ARC Resources Ltd. announces 18 per cent increase in 2011 year-end reserves and results of updated Independent Resources Evaluation for Northeast British Columbia Montney Assets

CALGARY, Jan. 26, 2012 /CNW/ - (ARX - TSX) ARC Resources Ltd. ("ARC") released today its
2011 year-end reserves and resources information.


  • Proved plus probable ("2P") reserves increased 18 per cent to 572 mmboe, comprised of 2.4 Tcf of natural gas and 170 mmbbls of liquids, at year-end 2011
  • Proved reserves increased eight per cent to 360 mmboe at year-end 2011
  • ARC achieved record production of 92,021 boe per day and 83,416 boe per day for the fourth quarter and full year 2011, respectively, due to a strong 2011 drilling program that delivered 13 per cent year-over-year production growth.  Full year 2011 production was comprised of 62 per cent natural gas production and 38 per cent crude oil and liquids production.
  • ARC replaced 385 per cent of 2011 production, adding 117 mmboe of 2P reserves after the net divestment of non-core properties with associated 2P reserves of 14.6 mmboe in 2011
  • Finding and Development costs ("F&D") of $5.50 per boe for 2P reserves and $10.84 per boe for proved reserves excluding Future Development Capital ("FDC")
  • All-in annual Finding, Development and Acquisition ("FD&A") costs of $5.24 per boe for 2P reserves, excluding FDC, represent ARC's lowest annual FD&A costs since 2001
  • Recycle ratio of 5.3 times and 5.0 times for the current year and three year average, respectively, for 2P reserves based on 2011 F&D costs excluding FDC and 2011 netback of $29.16 per boe
  • Increase in 2P and proved Reserve Life Index ("RLI") to 17 years and 10.7 years, respectively, based on the mid-point 2012 production guidance of 92,500 boe per day
  • Crude oil and natural gas liquids ("NGL's") reserves comprise 30 per cent of total 2P reserves at year-end 2011
  • 2P reserves per share increased 16 per cent and proved reserves per share increased six per cent relative to year-end 2010
  • Total 2P reserves for the Montney in NE B.C. increased to 1.9 Tcf of natural gas and 21 mmbbls of NGL's, a 48 per cent increase over year-end 2010 reserves of 1.3 Tcf of natural gas and 12.5 mmbbls of NGL's.  Reserves have been assigned to 146 net sections on ARC's total land position of 434 net sections in this region.
  • ARC commissioned an Independent Resources Evaluation ("Resources Evaluation" or "Independent Resources Evaluation") for its Montney lands in the northeast British Columbia ("NE B.C.") Montney region (1).  The findings confirm that the Montney is a significant long-term growth opportunity with considerable potential reserves, which go well beyond existing booked reserves and even the current estimates of the Economic Contingent Resource ("ECR").  In addition to year-end 2011 2P reserves of 1.9 Tcf of natural gas and 21 mmbbls of NGL's, the Resources Evaluation assigned an ECR best estimate of 4.1 Tcf of natural gas and 101 mmbbls of liquids.  As part of this study and based on a zero per cent porosity cut-off,  the estimate of Discovered Petroleum Initially in Place ("DPIIP") has increased to 25.5 Tcf (21.2 Tcf at a three per cent porosity cut-off)  and the estimate of Total Petroleum Initially in Place ("TPIIP") was identified to be 50.4 Tcf (39.6 Tcf at a three per cent porosity cut-off).  ARC estimates that approximately $54 million would need to be spent to drill and complete sufficient wells on ARC's land base in order to reclassify all of the TPIIP into DPIIP.
  • Total 2P reserves plus the ECR represent less than 13 per cent of the TPIIP based upon a zero per cent porosity cut-off (approximately 15 per cent of TPIIP based upon a three per cent porosity cut-off). ARC expects the ultimate recovery may exceed this level with the long-term natural gas price being the primary determinant of ultimate recovery.
  • ARC continues to update its long-term development plan as resource estimates grow with a range of scenarios being developed to reflect a range of potential recovery factors of the substantial NE B.C. Montney natural gas and liquids resource.

(1)     References to NE B.C. Montney pursuant to the Independent Resources Evaluation throughout this new release includes Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown, and Blueberry located in B.C. and Pouce Coupe located in Alberta.


The following discussion in "NE B.C. Montney Resources and Reserves", "Ante Creek Montney Resources and Reserves "and "2011 Operational and Property Review" 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, 2011, 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.

There is no certainty that it will be commercially viable to produce any of the resources that are categorized as discovered resources.  There is no certainty that any portion of ARC's resources that have been categorized as undiscovered resources will be discovered.  Furthermore, if discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. 


ARC's inventory of value-creating opportunities continue to expand at a rapid pace with the Montney formation in NE B.C. being the primary area of major resource expansion. In both dry gas and liquids-rich gas resource plays, the cycle time from drilling the initial discovery well to significant production coming on-stream often requires new infrastructure such that our current internal development plans span well beyond the period of production growth included in our year-end reserves report. We have successfully continued to move DPIIP into ECR, ECR into 2P reserves and probable reserves into proved reserves at a steady pace. Notably, our year-end 2011 2P reserves have increased by an amount equal to the ECR estimate released just 12 months ago. Since ARC's strategic plan and capital allocation decisions are based upon our assessment of the complete scale of the identified opportunities, rather than the subset of those opportunities which are currently booked as 2P reserves or identified as ECR, the discussion presented herein focuses on our total resource opportunity.

The DPIIP and TPIIP estimates presented herein for the NE B.C. Montney formation have been prepared by our independent reserve evaluators, GLJ, based upon mapping supported by significant well control. As with any reserve or resource estimate, the value will change over time as new information becomes available. At this time, ARC believes the TPIIP to be the most appropriate estimate of the opportunity that exists for the NE B.C. Montney and forms the basis for our ongoing short-term and long-term strategic decisions. Therefore, it is extremely relevant to the discussion of our resource and potential future reserve opportunities.

When conducting reserve and resource assessments, the process traditionally includes estimates of the level of porosity in the rock below which the reservoir fluids are not expected to contribute to future production and reserves; this is referred to as the "porosity cut-off".  In new resource plays where the technology is enabling our industry to extract commercial production rates from rock previously believed to be "too tight" to produce, it is uncertain as to what the correct porosity cut-off is.  In the early days of developing the Montney formation at Dawson, ARC used a six per cent porosity cut-off which was subsequently reduced to three per cent based upon the performance of the wells.  GLJ's resource assessment continues to reflect the use of a three per cent porosity cut-off, ARC however believes the three per cent porosity cut-off may be too high based on continued strong performance within Dawson.  For the purposes of this disclosure, the DPIIP and TPIIP results do not impose a porosity cut-off unless otherwise indicated, therefore, the discussion and analysis becomes focused on what the best estimate of the recovery factor will be over time rather than adjusting the in-place resource estimates and the recovery factor on an ongoing basis.  By removing the porosity cut-off, expected recovery factors have been lowered accordingly; future production performance will be used to refine the recovery factor estimates.  Footnotes have been added to certain tables presented herein to identify how the referenced volumes would change if a three per cent porosity cut-off was to be imposed on the in-place volume calculation. For information purposes, ARC's TPIIP at a three per cent porosity cut-off is estimated to be 39.6 Tcf which represents 78 per cent of the estimated TPIIP of 50.4 Tcf at a zero per cent porosity cut-off; this speaks to the high quality of the Montney formation on ARC's lands. 

NE B.C. Montney Resource Discussion and Analysis

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 both dry gas and liquids-rich gas opportunities.  It is one of the largest and lowest cost natural gas resource plays in North America and is expected to serve as the anchor supply to support major liquefied natural gas ("LNG") projects currently being planned for the west coast of British Columbia. ARC has a significant presence in the region with a land position of 434 net sections; this represents one of the largest land positions of any operator in the most prospective areas of the play.

Since 2003, when ARC first established a presence in the region, we have become a key player having increased total 2P reserves from 110 Bcf to 1.9 Tcf of natural gas and 21 mmbbls of NGL's, increased production from 17 mmcf per day to 235 mmcf per day of natural gas and 1,800 bbls per day of liquids and significantly expanded its land base from 62 net sections to 434 net sections.  At present, ARC's NE B.C. Montney portfolio includes ownership in Dawson, Parkland, Tower, Sunrise/Sunset, Attachie, Septimus, Sundown, and Blueberry.  Although the Montney in this region is typically thought of as a dry gas reservoir, recent drilling conducted by ARC at Tower, Septimus and Attachie has tested liquids-rich gas and/or light oil.

In an effort to better understand ARC's long-term future reserve and resource potential in the NE B.C. Montney, GLJ was commissioned to conduct an Independent Resources Evaluation for ARC's lands in the 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 conducted effective December 31, 2011 based on GLJ forecast pricing as at January 1, 2012. 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 following map illustrates the Evaluated Areas included in the Independent Resources Evaluation.

Following is a summary of ARC's land base within the Evaluated Areas.

Table 1

NE B.C. Montney Resources and Reserves Land Base - December 31, 2011(1)
Evaluated Areas           ARC Lands Net
      Net sections
with DPIIP
      Net sections
      Liquids Yield
Dawson           129       119       74       5
Parkland           23       23       20       20 - 40
Tower           48       35       6       50 - 200
Sunrise/Sunset           32       32       27       5
Attachie           115       78       10       30 - 200
Septimus           22       20       7       5 - 30
Pouce Coupe           26       21       2       5
Sundown           18       6       0       5
Blueberry           21       5       0       0 - 200
TOTAL NET SECTIONS           434       339       146        

DPIIP has been assigned on 339 net sections, representing 78 per cent of ARC's land base of 434 net sections in the Evaluated Areas.  To date, 2P reserves have been assigned on 146 net sections, representing 34 per cent of ARC's landholdings in this region.

In addition to consistently adding reserves at a low F&D cost, ARC has developed an inventory of ECR in excess of the 2P reserves in the NE B.C. Montney region. GLJ has estimated the 2P reserves to be 1.9 Tcf of natural gas and 21 mmbbls of NGL's.  In addition to 2P reserves, GLJ has estimated the ECR to be 4.1 Tcf of natural gas and 101 mmbbls of NGL's effective December 31, 2011, up significantly from 0.7 Tcf of natural gas and 4 mmbbls of NGL's at year-end 2010.  TPIIP of 50.4 Tcf was assigned on ARC's 434 net sections of Montney lands in NE B.C. The TPIIP is comprised of 25.5 Tcf of DPIIP and 24.9 Tcf of UPIIP. The following tables summarize the results of the Independent Resources Evaluation.

Table 2a                                                                                            
Resource Categories (1)(2)(3)                                                                                           Tcf
Total Petroleum Initially In Place (TPIIP)                                                                                           50.4
Discovered Petroleum Initially In Place (DPIIP)                                                                                           25.5
Undiscovered Petroleum Initially In Place (UPIIP)                                                                                           24.9
(1)     TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off which means all gas
bearing rock has been incorporated into the calculations. Using a three per cent porosity cut-off the
TPIIP, DPIIP and UPIIP estimates would be 39.6 Tcf, 21.2 Tcf, and 18.4 Tcf, respectively.
(2)     The Resource Categories do not include the free oil/liquids or associated solution gas in the Tower field. 
Refer to Tower commentary in "2011 Operational and Property Review".
(3)     All volumes in table are company gross and raw gas volumes.

Table 2b                                                  
Reserves and Economic Contingent Resources (1)(2)(6)                         Low
Natural Gas (Tcf)                                                  
Reserves (3)                         1.0           1.9           2.4(4)
Economic Contingent Resources                         2.5           4.1           5.7
Natural Gas Liquids (mmbbls) (5)                                                  
Reserves (3)                         11.3           21.1           26.6
Economic Contingent Resources                         64.2           101.0           133.9
(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 Low Estimate are proved reserves, the volume under the heading
Best Estimate are 2P reserves and the number under the heading High Estimate are 2P plus possible
(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 associated with each
(5)     The liquid yields are based on average yield over the producing life of the property.
(6)     Cumulative production has been 0.2 Tcf on a raw basis.

Table 2c                                                                                          
Prospective Resources (1)(2)                                                                 Low
Natural gas (Tcf)                                                                 2.9           4.0           5.3
Natural gas liquids (mmbbls)                                                                 69.0           98.0           131.2
(1)     All UPIIP other than Prospective Resources has been categorized as unrecoverable.
(2)     All volumes in table are company gross and sales volumes.

TPIIP consists of both DPIIP and UPIIP.  In the Independent Resources Evaluation, DPIIP was generally ascribed to ARC's properties which were located within a three mile radius of a hydrocarbon test, and UPIIP was ascribed to ARC's properties which were located outside of a three mile radius but within an area where the reservoir is believed to contain hydrocarbons. TPIIP is a raw gas number and in some areas contains variable amounts of hydrocarbon liquids (propane, butane and condensate). Management estimates that approximately $54 million would need to be spent to drill and complete sufficient wells on ARC's land base within a three mile radius of known gas tests in order to reclassify the UPIIP to DPIIP.

Resource plays of this nature evolve based upon increased knowledge and confidence derived from ongoing drilling and production activities. The following table illustrates the growth which has been delivered in NE B.C. Montney reserves and resources in the Evaluated Areas over the past five years.

Table 3                                        
        NE B.C Montney Historic Reserves and Resources  
                Proved plus Probable Reserves       Economic Contingent Resource       DPIIP  
                Natural Gas
      Natural Gas
        2011 (1)       1.9       21.1       4.1       101.0       25.5  
        2010 (2)       1.3       12.5       0.7       4.0       10.1  
        2009       0.8       3.4       NA       NA       NA  
        2008       0.5       2.1       NA       NA       NA  
        2007       0.2       1.0       NA       NA       NA
(1)     Represents the Evaluated Areas included in the 2011 GLJ Independent Resources Evaluation.
(2)     2010 Evaluated Areas included Dawson, Parkland, Sunrise/Sunset, Septimus, and Sundown.

While the year-over-year growth in ECR has been exceptional, the total of cumulative production to date, 2P reserves and ECR still represents less than 13 per cent of the TPIIP, a clear indication of the early stage of the development of ARC's NE B.C. Montney assets.  Based on ARC's track record of successfully converting ECR into reserves and growing ECR, management expects that the ECR and reserves will continue to grow as drilling progresses.

This significant growth in reserves and resources is the result of the utilization of multi-stage fracture stimulation of horizontal wells, a technique that ARC pioneered in the Dawson area in 2005.  In addition to utilizing this technology throughout our Montney lands, ARC is utilizing horizontal drilling with multi-stage fraccing across our Western Canadian asset base and recently has had success in oil prone reservoirs such as Pembina Cardium, Ante Creek and Goodlands. As evidenced in Table 3, both the DPIIP and ECR have increased considerably over a short period of time. It is for this reason we have now chosen to publish our TPIIP estimate since it is less variable and does in fact form the basis for understanding the progression of resource quantification to commercialization.

ARC has successfully grown its NE B.C. Montney production from 45 mmcf per day in 2008 to over 235 mmcf per day of natural gas and 1,800 bbls per day of liquids at present. This growth has been achieved through staged development and the deployment of an average of $245 million of capital investment per year over the past three years.  To continue this growth, significant additional capital will be required.  ARC's 2P reserves in the NE British Columbia Montney region now stand at over 1.9 Tcf of natural gas and 21 mmbbls of NGL's.  As the 2P reserves grow, the amount of FDC required to bring the reserves to production also increases.  The FDC for this region is now estimated by GLJ in our reserve report to be $2.1 billion.  We believe the ultimate potential extends well beyond the currently booked 2P reserves and ECR; accordingly, the future capital requirements will also be significantly greater.

As we continue to evolve the development plan for our NE B.C. Montney assets, our perspectives on the ultimate production potential of the assets also continues to evolve. We estimate that the currently assigned 2P reserves plus the current estimate of ECR (combined resource of 6 Tcf of natural gas and 123 mmbbls of liquids) could sustain a peak production rate up to 800 mmcf per day of natural gas and 17,000 bbls per day of liquids for ten years. This compares to fourth quarter 2011 production from this area of approximately 235 mmcf per day of natural gas.  As previously stated, the cumulative production to date plus currently booked 2P reserves and the current best estimate of ECR represents less than 13 per cent of the TPIIP, therefore higher recovery factors could lead to higher production rates.  The key determining factor in what the ultimate recovery and associated peak production rate will be is expected to be the price of natural gas in the long-term.  It is within this context that ARC's long-term development plan for the assets has been developed and is being refined.

ARC's long-term development plan focuses on the highest rate of return projects across our asset portfolio. We are also focused on maintaining a high level of capital discipline as has been exhibited since our inception.  In the prevailing environment of low natural gas prices, near-term development of dry gas projects is not a priority.  ARC is fortunate to be in properties such as Dawson where we are centered on the "sweet spot" of a dry gas resource and returns remain competitive, even at a Cdn$3 field gas price.  However, further near-term investment in new dry gas developments will likely be deferred in favour of liquids-rich opportunities that offer higher rates of return.

ARC's successful 2011 drilling programs at Tower and Attachie proved up discoveries of liquids-rich gas with the liquids content ranging from 30 to 200 bbls of liquids per mmcf of raw gas.  ARC will continue to exploit these reservoirs and expand our understanding of long-term potential as evidenced by the planned seven well program at Tower in our 2012 budget.  These new high liquids yield projects are very compelling; however, a better understanding of long-term production performance of both the natural gas and liquids components of these properties is required before full scale development can occur.

Early stage drilling in high quality reservoirs at Attachie, Sunrise, Parkland, Tower and Dawson are indicating significant future resource opportunities in excess of our 2P reserves and, we believe, in excess of the current estimate of ECR.  While providing significant future growth opportunities for ARC, an asset of this nature also poses unique challenges to our organization.  The most important strategic question we are addressing is how to extract the greatest value for our shareholders while managing the technical, market and execution risks inherent in a world class asset of this nature.  Key considerations with respect to the future risk managed value creation from the assets are both the pace of development and how we fund the very significant capital required to fully develop the resource.  Equally important is understanding the implications of developing significant new natural gas production in what appears to be a well-supplied North American market.  These issues are well understood by ARC's management team and our long-term strategic development plan continues to evolve with the size and scope of our opportunities and developments in the market.

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 gas prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost, and the effectiveness of fraccing technology and applications.  The contingencies that prevent the ECR from being classified as reserves are due to the early evaluation stage of these potential development opportunities.  Additional drilling, completion, and test results are required before these contingent resources are converted to reserves and a larger component of DPIIP is converted to ECR.


In addition to the NE B.C. Montney, ARC also has a significant land position in the Montney oil and liquids-rich gas resource play at Ante Creek in northwestern Alberta. Over the past 11 years ARC has strategically amassed land holdings of over 260 net sections of land at Ante Creek.  2P reserves at Ante Creek of 47.2 mmboe are comprised of 43 per cent liquids and account for eight per cent of ARC's total 2P reserves.  This property will provide material production growth in 2012 and will also be a key property for future development. The Ante Creek property was not included in the Independent Resources Evaluation and therefore has no independent assessment of ECR, DPIIP or TPIIP. During the course of 2012, ARC will be working with GLJ to conduct a similar analysis at Ante Creek as the one which was conducted in the NE B.C. Montney.  It is our expectation that similar to the NE B.C. Montney, significant unbooked resource potential will be identified at Ante Creek.



ARC had another year of exceptional drilling results in 2011.  Since year-end 2008, ARC's 2P reserves have almost doubled to 572 mmboe, while our F&D costs and associated recycle ratios have been among the best in the industry.  The NE B.C. Montney region has been the primary driver of this strong performance with reserves increasing by approximately 300 per cent since year-end 2008 and production increasing from 45 mmcf per day to 235 mmcf per day of natural gas and 1,800 bbls per day of liquids at present.

During 2011 ARC spent $726 million to execute its capital program.  ARC's 2011 capital spending included $92 million on facilities and an investment of $75 million in undeveloped land.  ARC drilled 164 gross (154 net) wells on operated lands with a 100 per cent success rate.  A significant portion of ARC's 2011 capital program was focused on resource play development with $240 million (33 per cent of the 2011 capital spending) being allocated to the Montney region in NE B.C. and Ante Creek in Alberta.

ARC's 2011 capital development program yielded 2P reserve additions of 132 mmboe, representing a 433 per cent replacement of 2011 production through internal development.  ARC divested of certain non-core properties in 2011 with attributed 2P reserves of 14.6 mmboe, net of acquisitions.  ARC's total reserve additions were 117 mmboe after the net divestment of properties, representing a total 2011 production replacement of 385 per cent.  This is the fourth year in a row that ARC has been able to replace greater than 200 per cent of production from internal development activities.

The following discussion includes well flow-test results which are not necessarily indicative of long-term performance or of ultimate recovery from the subject wells.

In 2011, ARC drilled 12 wells in the Dawson field and increased production to 165 mmcf per day with the commissioning of the second 60 mmcf per day Gas Plant.   The 2P reserves increased 15 per cent from 882 Bcf to 1,012 Bcf. 

As a result of well productivity in Dawson continuing to exceed expectations, ARC has a sufficient inventory of wells waiting to be brought on-stream to maintain current production of 165 mmcf per day throughout 2012.  ARC plans to drill one well at Dawson in 2012 to retain lands which would otherwise expire.

At Parkland, the Upper Montney section is approximately 100 meters thick with significant portions having greater than six per cent porosity.  ARC drilled 10 wells at Parkland in 2011.  ARC believes that existing horizontal wells are not draining the complete thickness of the Montney, and therefore requires a second horizontal well, beneath the existing ones to effectively drain the entire section.  During 2011, ARC drilled its first well into the lower portion of the upper Montney beneath an existing well bore and realized a one month initial production rate ("IP") of 4.7 mmcf per day which is similar to the upper well.  No communication between the two wells has been seen to date.  Should this continue to be the case, the future drilling inventory at Parkland will expand considerably.

The year-end 2011 2P reserves increased 28 per cent to 49.7 mmboe from 38.8 mmboe at year-end 2010 after the production of 3 mmboe in 2011.

ARC's 48 net sections of contiguous land north and west of the Parkland field is referred to as Tower.  When ARC acquired this land in 2010, it was considered to be a potential very tight oil play which was unproven at the time of the acquisition.  Since that time, ARC has realized a significant liquids-rich hydrocarbon opportunity.  ARC drilled three horizontal wells in the Tower field in 2011 applying newly developed multi-stage fracture stimulation techniques.  The 13-8-82-17 well was flowing at 610 boe per day (340 bbls per day of 45º API oil, condensate and natural gas liquids and 1.7 mmcf per day of gas) at the end of a 23 day production test.  The 5-14-81-17 well was flowing at 405 boe per day (240 bbls of 47º API condensate and natural gas liquids and 1.0 mmcf per day of gas) at the end of an 11 day production test. The A4-8-81-16 well, was flowing 445 boe per day, (230 bbls per day of 49º API condensate and natural gas liquids and 1.3 mmcf per day of gas) at the end of a 12 day production test.  The A4-8 well was put on production in late October 2011 with an initial 30 day average production rate of 258 barrels per day of oil and 1.1 mmcf per day of liquids-rich gas.  The test and production volumes only refer to the free liquids produced.  In addition to the free liquids, the gas stream is liquids-rich with 30 bbls per mmcf of gas; this will be recovered upon processing the gas.

GLJ has assigned 4.5 mmboe of 2P reserves (1.4 mmbbls liquids and 19 Bcf of natural gas) at Tower for year-end 2011.  The Tower prospect is a liquids-rich gas reservoir.  GLJ recognizes an oil reservoir in one gross (0.5 net) section of the pool with 2P reserves of 115 mbbls of oil and 549 mbbls of oil in ECR on the one oil section.

ARC's seven well 2012 capital program will include gathering additional fluid samples on new wells and completing recombined pressure-volume-temperature ("PVT") studies to better understand the fluids in place at Tower.

During 2011, ARC completed and tested a previously drilled horizontal well at Septimus.  The A13-11-81-20W6 well, tested at a stabilized rate of 11.5 mmcf per day of gas and expected 24 barrels per mmcf of liquids, at 1,200 psia at the end of a 3.5 day production test.  ARC acquired three additional sections of land in 2011, increasing its land base to 22 net sections.

ARC holds a prospective land base of 115 net sections of liquids-rich Montney acreage at Attachie.  During 2011, ARC drilled and tested three horizontal Montney wells spread across the large land base.  The first horizontal well, 4-20-84-24, on the west side of the land base, was completed in the second quarter of 2011 and achieved a stabilized test production rate of 10.7 mmcf per day of gas and 350 barrels per day of free liquids at a pressure of 1,300 psia over a 4.2 day test period.  This is a promising indicator of the potential of Attachie for commercial development.  ARC will continue to collaborate with third parties regarding options for commercial development and infrastructure requirements for this new play.

ARC's strategy for 2011 was to test new completion techniques on three Montney zones, the Upper Montney 'A' and 'B' and the Lower Montney 'E', to establish important production type curves for development of the Sunrise property.  The Montney 'A' well tested at 11.2 mmcf per day at 2,074 psia over a 2.1 day test period.  This well` has been on production since September 2011 and is currently producing 5.6 mmcf per day with significant back-pressure being held on the well at 1,885 psia.  The Montney 'B' well tested at 12 mmcf per day at 2,234 psia over a 2.4 day test period is currently producing 5.5 mmcf per day against 1,450 psia of back pressure.  The Montney 'E' well tested at 6.7 mmcf per day at 754 psia over a 2.5 day test period and is currently producing 3 mmcf per day against 360 psia of back pressure. Production of 15 mmcf per day from the three operated wells was brought on-stream through a third party facility late in the third quarter of 2011.

The very positive production results from all three zones have allowed GLJ to significantly increase 2P reserves from 235 Bcf at year-end 2010 to 483 Bcf at year-end 2011.  The Montney zone in Sunrise is approximately 320 meters thick, translating into a huge potential resource.

Ante Creek
The Ante Creek property in Northern Alberta is a Montney oil play in which ARC has a land position of 260 net sections.  ARC's Ante Creek production averaged 7,400 boe per day in 2011 (49 per cent crude oil and natural gas liquids, 51 per cent natural gas), a level which is currently facility constrained.  ARC plans to double drilling to 40 horizontal wells and complete a new 30 mmcf per day processing facility to alleviate processing constraints during 2011.  ARC drilled 20 horizontal wells in 2011 in anticipation of the new facility being on-stream at the end of the first quarter 2012. 

ARC added 4.7 mmboe of reserves at Ante Creek in 2011, to bring total reserves to 47.2 mmboe.  ARC believes that the Ante Creek property will provide significant near-term growth opportunities with continued drilling and expansion of facilities.

ARC continues to have positive results with the horizontal drilling program in the Pembina area.  In 2011, ARC drilled 37 horizontal wells in the Cardium formation and added 3.2 mmboe of 2P reserves through this development activity.  Production increased to 10,450 boe per day of primarily light oil in 2011, an increase of 14 per cent from 2010.  This is the first significant increase in production as a result of development drilling activity since ARC began operations in the Pembina area in 1996.


GLJ conducted an independent reserves evaluation effective December 31, 2011 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, 2012 as outlined in Table 4 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").

Table 4                                                              
GLJ January 1, 2012
Price Forecast
                        West Texas
Crude Oil
Crude Oil
          Natural Gas
          Foreign Exchange
2012                         97.00           97.96           3.49           0.98
2013                         100.00           101.02           4.13           0.98
2014                         100.00           101.02           4.59           0.98
2015                         100.00           101.02           5.05           0.98
2016                         100.00           101.02           5.51           0.98
2017                         100.00           101.02           5.97           0.98
2018                         101.35           102.40           6.21           0.98
2019                         103.38           104.47           6.33           0.98
2020                         105.45           106.58           6.46           0.98
2021                         107.56           108.73           6.58           0.98
Escalate thereafter at                         +2.0%/yr           +2.0%/yr           +2.0%/yr           0.98

Table 5                                                            
RESERVES SUMMARY           Light and
Crude Oil
Crude Oil
Crude Oil
Gas (Bcf)
Company Gross                                                            
Proved Producing           87,626       1,874       89,500       10,210       655       208,920       210,860
Proved Developed Non-producing           1,794       0       1,794       756       44       9,952       15,678
Proved Undeveloped           12,768       0       12,768       8,122       719       140,769       107,894
Total Proved           102,188       1,874       104,062       19,088       1,419       359,641       334,432
Proved plus Probable           135,071       2,308       137,379       32,774       2,413       572,374       485,121
Net  Interest                                                            
Proved Producing           75,293       1,801       77,094       7,640       556       177,318       179,481
Proved Developed Non-producing           1,587       0       1,587       626       38       8,485       13,097
Proved Undeveloped           11,025       0       11,025       6,736       604       118,362       91,114
Total Proved           87,905       1,801       89,706       15,002       1,197       304,165       283,692
Proved plus Probable           115,416       2,220       117,636       25,955       2,001       477,028       406,543
Company Interest (1)                                                            
Proved Producing           87,755       2,040       89,795       10,319       662       210,425       212,733
Proved Developed Non-producing           1,796       0       1,796       756       44       9,959       15,685
Proved Undeveloped           12,778       0       12,778       8,123       720       140,840       107,921
Total Proved           102,329       2,040       104,369       19,198       1,426       361,224       336,339
Proved plus Probable           135,253       2,526       137,779       32,903       2,423       574,435       487,418
(1)     Company Interest reserves represent gross reserves plus royalty interest reserves.

Table 6
            Light and
Medium Crude
Oil (mbbl)
      Heavy Crude
Oil (mbbl)
      Total Crude
Oil (mbbl)
      Natural Gas
      Oil Equivalent
PROVED PRODUCING                                                    
Opening Balance           90,258       2,071       92,329       11,302       643,377       210,861
 Exploration Discoveries           0       0       0       0       0       0
 Drilling Extensions           1,856       0       1,856       972       64,960       13,655
 Improved Recovery           880       0       880       28       300       958
 Infill Drilling           3,745       60       3,805       382       40,370       10,915
 Technical Revisions           1,886       6       1,892       636       51,995       11,193
 Acquisitions           21       6       27       3       307       81
 Dispositions           -1,362       0       -1,362       -1,427       -28,084       -7,470
 Economic Factors           -123       -1       -124       -66       -5,682       -1,137
 Production           -9,535       -268       -9,803       -1,620       -112,284       -30,137
Closing Balance           87,626       1,874       89,500       10,210       655,259       208,919
TOTAL PROVED                                                    
Opening Balance           103,104       2,105       105,209       18,329       1,265,363       334,432
 Exploration Discoveries           61       0       61       465       6,702       1,643
 Drilling Extensions           4,015       0       4,015       2,822       218,146       43,195
 Improved Recovery           451       0       451       26       284       524
 Infill drilling           5,157       30       5,187       380       41,558       12,493
 Technical Revisions           529       1       530       1,544       131,257       23,949
 Acquisitions           21       6       27       47       8,857       1,550
 Dispositions           -1,465       0       -1465       -2,447       -55,516       -13,165
 Economic Factors           -150       0       -150       -458       -85,421       -14,845
 Production           -9,535       -268       -9,803       -1,620       -112,284       -30,137
Closing Balance           102,188       1,874       104,062       19,088       1,418,946       359,641
Opening Balance           33,750       672       34,422       8,003       649,578       150,689
 Exploration Discoveries           131       0       131       204       2,981       832
 Drilling Extensions           2,733       0       2,733       5,996       319,364       61,956
 Improved Recovery           -152       0       -152       0       -48       -160
 Infill Drilling           714       -30       684       80       14,359       3,157
 Technical Revisions           -3,408       -208       -3,616       -101       -18,079       -6,727
 Acquisitions           11       0       11       87       16,598       2,864
 Dispositions           -899       0       -899       -741       -25,506       -5,891
 Economic Factors           3       0       3       158       35,134       6,017
 Production           0       0       0       0       0       0
Closing Balance           32,883       434       33,317       13,686       994,381       212,734
Opening Balance           136,854       2,777       139,631       26,332       1,914,941       485,121
 Exploration Discoveries           192       0       192       669       9,683       2,475
 Drilling Extensions           6,748       0       6,748       8,818       537,510       105,151
 Improved Recovery           299       0       299       26       236       364
 Infill Drilling           5,871       0       5,871       460       55,917       15,651
 Technical Revisions           -2,879       -207       -3,086       1,443       113,178       17,222
 Acquisitions           32       6       38       134       25,455       4,415
 Dispositions           -2,364       0       -2364       -3,188       -81,022       -19,056
 Economic Factors           -147       0       -147       -300       -50,287       -8,828
 Production           -9,535       -268       -9,803       -1,620       -112,284       -30,137
Closing Balance           135,071       2,308       137,379       32,774       2,413,327       572,375


ARC's 2P RLI increased to 17 years at year-end 2011 while the proved RLI was 10.7 years based upon the GLJ reserves and ARC's 2012 production guidance mid-point of 92,500 boe per day. The increase in the 2P RLI from 2008 through 2011 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 7                                                                                                    
Reserve Life Index                                                   2011(1)           2010(2)           2009           2008           2007
Total Proved                                                   10.7           10.4           10.3           10.3           9.7
Proved Plus Probable                                                   17.0           15.1           14.4           13.6           12.3
(1)     Based on 2012 production guidance midpoint of 92,500 boe per day.
(2)     2010 reserves excludes 10.6 mmboe proved and 14.1 mmboe 2P gross reserves relating to assets divested
in January 2011 and included in the year-end 2010 reserves evaluation.  The 2011 production guidance
excluded production from the divested assets of approximately 3,400 boe per day.


ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2012 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 8                                    
NPV of Cash Flow (1)   Undiscounted
at 5%
at 10%
at 15%
at 20%
Before Tax                                    
Proved Producing   6,954       4,750       3,662       3,014       2,583
Proved Developed Non-Producing   301       214       168       140       121
Proved Undeveloped   2,678       1,572       975       620       393
Total Proved   9,933       6,536       4,805       3,774       3,097
Probable   6,365       3,021       1,715       1,084       735
Proved plus Probable   16,298       9,557       6,520       4,858       3,832
After Tax (2)                                    
Proved Producing   5,888       4,117       3,229       2,693       2,332
Proved Developed Non-Producing   224       160       125       104       90
Proved Undeveloped   1,999       1,131       662       384       208
Total Proved   8,112       5,407       4,016       3,181       2,630
Probable   4,752       2,227       1,239       764       502
Proved plus Probable   12,863       7,635       5,255       3,945       3,132
(1)     Based on NI-51-101 Net Interest reserves and GLJ January 1, 2012 Forecast Prices and Costs.
(2)     Based on ARC's estimated tax pools at year-end 2011.
(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
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 56 per cent of the before tax 2P estimated value while total proved reserves account for 74 per cent of the before tax 2P estimated value.


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 now booked on the Montney acreage has yielded an increased capital cost expectation in the 2011 evaluation.

Following is a summary of GLJ estimated FDC required to bring total proved and probable reserves on production.

Table 9                                                                                      
Future Development Capital (1)
$ Millions
                                                            Total Proved                       Total Proved +
2012                                                             301                       448
2013                                                             521                       650
2014                                                             326                       496
2015                                                             328                       544
2016                                                             206                       287
Remainder                                                             165                       687
Total FDC undiscounted                                                             1,847                       3,112
Total FDC discounted at 10%                                                             1,444                       2,299
(1)     FDC as per GLJ independent reserve evaluation as of December 31, 2011 and based on GLJ forecast pricing as
at January 1, 2012.


ARC's F&D costs were $5.50 per boe and $10.84 per boe for 2P and proved reserves, respectively in 2011, excluding FDC ($11.96 per boe and $16.23 per boe, respectively, for 2P and proved reserves including 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 and Attachie.

Including net dispositions, ARC's 2011 FD&A costs were $5.24 per boe of 2P and $11.11 per boe of proved reserves before FDC ($12.23 per boe and $17.13 per boe, respectively, for 2P and proved reserves including FDC).  The three year average FD&A costs were $7.15 per boe for 2P reserves and $12.02 per boe for total proved reserves, excluding FDC.

ARC's three year 2P F&D and FD&A costs excluding FDC of $5.80 per boe and $7.15 per boe, respectively, are at the lowest levels since 1999 and 2001, respectively.  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 10                                              
                            Excluding FDC     Including FDC
FD&A costs - Company Gross (1)(2)
$ Thousands
                          Proved     Proved +
    Proved     Proved +
E&D capital expenditures                           726,011     726,011     726,011     726,011
E&D capital expenditures - change in FDC                           -     -     360,466     852,821
  Total E&D capital expenditures                           726,011     726,011     1,086,477     1,578,832
Net dispositions                           (111,285)     (111,285)     (111,285)     (111,285)
Net dispositions - change in FDC                           -     -     (27,111)     (32,389)
Total net dispositions                           (111,285)     (111,285)     (138,395)     (143,674)
  Total capital including net dispositions                           614,726     614,726     948,082     1,435,158
E&D reserve additions                           66,961     132,032     66,961     132,032
Net disposition reserves                           (11,615)     (14,641)     (11,615)     (14,641)
  Reserve additions including net dispositions                           55,346     117,391     55,346     117,391
FD&A costs - $ per boe:                                              
F&D Costs - Current Year                           10.84     5.50     16.23     11.96
F&D Costs - Three Year Average                           9.86     5.80     14.51     11.54
Net Disposition Cost - Current Year                           9.58     7.60     11.92     9.81
Net Disposition Cost - Three Year Average                           25.19     16.03     31.78     21.83
FD&A Costs - Current Year                           11.11     5.24     17.13     12.23
FD&A Costs - Three Year Average                           12.02     7.15     16.95     12.90
(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 11                                                                        
Company Gross Historic FD&A Costs
($ per boe)
                              2011         2010         2009         2008         2007
Proved Reserves:                                                                        
Annual FD&A excluding FDC                               11.11         13.35         10.53         14.31         20.71
Three year average FD&A excluding FDC                               12.02         12.82         13.86         18.50         18.75
Annual FD&A including FDC                               17.13         18.21         14.36         22.01         20.71
Three year average FD&A including FDC                               16.95         18.04         18.41         23.12         20.57
Proved plus Probable Reserves:                                                                        
Annual FD&A excluding FDC                               5.24         9.23         6.46         10.18         19.24
Three Year Average FD&A excluding FDC                               7.15         8.62         9.61         14.85         16.77
Annual FD&A including FDC                               12.23         14.26         11.59         17.08         20.29
Three Year Average FD&A including FDC                               12.90         14.08         14.81         20.04         19.43


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 as follows:
  Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
  Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
  High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.


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, 2011, 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  In relation to the disclosure of estimates in the Highlights, Resources and Reserves Discussion and Analysis, and 2011 Operational and Property Review, 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 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".

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.

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 "2011 Independent Reserve Evaluation" and the recognition of significant resources under the heading "Resources and Reserves Discussion and Analysis", 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, 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 2012 oil and gas production to average 90,000 to 95,000 barrels of oil equivalent per day from its properties in western Canada.  ARC's Common Shares trade on the TSX under the symbol ARX.


John P. Dielwart,
Chief Executive Officer












PDF with caption: "Evaluated Areas included in the Independent Resources Evaluation". PDF available at:

For further information:

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ARC Resources Ltd.
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Calgary, AB  T2P 0H7

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