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Press release from CNW Group

ARC RESOURCES LTD. 2010 YEAR-END RESERVES INCREASE BY 29 PER CENT

Thursday, February 10, 2011

ARC RESOURCES LTD. 2010 YEAR-END RESERVES INCREASE BY 29 PER CENT17:35 EST Thursday, February 10, 2011CALGARY, Feb. 10 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") released today its 2010 year-end reserves information.HIGHLIGHTS << - Proved reserves increased by 25 per cent to 336 mmboe (106 mmbbls oil, 18 mmbbls NGLs, and 1.3 Tcf of natural gas) and proved plus probable reserves increased by 29 per cent to 487 mmboe (140 mmbbls oil, 27 mmbbls NGLs, and 1.9 Tcf of natural gas), from year-end 2009 levels. Proved reserves constitute 69 per cent of the total proved plus probable reserves compared to 71 per cent at year-end 2009. - On a per share basis, proved plus probable reserves increased eight per cent and proved reserves increased four per cent compared to year-end 2009. - All-in Finding and Development costs ("F&D") were $6.47 per boe for proved plus probable reserves and $9.50 per boe for proved reserves excluding Future Development Capital ("FDC") ($11.60 per boe and $14.02 per boe, respectively including FDC)(1). - ARC added 44.2 mmboe through net acquisitions in 2010 at a cost of $657 million, resulting in a proved plus probable acquisition cost of $14.88 per boe excluding FDC, $20.79 per boe on a total proved basis. The only significant transaction was the acquisition of Storm Exploration Inc. ("Storm") in August 2010, which resulted in the addition of 44 mmboe of proved plus probable reserves and 31.4 mmboe of proved reserves. - ARC replaced 502 per cent (67 per cent through internal development) of annual production at an all-in annual Finding, Development and Acquisition ("FD&A") cost of $9.21 per boe excluding FDC for proved plus probable reserves. This brings ARC's three year average FD&A cost excluding FDC down to $8.60 per boe. The 2010 FD&A costs including FDC for proved plus probable reserves were $14.23 per boe. - ARC achieved a recycle ratio of 4.2 times and 3.9 times, respectively for the current year and three year average for proved plus probable reserves based on the 2010 netback of $27.02 per boe and F&D costs excluding FDC. - The proved plus probable reserve life index ("RLI") increased to 15.2 years with the proved RLI remaining effectively unchanged at 10.4 years based on the mid-point 2011 production guidance of 85,500 boe per day. - Total proved plus probable reserves for the Montney in northeastern British Columbia including Dawson, West Montney and Parkland areas increased to 1.4 Tcfe (872 Bcfe proved), a 68 per cent increase over year-end 2009 reserves of 0.8 Tcfe. In total, Montney reserves in this area account for 48 per cent of total proved plus probable reserves. - Natural gas liquids reserves increased 67 per cent in 2010 with the acquisition of the liquids-rich Parkland area, and now account for five per cent of total proved plus probable reserves. - ARC commissioned an independent Economic Contingent Resource Evaluation for three areas within the Montney including Dawson, West Montney and Parkland. In addition to year-end 2010 proved plus probable reserves of 1.4 Tcfe, the contingent resource evaluation assigned a contingent resource best estimate of 0.7 Tcfe in excess of proved plus probable reserves. The high case estimate of incremental contingent resources beyond the proved plus probable reserves is 1.2 Tcfe and 0.2 Tcfe of possible reserves. The low case estimate of incremental contingent resources is 0.6 Tcfe. As part of this study, the estimate of Discovered Gas Initially in Place has been revised to 10.1 Tcf. These findings support ARC's position that the Montney is a significant growth engine with considerable potential reserves and ARC will continue to develop the region in a strategic and prudent manner. Details can be found in the "Montney Economic Contingent Resource Evaluation" section in this news release. -------------------- (1) The F&D and FD&A calculations include $25 million of capital costs associated with the move to a new office building during 2010. If these costs are excluded, ARC's capital expenditures would have been $566 million resulting in proved F&D of $9.11 per boe and proved plus probable F&D of $6.20 per boe before FDC ($13.62 and $11.33 per boe respectively, including FDC). The all in, proved FD&A would have been $13.04 and $9.03 per boe for proved plus probable FD&A ($17.88 and $14.05 respectively including FDC). >>RESERVES CLASSIFICATIONReserves included herein are stated on a company interest basis (before royalty burdens and including royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading "Resources and Operational Information". In addition to the detailed information disclosed in this news release more detailed information on a company gross basis (working interest before deduction of royalties without including any royalty interests) will be included in ARC's Annual Information Form ("AIF"). Numbers presented may not add due to rounding.INDEPENDENT RESERVE EVALUATIONGLJ Petroleum Consultants Ltd. ("GLJ") conducted an independent reserves evaluation effective December 31, 2010 and prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGEH") and NI 51-101. Based on this evaluation, ARC's reserve profile as at December 31, 2010 is summarized below: << - ARC's year-end proved plus probable reserves increased 29 per cent to 487 mmboe compared to 379 mmboe of proved plus probable reserves recorded at year-end 2009. - Proved plus probable reserve additions from exploration and development activities (including revisions) were 91 mmboe while 44 mmboe were added through acquisitions (net of minor dispositions), bringing the total additions to 135 mmboe before 2010 production of 27 mmboe. - The 91 mmboe proved plus probable addition from development activities represents 337 per cent of the 27 mmboe produced during 2010 and the total 135 mmboe represents 502 per cent of the 27 mmboe produced during 2010. - Proved developed producing reserves represent 63 per cent of total proved reserves and 44 per cent of proved plus probable reserves. - Total proved reserves account for 69 per cent of proved plus probable reserves. - Approximately 34 per cent of ARC's proved plus probable reserves are crude oil and natural gas liquids and 66 per cent are natural gas on a 6:1 boe conversion basis. >>The reserve evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2011 as outlined in the following table. << ------------------------------------------------------------------------- West Texas Edmonton Intermediate Light Natural Gas Foreign GLJ January 1, 2011 Crude Oil Crude Oil at AECO Exchange Price Forecast ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($US/$Cdn) ------------------------------------------------------------------------- 2011 88.00 86.22 4.16 0.98 2012 89.00 89.29 4.74 0.98 2013 90.00 90.92 5.31 0.98 2014 92.00 92.96 5.77 0.98 2015 95.17 96.19 6.22 0.98 2016 97.55 98.62 6.53 0.98 2017 100.26 101.39 6.76 0.98 2018 102.74 103.92 6.90 0.98 2019 105.45 106.68 7.06 0.98 2020 107.56 108.84 7.21 0.98 Escalate thereafter at +2.0%/yr +2.0%/yr +2.0%/yr 0.98 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RESERVES SUMMARY ------------------------------------------------------------------------- Light and Medium Heavy Total Crude Oil Crude Oil Crude Oil NGLs Company Interest (mbbl) (mbbl) (mbbl) (mbbl) ------------------------------------------------------------------------- Proved Producing 90,411 2,220 92,631 11,455 Proved Developed Non- Producing 1,763 4 1,767 835 Proved Undeveloped 11,095 30 11,125 6,193 Total Proved 103,269 2,255 105,524 18,483 Proved plus Probable 137,063 2,970 140,033 26,520 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Company Gross ------------------------------------------------------------------------- Proved Producing 90,258 2,071 92,329 11,302 Proved Developed Non- Producing 1,761 4 1,765 835 Proved Undeveloped 11,085 30 11,115 6,193 Total Proved 103,104 2,105 105,209 18,329 Proved plus Probable 136,854 2,777 139,631 26,332 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net Interest ------------------------------------------------------------------------- Proved Producing 77,421 1,972 79,393 8,301 Proved Developed Non- Producing 1,482 4 1,486 677 Proved Undeveloped 9,441 29 9,470 4,956 Total Proved 88,343 2,005 90,348 13,935 Proved plus Probable 116,553 2,620 119,173 20,079 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------- Oil Oil Equivalent Equivalent Natural 2010 2009 Company Interest Gas (bcf) (mboe) (mboe) ------------------------------------------------------------- Proved Producing 651.9 212,733 185,623 Proved Developed Non- Producing 78.5 15,685 7,863 Proved Undeveloped 543.6 107,921 76,048 Total Proved 1,274.0 336,339 269,535 Proved plus Probable 1,925.2 487,418 378,953 ------------------------------------------------------------- ------------------------------------------------------------- Company Gross ------------------------------------------------------------- Proved Producing 643.4 210,860 183,663 Proved Developed Non- Producing 78.5 15,678 7,862 Proved Undeveloped 543.5 107,894 76,018 Total Proved 1,265.4 334,432 267,543 Proved plus Probable 1,914.9 485,121 376,543 ------------------------------------------------------------- ------------------------------------------------------------- Net Interest ------------------------------------------------------------- Proved Producing 550.7 179,481 156,959 Proved Developed Non- Producing 65.6 13,097 6,194 Proved Undeveloped 460.1 91,114 62,525 Total Proved 1,076.5 283,692 225,678 Proved plus Probable 1,603.7 406,543 314,350 ------------------------------------------------------------- ------------------------------------------------------------- RESERVES RECONCILIATION - COMPANY INTEREST(1) ------------------------------------------------------------------------- Light and Company Interest Medium Heavy Total (Company Gross + Crude Oil Crude Oil Crude Oil NGLs Royalties Receivable)(1) (mbbl) (mbbl) (mbbl) (mbbl) ------------------------------------------------------------------------- PROVED PRODUCING Opening Balance 93,137 2,353 95,490 8,443 Exploration Discoveries 0 0 0 5 Drilling Extensions 1,562 65 1,627 94 Improved Recovery 507 27 534 395 Infill Drilling 1,451 39 1,490 648 Technical Revisions 3,486 115 3,601 1,195 Acquisitions 407 0 407 2,488 Dispositions -2 0 -2 0 Economic Factors -537 0 -537 -264 Production -9,600 -379 -9,979 -1,549 Closing Balance 90,411 2,220 92,631 11,455 ------------------------------------------------------------------------- TOTAL PROVED Opening Balance 102,918 2,366 105,284 11,500 Exploration Discoveries 0 0 0 9 Drilling Extensions 2,871 95 2,966 414 Improved Recovery 536 5 541 24 Infill Drilling 3,355 39 3,394 1,852 Technical Revisions 3,318 129 3,447 1,057 Acquisitions 408 0 408 5,458 Dispositions -2 0 -2 0 Economic Factors -534 0 -534 -282 Production -9,600 -379 -9,979 -1,549 Closing Balance 103,269 2,255 105,524 18,483 ------------------------------------------------------------------------- PROBABLE Opening Balance 31,653 661 32,314 4,315 Exploration Discoveries 0 0 0 4 Drilling Extensions 3,458 -55 3,403 526 Improved Recovery 95 1 96 3 Infill Drilling 1,114 17 1,131 775 Technical Revisions -2,471 10 -2,461 254 Acquisitions 106 0 106 2,223 Dispositions -2 0 -2 0 Economic Factors -159 81 -78 -63 Production 0 0 0 0 Closing Balance 33,794 715 34,509 8,037 ------------------------------------------------------------------------- PROVED PLUS PROBABLE Opening Balance 134,571 3,027 137,598 15,815 Exploration Discoveries 0 0 0 13 Drilling Extensions 6,329 40 6,369 940 Improved Recovery 631 6 637 27 Infill Drilling 4,469 56 4,525 2,627 Technical Revisions 847 139 986 1,311 Acquisitions 514 0 514 7,681 Dispositions -4 0 -4 0 Economic Factors -693 81 -612 -345 Production -9,600 -379 -9,979 -1,549 Closing Balance 137,063 2,970 140,033 26,520 ------------------------------------------------------------------------- ------------------------------------------------- Company Interest Oil (Company Gross + Natural Equivalent Royalties Receivable)(1) Gas (mmcf) (mboe) ------------------------------------------------- PROVED PRODUCING Opening Balance 490,140 185,623 Exploration Discoveries 1,152 197 Drilling Extensions 10,357 3,447 Improved Recovery 20,993 4,428 Infill Drilling 92,387 17,536 Technical Revisions 63,510 15,382 Acquisitions 77,767 15,856 Dispositions -17 -5 Economic Factors -11,629 -2,739 Production -92,785 -26,992 Closing Balance 651,875 212,733 ------------------------------------------------- TOTAL PROVED Opening Balance 916,509 269,535 Exploration Discoveries 1,865 320 Drilling Extensions 64,644 14,154 Improved Recovery 797 698 Infill Drilling 138,889 28,394 Technical Revisions 101,982 21,501 Acquisitions 154,482 31,613 Dispositions -17 -5 Economic Factors -12,374 -2,878 Production -92,785 -26,992 Closing Balance 1,273,992 336,339 ------------------------------------------------- PROBABLE Opening Balance 436,736 109,419 Exploration Discoveries 813 140 Drilling Extensions 55,548 13,187 Improved Recovery 301 149 Infill Drilling 75,129 14,428 Technical Revisions 24,884 1,940 Acquisitions 61,380 12,559 Dispositions -11 -4 Economic Factors -3,585 -739 Production 0 0 Closing Balance 651,195 151,079 ------------------------------------------------- PROVED PLUS PROBABLE Opening Balance 1,353,245 378,953 Exploration Discoveries 2,678 459 Drilling Extensions 120,192 27,341 Improved Recovery 1,098 847 Infill Drilling 214,018 42,822 Technical Revisions 126,866 23,441 Acquisitions 215,862 44,172 Dispositions -28 -9 Economic Factors -15,959 -3,617 Production -92,785 -26,992 Closing Balance 1,925,187 487,418 ------------------------------------------------- (1) Additional reserves reconciliation information on a Company Gross basis is included at the end of this news release. >>RESERVE LIFE INDEX ("RLI")ARC's proved plus probable RLI was 15.2 years at year-end 2010 while the proved RLI was 10.4 years based upon the GLJ reserves and ARC's 2011 production guidance mid-point of 85,500 boe per day. The increase in the proved plus probable RLI from 2008 through 2010 is attributed to the successful development of the Montney region and the resultant increase in proved plus probable reserves. The following table summarizes ARC's historical RLI. << ------------------------------------------------------------------------- Reserve Life Index 2010(1) 2009 2008 2007 2006 ------------------------------------------------------------------------- Total Proved 10.4 10.3 10.4 9.8 9.8 Proved Plus Probable 15.2 14.5 13.8 12.5 12.4 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes 10.7 mmboe proved and 14.2 mmboe proved plus probable reserves relating to assets divested in January 2011 and included in the year-end 2010 reserves evaluation. The 2011 production guidance of 85,500 boe per day excluded production from the divested assets of approximately 3,400 boe per day. >>NET PRESENT VALUE ("NPV") SUMMARYARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2011 prior to provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV of Cash Flow estimated by GLJ represents the fair market value of the reserves. NPVs on both a before and after tax basis are presented below. << ------------------------------------------------------------------------- Dis- Dis- Dis- Dis- NPV of Cash Flow Undis- counted counted counted counted Before Income counted at 5% at 10% at 15% at 20% Taxes(1) $MM $MM $MM $MM $MM ------------------------------------------------------------------------- Proved Producing 7,690 5,084 3,839 3,116 2,643 Proved Developed Non-Producing 452 292 215 170 141 Proved Undeveloped 2,305 1,365 866 569 378 Total Proved 10,446 6,740 4,919 3,855 3,162 Probable 5,475 2,499 1,430 931 656 Proved plus Probable 15,921 9,240 6,350 4,786 3,818 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on NI-51-101 Net Interest reserves and GLJ January 1, 2011 Forecast Prices and Costs. >>At a 10 per cent discount factor, the proved producing reserves make up 60 per cent of the proved plus probable estimated value while total proved reserves account for 77 per cent of the proved plus probable estimated value.The following table provides an estimate of the NPV of Cash Flow on an after tax basis incorporating the impact of corporate income tax effective 2011. Details of ARC's tax pools at year-end 2010 are presented in the MD&A section of the year-end financial results news release dated February 10, 2011. << ------------------------------------------------------------------------- NPV of Cash Flow Dis- Dis- Dis- Dis- After Income Undis- counted counted counted counted Taxes(1) counted at 5% at 10% at 15% at 20% $Millions $MM $MM $MM $MM $MM ------------------------------------------------------------------------- Proved Producing 6,375 4,305 3,303 2,715 2,326 Proved Developed Non-Producing 336 216 157 123 101 Proved Undeveloped 1,720 985 593 359 210 Total Proved 8,432 5,505 4,053 3,197 2,637 Probable 4,086 1,848 1,042 666 460 Proved plus Probable 12,518 7,353 5,095 3,863 3,097 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Based on NI-51-101 Net Interest reserves and GLJ January 1, 2011 Forecast Prices and Costs. >>NET ASSET VALUE ("NAV")The following net asset value table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of ARC's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of ARC. The values presented below are at a point in time and are based on various assumptions including commodity price forecasts and foreign exchange rates, which will vary over time. It should not be assumed that the net present values estimated by GLJ represent the fair market value of the reserves. << ------------------------------------------------------------------------- NAV at December 31, 2010(1) $Millions, except per share/unit amounts 2010 2009 2008 2007 2006 ------------------------------------------------------------------------- Value of Proved Plus Probable Reserves discounted at 10% (Before Tax)(2)(3) $6,350 $5,805 $5,292 $4,651 $4,056 Undeveloped Lands(4) 413 359 428 229 109 Reclamation Fund 25 33 28 26 31 Working Capital Deficit(5) (69) (56) (60) (38) (52) Risk Management Contracts(6) 54 (15) 1 (36) (9) Long-term Debt (804) (846) (902) (715) (687) Asset Retirement Obligation(7) (29) (27) (57) (26) (62) ------------------------------------------------------------------------- Net asset value $5,940 $5,253 $4,732 $4,091 $3,386 Shares/Units outstanding (000's)(8) 284,380 238,984 219,182 213,179 207,173 ------------------------------------------------------------------------- NAV per share/unit before tax $20.89 $21.98 $21.59 $19.19 $16.34 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Financial information is per ARC's 2010 Consolidated Financial Statements. (2) Based on NI-51-101 Net interest proved plus probable reserves based on GLJ price forecast as at January 1 of each respective year. (3) Value excludes future income taxes estimated at $1.3 billion for the GLJ price forecast using a 10 per cent discount rate and after deducting ARC's accumulated federal tax pools of $2.4 billion and $0.2 billion of provincial pools as at Dec 31, 2010 and the pools associated with the FDC. The estimated future taxes do not take into account any corporate tax deductions such as interest or general and administrative expenses. (4) Based on December 31, 2010 Seaton-Jordan and Associates Ltd. evaluation. (5) Working capital deficit excludes risk management contracts and current portion of future income tax assets and liabilities. (6) Risk management contracts represent the fair market value of such contracts as at December 31, 2010 based on the GLJ forecast pricing used to arrive at the value of proved plus probable reserves. This amount differs from the value of risk management contracts in the 2010 Consolidated Financial Statements due to differing future pricing assumptions. (7) The Asset Retirement Obligation ("ARO") is calculated based on the same methodology that was used to calculate the ARO in ARC's year-end financial statements, with the exception that future expected ARO costs were discounted at 10 per cent. The total discounted ARO at 10 per cent of $80.3 million was reduced by $51 million, relating to well abandonment costs, which were incorporated in the value of the proved plus probable reserves discounted at 10 per cent pursuant to the forecast price case as per NI 51-101. (8) Represents common shares as at December 31, 2010 pursuant to conversion to corporation. Prior to December 31, 2010 the amount represents total trust units outstanding and issuable for exchangeable shares. >>At the inception of ARC Energy Trust (the "Trust") on July 16, 1996, the NAV was $11.42 per unit; since that time, the Trust distributed $26.18 per unit to January 17, 2011. After having distributed more than double the initial NAV, the NAV as at December 31, 2010 was $20.89 per share, an increase of 83 per cent relative to the NAV at inception. The increase in NAV reflects ARC's ability to grow value over time with internal development opportunities and opportunistic acquisitions. Despite a significant increase in reserves, the NAV per share decreased slightly in 2010 as a result of the lower natural gas price environment at year-end 2010 relative to 2009.In the absence of adding reserves, the NAV per share will decline as the reserves are produced out. The evaluation includes future capital expenditure expectations required to bring undeveloped reserves on production. ARC works continuously to add value, improve profitability and increase reserves, which enhances the NAV.CAPITAL AND OPERATIONAL REVIEWDuring 2010 ARC spent $591 million on Exploration and Development ("E&D") and corporate activities and participated in drilling 176 gross (165 net) wells on ARC's operated lands with a 100 per cent success rate. Positive results from the capital program and continued strong production results at Dawson resulted in ARC adding 91 mmboe of proved plus probable reserves in 2010 prior to acquisitions. This represents a 337 per cent replacement of 2010 production of 27 mmboe prior to acquisitions. This is the third year in a row that ARC has been able to replace greater than 200 per cent of production from drilling and development activities. Excluding changes in FDC, ARC's Finding and Development costs ("F&D") were $6.47 per boe for proved plus probable reserves and $9.50 per boe for total proved reserves.A significant portion of ARC's 2010 capital program was focused on resource play development with $283 million (48 per cent of the 2010 capital spending) being allocated to the Montney region in northeastern British Columbia. See "Montney Economic Contingent Resource Evaluation" for further discussion of oil and gas reserves and resources in the Montney region.DAWSONWith the completion of the Phase One gas plant in May 2010, production at Dawson averaged a record 120 mmcf per day of natural gas during the fourth quarter of 2010. A total of 27 horizontal wells were drilled and construction commenced on the Phase Two 60 mmcf per day gas plant. There were 36 horizontal wells standing at year-end with behind-pipe production capacity in excess of 100 mmcf per day, waiting to be brought on production with the completion of the Phase Two gas plant expected to come on-stream in early April 2011.The 2011 capital budget calls for spending of $98 million at Dawson including the drilling of one step out vertical well along with the drilling of 13 horizontal wells and completion of the Phase Two gas plant. With completion of the Phase Two gas plant, ARC expects Dawson production to increase to approximately 165 mmcf per day. ARC will also be testing the lower Montney zone that has proven to be productive elsewhere in the region.WEST MONTNEYIn the West Montney assets, which include Sunrise, Septimus and Sundown, ARC drilled three Montney horizontal wells and one vertical well, and participated in one partner-operated horizontal well. The three operated horizontal wells each targeted different sections within the Montney: the well-known Montney 'A', a second upper Montney zone referred to as the 'B', and the 'E' in the lower Montney. ARC is currently tieing-in seven existing Sunrise wells to a third party processing facility, which is expected to bring on-stream 15 mmcf per day of natural gas production when tie-in is complete in mid-2011. ARC drilled one vertical well at Sunset and one vertical well in Monias in 2010.ARC plans to spend $25 million in the West Montney area in 2011 to drill two horizontal wells and one vertical well for acid gas disposal and complete the tie-in of existing wells to the third party processing facility. ARC deferred the proposed 60 mmcf per day Sunrise gas plant from 2012 to 2013.PARKLANDIn August 2010, ARC added the Parkland field to its existing Montney portfolio with the acquisition of Storm. The Parkland property is an excellent strategic fit for ARC given its similar geological characteristics and close proximity to the Dawson and West Montney fields. The Parkland field production averaged 7,800 boe per day from acquisition date, consisting of 83 per cent natural gas and 17 per cent natural gas liquids production. The Parkland field added proved plus probable reserves of 38.8 mmboe and expanded ARC's undeveloped land holdings by 64 gross (48 net) sections.In 2011, ARC plans to spend $67 million on the drilling of 11 horizontal wells, two vertical delineation wells and to expand compression in an effort to increase liquids production. ARC also plans to test a lower interval in the upper Montney as well as drill two wells to determine the productive capacity of the liquids-rich northern area.ATTACHIEDuring 2010, ARC acquired 90 sections of undeveloped land in the Attachie area, which is located northwest of the Dawson field. ARC plans to drill four vertical wells and two horizontal wells in 2011. At present, there are no proved or probable reserves or production at Attachie.ANTE CREEKIn Ante Creek, ARC drilled 12 horizontal Montney wells targeting a mixture of oil and gas production. With the success of these wells and a late 2009 acquisition of approximately 1,000 boe per day, Ante Creek production increased to a record 7,500 boe per day in 2010.ARC is allocating significant capital to Ante Creek in 2011 with $55 million to be spent on the drilling of 14 horizontal and two vertical wells. In addition, ARC has allocated $30 million of 2011 capital to build a new 30 mmcf per day gas plant to process solution gas in an effort to increase liquids production in early 2012. ARC expects liquids production to grow to approximately 5,000 barrels per day and total production at Ante Creek to increase to approximately 11,000 boe per day over the course of 2012.PEMBINAThe Pembina area development included 25 successful Cardium drills, including 10 horizontal wells brought on production in the fourth quarter of 2010 with stable first month production rates averaging 200 boe per day per well. The 2011 capital budget will build on 2010 success with 42 more planned horizontal Cardium wells to be drilled.GOODLANDSARC experienced significant drilling success in 2011 at Goodlands in Manitoba with 14 new horizontal oil wells. The Goodlands area provides some of the best drilling economics in ARC's portfolio due to the high netback light oil. ARC will spend $58 million in southeast Saskatchewan and Manitoba during 2011 to drill 48 wells and explore for additional opportunities.2010 ACQUISITION ACTIVITYIn 2010, ARC spent $657.2 million on acquisitions net of dispositions. The most significant transaction was the $652.1 million corporate acquisition of Storm completed in August 2010, which added proved plus probable and proved reserves of 44 mmboe and 31 mmboe, respectively at a cost of $14.83 per boe proved plus probable reserves and $20.74 per boe proved reserves excluding FDC. In addition to reserves and production of approximately 9,600 boe per day, the Storm acquisition also contributed significant developed and undeveloped land holdings with 30 gross (23 net) sections of developed land and 64 gross (48 net) sections of undeveloped land being added to ARC's Montney land portfolio.In total, net acquisition activity added 44 mmboe of proved plus probable reserves and 32 mmboe of proved reserves a cost of $14.88 per boe and $20.79 per boe, respectively, excluding FDC. Including FDC, the net acquisition costs were $19.67 per boe proved plus probable and $26.27 per boe proved reserves.FUTURE DEVELOPMENT CAPITAL ("FDC")NI 51-101 requires that F&D costs be calculated including changes in FDC. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. The increased level of undeveloped reserves now booked in the Montney acreage has yielded an increased capital cost expectation in the 2010 evaluation.Following is a summary of GLJ estimated FDC required to bring total proved and probable reserves on production. << ------------------------------------------------------------------------- Future Development Capital(1) Total Proved + $Millions Total Proved Probable ------------------------------------------------------------------------- 2011 416 459 2012 323 394 2013 391 468 2014 267 285 2015 16 304 Remainder 101 381 ------------------------------------------------------------------------- Total undiscounted $1,514 $2,291 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Total discounted at 10% $1,220 $1,738 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) FDC as per GLJ independent reserve evaluation as of December 31, 2010 and based on GLJ forecast pricing as at January 1, 2011. >>FINDING DEVELOPMENT AND ACQUISITION COSTS ("FD&A")Prior to acquisitions, ARC's F&D costs were $6.47 per boe and $9.50 per boe for proved plus probable and proved reserves, respectively in 2010, excluding FDC. The low F&D costs are attributed to the high quality of ARC's property portfolio, excellent results from ARC's development program and strong reserve growth particularly in the Dawson and Ante Creek areas.Including acquisitions, ARC's 2010 FD&A costs excluding FDC were $9.21 per boe of proved plus probable and $13.31 per boe of proved reserves while FD&A costs including FDC were $14.23 per boe and $18.15 per boe, respectively for proved plus probable and proved reserves. The three year average FD&A costs were $8.60 per boe for proved plus probable reserves and $12.76 per boe for total proved excluding FDC.The following table illustrates FD&A costs excluding and including FDC. << ------------------------------------------------------------------------- FD&A costs - Company Excluding FDC Including FDC Interest(1)(2) ------------------------------------------------ $Thousands, except per Proved + Proved + boe amounts Proved Probable Proved Probable ------------------------------------------------------------------------- E&D Capital Expenditures(3) $590,914 $590,914 $590,914 $590,914 E&D Expenditures - Change in FDC - - 280,927 467,792 ------------------------------------------------------------------------- Total E&D Capital Expenditures(3) 590,914 590,914 871,841 1,058,706 ------------------------------------------------------------------------- Net Acquisition Capital 657,236 657,236 657,236 657,236 Net Acquisitions - Change in FDC - - 172,974 211,507 ------------------------------------------------------------------------- Net Acquisition Capital Expenditures 657,236 657,236 830,210 868,743 ------------------------------------------------------------------------- Total Capital including Net Acquisitions $1,248,150 $1,248,150 $1,702,051 $1,927,449 ------------------------------------------------------------------------- E&D Reserve Additions 62,188 91,294 62,188 91,294 Net Acquisition Reserve Additions 31,608 44,163 31,608 44,163 ------------------------------------------------------------------------- Reserve Additions including Net Acquisitions 93,796 135,457 93,796 135,457 ------------------------------------------------------------------------- ------------------------------------------------------------------------- F&D Costs - Current Year $9.50 $6.47 $14.02 $11.60 F&D Costs - Three Year Average $10.28 $6.93 $15.45 $12.52 Net Acquisition Cost - Current Year $20.79 $14.88 $26.27 $19.67 Net Acquisition Cost - Three Year Average $21.86 $14.77 $27.20 $19.67 FD&A Costs - Current Year $13.31 $9.21 $18.15 $14.23 FD&A Costs - Three Year Average $12.76 $8.60 $17.96 $14.05 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The aggregate of the Exploration and Development ("E&D") costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. (2) Under NI 51-101, the calculation of F&D costs must incorporate the changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. In all cases, the F&D, or FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions both before and after FDC costs. (3) Includes $24.6 million pertaining to leasehold costs on new corporate office space. ------------------------------------------------------------------------- Company Interest Historic FD&A Costs 2010 2009 2008 2007 2006 ------------------------------------------------------------------------- Proved Reserves: Annual FD&A excluding FDC $13.31 $10.48 $14.22 $20.37 $24.51 Three year average FD&A excluding FDC $12.76 $13.76 $18.28 $18.51 $17.77 ------------------------------------------------------------------------- Annual FD&A including FDC $18.15 $14.29 $21.87 $20.37 $27.53 Three year average FD&A including FDC $17.96 $18.27 $22.85 $20.30 $20.31 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Proved plus Probable Reserves: Annual FD&A excluding FDC $9.21 $6.44 $10.13 $19.00 $22.41 Three Year Average FD&A excluding FDC $8.60 $9.57 $14.70 $16.57 $15.59 ------------------------------------------------------------------------- Annual FD&A including FDC $14.23 $11.56 $17.00 $20.03 $27.20 Three Year Average FD&A including FDC $14.05 $14.75 $19.84 $19.19 $18.99 ------------------------------------------------------------------------- ------------------------------------------------------------------------- >>MONTNEY ECONOMIC CONTINGENT RESOURCE EVALUATIONThe following discussion on the "Montney Economic Contingent Resource Evaluation" and "Reserves and Resources Overview" is subject to a number of cautionary statements, assumptions and risks. See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information" for additional cautionary language, explanations and discussion and "Forward Looking Statements" for a statement of principal assumptions and risks that may apply.All GLJ estimates of DGIIP and Economic Contingent Resource are as at December 31, 2010 and based on GLJ forecast pricing as at January 1, 2011 and have been prepared in accordance with the COGE Handbook. There is no certainty that it will be commercially viable to produce any of the resources.The Montney region in northeastern British Columbia has been identified as one of the most significant unconventional natural gas resource plays in North America with potential for significant volumes of recoverable resource. ARC entered the Montney region in 2003 with the corporate acquisition of Star Oil & Gas at which time total production at Dawson was 17 mmcf per day and the proved plus probable reserves were 110 Bcf. Since then, ARC has established itself as one of the key players in the Montney region having drilled 82 vertical wells and 73 horizontal wells, increased total proved plus probable reserves to 1.4 Tcfe, increased production to 120 mmcf per day, and significantly expanded its land base from 65 gross (62 net) sections of developed and undeveloped land to 396 gross (354 net) sections. At present, ARC's Montney portfolio includes ownership in Dawson, Parkland, West Montney (Sunrise, Septimus and Sundown)and Attachie.Despite this success, ARC still believes that there are significant volumes of natural gas resource that can be added to reserves in the future assuming continued successful development of the field. In an effort to quantify the future reserve potential, ARC commissioned an Economic Contingent Resource Evaluation ("Contingent Resource Evaluation") for three areas within the Montney including Dawson, Parkland and West Montney, which consists of Sunrise, Septimus and Sundown (the "Evaluated Areas"). The contingent resource evaluation was conducted by GLJ effective December 31, 2010 based on forecast pricing as at January 1, 2011. The Attachie area was not included in the contingent resource evaluation due to insufficient data on ARC lands.Discovered Gas Initially in Place ("DGIIP") is the quantity of gas that is estimated to be contained in known accumulations prior to production. DGIIP is typically broken down into four components including production, reserves, contingent resource and discovered unrecoverable petroleum initially in place. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Economic Contingent Resources are those Contingent Resources that are currently economically recoverable. In the core of ARC's Montney Gas region in northeastern British Columbia; the contingencies that prevent the economic contingent resources from being classified as reserves are associated with the early evaluation stage of these potential development opportunities. Additional drilling, completion, and testing data is generally required before ARC can commit to their development. The independent evaluation identified total DGIIP for the greater Montney region to be 10.1 Tcf for ARC's landholdings in the Evaluated Areas.In addition to the 1.4 Tcfe of proved plus probable reserves assigned to the Evaluated Areas at year-end 2010, the contingent resource evaluation assigned a low estimate of contingent resource of 0.6 Tcfe. The low estimate is the most conservative estimate and carries the greatest degree of confidence - at least 90 per cent - that the resource will be recovered. The best estimate (50 per cent degree of confidence) of contingent resource was 0.7 Tcfe. The high estimate (less than 10 percent degree of confidence) of contingent resources is 1.2 Tcfe. GLJ estimated 0.18 Tcfe of possible reserves in the Evaluated Area. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 per cent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. The remainder of the DGIIP beyond what has been cumulatively produced, classified as proved plus probable plus possible reserves, or classified as contingent resource is currently considered to be the unrecoverable portion.In total, ARC has 354 net sections of Montney acreage in northeast British Columbia, of which 105 net sections have 1.4 Tcfe of proved plus probable reserves assigned. ARC's DGIIP on 193 net sections of land evaluated is 10.1 Tcf. In addition, GLJ assigned a high estimate economic contingent resource of 1.2 Tcfe net to ARC in the Evaluated Area. Management continues to see significant reserve adding opportunities in this area. << ------------------------------------------------------------------------- Reserves and Resources - December 31, 2010(1) --------------------------------------------------------------- Estimated Economic Estimated Reserves Contingent Resource (Bcfe)(1) (Bcfe)(2) ----------------------------------------------- Cumu- Proved + lative Proved Proba- Produc- + ble + Low Best High Montney DGIIP(1) tion Proba Possi- Estim- Estim- Estim- Area (Bcf) (Bcfe) Proved ble ble(4) ate ate ate ------------------------------------------------------------------------- Dawson 3,800 106 601 901 1,002 318 381 477 West Mont- ney(3) 5,500 6 111 253 315 272 331 708 Parkland 800 66 160 227 248 17 18 23 ------------------------------------------------------------------------- Total 10,100 178 872 1,381 1,565 607 730 1,208 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Per GLJ independent reserve evaluation as of December 31, 2010 and based on GLJ forecast pricing as at January 1, 2011. The Bcfe values are sales volumes, with the exception of DGIIP which is presented as raw volumes (Bcf). (2) Per independent GLJ "Economic Contingent Resource Evaluation" as of December 31, 2010 and based on GLJ forecast pricing as of January 1, 2011. (3) Includes Sunrise/Sunset, Septimus and Sundown. (4) 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 of recovery associated with each class. >>RESERVES AND RESOURCES OVERVIEWARC's believes that significant additional reserves will be recognized in the future with continued drilling success on undeveloped Montney acreage together with further development and completion refinements and improved economic circumstances. Historic drilling success and recoveries on the more fully developed Montney acreage, abundant well log and production test data, and the application of drilling densities of ARC and third parties in the area all support ARC's belief that significant additional resources will be recovered in the future. 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 no current well data exists, limited access to capital, low gas prices that would curtail the economics of development and the future performance of wells.DAWSONGLJ's best estimate of DGIIP for the 107 net sections of land that ARC owns at Dawson is 3,800 Bcf. As of December 31, 2010, cumulative production at Dawson has been 106 Bcfe, with 901 Bcfe of proved plus probable reserves and a best estimate of Economic Contingent Resource of 381 Bcfe. ARC has 40 net sections of land at Dawson on which no reserves have yet been assigned and 12 net sections with no contingent resources assigned.WEST MONTNEYIn the West Montney area, which includes Sunrise, Septimus and Sundown, the upper Montney section thickens and a second porous and permeable zone referred to as the Montney B is present. To date, all of the production has come from the Montney A. GLJ has assigned DGIIP and reserves to the Montney B as gas has been tested from this horizon by ARC and other operators. In 2011, ARC plans to bring at least one Montney B well onto production so as to get a better understanding of the production potential of this zone. There is a deeper zone, referred to as the Lower Montney E, that also has shown development potential in the region, DGIIP has been evaluated in the lower Montney zone, however no economic contingent resource has been assigned. << Sunrise ------- >>GLJ's best estimate of DGIIP for the 32 net sections of land that ARC owns at Sunrise is 3,334 Bcf. As of December 31, 2010, cumulative production at Sunrise has been 6 Bcfe, with 241 Bcfe of proved plus probable reserves and a best estimate of Economic Contingent Resource of 294 Bcfe. ARC has 14.5 net sections of land at Sunrise on which no reserves have yet been assigned and 6.5 net sections with no contingent resources assigned. << Septimus and Sundown -------------------- >>GLJ's best estimate of DGIIP for the 37 net sections of land that ARC owns at Septimus/Sundown is 2,166 Bcf. As of December 31, 2010, there has not been any significant production at Septimus/Sundown, with just 12 Bcfe of proved plus probable reserves and a best estimate of Economic Contingent Resource of 37 Bcfe. ARC has 33 net sections of land at Septimus/Sundown on which no reserves have yet been assigned and 31 net sections with no contingent resources assigned.PARKLANDARC owns 71 net sections of land in Parkland. GLJ's best estimate of DGIIP on 17 net sections of land on which reserves have been assigned is 800 Bcf. As of December 31, 2010, cumulative production at Parkland has been 66 Bcfe, with 227 Bcfe of proved plus probable reserves, including 7.4 mbbls of natural gas liquids reserves, and a best estimate of Economic Contingent Resource of 18 Bcfe. ARC has 54 net sections of land at Parkland on which no reserves or contingent resources have yet been assigned. << RESERVES RECONCILIATION - COMPANY GROSS ------------------------------------------------------------------------- Light and Company Gross Medium Heavy Total (Company Interest - Crude Oil Crude Oil Crude Oil NGLs Royalties Receivable) (mbbl) (mbbl) (mbbl) (mbbl) ------------------------------------------------------------------------- PROVED PRODUCING Opening Balance 92,988 2,199 95,187 8,299 Exploration Discoveries 0 0 0 5 Drilling Extensions 1,561 65 1,626 94 Improved Recovery 509 22 531 395 Infill Drilling 1,451 30 1,481 648 Technical Revisions 3,435 53 3,488 1,166 Acquisitions 407 0 407 2,488 Dispositions 0 0 0 0 Economic Factors -535 0 -535 -260 Production -9,559 -298 -9,857 -1,533 Closing Balance 90,258 2,071 92,329 11,302 ------------------------------------------------------------------------- TOTAL PROVED Opening Balance 102,756 2,212 104,968 11,355 Exploration Discoveries 0 0 0 9 Drilling Extensions 2,871 95 2,966 414 Improved Recovery 538 0 538 24 Infill drilling 3,355 30 3,385 1,852 Technical Revisions 3,266 66 3,332 1,027 Acquisitions 408 0 408 5,458 Dispositions 0 0 0 0 Economic Factors -531 0 -531 -277 Production -9,559 -298 -9,857 -1,533 Closing Balance 103,104 2,105 105,209 18,329 ------------------------------------------------------------------------- PROBABLE Opening Balance 31,607 622 32,229 4,281 Exploration Discoveries 0 0 0 4 Drilling Extensions 3,458 -55 3,403 526 Improved Recovery 95 0 95 3 Infill Drilling 1,114 15 1,129 775 Technical Revisions -2,472 10 -2,462 253 Acquisitions 106 0 106 2,223 Dispositions 0 0 0 0 Economic Factors -158 80 -78 -63 Production 0 0 0 0 Closing Balance 33,750 672 34,422 8,003 ------------------------------------------------------------------------- PROVED PLUS PROBABLE Opening Balance 134,363 2,834 137,197 15,637 Exploration Discoveries 0 0 0 13 Drilling Extensions 6,329 40 6,369 940 Improved Recovery 633 0 633 27 Infill Drilling 4,469 45 4,514 2,627 Technical Revisions 794 76 870 1,280 Acquisitions 514 0 514 7,681 Dispositions 0 0 0 0 Economic Factors -689 80 -609 -340 Production -9,559 -298 -9,857 -1,533 Closing Balance 136,854 2,777 139,631 26,332 ------------------------------------------------------------------------- ------------------------------------------------- Company Gross Natural Oil (Company Interest - Gas Equivalent Royalties Receivable) (mmcf) (mboe) ------------------------------------------------- PROVED PRODUCING Opening Balance 481,057 183,663 Exploration Discoveries 1,152 197 Drilling Extensions 10,355 3,446 Improved Recovery 20,993 4,425 Infill Drilling 92,384 17,526 Technical Revisions 62,390 15,051 Acquisitions 77,742 15,852 Dispositions 0 0 Economic Factors -11,434 -2,701 Production -91,262 -26,600 Closing Balance 643,377 210,860 ------------------------------------------------- TOTAL PROVED Opening Balance 907,316 267,543 Exploration Discoveries 1,865 320 Drilling Extensions 64,644 14,154 Improved Recovery 797 695 Infill drilling 138,887 28,385 Technical Revisions 100,840 21,165 Acquisitions 154,457 31,609 Dispositions 0 0 Economic Factors -12,181 -2,838 Production -91,262 -26,600 Closing Balance 1,265,363 334,432 ------------------------------------------------- PROBABLE Opening Balance 434,941 109,000 Exploration Discoveries 813 140 Drilling Extensions 55,548 13,187 Improved Recovery 301 148 Infill Drilling 75,128 14,425 Technical Revisions 25,012 1,963 Acquisitions 61,378 12,559 Dispositions 0 0 Economic Factors -3,543 -732 Production 0 0 Closing Balance 649,578 150,689 ------------------------------------------------- PROVED PLUS PROBABLE Opening Balance 1,342,257 376,543 Exploration Discoveries 2,678 459 Drilling Extensions 120,192 27,341 Improved Recovery 1,098 843 Infill Drilling 214,015 42,810 Technical Revisions 125,852 23,127 Acquisitions 215,835 44,168 Dispositions 0 0 Economic Factors -15,724 -3,570 Production -91,262 -26,600 Closing Balance 1,914,941 485,121 ------------------------------------------------- ------------------------------------------------------------------------- FD&A costs - Company Gross(1)(2) Excluding FDC Including FDC $Thousands, except per ------------------------------------------------ boe amounts Proved P+P Proved P+P ------------------------------------------------------------------------- E&D Capital Expenditures(3) $590,914 $590,914 $590,914 $590,914 E&D Expenditures - Change in FDC - - 280,927 467,792 ------------------------------------------------------------------------- Total E&D Capital Expenditures(3) 590,914 590,914 871,841 1,058,706 ------------------------------------------------------------------------- Net Acquisition Capital 657,236 657,236 657,236 657,236 Net Acquisitions - Change in FDC - - 172,974 211,507 ------------------------------------------------------------------------- Net Acquisition Capital Expenditures 657,236 657,236 830,210 868,743 ------------------------------------------------------------------------- Total Capital including Net Acquisitions $1,248,150 $1,248,150 $1,702,051 $1,927,449 ------------------------------------------------------------------------- E&D Reserve Additions 61,880 91,010 61,880 91,010 Net Acquisition Reserve Additions 31,609 44,168 31,609 44,168 ------------------------------------------------------------------------- Reserve Additions including Net Acquisitions 93,489 135,178 93,489 135,178 ------------------------------------------------------------------------- ------------------------------------------------------------------------- F&D Costs - Current Year $9.55 $6.49 $14.09 $11.63 F&D Costs - Three Year Average $10.34 $6.95 $15.50 $12.51 Net Acquisition Cost - Current Year $20.79 $14.88 $26.26 $19.67 Net Acquisition Cost - Three Year Average $21.87 $14.77 $27.35 $19.88 FD&A Costs - Current Year $13.35 $9.23 $18.21 $14.26 FD&A Costs - Three Year Average $12.82 $8.62 $18.04 $14.08 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) The aggregate of the Exploration and Development ("E&D") costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. (2) Under NI 51-101, the calculation of FD&A costs must incorporate the changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. In all cases, the F&D, or FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions both before and after FDC costs. (3) Includes $24.6 million pertaining to leasehold costs on new corporate office space. ------------------------------------------------------------------------- Company Gross Historic FD&A Costs 2010 2009 2008 2007 2006 ------------------------------------------------------------------------- Proved Reserves: Annual FD&A including FDC $18.21 $14.36 $22.01 $20.71 $28.05 Three year average FD&A including FDC $18.04 $18.41 $23.12 $20.57 $20.63 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Proved plus Probable Reserves: Annual FD&A including FDC $14.26 $11.59 $17.08 $20.29 $27.79 Three Year Average FD&A including FDC $14.08 $14.81 $20.04 $19.43 $19.28 ------------------------------------------------------------------------- ------------------------------------------------------------------------- >>INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES, RESOURCES AND OPERATIONAL INFORMATIONAll amounts in this news release are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on "company interest reserves" using forecast prices and costs. "Company interest reserves" consist of "company gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101") plus ARC's royalty interests in reserves. "Company interest reserves" are not a measure defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2010, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com. In relation to the disclosure of estimates in the Highlights, Capital and Operational Review, Montney Economic Contingent Resource Evaluation and Reserves and Resources Overview, such estimates for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.This news release contains references to estimates of gas classified as discovered gas initially in place in the area west of Dawson in British Columbia which are not, and should not be confused with, oil and gas reserves. "Discovered gas initially in place" ("DGIIP") is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation prior to production. DGIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources and the remainder as at evaluation date is by definition classified as unrecoverable. There is no certainty that it will be economically viable to produce any portion of the resources.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.ARC's belief that it will establish significant additional reserves over time in the discussion of the Montney Economic Contingent Resource Evaluation is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward Looking Statements".Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, resources, see above.NOTICE TO U.S. READERSThe oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves, each as defined in NI 51-101. Accordingly, proved reserves disclosed in this news release may not be comparable to U.S. standards, and in this news release, ARC has disclosed reserves designated as "probable reserves" and "proved plus probable reserves" and "proved plus probable plus possible reserves". Probable reserves and possible reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. The SEC's guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Moreover, ARC has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. As a consequence of the foregoing, ARC's reserve estimates and production volumes in this news release may not be comparable to those made by companies utilizing United States reporting and disclosure standards. Additionally, the SEC prohibits disclosure of oil and gas resources including contingent resources, whereas Canadian issuers may disclose oil and gas resources. Resources are different than, and should not be construed as, reserves.FORWARD-LOOKING INFORMATION AND STATEMENTSThis news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading "Independent Reserve Evaluation" and the recognition of significant resources under the heading "Montney Economic Contingent Resource Evaluation", the volumes and estimated value of ARC's oil and gas reserves; the life of ARC's reserves; the volume and product mix of ARC's oil and gas production; future oil and natural gas prices and ARC's commodity risk management programs; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations.The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities consistent with past results; the continued and timely development of infrastructure in areas of new production; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserve and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its plans expenditures. There are a number of assumptions associated with the development of the lands at Dawson, West Montney and Parkland, including the quality of the Montney reservoir, continued performance from existing wells, future drilling programs and performance from new wells, the growth of infrastructure, well density per section, recovery factors and development necessarily involves known and unknown risks and uncertainties, including those risks identified in this press release. ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; the early stage of development of some areas in Dawson, West Montney and Parkland; the potential for variation in the quality of the Montney formation, changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; unanticipated results from ARC's exploration and development activities; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form).The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.ARC Resources Ltd. ("ARC") is one of Canada's largest conventional oil and gas companies with an enterprise value of approximately $8 billion. ARC expects 2011 oil and gas production to average 84,000 to 87,000 barrels of oil equivalent per day from six core areas in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX. << ARC RESOURCES LTD. John P. Dielwart, Chief Executive Officer >>For further information: about ARC Resources Ltd., please visit our website www.arcresources.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6427, Toll Free 1-888-272-4900, ARC Resources Ltd., Suite 1200, 308 - 4th Avenue S.W., Calgary, AB, T2P 0H7