ARC Resources Ltd. Announces Fifth Consecutive Year of Greater than 200 per cent Produced Reserves Replacement in 2012 CALGARY, Feb. 6, 2013 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") released today its 2012 year-end reserves and resources information. HIGHLIGHTS -- Replaced 200 per cent of 2012 total production, adding 69 mmboe of proved plus probable ("2P") reserves. 2P reserves increased six per cent to 607 mmboe, comprised of 2.5 Tcf of natural gas and 186 mmbbls of crude oil and natural gas liquids ("NGL's") at year-end 2012. ARC's 2P Reserve Life Index ("RLI") increased to 17.5 years, based on the 2013 mid-point production guidance of 95,000 boe/d. -- Replaced 214 per cent of 2012 crude oil and NGL's production, adding 29 mmbbls of 2P crude oil and NGL's reserves. ARC's significant focus on crude oil and liquids development resulted in a nine per cent increase in 2P crude oil and NGL's reserves from 170 mmbbls to 186 mmbbls. -- Finding and Development costs ("F&D") of $9.01 per boe for 2P reserves and $15.73 per boe for proved reserves excluding Future Development Capital ("FDC"). ARC's three year average F&D costs for 2P reserves were $6.63 per boe, excluding FDC. The 2012 capital development program focused significantly on oil and liquids development which typically carries higher finding and development costs, while yielding higher returns given the current commodity price environment. -- All-in annual Finding, Development and Acquisition ("FD&A") costs of $9.34 per boe for 2P reserves, excluding FDC. ARC's three year average FD&A costs were $7.80 per boe for 2P reserves, excluding FDC. -- Recycle ratio of 2.7 times and 3.6 times for the current year and three year average, respectively, for 2P reserves based on current and three year average F&D costs, excluding FDC, and ARC's 2012 netback of $24.17 per boe. -- ARC continued to update an Independent Resources Evaluation ("Resources Evaluation" or "Independent Resources Evaluation") for its Montney lands in the northeast British Columbia ("NE B.C.") Montney region, which reaffirmed the significant resource base on ARC's NE B.C. Montney lands. In addition to the 50.1 Tcf of gas resource, an oil resource of 1.5 billion barrels was identified at Tower. 2012 INDEPENDENT RESERVES EVALUATION GLJ conducted an independent reserves evaluation effective December 31, 2012 and prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and NI 51-101. The reserve evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2013 as outlined in Table 1 below. Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without including any 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 "Information Regarding Disclosure on Oil and Gas Reserves, Resources and Operational Information". In addition to the detailed information disclosed in this news release more detailed information will be included in ARC's Annual Information Form ("AIF"). Based on this independent reserves evaluation, ARC's reserve profile as at December 31, 2012 is summarized below: -- ARC's year-end 2012 2P reserves increased six per cent to 607 mmboe compared to 572 mmboe of 2P reserves recorded at year-end 2011 -- 2P reserve additions from exploration and development activities (including revisions) were 67.5 mmboe while 1.1 mmboe was added through acquisitions (net of minor dispositions), bringing the total additions to approximately 69 mmboe before 2012 production of 34 mmboe -- The 67.5 mmboe 2P reserves additions from development activities represents 196 per cent of the 34 mmboe produced during 2012 -- Proved developed producing reserves represent 55 per cent of total proved reserves and 33 per cent of 2P reserves -- Total proved reserves account for 60 per cent of 2P reserves -- Approximately 31 per cent of ARC's proved plus probable reserves are crude oil and natural gas liquids and 69 per cent are natural gas on a 6:1 boe conversion basis -- Record positive technical revisions of 41 mmboe mainly from the Sunrise, Dawson, Ante Creek, and Pembina fields. The positive technical revisions illustrate the strength of ARC's asset base. Table 1 GLJ January 1, 2013 West Texas Edmonton Intermediate Light Natural Gas Foreign Price Crude Oil Crude Oil at AECO Exchange Forecast ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($US/$Cdn) 2013 90.00 85.00 3.38 1.00 2014 92.50 91.50 3.83 1.00 2015 95.00 94.00 4.28 1.00 2016 97.50 96.50 4.72 1.00 2017 97.50 96.50 4.95 1.00 2018 97.50 96.50 5.22 1.00 2019 98.54 97.54 5.32 1.00 2020 100.51 99.51 5.43 1.00 2021 102.52 101.52 5.54 1.00 2022 104.57 103.57 5.64 1.00 Escalate thereafter at +2.0%/yr +2.0%/yr +2.0%/yr 1.00 Table 2 Oil Oil Light and Equivalent Equivalent Medium Heavy Total Crude Crude Crude Natural 2012 2011 RESERVES Oil Oil Oil NGLs Gas SUMMARY (mbbl) (mbbl) (mbbl) (mbbl) (Bcf) (mboe) (mboe) Company Gross Proved Producing 88,539 1,739 90,278 9,578 607 201,018 208,920 Proved Developed Non-producing 1,973 0 1,973 1,260 53 12,044 9,952 Proved Undeveloped 14,743 0 14,743 9,375 760 150,841 140,769 Total Proved 105,255 1,739 106,994 20,214 1,420 363,904 359,641 Proved plus Probable 146,442 2,256 148,698 36,850 2,529 606,982 572,374 Table 3 RESERVES RECONCILIATION COMPANY GROSS Light and Medium Heavy Crude Crude Total Oil Crude NGLs Natural Equivalent Oil Oil Oil Gas (mbbl) (mbbl) (mbbl) (mbbl) (mmcf) (mboe) PROVED PRODUCING Opening Balance 87,626 1,874 89,500 10,210 655,259 208,920 Exploration Discoveries 0 0 0 0 0 0 Extensions and Improved Recovery( (1)) 9,001 167 9,168 1,250 41,202 17,285 Technical Revisions 3,508 -44 3,464 37 53,151 12,359 Acquisitions 140 0 140 7 118 167 Dispositions 0 0 0 -23 -1,102 -207 Economic Factors -602 -13 -615 -103 -17,046 -3,559 Production -11,134 -245 -11,379 -1,800 -124,607 -33,947 Closing Balance 88,539 1,739 90,278 9,578 606,975 201,018 TOTAL PROVED Opening Balance 102,188 1,874 104,062 19,088 1,418,946 359,641 Exploration Discoveries 0 0 0 7 279 54 Extensions and Improved Recovery ( (1)) 11,676 167 11,843 1,989 62,485 24,246 Technical Revisions 3,591 -44 3,547 2,305 224,366 43,246 Acquisitions 359 0 359 -11 78 361 Dispositions 0 0 0 -142 -3,985 -806 Economic Factors -1,425 -13 -1,438 -1,222 -157,388 -28,891 Production -11,134 -245 -11,379 -1,800 -124,607 -33,947 Closing Balance 105,255 1,739 106,994 20,214 1,420,174 363,904 PROVED PLUS PROBABLE Opening Balance 135,071 2,308 137,379 32,774 2,413,327 572,374 Exploration Discoveries 0 0 0 9 356 68 Extensions and Improved Recovery( (1)) 19,064 278 19,342 3,086 109,529 40,683 Technical Revisions 4,045 -76 3,969 4,174 199,221 41,347 Acquisitions 912 0 912 204 6,676 2,229 Dispositions 0 0 0 -203 -5,629 -1,141 Economic Factors -1,516 -9 -1,525 -1,394 -70,270 -14,631 Production -11,134 -245 -11,379 -1,800 -124,607 -33,947 Closing Balance 146,442 2,256 148,698 36,850 2,528,603 606,982 Reserves additions for Infill Drilling, Improved Recovery and (1) Extensions are combined and reported as "Extensions and Improved Recovery". RESERVE LIFE INDEX ("RLI") ARC's 2P RLI increased to 17.5 years at year-end 2012 while the proved RLI was 10.5 years based upon the GLJ reserves and ARC's 2013 production guidance mid-point of 95,000 boe per day. The increase in the 2P RLI from 2008 through 2012 is attributed to the successful development of the Montney region and the resultant growth in 2P reserves. The following table summarizes ARC's historical RLI. Table 4 Reserve Life Index 2012((1)) 2011 2010 2009 2008 Total Proved 10.5 10.7 10.4 10.3 10.3 Proved Plus Probable 17.5 17.0 15.1 14.4 13.6 (1) Based on 2013 production guidance midpoint of 95,000 boe per day. NET PRESENT VALUE ("NPV") SUMMARY ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2013 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. Table 5 Discounted Discounted Discounted Discounted NPV of Cash Undiscounted at 5% at 10% at 15% at 20% Flow ((1)) $MM $MM $MM $MM $MM Before Tax Proved Producing 5,887 4,163 3,249 2,686 2,305 Proved Developed Non-Producing 333 234 179 145 122 Proved Undeveloped 2,369 1,321 767 441 234 Total Proved 8,589 5,719 4,195 3,272 2,661 Probable 6,253 3,123 1,843 1,205 841 Proved plus Probable 14,842 8,841 6,039 4,477 3,502 After Tax ((2) (3)) Proved Producing 4,985 3,582 2,829 2,360 2,039 Proved Developed Non-Producing 249 175 133 107 90 Proved Undeveloped 1,771 942 500 240 76 Total Proved 7,005 4,699 3,462 2,707 2,205 Probable 4,675 2,302 1,330 844 569 Proved plus Probable 11,680 7,001 4,792 3,552 2,774 (1) Based on NI-51-101 Net Interest reserves and GLJ January 1, 2013 Forecast Prices and Costs. (2) Based on ARC's estimated tax pools at year-end 2012. (3) The after-tax net present value of ARC's oil and gas properties here reflects the tax burden on the properties on a stand-alone basis. It does not consider the business-entity-level tax situation, or tax planning. It does not provide an estimate of the value at the level of the business entity, which may be significantly different. ARC's Audited Consolidated Financial Statements and Management's Discussion & Analysis should be consulted for information at the business entity level. At a 10 per cent discount factor, the proved producing reserves constitute 54 per cent of the before tax 2P estimated value while total proved reserves account for 69 per cent of the before tax 2P estimated value. 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 increase in reserves and in particular the level of undeveloped reserves booked on the Montney acreage has resulted in a higher capital cost estimate in the 2012 reserve evaluation. Following is a summary of GLJ estimated FDC required to bring total proved and probable reserves on production. Table 6 Future Development Capital ((1)) Total Proved + $ Millions Total Proved Probable 2013 468 601 2014 518 809 2015 492 641 2016 279 458 2017 104 352 Remainder 109 519 Total FDC undiscounted 1,970 3,380 Total FDC discounted at 10% 1,589 2,593 (1) FDC as per GLJ independent reserve evaluation as of December 31, 2012 and based on GLJ forecast pricing as at January 1, 2013. FINDING DEVELOPMENT AND ACQUISITION COSTS ("FD&A") ARC's F&D costs were $9.01 per boe and $15.73 per boe for 2P and proved reserves, respectively in 2012, excluding FDC ($12.65 per boe and $18.61 per boe, respectively, for 2P and proved reserves including FDC). ARC's three year average F&D costs were $6.63 per boe for 2P reserves and $11.49 per boe for proved reserves, 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 at Sunrise, Dawson, Parkland, Tower, Ante Creek, Attachie and Pembina. Including net acquisitions, ARC's 2012 FD&A costs were $9.34 per boe of 2P and $16.76 per boe of proved reserves, excluding FDC ($13.26 per boe and $19.96 per boe, respectively, for 2P and proved reserves including FDC). The three year average FD&A costs were $7.80 per boe for 2P reserves and $13.38 per boe for proved reserves, excluding FDC. ARC's low FD&A costs are a reflection of ARC's focus on high quality assets, cost management and allocation of resources and capital to the highest rate of return projects. The following table illustrates FD&A costs excluding and including FDC. Table 7 Excluding FDC Including FDC FD&A costs - Company Gross ((1)(2)) Proved + Proved + $ Thousands Proved Probable Proved Probable E&D capital expenditures 607,974 607,974 607,974 607,974 E&D capital expenditures - change in FDC - - 111,418 245,807 Total E&D capital expenditures 607,974 607,974 719,392 853,781 Net acquisition (disposition) 32,435 32,435 32,435 32,435 Net acquisition (disposition) - change in FDC - - 10,781 22,717 Total net acquisition (disposition) 32,435 32,435 43,216 55,152 Total capital including net acquisition (disposition) 640,409 640,409 762,608 908,933 E&D reserve additions 38,655 67,466 38,655 67,466 Net acquisition (disposition) reserves (445) 1,088 (445) 1,088 Reserve additions including net dispositions 38,210 68,554 38,210 68,554 FD&A costs - $ per boe: F&D Costs - Current Year 15.73 9.01 18.61 12.65 F&D Costs - Three Year Average 11.49 6.63 15.99 12.02 FD&A Costs - Current Year 16.76 9.34 19.96 13.26 FD&A Costs - Three Year Average 13.38 7.80 18.25 13.30 (1) The aggregate of Exploration and Development ("E&D") costs incurred in the most recent financial year and the change in estimated future development costs ("FDC") 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 change in future development capital 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. Table 8 Company Gross Historic FD&A Costs ($ per boe) 2012 2011 2010 2009 2008 Proved Reserves: Annual FD&A excluding FDC 16.76 11.11 13.35 10.53 14.31 Three year average FD&A excluding FDC 13.38 12.02 12.82 13.86 18.50 Annual FD&A including FDC 19.96 17.13 18.21 14.36 22.01 Three year average FD&A including FDC 18.25 16.95 18.04 18.41 23.12 Proved plus Probable Reserves: Annual FD&A excluding FDC 9.34 5.24 9.23 6.46 10.18 Three Year Average FD&A excluding FDC 7.80 7.15 8.62 9.61 14.85 Annual FD&A including FDC 13.26 12.23 14.26 11.59 17.08 Three Year Average FD&A including FDC 13.30 12.90 14.08 14.81 20.04 NE B.C. MONTNEY RESOURCES EVALUATION The following discussion in "NE B.C. Montney Resources Evaluation" is subject to a number of cautionary statements, assumptions and risks as set forth therein. 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. See also "Definitions of Oil and Gas Reserves, Resources and Reserves". The discussion includes reference to TPIIP, DPIIP and ECR as per the GLJ Petroleum Consultants Ltd. ("GLJ") Resources Evaluation as at December 31, 2012, prepared in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). Unless indicated otherwise in this news release, all references to ECR volumes are Best Estimate ECR volumes. The Montney formation in NE B.C. has been identified as a world class unconventional natural gas resource play with the potential for significant volumes of recoverable resources. The area includes dry gas and liquids-rich gas and crude oil development opportunities. It is one of the largest and lowest cost natural gas resource plays in North America. ARC has a significant presence in the region with a land position of 447 net sections, located primarily in the most prospective areas of the play. GLJ were commissioned to conduct an Independent Resources Evaluation for ARC's lands in the NE B.C. Montney region including Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown, and Blueberry in northeastern B.C and Pouce Coupe just across the border in Alberta (the "Evaluated Areas"). The Resources Evaluation was effective December 31, 2012 based on GLJ forecast pricing as at January 1, 2013. All references in the following discussion to ECR, TPIIP and DPIIP are in reference to the Evaluated Areas included in the Independent Resources Evaluation. See "Definitions of Oil and Gas Resources and Reserves". The evaluation reaffirmed that the NE B.C. Montney region provides a significant long-term growth opportunity with considerable potential reserves, extending well beyond existing booked reserves and even the current estimates of the Economic Contingent Resource ("ECR"). ARC's NE B.C. Montney assets provide optionality for future growth through commodity price cycles given the diversity of ARC's Montney landholdings with exposure to liquids-rich natural gas, crude oil and dry natural gas. We believe there is considerable upside in our NE B.C. Montney assets given our significant resource base. ARC's 2012 capital development program was focused on crude oil and liquids opportunities throughout ARC's entire asset portfolio. In NE B.C., ARC's capital development program consisted of drilling 16 gross operated wells comprised of two dry gas wells for land retention purposes, three liquids-rich delineation wells and 11 oil wells at Tower. Given the limited development activity in NE B.C. Montney region in 2012, the 2012 resource evaluation conducted by GLJ did not result in significant changes to resource estimates, with the exception of the Tower prospect. Tower resource estimates were reclassified in 2012 due to the recognition of a significant portion of the Tower field as an oil reservoir in the 2012 evaluation; where previously Tower had been classified as a liquids-rich gas reservoir. When GLJ conducted the 2011 resource evaluation, there was very limited production data at Tower, therefore, the reservoir was classified as a liquids-rich gas field. With additional oil production data and extensive reservoir fluid and simulation analysis, GLJ now views the majority of the Tower field as an oil reservoir. With the majority of the Tower lands now considered to be oil bearing, GLJ has split the resource assessment into two distinct sections: Gas bearing zones which account for the vast majority of ARC's Montney lands and includes 13 upper Montney sections at Tower as well as the lower Montney at Tower; and Oil bearing zones which are restricted to the upper Montney on 43 sections of land at Tower. TPIIP for the gas bearing lands in the evaluated areas was effectively unchanged at 50.1 Tcf, despite the reclassification of the majority of the Tower field to an oil reservoir from liquids rich gas reservoir. The 2012 drilling program resulted in a modest increase of seven per cent DPIIP for the evaluated areas to 27.2 Tcf. Small increases in gas ECR to 4.2 Tcf and reserves to 2.1 Tcf were primarily the result of GLJ revising upwards their view of ultimate recoverable reserves on a per well basis as a result of strong production, which more than offset reductions associated with lower forecast commodity prices. The natural gas prospective resources decreased slightly from 4.0 Tcf to 3.8 Tcf primarily due to economic factors based on the GLJ's lower forecast commodity prices in the 2012 evaluation. NGL reserves associated with the gas resource increased 17 per cent from 21.1 mmbbls to 24.7 mmbbls, NGL's ECR increased 10 percent from 101.0 mmbbls to 111.2 mmbbls and NGL's prospective resource increased 16 per cent to 113.6 mmbbls, due to increased land holdings, production results from the Attachie pilot, and delineation drilling at Attachie. At Tower, ARC holds 56 net sections of which 43 sections of Upper Montney have been classified as oil bearing while the reserves and resources associated with the remaining 13 sections and the lower Montney are included in the numbers for the gas bearing lands. GLJ has identified 1,467 mmbbls of DPIIP, 12.6 mmbbls of ECR and 6.2 mmbbls of reserves on the oil bearing lands at Tower. The Tower field is still in the early stages of development, therefore additional production data is required to better understand the recoverable potential of this field. However, with advancements in drilling and completion technology, early indications are very favorable for exploitation of this significant oil resource. The following tables summarize the results of the 2012 and 2011 resources evaluations. Table 9a 2012 2011 Natural Gas Resource Categories ((1)(2)(3)(4)) Tcf Tcf Total Petroleum Initially In Place (TPIIP) 50.1 50.4 Discovered Petroleum Initially In Place (DPIIP) 27.2 25.5 Undiscovered Petroleum Initially In Place (UPIIP) 22.9 24.9 (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. Using a three per cent porosity cut-off, the 2012 TPIIP, DPIIP and UPIIP estimates would be 38.5 Tcf, 22.3 Tcf, and 16.2 Tcf, respectively. (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. Table 9b 2012 2011 Oil Resource Categories ((1)(2)(3)) mmbbls mmbbls Total Petroleum Initially In Place (TPIIP) 1,467.0 15.4 Discovered Petroleum Initially In Place (DPIIP) 1,467.0 15.4 (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. Using a six per cent porosity cut-off, the 2012 TPIIP and DPIIP estimates would both be 640.1 mmbbls. (2) All volumes in table are company gross. (3) The oil DPIIP is a Stock Tank Barrel ("STB"). The 2011 evaluation identified oil resource on only one gross section; the 2012 evaluation identified oil resource on 43 gross sections. Table 9c Reserves and Economic Contingent Resources( )((1) 2012 Best 2011 Best (2)) Estimate Estimate Natural Gas (Tcf) Reserves ((3)) 2.1 1.9 Economic Contingent Resources 4.2 4.1 Natural Gas Liquids( )(mmbbls)( (4)) Reserves ((3)) 24.7 21.1 Economic Contingent Resources 111.2 101.0 Oil( )(mmbbls)( ) Reserves ((3)) 7.6 0.1 Economic Contingent Resources 12.6 0.5 (1) All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable. (2) All volumes in table are company gross and sales volumes. (3) For reserves, the volume under the heading Best Estimate are 2P reserves. (4) The liquid yields are based on average yield over the producing life of the property. Table 9d 2012 Best 2011 Best Prospective Resources ((1)(2)) Estimate Estimate Natural gas (Tcf) 3.8 4.0 Natural gas liquids (mmbbls) 113.6 98.0 (1) All UPIIP other than Prospective Resources has been categorized as unrecoverable. GLJ estimated DPIIP values using a porosity cut-off of three per cent for natural gas and six per cent for oil. (2) All volumes in table are company gross and sales volumes. Based upon the forgoing analysis and ARC's expertise in the Montney formation in NE B.C., it is expected that significant additional reserves will be developed in the future with continued drilling success on currently undeveloped Montney acreage together with further development, completion refinements and improved economic conditions. Historic drilling success and recoveries on the more fully developed Montney acreage, abundant well log and production test data, and the application of increased drilling densities support ARC's belief that significant additional resources will be recovered. 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 commodity 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. DEFINITIONS OF OIL AND GAS RESOURCES AND RESERVES Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows: Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories: Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies. Economic Contingent Resources 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. The Best Estimate 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. INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES, RESOURCES AND OPERATIONAL INFORMATION All 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 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. 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 gross reserves" using forecast prices and costs. Our oil and gas reserves statement for the year-ended December 31, 2012, 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. This news release contains references to estimates of oil and gas classified as TPIIP and DPIIP in the Montney region in northeastern British Columbia which are not, and should not be confused with, oil and gas reserves. See "Definitions of Oil and Gas Resources and Reserves". 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 with conversion of DPIIP into ECR, ECR into 2P reserves and probable reserves into proved reserves 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". NOTICE TO U.S. READERS The 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 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, 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. FORWARD-LOOKING INFORMATION AND STATEMENTS This 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 "2012 Independent Reserve Evaluation" and the recognition of significant resources under the heading "NE B.C. Montney Resources 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 Evaluated Areas, 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, and 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 the Evaluated Areas; 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, unfavorable 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 2013 oil and gas production to average 93,000 to 97,000 barrels of oil equivalent per day from its properties in western Canada. ARC's Common Shares trade on the TSX under the symbol ARX. ARC RESOURCES LTD. Myron M. Stadnyk President and Chief Executive Officer For further information about ARC Resources Ltd., please visit our website www.arcresources.com or contact: Investor Relations, E-mail:email@example.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 SOURCE: ARC Resources Ltd. To view this news release in HTML formatting, please use the following URL: http://www.newswire.ca/en/releases/archive/February2013/06/c3472.html CO: ARC Resources Ltd. ST: Alberta NI: OIL FIELD -0- Feb/06/2013 23:01 GMT
ARC Resources Ltd. Announces Fifth Consecutive Year of Greater than 200 per cent Produced Reserves Replacement in 2012
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