FORWARD LOOKING STATEMENTSThis presentation contains forward-looking information as to ARC‟s internal projections, expectations or beliefs relating to future events orfuture performance and includes information as to our future well inventory in our core areas, our exploration and development drilling andother exploitation plans for 2013 and beyond, and related production expectations, the volume of ARCs oil and gas reserves and thevolume of ARCs gas resources in the NE BC Montney (as defined herein), the recognition of additional reserves and the capital requiredto do so, the life of ARCs reserves, the volume and product mix of ARCs oil and gas production, future results from operations andoperating metrics. These statements represent management‟s expectations or beliefs concerning, among other things, future operatingresults and various components thereof or the economic performance of ARC Resources. The projections, estimates and beliefscontained in such forward-looking statements are based on managements assumptions relating to the production performance of ARC‟soil and gas assets, the cost and competition for services, the continuation of ARC‟s historical experience with expenses andproduction, changes in the capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of thecurrent regulatory and tax regime in Canada and necessarily involve known and unknown risks and uncertainties, such as changes in oiland gas prices, infrastructure constraints in relation to the development of the Montney in British Columbia, risks associated with thedegree of certainty in resource assessments and including the business risks discussed in the annual MD&A and related tomanagement‟s assumptions, which may cause actual performance and financial results in future periods to differ materially from anyprojections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautionedthat events or circumstances could cause actual results to differ materially from those predicted. Other than the 2013 Guidance which isupdated and discussed quarterly, ARC does not undertake to update any forward looking information in this document whether as to newinformation, future events or otherwise except as required by securities laws and regulations.We have adopted the standard of 6 mcf:1 bbl when converting natural gas to barrels of oil equivalent ("boes"). Boes may bemisleading, particularly if used in isolation. A boe conversion ratio of 6 mcf per barrel is based on an energy equivalency conversionmethod primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio basedon the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversionratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.Contained in the “Strategy” section is forward-looking information. The reader is cautioned that assumptions used in the preparations ofsuch information, particularly those pertaining to dividends, production levels, operating costs and drilling results, although consideredreasonable by the Company at the time of preparation, may prove to be incorrect. A number of factors, including, but not limited to:commodity prices, reservoir performance, weather, drilling performance and industry conditions, may cause the actual results achieved tovary from projections, anticipated results or other information provided herein and the variations may be material. Consequently, there isno representation by the Company that actual results achieved will be the same in whole or in part as those presented herein.
CORPORATE OVERVIEWProduction (2012 Annual) 93,500 boed Liquids 36,400 boed Natural gas 343 mmcfd Crude OilReserves (2P Gross) 607 mmboe NE BC/ NW AB Liquids-rich Gas 17.5 year RLI (1) Dry Gas NORTH ABCurrent monthly dividend $0.10Annualized total return 18% (2) REDWATER 7.5% (3)Enterprise value ~$8 billion (4) PEMBINAShares outstanding ~309 MM (5) SE SASK/ MANITOBADaily average trading volume 1.1 million shares S AB/ SW SASKNet debt (millions) $745 (1.0 X cash flow)(5)Member of S&P TSX 60 Index(1) Based on 2013 production guidance midpoint of 95,000 boe/d.(2) Annualized total return since inception to January 31, 2012, including January 2012 dividend, and assuming DRIP participation.(3) Annualized five year total return from January 31, 2008 (last 5 years).(4) Market Capitalization as at February 1, 2013 and net debt as at December 31, 2012.(5) As at December 31, 2012 based on annualized 2012 cash flow.
2012 FINANCIAL AND OPERATIONAL PERFORMANCE Three Months Ended Year Ended December 31 December 31(CDN$ millions, except per share and per boe amounts) 2012 2011 2012 2011Production (boe/d) 95,725 92,021 93,546 83,416 Gas 61% 64% 61% 62% Liquids 39% 36% 39% 38%Revenue 374.2 385.9 1,386.8 1,435.6 Gas 106.3 112.2 329.3 434.0 Liquids 267.9 273.7 1,057.5 1,001.6Funds from operations 208.4 226.6 719.8 844.3 Per share 0.68 0.79 2.42 2.95Operating Income 59.2 74.7 163.2 293.5 Per share 0.19 0.26 0.55 1.02Dividends 92.5 86.7 357.4 344.0 Per share 0.30 0.30 1.20 1.20Capital expenditures 190.2 195.0 608.0 726.0Net debt outstanding 745.6 909.7 745.6 909.7Weighted average number of shares outstanding(millions) 308.4 288.3 297.2 286.6Netback (pre-hedging) 26.85 27.55 24.17 29.16
VALUE PROPOSITION• We believe that top performing companies all have the following attributes: – Great assets – Operational excellence – Capital discipline – Management that delivers results – Strong balance sheet with financial flexibility• 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
PRODUCTION GROWTH Production Growth - Montney and Non-Montney 100,000 Montney Gas (boe/d) Montney Oil/Liquids (bbls/d) Non-Montney Gas (boe/d) Non-Montney Liquids (boe/d) 80,000 Forecast Total Non-Montney productionProduction (Boe/d) 60,000 40,000 20,000 Forecast Forecast -
INCOME AND GROWTH ARC HAS DELIVERED BOTH• ARC has a 16 year history of risk managed value creation - Provided an 18% annual total return since inception - Paid out $4.6 billion in total dividends - $28.68/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* Gas 75,000 LiquidsBoe/d 50,000 Proved Undeveloped 25,000 20% 0 1997 1998 1999 2001 2002 2003 2005 2006 2007 2008 2009 2010 2011 2012 1996 2000 2004 * Compound annual growth rate
200 PER CENT RESERVE REPLACEMENT IN 2012• 2012 is the fifth consecutive year of greater than 200% reserve replacement• Increase in 2P reserves of 6% to 607 mmboe• Replaced 214% of crude oil and liquids reserves, increasing 9% to 186 mmbbls• Reserves have more than doubled over the past five years, providing a clear line of sight for resource development 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 2012
CAPITAL EFFICIENCY EXCELLENT FD&A PERFORMANCE IN 2012• Replaced 200% of production at an all in FD&A cost of $9.34/boe(1)• 2012 recycle ratio of 2.7 times based on F&D of $9.01/boe(1) and pre-hedging netback of $24.17/boe• Three year FD&A of $7.80 before FDC FD&A Costs and Recycle Ratio (1) $25.00 6.0 FD&A 5.0 $20.00 F&D Recycle Ratio 4.0 Recycle Ratio $15.00 3.0 $10.00 2.0 $5.00 1.0 $- - 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 (1) FD&A and F&D for 2P reserves before Future Development Capital (“FDC”) (2) FD&A costs including FDC were $13.26/boe and $13.30/boe, respectively, for 2012 and three year average.
SUSTAINABLE DIVIDEND $4.6 BILLION IN DIVIDENDS SINCE INCEPTION• The dividend is a critical component of our business strategy• Sustained dividend levels through commodity price cycles due to quality of assets, active hedging program and balance sheet strength Historic Dividends and Funds from Operations $5.00 100% $4.50 $4.00 80% $3.50 Payout Ratio % $3.00 60% $/share $2.50 $2.00 40% $1.50 $1.00 20% $0.50 $- 0% 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Cash Flow per Share Dividend per Share Payout Ratio Payout Ratio including DRIP
FOCUS ON OIL AND LIQUIDS 15% OIL AND LIQUIDS PRODUCTION GROWTH• IN 2012 oil and liquids development resulted in 15% growth in crude oil and Focus on crude liquids production to ~36,400 boe/d in 2012 primarily at Ante Creek, Pembina and Goodlands• Crude oil and liquids comprised 39% of total 2012 production while contributing 76% of total year revenue• Drilled 144 gross operated wells in 2012 (98% oil and liquids-rich) Q4 Revenue 3% 3% 24% 34% Q4 Production 2012 2012 5% Production Revenue 61% Crude Oil 2% 68% Condensate NGL’s Natural Gas
OUR STRATEGYRISK 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
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
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, 2012 using forecast prices and costs. The reserves evaluation was prepared in accordancewith National Instrument 51-101 ("NI 51-101"). Crude oil, natural gas and natural gas liquids benchmark reference pricing, asat December 31, 2012, inflation and exchange rates used in the evaluation are based on GLJs January 1, 2013 pricing.Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without includingany 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.
KEY RESERVE INFORMATION 18% COMPOUND ANNUAL GROWTH • Reserves as of December 31, 2012 (mmboe) - Proved Producing 201 (100 mmboe liquids, 607 bcf gas) - Total Proved 364 (127 mmbbls liquids, 1.4 Tcf gas) - Proved Plus Probable 607 (186 mmbbls liquids, 2.5 Tcf gas) 700 18% CAGR Probable Proved 600 Producing Gas 33% 40% 500 Liquids Provedmmboe 400 Undeveloped 25% Proved 300 Non-Producing 2% 2P Reserves 200 NGLs 6% Crude 100 oil 25% 0 Natural Gas 69% INTERNAL DEVELOPMENT MONTNEY
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, 2013 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 thispresentation, 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 budgetconstraints, ARCs policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view ofARC on gas prices, 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.
MONTNEY GROWTH ASSETS RESERVES AND RESOURCES• Independent Resources Evaluation conducted by GLJ effective December 31, 2012• In addition to the 50.1 Tcf of natural gas resource, an oil resource of 1.5 billion barrels was identified at Tower• The amount of natural gas and liquids ultimately recovered from ARC‟s NEBC Montney resource will be primarily a function of the future price of both commodities 0% Porosity Cut- 3% Porosity Cut- Natural Gas Resource Categories (1) (2) (3) (4) Off (Tcf) Off (Tcf) Total Petroleum Initially In Place (TPIIP) 50.1 38.5 Discovered Petroleum Initially In Place (DPIIP) 27.2 22.3 Undiscovered Petroleum Initially In Place (UPIIP) 22.9 16.2 (1) TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off which means that all gas bearing rock has been incorporated into the calculations. (2) The Resource Categories do not include the free oil/liquids. (3) All volumes in table are company gross and raw gas volumes. (4) TPIIP and DPIIP include 0.7 Tcf of solution gas associated with Tower oil. 3% Porosity Cut- 6% Porosity Cut- Oil Resource Categories (1) (2) (3) Off (mmbbls) Off (mmbbls) Total Petroleum Initially In Place (TPIIP) 1,467.0 640.1 Discovered Petroleum Initially In Place (DPIIP) 1,467.0 640.1 (1) TPIIP and DPIIP have been estimated using a three percent porosity cut-off for oil due to lower mobility for oil relative to gas. (2) All volumes in table are company gross. (3) The oil DPIIP is a Stock Tank Barrel (“STB”).
MONTNEY GROWTH ASSETSRESERVES AND RESOURCES 2012 Best 2011 BestReserves and Economic Contingent Resources (1)(2) Estimate EstimateNatural Gas (Tcf)Reserves (3) 2.1 1.9Economic Contingent Resources 4.2 4.1Natural Gas Liquids (mmbbls) (4)Reserves (3) 24.7 21.1Economic Contingent Resources 111.2 101.0Oil (mmbbls)Reserves (3) 7.6 0.1Economic Contingent Resources 12.6 0.5(1) All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable.(2) All volumes in table are company gross and sales volumes.(3) For reserves, the volume under the heading Best Estimate are 2P reserves.(4) The liquid yields are based on average yield over the producing life of the property. 2012 Best 2011 BestProspective Resources (1)(2) Estimate EstimateNatural gas (Tcf) 3.8 4.0Natural gas liquids (mmbbls) 113.6 98.0 (1) All UPIIP other than Prospective Resources has been categorized as unrecoverable. GLJ estimated DPIIP values using a porosity cut-off of three per cent for natural gas and six per cent for oil. (2) All volumes in table are company gross and sales volumes.
Total Company 2013 CAPITAL PROGRAM SETTING THE STAGE FOR 2014 PRODUCTION • GROWTH $830 million capital program (~178 gross operated wells) with majority of spending in oil and liquids-rich gas plays and infrastructure. NE BC - $324MM(1) ~36 gross operated wells 2013 Capital Budget NE BC - $324MM* (2) ~44,500 boe/dgross operated wells ~36 Volumes ~$100MM42,099 boe/d directed towards NORTHERN AB - $211MM(1) Year ~37 NORTHERN AB - $211MM* facilities at Parkland/Tower towards gross gross operated wells operated wells Capital Average Gross Net ~$100MM directed ~37 ~15,000 boe/d(2) $MM (boe/d) Wells Wells facilities at Parkland/Tower 14,163 boe/d Operated* 774 84,500 178 160 Parkland/Tower, Dawson Non-Operated 56 10,600 103 10 REDWATER - $10MM(1) REDWATER - $10MM* 0 wells Total 830 95,000 281 170 0 wells ~3,600 boe/d(2) 3,539 boe/d *Corporate $22 MM PEMBINA - $131MM (1) ~54 gross operated - $131MM* PEMBINA wells ~54 gross operated wells ~11,000 boe/d(2) 9,220 boe/d S. AB/SW SASK - $6MM(1) SE SASK/MANITOBA - $126MM(1) 0 wells AB/SW SASK - $6MM* gross operated wells SE ~51 ~7,900 boe/d(2) 0 wells ~12,600 boe/d(2) 6,214 boe/d (1) Includes Operated and Non-operated. (2) 2013 annual average production.
2013 BUDGET 2013/2014 Production Growth 2013 Budget - Volumes (BOED) All Properties OPT DEV PO ACTUAL140,000 2014 base production, does not show 2014 CAPEX program120,000100,000 80,000 Base Decline ~22% Base Decline ~22% Base Decline ~22% 60,000 40,000 • Overall Corporate base decline of ~ 22%. • Oil and Liquids production increases ~ 5%. 20,000 • Gas production grows by ~2%. • Risks to the plan: commodity prices, timing issues and cost pressures related to service sector demand for equipment and personnel, regulatory approvals and liquids sales pipeline capacities. 0
ASSET OVERVIEW• ARC‟s key assets with the greatest value creation opportunities and highest future reserves contributions are: Montney Growth Assets • Ante Creek – oil resource play • Parkland/Tower– oil and liquids-rich gas resource play • Dawson – natural gas resource play • West Montney – liquids-rich and natural gas resource play Base Assets • Pembina Cardium – oil resource play • Goodlands and SE Saskatchewan – oil resource play• ARC plans to develop these opportunities, subject to a supportive commodity price environment, over the next five years
ASSET OVERVIEWWESTERN CANADA Montney Growth Assets Base Assets Blueberry • Attachie • • Tower Septimus • • Parkland Sunset/Sunrise • • Dawson Sundown • • Ante Creek • Redwater Natural Gas • Pembina Liquids-rich gas • Hatton Crude Oil • Weyburn • Jenner • Midale • Goodlands Lougheed •
ANTE CREEKASSET DETAILS Net production (boe/d) – Q4 2012 10,300 Liquids (bbls/d) 5,100 Gas (mmcf/d) 32 Production split % (liquids/gas) ~50/50 Land (Montney net sections) 267 Working Interest ~99% 10-07 Gas Plant Reserves (2P mmboe) 47.7 Liquids (mmbbls) 20.9 Gas (bcf) 160 10-36 Gas Plant Reserve Life Index 11 2013 Plans • Increase production to ~15,000 boe/d by end of 2013 as we “drill to fill” new gas plant • Transition to pad drilling to minimize environmental footprint and optimize operational efficiency
ANTE CREEK OIL – OPERATIONAL EXCELLENCE• INDUSTRY LEADINGand complete costs are <75% of industry average. ARC‟s Ante Creek/Kaybob Montney drill CAPITAL EFFICIENCY • ARC $3.8 MM per well vs. Industry $5.3 MM per well (1)• ARC‟s Ante Creek average 30 day IP rate in the Ante Creek/Kaybob area is comparable to Industry 1,200 30 Day Average Daily IP Rate (boe/d) 1,000 800 ARC Gas ARC Liquids Others Gas Others Liquids 600 ARC Average IP ~ 350 boe/d 400 200 0 (1) Source information from Well Completions & Frac Database – Canadian Discovery Ltd. and Introspec Energy Group Inc., wells rig released Jan 2011 to current. (2) All reported wells from 60-20W5 to 69-26W5. Taken within first month of production, includes only those originally licensed to ARC and does not include wells acquired by ARC. All wells have Oil IP3 > 0.
ANTE CREEK MONTNEY DEVELOPMENT ECONOMICS 450 Key Metrics DCET Capex per well ($MM) 4.0 400 Reserves per well (Mboe) 283 IP (1 mo) (boe/d) 400 350 IP (12 mo) (boe/d) 245 Economics ($85/bbl) $4/GJ $3/GJ 300 IRR (% AT) 45% 35% Recycle Ratio 2.1 2.0 250 BOE/D 200 150 100 50 0 0 6 12 18 24 30 36 Months• All economics run at FLAT price forecasts with C$85/bbl and $3 GJ AECO• Liquid yield assumptions – NGL 21 bbl/mmcf, COND 9.5 bbl/mmcf
ANTE CREEK 2013 BUDGET – $186MM OPERATED 2013 Budget - Volumes (BOED) Operated DEV PO ACTUAL16,00014,00012,00010,000 8,000 Base Decline ~28% 6,000 4,000 2,000 • Drill 34 wells and grow production to 15,000 boed by the end of 2013. • Drill 4 step-out wells to hold land (expiries) and prove up undeveloped land base. 0
MONTNEY LANDSWORLD CLASS RESOURCE • NE BC Montney lands are a major growth engine. • Significant opportunity to grow liquids production. • Total BC Montney production of ~235 mmcf/d natural gas and 2,600 bbls/d oil and liquids with Dawson contributing approximately 165 mmcf/d • New, 60 mmcf/d gas plant with 130 bbls/mmcf of liquids handling capacity approved for Parkland/Tower. Site clearing commenced and plant is expected to be on-stream in early 2014. • Ideally positioned with access to west coast and other Alberta markets.
MONTNEY LANDS SIGNIFICANT MONTNEY PRESENCE • ARC has a significant presence in B.C. and Alberta Montney • First to drill B.C. Montney horizontal well in 2005 at Dawson BC Montney Hz Wells – Rig Released by BC Montney Gross Operated Raw Gas B.C.Operator (since Jan - by Operator Montney HZ Wells - Rig Released Wells 1, 2003) B.C. MontneyProductionGas Production (mmcfe/d)* Gross Operated Raw (mmcfe/d)450 400 Thousands400 350350 300 3Q2012 Production - mmcfe/d300 250250 200200 150150100 10050 50 0 0 ECA RDS MUR ARX TLM PRQ TOU CNQ CR CAN PPY PGF ECA RDS ARX MUR TLM PRQ TOU CNQ CR PPY PGF CAN = Canbriam (Private) Source: ITG IR, raw data provided by geoSCOUT Wells licensed since Jan. 1, 2003 Source: ITG IR, raw data provided by geoSCOUT * - i ncl udes wellhead condensate
MONTNEY HORIZONTAL WELLS 30 DAY HZ IP RATES GLACIER - TOWN ARC’S MONTNEY WELLS HAVE EXCEEDED EXPECTATIONS 16,000 14,000 ARC Others 12,000 10,000Production Rate (mcf/d) ARC Wells P50 = 5.2 Mmcf/d 8,000 Other Wells P50 = 3.4 Mmcf/d 6,000 4,000 2,000 0 (1) Graph represents peak calendar day IP rates for the first month of production to November 2012. (2) Region includes all horizontal wells from NE BC and NW AB Montney.
PARKLAND/TOWER EVALUATING POTENTIAL AND DEVELOPING EXISTING LANDS Parkland Tower Net production Q4 2012 (boe/d) 7,600 1,200 Liquids (bbls/d) 940 770 Gas (mmcf/d) 40 2.5 Land (net sections) 23 56 Working Interest ~84% ~90% Reserves (2P mmboe) 50.8 15.1 Liquids (mmbbls) 8.5 8.5 Gas (bcf) 254 39.7 Farm-in Lands Reserve Life Index 18 242013 Plans• 11 wells drilled at Tower in 2012, 14 wells drilled since late 2011• Nine operated wells now tied-in at Tower, with restricted production rates as result of liquids handling facility limitations• First of two, eight well pads spud in Q4 2012; continue with pad drilling program in 2013• Received regulatory approval to construct two 60 mmcf/d gas processing and liquids handling facilities. Site clearing started late Dec 2012; expect to commission the first phase in early 2014.
PARKLANDLAYERED DEVELOPMENT • Producing Formation: Upper Montney Gross thickness 100m Net pay 90m Porosity 6% Permeability 0.01 to 0.1 mD • Large DGIP volumes in Parkland, currently have modest recoveries per well • 100 Bcf DGIP per section, ~100 meters of pay • EUR/well typically ~ 5 Bcf (20% Recovery factor)
PARKLAND LAYERED WELL PERFORMANCE • Drilled and completed 2 wells in upper sand of the Upper Montney and 1 well offset in the lower sand in 2011 • All wells had similar IP, ranging from 4.7 – 5.1 MMcfd • No pressure response between the upper wells and the lower Montney well to date • Lack of vertical communication indicates potential of un-stimulated rock • Lower sand Montney performance to date in line with upper type well Layered Well Placement 7,000 Upper #1 Upper #2 6,000 400 m 5,000 Rate Mcfd 4,000 3,000 Lower Montney50 m 2,000 1,000 200 m 200 m 0 Upper MTY Well #1 (10 Stage) Upper MTY Well #2 (9 Stage) Lower MTY Well (9 Stage)
TOWER 2012 ACCOMPLISHMENTS Tower Production 2012 Accomplishments: 2,500 • 2012 Operated Program average 30 day IP rate: 375 boe/d per well 2,000 Gas (Forecast) • Production volumes limited due to Liquids (Forecast) liquid handling restrictions Gas 1,500 Liquids • First of two 8 well developmentSales (boe/d) pads to be completed in 2013; spud ARC purchased in late October 2012 1,000 the Tower property in 2010 2013 Plans: • 60 mmcf/d gas processing and 500 liquids handling facility expected on-stream early 2014; site clearing - and pile driving commenced 2010 2011 2012 2013 • Continue with pad drilling program in 2014 – expect „step‟ production profile as all wells brought on at one time (8 wells per pad) (1) ARC purchased the Tower property in August 2010.
TOWEROPERATIONAL EXCELLENCE - MINIMIZINGFOOTPRINT • Pad drilling will substantially minimize surface land footprint • Expect 8 to 16 wells per pad depending on reservoir characteristics • Considerable cost savings related to pad development compared to single well leases, up to 20% • Numerous operational and capital efficiencies due to pad development: reduced rig moves; single lease to survey, acquire and build; consolidated facilities, electricity to one site, single trunk line • The cycle time from spud to on production is extended by 5 months for an 8 well pad. All wells are drilled and completed before production commences
TOWER MONTNEY DEVELOPMENT ECONOMICS 600 Key Metrics DCET Capex per well ($MM) 5.3 Reserves per well (Mboe) 400 500 IP (1 mo) (boe/d) 500 IP (12 mo) (boe/d) 260 Economics ($85/bbl) $4/GJ $3/GJProduction Rate (boe/d) 400 IRR (% AT) 41% 37% Recycle Ratio 3.3 3.1 300 200 100 0 0 6 12 18 24 30 36 Months • All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO • Difference between EDM and quality & transport adjustments = +4.25 $/bbl • Liquid yield assumptions – 79.2 bbl/MMcf, shrinkage = 20.6%
TOWER/PARKLAND 2013 BUDGET – $249MM OPERATED 2013 Budget - Volumes (BOED) Operated DEV PO ACTUAL25,00020,000 2014 base production, does not include 2014 CAPEX program15,00010,000 Base Decline ~21% 5,000 • Drill 24 horizontal wells. • Construct the oil handling, gas processing and pipeline infrastructure with a planned start-up in early 2014 0 • Significant capital being spent in 2013 with volumes coming on-stream in 2014.
DAWSONASSET DETAILS Net production (boe/d) –Q4 2012 28,800 Liquids (bbls/d) 800 Gas (mmcf/d) 168 45 mmcfd Compressor Production split % (liquids/gas) ~97% gas Station 120 mmcfd Land (Montney net sections) 130 Gas Plant Working Interest ~96% Reserves (2P mmboe) 181 Liquids (mmbbls) 5.2 Gas (bcf) 1,052 Reserve Life Index 17 2013 Plans • Inventory of completed gas wells to be tied-in during first half of 2013 • Drill 9 wells in 2013,maintain 2013 production flat at 165 mmcf/d
DAWSON TYPE CURVE GROWTH• 2008 type curve analysis was completed using initial production results and verified with a vertical well production multiplier• 2009-2011 Type curve used P90 IP‟s with decline analysis and assigned decline exponent rate• 2012 Type curve realized the consistent flat production, coupled with a sharp decline exponent rate• 2013 type curve uses historical pressure and production data from 60+ wells to estimate existing remaining reserves and forecast future wells 6,000 2013 Type Curve 5,000 2012 Type Curve 2009-2011 Type CurveGas Rate (Mcf/d) 4,000 2008 Type Curve 3,000 2,000 1,000 0 0 3 6 9 12 15 18 21 24 27 30 33 36 Months on Production
DAWSON MONTNEY DEVELOPMENT ECONOMICS 7,000 Key Metrics DCET Capex per well ($MM) 5.2 6,000 Reserves per well (Bcf) 7.1 IP (1 mo) (MMcf/d) 5.0 IP (12 mo) (MMcf/d) 4.8 5,000 $4/GJ $3/GJ Economics ($85/bbl) IRR (% AT) 72% 44%Gas Rate (Mcf/d) 4,000 Recycle Ratio 3.8 2.8 3,000 2,000 1,000 0 0 6 12 18 24 30 36 Months • All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO • Liquid yield assumptions – 3.1bbl/mmcf C5, 0.7bbl/mmcf C4, 0.4bbl/mmcf C3
DAWSON2013 BUDGET – $52MM OPERATED 2013 Budget - Volumes (BOED) Operated PO ACTUAL35,00030,00025,00020,000 Base Decline ~28%15,00010,000 5,000 • Dawson is a world-class asset that continues to exceed expectations. • Drill 9 horizontal Montney wells, on two pads, add compression to 1-34 compressor station and optimize gas plant. 0
PEMBINA ASSET DETAILS Net production (boe/d) – Q4 2012 12,300 Cardium production ~82% Production split % (liquids/gas) ~75%/25% Land (Cardium net sections) 134 Working Interest ~79% Reserves (2P mmboe) Cardium 49.4 Reserve Life Index 152013 Plans• ARC is the second largest operator in the Pembina area• Continued focus on long term value through prudent reservoir and waterflood management• 11-31 Berrymoor plant expansion expected on stream May 2013• Drill 52 Hz wells and two vertical injectors throughout the Pembina area (operated)
PEMBINA OIL AND LIQUIDS GROWTHARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD Pembina ~33% Increase in Oil & Liquids Production since 2006 14,000 12,000 10,000 8,000Boe/d Q4 2012 - 9,200 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
PEMBINA OIL – OPERATIONAL EXCELLENCE INDUSTRY LEADING • ARC‟s average drill and complete costs are 80% of industry average CAPITALMM per well vs. Industry $2.4 MM per well • ARC $1.9 EFFICIENCY (1) • ARC‟s Cardium well performance is comparable to industry peer average 450 Cardium Area IP Average (3 Month Rate) 400 350 ARC Others 300 250IP3 (boe/d) ARC Average Oil IP 200 ~ 137 bbls/d 150 100 50 -(1) Source information from Well Completions & Frac Database – Canadian Discovery Ltd. and Introspec Energy Group Inc., wells rig released Jan 2011 to Nov 2012.(2) IP3 data from Accumap - includes wells with greater than 750hrs, wells within TWP 47-49 RNG 5-10W5, on production after January 1, 2008.
PEMBINA 2013 BUDGET – $131MM 2013 Budget - Volumes (BOED) Operated and Non-Operated DEV PO ACTUAL14,00012,00010,000 8,000 Base DeclineBase Decline ~23% ~23% Base Decline ~23% 6,000 4,000 • Drill 52 gross operated Hz wells and 2 vertical injectors throughout the Pembina area. 2,000 • Grow operated production to >10,000 boed and total production to over ~12,000 boed. • Continue to optimize waterfloods throughout the area by spending $9 MM (gross) on drilling water injection wells, converting wells producers to injectors and injection stimulations. 0
SE SASKATCHEWAN / MANITOBA OIL ASSET DETAILSNet production (boe/d) – Q4 2012 12,200 2013 Plans:Production split 99% liquids • Continue to drill horizontally in a number of properties that were previously only verticallyLand (net sections) 241 exploited.Working Interest ~81% • Drilling 51 gross operated wells in 2013 with significant focus at Goodlands in Manitoba.Reserves (2P mmboe) 48.1 • Continued focus on long term value throughReserves Life Index 11 prudent reservoir and waterflood management
WHY INVEST IN ARC RESOURCES• ARC is a top-tier oil and natural gas producer focused on “Risk Managed Value Creation”• Extensive land position in top quality resource plays provides significant growth opportunity. • Significant near-term oil and liquids growth opportunities • Significant long-term natural gas growth opportunity in B.C. Montney• Diverse inventory of high quality oil, liquids-rich gas and natural gas development opportunities provides optionality through commodity price cycles• History of proven performance • Grown absolute production from 9,500 boe/d to ~95,000 boe/d to date • Grown P+P reserves from 47 mmboe to 607 mmboe to date • Progressive approach of applying new technologies to “unlock” value • Proven track record of “Operational Excellence” in both cost management and safety• Solid balance sheet with protective hedging program• Experienced management team with track record of delivering results
PRODUCTION GROWTH Production Growth - Montney and Non-Montney 100,000 Montney Gas (boe/d) Montney Oil/Liquids (bbls/d) Non-Montney Gas (boe/d) Non-Montney Liquids (boe/d) 80,000 Forecast Total Non-Montney productionProduction (Boe/d) 60,000 40,000 20,000 Forecast Forecast -
2013 BUDGET($ millions) 2011 (Actual) 2012 (Actual) 2013 (Budget)Development 396 408 563Development – Facilities 92 73 162Maintenance 21 23 35Optimization 14 6 13Exploration & Seismic 94 49 11Enhanced Oil Recovery 20 21 27Land 75 10 -Other 14 18 19Total Capital $726 $608 $830(1) Other 2013 budgeted capital of $19 million comprises capitalized General and Administrative Expenses (“G&A”) including a portion of Long-Term Incentive Plan (“LTIP” or the “Whole Unit Plan”) expense, information technology and corporate office capital.
2013 GUIDANCE 2012 Guidance 2012 Actual 2013 Guidance Oil (bbls/d) 30,000 – 31,000 31,454 32,000 – 34,000 Condensate (bbls/d) 2,100 – 2,500 2,217 1,800 – 2,000 Gas (mmcf/d) 340 – 350 342.9 340 – 350 NGL‟s (bbls/d) 2,100 – 2,600 2,728 2,400 – 2,800 Total (boe/d) 91,000 – 94,000 93,546 93,000 – 97,000 Operating costs 9.50 – 9.70 9.40 9.50 – 9.70 Transportation costs 1.30 – 1.40 1.29 1.40 – 1.50 G&A expenses (1) 2.45 – 2.60 2.84 2.50 – 2.70 Interest 1.20 – 1.30 1.32 1.20 – 1.30 Income Taxes (2) 0.90 – 1.05 0.87 1.05 – 1.15 Capital expenditures (millions) (3) 600 830 608 Net property and undeveloped land acquisitions ($ millions) (4) 25 - 50 32 - Weighted average shares outstanding (millions) (5) 297 297 311(1) The 2013 G&A expense before Long-Term Incentive Plan approximates $1.75 - $1.90 per boe.(2) 2013 Corporate tax estimate will vary depending on level of commodity prices.(3) The $830 million 2013 capital budget does not include land and net property acquisitions as this amount is unbudgeted.(4) Based on weighted average shares plus the dilutive impact of share options outstanding during the period.
ACCESS TO CAPITAL DEBTDebt raised from three different sources:1. Bank Credit Facility - $1.0 billion plus $25 million overdraft facility, 12 banks under facility • Undrawn as at December 31, 2012 • Term extends to August 3, 2016 • Pre-approval for an additional $250 million (Accordion)2. Long-term notes • Private Placement market • Currently have US$631 million and CDN$63 million drawn (Q4 2012)3. Prudential Master Shelf • Direct long-term relationship with major insurance company • Currently have US$97 million drawn out of capacity of US$225 million (Q4 2012) • Term extends to April 14, 2015
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 undrawn credit facility of $1.0 billion allows for significant flexibility to repay debt Long-term Notes Principal Repayment Schedule 120 100 80 C$ Millions 60 40 20 0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2004 Series A 4.62% 2004 Series B 5.10% Pru MS Series C 5.42% 2009 Series C 7.19% 2009 Series D 8.21% Pru MS Series D 4.98% 2009 Series E 6.50% 2010 Series F 5.36% 2012 Series G 3.31% 2012 Series H 3.81% 2012 Series I 4.49% Assumes USD/CAD exchange rate = $1.00
HEDGE POSITIONS AS OF FEBRUARY 6, 2013 Summary of Hedge Positions as at February 6, 2013 (1) 2013 2014 2015 - 2017 Crude Oil – WTI (2): (US$/bbl) US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d Ceiling 104.01 14,992 100.00 2,479 - - Floor 95.01 14,992 90.00 2,479 - - Sold Floor 64.17 11,984 70.00 1,240 - - Crude Oil Floors as % of Guidance (3) 43% 6% - Natural Gas – Nymex (3): (US$/mmbtu) US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d US$/mmbtu mmbtu/d Ceiling 3.95 168,767 $ 4.83 90,000 $ 5.00 60,000 Floor 3.41 168,767 $ 4.00 90,000 $ 4.00 60,000 Natural Gas Floors as % of Guidance (3) 49% 23% 15% Total Floors as % of Guidance (3) 45% 16% 9%(1) The prices and volumes noted above represent averages for several contracts representing different periods 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 2013, all floor positions settle against the monthly average WTI price, providing protection against monthly volatility. Positions establishing the “Ceiling” have been sold against either the annual average WTI price or a six month average WTI price. In the case of settlements on annual and six month term positions, ARC will only have a negative settlement if prices average above the strike price for an entire year or the six month period, respectively. These positions provide ARC with greater potential upside price participation for individual months.(3) Based on 2013 guidance midpoint of 95,000 boe/d for 2013, and 2014 production estimate of 110,000 boe/d (60% natural gas, 40% crude oil and liquids) for 2014 through 2017 hedge levels. Crude oil floors as a % of production are based on guidance volumes for crude oil and condensate production for the respective period.
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 occurringaccumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. “Totalresources” 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. 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.
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. Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely thatthe actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should beat least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. Forecast
This presentation contains forward-looking statements that may be identified by words like“outlook”, “estimates” and similar expressions. These forward-looking statements are based oncertain assumptions that involve a number of risks and uncertainties and are not guarantees offuture performance. Reference is made to the section titled “Forward Looking Statements” at thebeginning of the presentation and also to the November 7, 2012 news release titled “ARC ResourcesLtd. Announces an $830 Million Capital Budget For 2013, Setting the Stage for SignificantProduction Growth in 2014” which may be found on SEDAR at www.sedar.com and which arehereby incorporated by reference in this presentation and which outline a number of assumptions,risks and uncertainties associated with forward looking statements. Actual results could differmaterially 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 andoperating performance and other risks associated with oil and gas operations.For further information about ARC Resources please visit our website www.arcresources.comOr contact:Investor RelationsE-mail: email@example.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