ARC Resources Ltd. Announces Fifth Consecutive Year of Greater than 200 per cent Produced Reserves Replacement in 2012

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. 

    --  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.


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
    --  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

Table 1                                                                 

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 
at                     +2.0%/yr     +2.0%/yr       +2.0%/yr         1.00 
Table 2                                                                                 

                                                                       Oil          Oil
                  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                                                                           
Producing      88,539    1,739    90,278      9,578       607      201,018      208,920 
Non-producing   1,973        0     1,973      1,260        53       12,044        9,952 
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                                                                               

                 Crude      Crude       Total                                    Oil
                                        Crude       NGLs       Natural     Equivalent
                  Oil        Oil         Oil                      Gas
                (mbbl)     (mbbl)      (mbbl)     (mbbl)        (mmcf)         (mboe)


Balance         87,626      1,874      89,500     10,210       655,259        208,920

  Discoveries        0          0           0          0             0              0

  and Improved
  (1))           9,001        167       9,168      1,250        41,202         17,285

  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

  Factors         -602        -13        -615       -103       -17,046         -3,559

  Production   -11,134       -245     -11,379     -1,800      -124,607        -33,947

Balance         88,539      1,739      90,278      9,578       606,975        201,018

TOTAL PROVED                                                                         

Balance        102,188      1,874     104,062     19,088     1,418,946        359,641

  Discoveries        0          0           0          7           279             54

  and Improved
  Recovery (
  (1))          11,676        167      11,843      1,989        62,485         24,246

  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

  Factors       -1,425        -13      -1,438     -1,222      -157,388        -28,891

  Production   -11,134       -245     -11,379     -1,800      -124,607        -33,947

Balance        105,255      1,739     106,994     20,214     1,420,174        363,904


Balance        135,071      2,308     137,379     32,774     2,413,327        572,374

  Discoveries        0          0           0          9           356             68

  and Improved
  (1))          19,064        278      19,342      3,086       109,529         40,683

  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

  Factors       -1,516         -9      -1,525     -1,394       -70,270        -14,631

  Production   -11,134       -245     -11,379     -1,800      -124,607        -33,947

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 
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. 
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                                                              
Producing             5,887      4,163      3,249      2,686      2,305 
Non-Producing           333        234        179        145        122 
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)
Producing             4,985      3,582      2,829      2,360      2,039 
Non-Producing           249        175        133        107         90 
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.


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.


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                                             

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


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 

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

(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.


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

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
        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.


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

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 "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.


Myron M. Stadnyk
President and Chief Executive Officer

For further information about ARC Resources Ltd., please visit our  website or contact: Investor Relations, 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:

CO: ARC Resources Ltd.
ST: Alberta

-0- Feb/06/2013 23:01 GMT

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