Investor Presentation. June 2013

Transcription

1 Investor Presentation June 2013

2 FORWARD LOOKING STATEMENTS This presentation contains forward-looking information as to ARC s internal projections, expectations or beliefs relating to future events or future performance and includes information as to our future well inventory in our core areas, our exploration and development drilling and other exploitation plans for 2013 and beyond, and related production expectations, the volume of ARC's oil and gas reserves and the volume of ARC's gas resources in the NE BC Montney (as defined herein), the recognition of additional reserves and the capital required to do so, the life of ARC's reserves, the volume and product mix of ARC's oil and gas production, future results from operations and operating metrics. These statements represent management s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of ARC Resources. The projections, estimates and beliefs contained in such forward-looking statements are based on management's assumptions relating to the production performance of ARC s oil and gas assets, the cost and competition for services, the continuation of ARC s historical experience with expenses and production, changes in the capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of the current regulatory and tax regime in Canada and necessarily involve known and unknown risks and uncertainties, such as changes in oil and gas prices, infrastructure constraints in relation to the development of the Montney in British Columbia, risks associated with the degree of certainty in resource assessments and including the business risks discussed in the annual MD&A 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 2013 Guidance which is updated and discussed quarterly, ARC does not undertake to update any forward looking information in this document whether as to new information, future events or otherwise except as required by securities laws and regulations. We have adopted the standard of 6 mcf:1 bbl when converting natural gas to barrels of oil equivalent ("boes"). Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. Contained in the Strategy section is forward-looking information. The reader is cautioned that assumptions used in the preparations of such information, particularly those pertaining to dividends, production levels, operating costs and drilling results, although considered reasonable 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 to vary from projections, anticipated results or other information provided herein and the variations may be material. Consequently, there is no representation by the Company that actual results achieved will be the same in whole or in part as those presented herein.

3 CORPORATE OVERVIEW 10 th Largest Canadian Listed Producer* Production (Q1 2013) Reserves (2P Gross) 95,472 boe/d 607 mmboe Reserve Life Index 17.5 years (1) Annual Dividend $1.20/share Annualized Total Return: Since Inception 19% (2) Since Jan 1, % (3) Enterprise Value ~$9 billion (4) Member of S&P TSX 60 Index *Canadian production 2012 annual average (1) Based on 2013 production guidance midpoint of 95,000 boe/d. (2) Annualized total return since inception to May 29, 2013, including May 2013 dividend, and assuming DRIP participation. (3) Annualized total return from January 1, 2008 to May 29, (4) Market Capitalization as at May 29, 2013 and net debt as at March 31, 2013.

4 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

5 RISK MANAGED VALUE CREATION PRODUCTION GROWTH

6 INCOME AND GROWTH ARC HAS DELIVERED BOTH ARC has a 16+ year history of risk managed value creation Provided an 19% annual total return since inception Paid out $4.7 billion in total dividends - $29.08/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 Proved Undeveloped 20% * Compound annual growth rate

7 PER SHARE GROWTH RESERVES AND PRODUCTION PER SHARE GROWTH Consistent growth in absolute and per share reserves and production over the past five years Production per thousand shares 2P Reserves per share Normalized per thousand shares (1) Dividend adjusted per thousand shares (2) (1) Normalized production and reserves per share indicates that all periods as presented have been adjusted to reflect a net debt to capitalization of 15 per cent for comparability amongst all periods presented. (2) Dividend adjusted production and reserves per share assumes that historic dividends paid since January 1, 2008 have been reinvested by ARC, resulting in a reduction of the number of shares outstanding and, in turn, higher normalized production per share and normalized reserves per share.

8 200 PER CENT RESERVE REPLACEMENT IN 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 Reserve Replacement

9 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/bbe Three year FD&A of $7.80 before FDC (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.

10 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

11 FOCUS ON OIL AND LIQUIDS OIL AND LIQUIDS PRODUCTION GROWTH IN 2013 Focus on crude oil and liquids development resulted in liquids production of ~37,400 boe/d in Q1 2013, growth of 3% relative to Q attributed to Ante Creek, Pembina, Tower and Goodlands Crude oil and liquids comprised 39% of Q production while contributing 72% of total revenue Drilled 60 gross operated wells in Q (92% oil and liquids-rich) Q Production Crude Oil Condensate NGL s Natural Gas Q Revenue

12 OUR STRATEGY RISK MANAGED VALUE CREATION

13 RESERVES AND RESOURCES The 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 reserves and 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") with an effective date of December 31, 2012 using forecast prices and costs. The reserves evaluation was prepared in accordance with National Instrument ("NI "). Crude oil, natural gas and natural gas liquids benchmark reference pricing, as at December 31, 2012, inflation and exchange rates used in the evaluation are based on GLJ's January 1, 2013 pricing. Reserves included herein are stated on a company gross basis (working interest before deduction of 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. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves 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.

14 NE B.C. MONTNEY VAST RESOURCE BASE We engaged GLJ to provide a resources evaluation of our properties at Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown and Blueberry located in northeastern British Columbia and at Pouce Coupe located in northwestern Alberta (collectively, the "Evaluated Areas" or "NE BC Montney"). 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 GLJ's January 1, 2013 pricing The estimates of Economic Contingent Resources (or ECR), DPIIP, TPIIP, UPIIP and Prospective Resources should not be confused with reserves and readers should review the definitions and notes set forth at the end of this presentation. Actual natural gas resources may be greater than or less than the 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 no certainty that any portion of ARC's resources that have been categorized as undiscovered resources will be discovered. Furthermore, if discovered, there is 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 in order for additional resources to be recovered in the future. The principal risks that would inhibit the recovery of additional reserves relate to the potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the capital which would be required to develop the resources, low gas prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fraccing technology and applications. The contingencies that prevent the ECR from being classified as reserves are due to the early evaluation stage of these potential development opportunities. Additional drilling, completion, and test results 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 Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, ARC's 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 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.

15 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)

16 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% Natural Gas Resource Categories (1) (2) (3) (4) Porosity Cut-Off (Tcf) 3% Porosity Cut-Off (Tcf) Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially In Place (UPIIP) (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. Oil Resource Categories (1) (2) (3) 3% Porosity Cut-Off (mmbbls) 6% Porosity Cut-Off (mmbbls) Total Petroleum Initially In Place (TPIIP) 1, Discovered Petroleum Initially In Place (DPIIP) 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 ).

17 MONTNEY GROWTH ASSETS RESERVES AND RESOURCES 2012 Best Estimate 2011 Best Estimate Reserves and Economic Contingent Resources (1)(2) Natural Gas (Tcf) Reserves (3) Economic Contingent Resources Natural Gas Liquids (mmbbls) (4) Reserves (3) Economic Contingent Resources Oil (mmbbls) Reserves (3) Economic Contingent Resources (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. Prospective Resources (1)(2) 2012 Best Estimate 2011 Best Estimate Natural gas (Tcf) Natural gas liquids (mmbbls) (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.

18 2013 BUDGET

19 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 Capital Budget Capital $MM Volumes Year Average (boe/d) Gross Wells Net Wells Operated* , Non- Operated 56 10, Total , *Corporate $22 MM (1) Includes Operated and Non-operated. (2) 2013 annual average production.

20 2013 BUDGET 2013/2014 PRODUCTION GROWTH

21 ASSET OVERVIEW

22 ASSET OVERVIEW WESTERN CANADA Montney Growth Assets Base Assets Blueberry Attachie Septimus Sunset/Sunrise Sundown Tower Parkland Dawson Ante Creek Pembina Redwater Jenner Hatton Weyburn Lougheed Midale Goodlands Natural Gas Liquids-rich gas Crude Oil

23 ANTE CREEK A Montney Oil Success Story

24 ANTE CREEK ASSET DETAILS Net production (boe/d) Q ,600 Liquids (bbls/d) 5,200 Gas (mmcf/d) 33 Production split % (liquids/gas) ~50/50 Land (Montney net sections) 268 Working Interest ~99% Reserves (2P mmboe) 47.7 Liquids (mmbbls) 20.9 Gas (bcf) 160 Reserve Life Index 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

25 ANTE CREEK OIL OPERATIONAL EXCELLENCE INDUSTRY LEADING CAPITAL EFFICIENCY ARC s Ante Creek/Kaybob Montney drill and complete costs are <75% of industry average. 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 ARC Average IP (2) ~ 350 boe/d (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.

26 ANTE CREEK MONTNEY DEVELOPMENT ECONOMICS Key Metrics DCET Capex per well ($MM) 4.0 Reserves per well (Mboe) 283 IP (1 mo) (boe/d) 400 IP (12 mo) (boe/d) 245 Economics ($85/bbl) $4/GJ $3/GJ IRR (% AT) 45% 35% Recycle Ratio All economics run at FLAT price forecasts with C$85/bbl and $3 GJ AECO Liquid yield assumptions : NGL 21 bbl/mmcf, Condensate 10 bbl/mmcf

27 ANTE CREEK 2013 BUDGET - $186MM OPERATED

28 BRITISH COLUMBIA Montney Gas and Liquids

29 MONTNEY LANDS WORLD 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 2,500 bbls/d oil and liquids with Dawson contributing approximately 170 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 Ideally positioned with access to west coast and other Alberta markets.

30 MONTNEY LANDS SIGNIFICANT MONTNEY RESOURCE 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 Operator (since Jan 1, 2003) BC Montney Gross Operated Raw Gas Production (mmcfe/d)

31 boe/d ARC IN THE MONTNEY Tradition of Pace Development and Long-term Vision Forecast 2013 Construction begins of Parkland Phase Parkland Gas Plant: Phase Dawson Gas Plant: Phase Ante Creek Gas Plant ARC acquires ARC enters Dawson Field Ante Creek 2005 ARC drills first Montney Hz / / 08 Dawson Gas Plant: Phase ARC builds Montney land base ARC acquires Storm

32 MONTNEY HORIZONTAL WELLS 30 DAY HZ IP RATES GLACIER - TOWN ARC S MONTNEY WELLS HAVE EXCEEDED EXPECTATIONS (1) Graph represents peak calendar day IP rates for the first month of production to November (2) Region includes all horizontal wells from NE BC and NW AB Montney.

33 PARKLAND/TOWER Liquids Rich Gas

34 PARKLAND/TOWER EVALUATING POTENTIAL AND DEVELOPING EXISTING LANDS Parkland Tower Net production Q (boe/d) 7,700 1, Plans Liquids (bbls/d) Gas (mmcf/d) Land (net sections) Working Interest ~84% ~90% Reserves (2P mmboe) Liquids (mmbbls) Gas (bcf) Reserve Life Index wells drilled to date through Q at Tower (including one eight well pad and two wells finished drilling on the second eight well pad at the end of Q1 2013) Continue drilling second eight well pad at Tower; expected to finish drilling in Q2 and will complete both pads in Q3 Nine operated wells tied-in at Tower, with restricted production rates as result of liquids handling facility limitations Construction on the first 60 mmcf per day phase of the Parkland/Tower gas processing and liquids handling facility in 2013 is on schedule and on budget; all piles were set and major equipment arriving on site. The facility is expected to be on-stream in early 2014.

35 PARKLAND LAYERED 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)

36 PARKLAND LAYERED WELL PERFORMANCE Layered Well Placement Upper #1 Upper #2 400 m 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 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 50 m Lower Montney 200 m 200 m

37 PARKLAND MONTNEY DEVELOPMENT ECONOMICS Key Metrics DCET Capex per well ($MM) 5.2 Reserves per well (Bcf) 5.8 IP (1 mo) (MMcf/d) 5.0 IP (12 mo) (MMcf/d) 4.0 Economics ($85/bbl) $4/GJ $3/GJ IRR (% AT) 79% 54% Recycle Ratio All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO Liquid yield assumptions: NGL 13 bbl/mmcf, Condensate 11 bbl/mmcf

38 TOWER 2012 ACCOMPLISHMENTS (1) ARC purchased the Tower property in August Accomplishments: 2012 Operated Program average 30 day IP rate: 375 boe/d per well Production volumes limited due to liquid handling restrictions 2013 Plans: First of two eight well development pads to be completed in mmcf/d gas processing and liquids handling facility expected on-stream early 2014; site cleared, piles set, and major equipment is arriving on site. Facility liquids handling capability of 8,000 bbls/d (5,000 bbls/d oil and 3,000 bbls/d liquids) Expect step production profile as all wells brought on at one time (8 wells per pad)

39 TOWER OPERATIONAL EXCELLENCE MINIMIZING FOOTPRINT 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

40 TOWER MONTNEY DEVELOPMENT ECONOMICS Key Metrics DCET Capex per well ($MM) 5.3 Reserves per well (Mboe) 400 IP (1 mo) (boe/d) 500 IP (12 mo) (boe/d) 260 Economics ($85/bbl) $4/GJ $3/GJ IRR (% AT) 41% 37% Recycle Ratio All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO Premium pricing to EDM of +$4.25/bbl Liquid yield assumptions: 300 bbl/mmcf (Oil 221 bbl/mmcf, NGL and Condensate 79 bbl/mmcf)

41 TOWER/PARKLAND 2013 BUDGET - $249MM OPERATED

42 DAWSON World Class Asset

43 DAWSON ASSET DETAILS Net production (boe/d) Q ,900 Liquids (bbls/d) 800 Gas (mmcf/d) 169 Production split % (liquids/gas) ~97% gas Land (Montney net sections) 130 Working Interest ~96% Reserves (2P mmboe) 181 Liquids (mmbbls) 5.2 Gas (bcf) 1,052 Reserve Life Index Plans Drill 9 wells in 2013 to maintain Dawson production flat at 165 mmcf/d for 2013 and into 2014

44 DAWSON TYPE CURVE GROWTH 2008 type curve analysis was completed using initial production results and verified with a vertical well production multiplier 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

45 DAWSON MONTNEY DEVELOPMENT ECONOMICS Key Metrics DCET Capex per well ($MM) 5.2 Reserves per well (Bcf) 7.1 IP (1 mo) (MMcf/d) 5.0 IP (12 mo) (MMcf/d) 4.8 Economics ($85/bbl) $4/GJ $3/GJ IRR (% AT) 72% 44% Recycle Ratio All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO Liquid yield assumptions: NGL 1 bbl/mmcf, Condensate 3 bbl/mmcf

46 DAWSON 2013 BUDGET - $52MM OPERATED

47 WEST MONTNEY Long-term Growth Opportunity

48 WEST MONTNEY ASSET DETAILS Net production (boe/d)- Q ,550 Liquids (bbls/d) 80 Gas (mmcf/d) 20.8 Land (net Montney sections) 216 Working Interest ~90% Reserves (2P mmboe) 131 Liquids (mmbbls) 11 Gas (bcf) 723 Reserve Life Index 88

49 WEST MONTNEY OPERATIONAL EXCELLENCE DEVELOPMENT PLANNING

50 SUNRISE SUNRISE PRODUCTION OUTPERFORMING EXPECTATIONS Realized positive technical revisions in Sunrise based on 2-25 Hz well pad performance. Estimated Ultimate Recovery (EUR) is Cumulative Production + 2P Reserves. Montney A Sunrise A2-25 Hz MTYA (Raw) Cum to Dec.31, 2012: 2.2 Bcf ARC EUR Forecast: Bcf GLJ 2011 EUR: 7 Bcf GLJ 2012 EUR: 10 Bcf Montney B Sunrise B2-25 Hz MTYB (Raw) Cum to Dec. 31, 2012: 2.3 Bcf ARC EUR Forecast: Bcf GLJ 2011 (2P) EUR: 6 Bcf GLJ 2012 (2P) EUR: 10 Bcf

51 SUNRISE MONTNEY SUNRISE DEVELOPMENT ECONOMICS Key Metrics DCET Capex per well ($MM) 5.5 Reserves per well (Bcf) 9.7 IP (1 mo) (MMcf/d) 5.2 IP (12 mo) (MMcf/d) 4.5 Economics ($85/bbl) $4/GJ $3/GJ IRR (% AT) 51% 32% Recycle Ratio All economics run at FLAT price forecasts with C$85/bbl; $3/GJ AECO Liquid yield assumptions: NGL 4 bbls/mmcf, Condensate 1 bbl/mmcf (assume ARC Plant scenario)

52 BASE ASSETS Significant cash flow, stable production

53 BASE ASSETS Pembina Redwater Jenner Hatton Weyburn Lougheed Midale Goodlands Natural Gas Liquids-rich gas Crude Oil

54 PEMBINA Revitalizing a Mature Oil Field

55 PEMBINA ASSET DETAILS Net production (boe/d) Q ,500 Cardium production ~81% Production split % (liquids/gas) ~75%/25 % Land (Cardium net sections) 134 Working Interest ~79% Reserves (2P mmboe) Cardium 49.4 Reserve Life Index Plans ARC is the second largest operator in the Pembina area Continued focus on long term value through prudent reservoir and waterflood management Berrymoor plant expansion expected on stream May 2013 Drill 52 Hz wells and two vertical injectors throughout the Pembina area (operated)

56 PEMBINA OIL AND LIQUIDS GROWTH Forecast ARC HAS GROWN LIQUIDS PRODUCTION IN THIS MATURE FIELD

57 PEMBINA OIL OPERATIONAL EXCELLENCE INDUSTRY LEADING CAPITAL EFFICIENCY ARC s average drill and complete costs are 80% of industry average ARC $1.9 MM per well vs. Industry $2.4 MM per well (1) ARC s Cardium well performance is comparable to industry peer average (1) Source information from Well Completions & Frac Database Canadian Discovery Ltd. and Introspec Energy Group Inc., wells rig released Jan 2011 to Nov (2) IP3 data from Accumap - includes wells with greater than 750hrs, wells within TWP RNG 5-10W5, on production after January 1, 2008.

58 PEMBINA CARDIUM DEVELOPMENT ECONOMICS Key Metrics DCET Capex per well ($MM) 2.3 Reserves per well (Mboe) 171 IP (1 mo) (boe/d) 227 IP (12 mo) (boe/d) 90 Economics ($85/bbl) $4/GJ $3/GJ IRR (% AT) 52% 50% Recycle Ratio All economics run at FLAT price forecasts with C$85/bbl and $3/GJ AECO Liquids yield assumptions: NGL 38.6 bbl/mmcf, Condensate 3.7 bbl/mmcf

59 PEMBINA 2013 BUDGET - $131MM

60 SE SASKATCHEWAN OIL Solid Long-life Assets

61 SE SASKATCHEWAN/MANITOBA OIL ASSET DETAILS Net production (boe/d) Q Production split 12,100 99% liquids Land (net sections) 240 Working Interest ~82% Reserves (2P mmboe) 48.1 Reserves Life Index Plans: Continue to drill horizontally in a number of properties that were previously only vertically exploited. Drilling 51 gross operated wells in 2013 with significant focus at Goodlands in Manitoba. Continued focus on long term value through prudent reservoir and waterflood management

62 SUMMARY

63 WHY INVEST IN ARC RESOURCES? ARC is a top-tier oil and natural gas producer focused on Risk Managed Value Creation Commitment to sustainable dividend enforces higher degree of capital discipline and provides predictable return to shareholders Clear line of site for profitable and meaningful growth given significant presence in top quality resource plays Diverse inventory of development opportunities provides optionality through commodity price cycles Focus on operational excellence through capital efficiency and cost management to maximize rates of return Strong balance sheet to provide financial flexibility Active hedging program to provide greater certainty over cash flow, dividends and rates of return on development projects Experienced management team with track record of delivering results

64 RISK MANAGED VALUE CREATION PRODUCTION GROWTH

65 APPENDIX

66 Q FINANCIAL AND OPERATIONAL PERFORMANCE Three Months Ended March 31 (CDN$ millions, except per share and per boe amounts) Production (boe/d) Gas Liquids Revenue Gas Liquids Funds from operations Per share Operating Income Per share Dividends Per share 95,472 61% 39% ,970 62% 38% Capital expenditures Net debt outstanding Weighted average number of shares outstanding (millions) Netback (pre-hedging)

67 2013 BUDGET ($ millions) 2011 (Actual) 2012 (Actual) 2013 (Budget) Development Development Facilities Maintenance Optimization Exploration & Seismic Enhanced Oil Recovery Land Other Total 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.

68 2013 GUIDANCE 2013 Guidance 2013 Q1 Actual 2012 Actual Oil (bbls/d) 32,000 34,000 32,505 31,454 Condensate (bbls/d) 1,800 2,000 2,032 2,217 Gas (mmcf/d) NGL s (bbls/d) 2,400 2,800 2,831 2,728 Total (boe/d) 93,000 97,000 95,472 93,546 Operating expenses Transportation expenses G&A expenses (1) Interest expenses Current Income Tax expense ($ millions) Capital expenditures ($ millions) (2) Net property and undeveloped land acquisitions ($ millions) (3) Weighted average shares outstanding (millions) (1) The 2013 G&A expense before Long-Term Incentive Plan approximates $ $1.90 per boe. (2) The $830 million 2013 capital budget does not include land and net property acquisitions as this amount is unbudgeted. (3) Based on weighted average shares plus the dilutive impact of share options outstanding during the period.

69 EARNINGS STRONG PERFORMANCE THROUGH CYCLES (1) (2) (1) Amounts presented for the periods are in accordance with IFRS and amounts presented for periods are in accordance with Canadian GAAP. (2) Net Income presented for the periods is prior to the deduction of non-controlling interest under Canadian GAAP

70 $/Share COMMITTED TO THE DIVIDEND $4.6 Billion Paid to Shareholders Since Inception Stable monthly dividend at $0.10 per share or higher for 196 months Paid $28.98 per share since inception A shareholder who bought 1 share at $10 IPO in 1996 would have seen that share grow to 7 shares with a total value $187 through dividend reinvestment $ $ $ $ $ $ $80.00 $60.00 $40.00 $20.00 Cumulative Shareholder Value $ *Data to April 30, 2013 Stock Price Cumulative Dividend Share Value including DRIP

71 ACCESS TO CAPITAL DEBT Debt raised from three different sources: 1. Bank Credit Facility - $1.0 billion plus $25 million overdraft facility, 12 banks under facility Undrawn as at March 31, 2013 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 (Q1 2013) 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 (Q1 2013) Term extends to April 14, 2015

72 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

73 HEDGE POSITIONS AS OF MAY 1, 2013 Summary of Hedge Positions as at May 1, 2013 (1) May - Dec Crude Oil WTI (2) : (US$/bbl) US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d US$/bbl bbl/d Ceiling $ ,992 $ ,479 $ - - $ - - Floor $ ,992 $ ,479 $ - - $ - - Sold Floor $ ,984 $ ,240 $ - - $ - - Crude Oil Floors as % of Guidance (3) 39% 6% Natural Gas - Nymex: (US$/mmbtu) $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d $/mmbtu mmbtu/d Ceiling $ ,767 $ ,000 $ ,000 $ ,000 Floor $ ,767 $ ,000 $ ,000 $ ,000 Natural Gas Floors as % of Guidance (3) 59% 35% 20% 18% Total Floors as % of Guidance (3) 51% 23% 12% 11% (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.

74 CANADIAN CRUDE OIL DIFFERENTIALS Prices for Canadian crude oil relative to WTI have seen volatility over the past year which is mainly attributed to: Production Increases Growth in Canadian and Bakken production Refinery Capacity upgrades to refinery slates (to accept more heavy crudes) and refinery outages Infrastructure Bottlenecks down-stream pipeline constraints which push crude back into Canada The majority of ARC s production is light and medium quality approximately 4% is heavy

75 NGL MARKETS Infrastructure Western Canadian NGL infrastructure market dominated by a few major players Infrastructure has not kept pace with development Expansions are planned to come on-line in 2015 Western Canadian NGL Market Propane is reliant on exports to U.S. due to limited Canadian demand Butane markets well balanced due to demand from refining and crude oil blending Condensate market remains strong with imports from U.S. required as diluent for oil sands production growth ARC s NGL Exposure NGL revenue (4,700 bbl/day) makes up approximately 2% of ARC s revenue ARC has diversified pricing exposure away from Western Canadian markets for Propane and Butane ARC Propane Pricing ARC Butane Pricing ARC Condensate Pricing ARC NGL Component Breakdown

76 NATURAL GAS MARKET US Production continues to stay strong at ~64 bcf/d Prices have recovered from decade lows seen in 2012 as increased heating demand has helped alleviate inventory concerns

77 NATURAL GAS ARC NATURAL GAS MARKETING Two-phased approach of diversification both physically (to minimize operational risk) and financially (to manage price exposure) The majority of ARC s production has access to three major pipeline networks which deliver gas to markets in Western Canada and midwest U.S.

78 Environmental Performance COMMITTED TO SOCIALLY RESPONSIBLE OPERATORSHIP ARC is committed to minimizing our operational footprint and our impact on the environment Industry Leadership Publish bi-annual Corporate Responsibility Report meeting GRI C level Listed on the CDP s Carbon Disclosure Leadership Index Included in the Jantzi Social Index Performance Awards and External Recognition Winner of Chairman s Award in the Canadian Association of Petroleum Producers 2013 Responsible Canadian Energy Awards for the low emissions design of our Dawson gas plant Environmental Initiatives and Accomplishments Air Land Water Energy Efficiency >60,000 tonnes of GHG emissions avoided at Dawson gas plant due to low emissions design Redwater Soil Treatment Facility has reclaimed >20,000 tonnes of soil Target water use reductions through recycling programs and alternative sourcing 16% decrease in corporate emission intensity since 2011

79 Health and Safety Performance SAFETY IS A TOP PRIORITY ARC takes every measure to ensure the safety of the environment, surrounding communities and our employees and contractors. Ongoing Initiatives Employees take part in frequent H&S training Foster culture where safety is a top priority Regular safety communications and meetings Major Accomplishments Zero lost time incidents among employees 50% decrease in contractor lost time incidents 22% reduction in corporate health and safety incidents CLEAR program facilitates safety communications with field contractors Internal and external audits of H&S management system

80 DEFINITIONS OF OIL AND GAS RESERVES AND RESOURCES Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. reserves are classified according to the degree of certainty associated with the estimates as follows: Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Resources encompasses all petroleum quantities that originally existed on or within the earth s crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. Total resources is equivalent to Total Petroleum Initially-In-Place. Resources are classified in the following categories: Total Petroleum Initially-In-Place ( TPIIP ) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. Discovered Petroleum Initially-In-Place ( DPIIP ) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies. Forecast

81 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 and resources. 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. Forecast

82 FORWARD LOOKING STATEMENTS This presentation contains forward-looking statements that may be identified by words like outlook, estimates and similar expressions. These forward-looking statements are based on certain assumptions that involve a number of risks and uncertainties and are not guarantees of future performance. Reference is made to the section titled Forward Looking Statements at the beginning of the presentation and also to the November 7, 2012 news release titled ARC Resources Ltd. Announces an $830 Million Capital Budget For 2013, Setting the Stage for Significant Production Growth in 2014 which may be found on SEDAR at and which are hereby incorporated by reference in this presentation and which outline a number of assumptions, risks and uncertainties associated with forward looking statements. Actual results could differ materially as a result of changes to ARC s plans, the impact of changes in commodity prices, general economic, market and business conditions as well as production, development and operating performance and other risks associated with oil and gas operations. For further information about ARC Resources please visit our website Or contact: Investor Relations ir@arcresources.com T F Toll Free ARC Resources Ltd. 1200, Avenue S.W. Calgary, AB T2P 0H7