001 (1) Graph represents peak calendar day IP rates for the first month of production to July 2012. (2) Region includes all horizontal wells from NE BC and NW AB Montney.
  45. 45. DAWSON DEVELOPMENT ECONOMICS Type Curve IP (1mo) MMcf/d 5.0 6,000 IP (12mo) MMcf/d 5,000 4.2Gas Rate (Mcf/d) 4,000 EUR (Bcf) 6.2 3,000 2,000 1,000 Type Curve 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Months F&D ($/boe) 5.1 Economics - Type Curve at C$85/bbl Capital $k $4/GJ $3/GJ $2/GJ Drilling & Completion 4,600 Tie-In 500 IRR (% AT) 80% 40% 5% Total 5,100 Recycle Ratio 3.2 2.3 1.1• All economics run at FLAT price forecasts.• Condensate 3.5 bbls/MMcf , Butane 0.6 bbls/MMcf and Propane 0.4 bbls/MMcf .• Deep drill royalty credit ~1$MM applied to all cases.
  46. 46. Sunrise/Sunset/Sundown
  47. 47. SUNRISE/SUNSET/SUNDOWNASSET DETAILS Net production (boe/d) – Q2 2012 2,500 Attachie Production split % (liquids/gas) 100% gas Land (Montney net sections) 52 Working Interest ~76% Tower Septimus Reserves (2P mmboe) 82.8 Parkland Liquids (mmbbls) 2.3 Sunset Gas (bcf) 483 Sunrise Dawson Reserve Life Index 54.7 SundownARC <100%ARC 100%
  48. 48. SUNRISERESERVOIR DESCRIPTION • Producing Formation: – Montney(Upper Montney) – Gross thickness = 325m – Net pay = 160m – Porosity = 6% – Permeability = 0.01 – 0.1 mD(Middle Montney)(Lower Montney)
  49. 49. SUNRISE/SUNSET DEVELOPMENT ECONOMICS 7,000 Type Curve 6,000 IP (1mo) MMcf/d 6.0 5,000Gas Rate mcf/d IP (12mo) Mcf/d 2.8 4,000 EUR Bcf 7.0 3,000 2,000 1,000 Type Curve 0 2 4 6 8 10 12 14 16 18 20 22 24 Months F&D ($/boe) 5.25 Economics - Type Curve at C$85/bbl Capital Costs ($k) $4/GJ $3/GJ $2/GJ Drilling & Completion 5,600 IRR (% AT) 50% 30% 10% Equip & Tie-In 400 Total 6,000 Recycle Ratio 3.3 2.6 1.6 • All economics run at FLAT price forecasts. • Assumes development is done with 8 wells per pad • Condensate 1 bbls/MMcf, Propane 3 bbls/MMcf, Butane 1 bbls/MMcf. • Royalties noted (24%) based on approximate subsequent year royalty rate after $1,250k credit is drawn down. • Assumes one month lag from capital spent to production date, and on-lease tie-in well.
  50. 50. Summary
  51. 51. WHY INVEST IN ARC RESOURCES• ARC is a top-tier oil and natural gas producer focused on “Risk Managed Value Creation”• Extensive land position in top quality resource plays provides significant growth opportunity. • Significant near-term oil and liquids growth opportunities • Significant long-term natural gas growth opportunity in B.C. Montney• Diverse inventory of high quality oil, liquids-rich gas and natural gas development opportunities provides optionality through commodity price cycles• History of proven performance • Grown absolute production from 9,500 boe/d to 95,000 boe/d to date • Grown P+P reserves from 47 mmboe to 572 mmboe to date • Progressive approach of applying new technologies to “unlock” value • Proven track record of “Operational Excellence” in both cost management and safety• Solid balance sheet with protective hedging program• Experienced management team with track record of delivering results
  52. 52. PRODUCTION GROWTH Forecast Forecast Forecast
  53. 53. Appendix
  54. 54. 2012 FINANCIAL AND OPERATIONAL PERFORMANCE Q2 2012 YTD 2012(CDN$ millions, except per share and per boe amounts) 2012 2011 2012 2011Production (boe/d) 93,997 82,367 94,484 78,147 Gas 62% 63% 62% 60% Liquids 38% 37% 38% 40%Revenue 317.2 374.3 683.2 698.4 Gas 64.3 115.1 150.1 204.9 Liquids 252.9 259.2 533.1 493.5Funds from operations 165.8 210.1 346.5 404.2 Per share 0.57 0.73 1.19 1.42Operating Income 30.5 76.4 77.4 149.2 Per share 0.10 0.27 0.27 0.52Dividends 87.3 85.8 174.2 171.4 Per share 0.30 0.30 0.60 0.60Capital expenditures 97.9 144.5 284.8 301.7Net debt outstanding 996.0 744.8 996.0 744.8Weighted average number of shares outstanding 290.8 286.0 290.2 285.4(millions)Netback (pre-hedging) 20.86 32.15 23.35 31.5
  55. 55. 2012 GUIDANCE 2012 Revised 2012 Guidance Guidance 2012 YTD Actual Oil (bbls/d) 31,000 – 32,000 30,000 – 31,000 31,068 Condensate (bbls/d) 2,100 – 2,500 2,100 – 2,500 2,390 Gas (mmcf/d) 330 – 350 340 – 350 350 NGL’s (bbls/d) 2,100 – 2,600 2,100 – 2,600 2,673 Total (boe/d) 90,000 - 95,000 91,000 – 94,000 94,484 Operating costs 9.55 – 9.95 9.50 – 9.70 9.11 Transportation costs (1) 1.00 – 1.10 1.30 – 1.40 1.20 G&A expenses (2) 2.30 – 2.50 2.45 – 2.60 2.54 Interest (3) 1.10 – 1.20 1.20 – 1.30 1.24 Cash Taxes (4) 1.10 – 1.25 1.15 – 1.20 1.15 Capital expenditures (millions) (5) 600 600 285 Land expenditures and minor net property acquisitions ($ millions) (6) - 25 - 50 23 Weighted average shares outstanding (millions) 293 293 290(1) Transportation costs exceeded guidance slightly due to increased trucking activity in the first half of 2012. Going forward, transportation costs are expected to increase as ARC plans to ship a large proportion of its crude oil production on its own as opposed to relying on third-party marketers, resulting is receiving a premium price for its products.(2) The 2012 annual guidance for general and administrative cost per boe is based on a range of $1.75 - $1.85 prior to the recognition of any expense associated with ARC’s long-term incentive plan and $0.70- $0.75 per boe associated with ARC’s long-term incentive plan. Actual per boe costs for each of these components for the six months ended June 30, 2012 were $1.76 per boe and $0.78 per boe, respectively.(3) Includes impact of US$360 million and CDN$40 million of long-term notes to be issued by August 31, 2012.(4) The 2012 corporate tax estimate will vary depending on the level of commodity prices and represents only the current income tax expense.(5) Excludes amounts related to unbudgeted net acquisitions of land and small producing properties which totaled approximately $23 million in the first half of 2012.(6) Land expenditures and minor net property acquisitions are not included in the $600 million capital program .
  56. 56. ACCESS TO CAPITAL DEBTDebt raised from three different sources:1. Bank Credit Facility - $1 billion plus $25 million overdraft facility, 12 banks under facility • $484 million drawn under credit facility as at June 30, 2012 was repaid in full in August 2012 with proceeds from long-term note issuance and equity proceeds • The credit facility was extended to August 3, 2015 • Pre-approval for an additional $250 million (Accordion)2. Long-term notes • Private Placement market • Currently have US$271 MM and CDN$23 MM drawn (Q2 2012) • New Issue of US$360 MM and CDN$40MM of notes closed Aug 23, 20123. Prudential Master Shelf • Direct long-term relationship with major insurance company • Currently have US$106.3 MM drawn out of capacity of US$225 MM (Q2 2012) • Term extended to April 14, 2015
  57. 57. DEBT MATURITIES SPREAD OVER TIME• ARC’s long-term notes are structured so that they mature over a number of years; this reduces refinancing risk• ARC’s unused credit capacity of $1 billion (after debt and equity proceeds) allows for significant flexibility to repay debt Long-term Principal Note Repayment Schedule 120 100 80 C$ Millions 60 40 20 0 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
  58. 58. HEDGE POSITIONS AS OF JULY 31, 2012 Summary of Hedge Positions as at July 31, 2012 (1)(2) Jul – Oct 2012 Nov – Dec 2012 Jul – Dec 2012 2013 2014 - 2017Crude Oil – WTI:(US$/bbl) US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d Sold Call $ 91.11 18,000 $ 91.11 18,000 $ 91.11 18,000 $ 105.01 11,984 - - Bought Put $ 90.00 18,000 $ 90.00 18,000 $ 90.00 18,000 $ 95.01 11,984 - - Sold Put $ 63.44 16,000 $ 63.44 16,000 $ 63.44 16,000 $ 64.17 11,984 - - Crude Oil Floors as % of 2012 Guidance (3) 56% 56% 56% 37% -Natural Gas - Nymex:(US$/mmbtu) $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d Sold Call $ 3.86 130,000 $ 5.00 30,000 Bought Put $ 3.34 130,000 $ 4.00 30,000 Sold Swap $ 3.77 220,000 $ 3.48 175,000 3.71 205,082 Natural Gas Floors as % of 2012 Guidance (3) 63% 50% 59% 37% 9% Total Floors as % of 2012 Guidance (3) 55% 48% 53% 35% 5%(1) The prices and volumes noted above represent averages for several contracts and 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.(2) For crude oil, all put positions settle against the monthly average WTI price, providing protection against monthly volatility. Calls have been sold against either the monthly average or the annual average WTI price. For annual sold calls, volumes are based on full year and ARC will only have a negative settlement if prices average above the strike price for an entire year, providing ARC with greater potential upside price participation for individual months.(3) The above calculated floors (bought puts) are determined using the high end of 2012 guidance volumes.
  59. 59. RESERVES AND RESOURCESThe discussion in this presentation in respect of reserves and resources is subject to a number of cautionary statements,assumptions and risks as set forth below and elsewhere in this presentation. See also the definitions of oil and gas reservesand resources found at the end of this presentation.The reserves data set forth in this presentation is based upon an evaluation by GLJ Petroleum Consultants Ltd. ("GLJ") withan effective date of December 31, 2011 using forecast prices and costs. The reserves evaluation was prepared inaccordance with National Instrument 51-101 ("NI 51-101"). Crude oil, natural gas and natural gas liquids benchmarkreference pricing, as at December 31, 2011, inflation and exchange rates used in the evaluation are based on GLJsJanuary 1, 2012 pricing. Reserves included herein are stated on a company gross basis (working interest before deductionof royalties without including any royalty interests) unless noted otherwise.There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. Therecovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates onlyand there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquidreserves may be greater than or less than the estimates provided herein.See also ”NE B.C. Montney Vast Resource Base”, for further discussion regarding reserves and resources. See “Definitions of Oil and Gas Reserves and Resources” in this presentation.
  60. 60. KEY RESERVE INFORMATION 19% COMPOUND ANNUAL GROWTH• Reserves as of December 31, 2011* (mmboe) - Proved Producing 209 (98 mmboe liquids, 655 bcf gas) - Total Proved 360 (123 mmboe liquids, 1,419 bcf gas) - Proved Plus Probable 572 (170 mmboe liquids, 2,413 bcf gas) 700 19% CAGR 600 Probable Proved Producing Gas 37% 36% 500 Liquids Provedmmboe 400 Undeveloped Proved Non- 25% Producing 300 2% NGLs 200 6% Crude oil 100 24% 0 Natural Gas 70% INTERNAL DEVELOPMENT MONTNEY
  61. 61. 385 PER CENT RESERVE REPLACEMENT IN 2011• Fourth consecutive year of greater than 200% reserve replacement through the drill bit• Proved plus probable reserves increased 18% to 572 mmboe after divest of non-core assets with 14.6 mmboe of 2P reserves 700% Acquisitions 600% Development 500% 400% 300% 200% 100% 0% 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
  62. 62. DEFINITIONS OF OIL AND GAS RESERVES AND RESOURCESReserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from knownaccumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of establishedtechnology; and specified economic conditions, which are generally accepted as being reasonable. reserves are classified according to thedegree 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 equivalentto “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. Forecast 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.
  63. 63. DEFINITIONS OF OIL AND GAS RESERVES AND RESOURCES Economic Contingent Resources 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 andresources 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 Forecast 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.
  64. 64. This presentation contains forward-looking statements that may be identified by words like“outlook”, “estimates” and similar expressions. These forward-looking statements are based oncertain assumptions that involve a number of risks and uncertainties and are not guarantees offuture performance. Reference is made to the November 2, 2011 news release titled “ARCResources Ltd. Announces A $760 Million Capital Budget For 2012, Which includes a Twelve PerCent Production Growth Target”, the January 26, 2012 release titled “ARC Resources Ltd.Announces 18 per cent increase in year-end Reserves and results of updated IndependentResources Evaluation for Northeast British Columbia Montney Assets”; and the February 8, 2012release titled “ARC Resources Ltd. reports Fourth Quarter 2011 Results” which may be found onSEDAR at and are incorporated by reference and outline a number of risks anduncertainties associated with forward looking statements. Actual results could differ materiallyas a result of changes to ARC’s plans, the impact of changes in commodity prices, generaleconomic, market and business conditions as well as production development and operatingperformance and other risks associated with oil and gas operations.For further information about ARC Resources please visit our website www.arcresources.comOr contact: For further information about ARC’s properties pleaseInvestor Relations view our virtual field tour (in our operations section) atE-mail: www.arcresources.comT 403.503.8600 F 403.509.6417Toll Free 1.888.272.4900ARC Resources Ltd.1200, 308 – 4 Avenue S.W.Calgary, AB T2P 0H7