ARC Energy Trust releases 2009 year-end reserves information

CALGARY, Feb. 9 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC") released today its 2009 year-end reserves information.

    
    HIGHLIGHTS

    -   Proved reserves increased by 11 per cent to 270 mmboe and proved plus
        probable reserves increased by 18 per cent to 379 mmboe, compared to
        year-end 2008 levels. On a per-unit basis at year-end 2009, proved
        reserves increased by two per cent and proved plus probable reserves
        increased by eight per cent relative to year-end 2008.
    -   ARC replaced 347 per cent of annual production at an all-in annual
        Finding, Development and Acquisition ("FD&A") cost of $6.44 per
        barrel of oil equivalent ("boe") before consideration of future
        development capital ("FDC") for the proved plus probable reserves
        category. This is the third consecutive year of reducing FD&A costs
        and brings our three year average FD&A prior to FDC down to $9.57 per
        boe. FD&A costs including FDC were $11.57 per boe, a 32 per cent
        reduction from the $17 per boe achieved in 2008.
    -   ARC has realized its lowest proved plus probable F&D cost in a decade
        of $5.45 per boe prior to FDC.
    -   Net acquisition spending was $158 million resulting in a net
        acquisition cost of $10.97 per boe for the proved plus probable
        category and $19.87 per boe for the total proved category, prior to
        FDC.
    -   These reserves additions result in a one year recycle ratio of 3.8
        times, using our $6.44 per boe proved plus probable FD&A cost prior
        to FDC, and 2.6 times using our $9.57 per boe three year average
        FD&A, based on the 2009 operating netback of $24.72 per boe.
    -   Total proved plus probable reserves for the Upper Montney in the
        Dawson and West Montney areas have increased to 784 Bcf, a 73 per
        cent increase over year-end 2008 and a 333 per cent increase from
        year-end 2007.
    -   The proved plus probable reserve life index ("RLI") increased to 14.5
        years with the proved RLI remaining effectively unchanged at 10.3
        years based on the mid-point 2010 production guidance of 71,500 boe
        per day.
    

RESERVES

Reserves included herein are stated on a company interest basis (before royalty burdens and including royalty interests) unless noted otherwise. All reserves information has been prepared in accordance with National Instrument ("NI") 51-101. This news release contains several cautionary statements that are specifically required by NI 51-101 under the heading "Resources and Operational Information". In addition to the detailed information disclosed in this news release more detailed information on a company gross basis (working interest before deduction of royalties without including any royalty interests) will be included in ARC's Annual Information Form ("AIF"). Numbers presented may not add due to rounding.

Based on an independent reserves evaluation conducted by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2009 and prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGEH") and NI 51-101, ARC had proved plus probable reserves of 379 mmboe. Reserve additions from exploration and development activities (including revisions) were 66 mmboe while 14 mmboe were added through acquisitions (net of minor dispositions), bringing the total additions to 80 mmboe. The 66 mmboe addition through development activities represents 285 per cent of the 23 mmboe produced during 2009 and the total 80 mmboe represents 347 per cent of the 23 mmboe produced during 2009. As a result, year-end 2009 reserves are 18 per cent higher than the 322 mmboe of proved plus probable reserves recorded at year-end 2008. Proved developed producing reserves represent 69 per cent of total proved reserves and 49 per cent of proved plus probable reserves; total proved reserves account for 71 per cent of proved plus probable reserves. Approximately 40 per cent of ARC's proved plus probable reserves are crude oil and natural gas liquids and 60 per cent are natural gas on a 6:1 boe conversion basis.

    
    RESERVES SUMMARY Using GLJ January 1, 2010 Forecast Prices and Costs

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    Company Interest (Gross + Royalties Receivable)

                                                                Oil      Oil
             Light and    Heavy    Total             Total     Equi-    Equi-
                Medium    Crude    Crude           Natural   valent   valent
             Crude Oil      Oil      Oil     NGLs      Gas     2009     2008
                 (mbbl)   (mbbl)   (mbbl)   (mbbl)    (bcf)   (mboe)   (mboe)
    -------------------------------------------------------------------------
    Proved
     Producing  93,137    2,353   95,490    8,443    490.1  185,623  180,777
    Proved
     Developed
     Non-
     Producing   1,113       13    1,126      420     37.9    7,863    7,794
    Proved
     Undeveloped 8,667        0    8,667    2,636    388.5   76,048   54,719
    Total
     Proved    102,917    2,366  105,284   11,500    916.5  269,535  243,292
    Proved
     plus
     Probable  134,570    3,027  137,598   15,815  1,353.2  378,953  321,723
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    Company Gross

                                                                Oil      Oil
             Light and    Heavy    Total             Total     Equi-    Equi-
                Medium    Crude    Crude           Natural   valent   valent
             Crude Oil      Oil      Oil     NGLs      Gas     2009     2008
                 (mbbl)   (mbbl)   (mbbl)   (mbbl)    (bcf)   (mboe)   (mboe)
    -------------------------------------------------------------------------
    Proved
     Producing  92,989    2,199   95,187    8,299    481.1  183,663  178,659
    Proved
     Developed
     Non-
     Producing   1,112       13    1,125      420     37.9    7,862    7,793
    Proved
     Undeveloped 8,655        0    8,655    2,636    388.4   76,018   54,700
    Total
     Proved    102,756    2,212  104,968   11,355    907.3  267,543  241,154
    Proved
     plus
     Probable  134,363    2,834  137,197   15,637  1,342.3  376,543  319,114
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    Net Interest

                                                                Oil      Oil
             Light and    Heavy    Total             Total     Equi-    Equi-
                Medium    Crude    Crude           Natural   valent   valent
             Crude Oil      Oil      Oil     NGLs      Gas     2009     2008
                 (mbbl)   (mbbl)   (mbbl)   (mbbl)    (bcf)   (mboe)   (mboe)
    -------------------------------------------------------------------------
    Proved
     Producing  79,083    2,157   81,239    5,857    419.2  156,959  152,789
    Proved
     Developed
     Non-
     Producing     921       12      933      297     29.8    6,194    5,604
    Proved
     Undeveloped 7,151        0    7,151    2,062    319.9   62,525   41,350
    Total
     Proved     87,154    2,168   89,322    8,216    768.8  225,678  199,742
    Proved
     plus
     Probable  112,919    2,745  115,664   11,399  1,123.7  314,350  262,928
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    RESERVES RECONCILIATION
    Company Interest (Company Gross + Royalties Receivable)

                 Light and     Heavy     Total               Total       Oil
                    Medium     Crude     Crude             Natural     Equiv-
                 Crude Oil       Oil       Oil      NGLs       Gas     alent
                     (mbbl)    (mbbl)    (mbbl)    (mbbl)    (mmcf)    (mboe)
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    PROVED PRODUCING
    Opening
     Balance        94,922     2,552    97,474     8,692   447,665   180,777
      Exploration
       Discoveries       0         0         0         0         0         0
      Drilling
       Extensions      501         0       501       128    32,136     5,985
      Improved
       Recovery      3,871         7     3,878       192     8,678     5,516
      Infill
       Drilling      1,433        12     1,445       301    52,041    10,419
      Technical
       Revisions     1,775       120     1,895       203     9,271     3,643
      Acquisitions     615         0       615       294    14,522     3,330
      Dispositions    -241         0      -241        -1       -90      -257
      Economic
       Factors         -71        36       -35       -20    -3,258      -598
      Production    -9,667      -374   -10,041    -1,346   -70,824   -23,191
    Closing
     Balance        93,137     2,353    95,490     8,443   490,140   185,623
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    TOTAL PROVED
    Opening
     Balance       105,031     2,561   107,592    11,214   746,914   243,292
      Exploration
       Discoveries      11         0        11         3     1,267       225
      Drilling
       Extensions      450         0       450       371   110,976    19,317
      Improved
       Recovery      1,897        16     1,913        14       807     2,061
      Infill
       drilling      1,962        12     1,974       456    61,394    12,662
      Technical
       Revisions     2,176       116     2,292       202    31,824     7,797
      Acquisitions   1,369         0     1,369       606    37,535     8,231
      Dispositions    -241         0      -241        -1       -90      -257
      Economic
       Factors         -70        35       -35       -20    -3,294      -602
      Production    -9,667      -374   -10,041    -1,346   -70,824   -23,191
    Closing
     Balance       102,918     2,366   105,284    11,500   916,509   269,535
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    PROBABLE
    Opening
     Balance        30,168       682    30,850     3,364   265,302    78,431
      Exploration
       Discoveries       4         0         4         1       435        77
      Drilling
       Extensions      571         0       571       218   109,540    19,046
      Improved
       Recovery        371         2       373         5        89       393
      Infill
       Drilling        442         2       444       294    33,252     6,280
      Technical
       Revisions    -1,516       -36    -1,552         4     3,148    -1,021
      Acquisitions   1,843         0     1,843       440    26,205     6,650
      Dispositions    -183         0      -183         0       -24      -186
      Economic
       Factors         -46        10       -36       -11    -1,210      -251
      Production         0         0         0         0         0         0
    Closing
     Balance        31,653       661    32,314     4,315   436,736   109,419
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    PROVED PLUS
     PROBABLE
    Opening
     Balance       135,199     3,243   138,442    14,578 1,012,216   321,723
      Exploration
       Discoveries      15         0        15         4     1,702       302
      Drilling
       Extensions    1,021         0     1,021       589   220,516    38,363
      Improved
       Recovery      2,268        18     2,286        19       896     2,454
      Infill
       Drilling      2,404        14     2,418       750    94,646    18,942
      Technical
       Revisions       660        80       740       206    34,972     6,776
      Acquisitions   3,212         0     3,212     1,046    63,740    14,881
      Dispositions    -424         0      -424        -1      -114      -443
      Economic
       Factors        -116        45       -71       -31    -4,504      -853
      Production    -9,667      -374   -10,041    -1,346   -70,824   -23,191
    Closing
     Balance       134,571     3,027   137,598    15,815 1,353,245   378,954
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Additional reserves reconciliation information on a Company Gross basis is included at the end of this news release.

RESERVE LIFE INDEX ("RLI")

ARC's proved plus probable RLI was 14.5 years at year-end 2009 while the proved RLI was 10.3 years based upon the GLJ reserves and ARC's 2010 production guidance mid-point of 71,500 boe per day. The following table summarizes ARC's historical RLI.

    
    Reserve Life Index
                           2009     2008     2007     2006     2005     2004
    -------------------------------------------------------------------------
    Total Proved           10.3     10.4      9.8      9.8     10.3      9.7
    Proved Plus Probable   14.5     13.8     12.5     12.4     12.9     12.2
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NET PRESENT VALUE ("NPV") SUMMARY

ARC's crude oil, natural gas and natural gas liquids reserves were evaluated using GLJ's product price forecasts effective January 1, 2010 prior to provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimated by GLJ represent the fair market value of the reserves.

    
    NPV of Cash Flow Before Income Taxes Using GLJ January 1, 2010 Forecast
    Prices and Costs

    NI 51-101
     Net                      Discounted  Discounted  Discounted  Discounted
     interest   Undiscounted       at 5%      at 10%      at 15%      at 20%
                         $MM         $MM         $MM         $MM         $MM
    -------------------------------------------------------------------------
    Proved Producing   7,164       4,755       3,618       2,956       2,520
    Proved Developed
     Non-Producing       230         157         119          96          80
    Proved
     Undeveloped       1,889       1,219         847         615         458
    Total Proved       9,283       6,130       4,584       3,666       3,058
    Probable           4,285       2,072       1,222         806         569
    Proved plus
     Probable         13,568       8,202       5,805       4,472       3,627
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At a 10 per cent discount factor, the proved producing reserves make up 62 per cent of the proved plus probable value while total proved reserves account for 79 per cent of the proved plus probable value.

The following table provides an estimate of the NPV of Cash Flow on an after tax basis assuming that ARC would be subject to the equivalent of corporate income tax on its income beginning in 2011. It should be noted that this estimate does not take into account any corporate tax deductions such as interest and general and administrative expenses or for any tax pools generated by capital expenditures beyond what exists in the GLJ forecast. Details of ARC's tax pools at year-end 2009 are presented in the MD&A section of the year-end financial results news release dated February 9, 2010.

    
    NPV of Cash Flow After Income Taxes Using GLJ January 1, 2010 Forecast
    Prices and Costs

    NI 51-101
     Net                      Discounted  Discounted  Discounted  Discounted
     interest   Undiscounted       at 5%      at 10%      at 15%      at 20%
                         $MM         $MM         $MM         $MM         $MM
    -------------------------------------------------------------------------
    Proved Producing   6,023       4,095       3,173       2,629       2,267
    Proved Developed
     Non-Producing       177         121          92          74          62
    Proved
     Undeveloped       1,416         891         598         415         291
    Total Proved       7,616       5,107       3,863       3,118       2,621
    Probable           3,220       1,548         903         588         409
    Proved plus
     Probable         10,836       6,655       4,766       3,706       3,030
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    GLJ January 1, 2010 Price Forecast
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                             West Texas    Edmonton      Natural
                           Intermediate       Light       Gas at     Foreign
                              Crude Oil   Crude Oil         AECO    Exchange
    Year                       ($US/bbl)  ($Cdn/bbl) ($Cdn/mmbtu)  ($US/$Cdn)
    -------------------------------------------------------------------------
                      2010        80.00       83.26         5.96        0.95
                      2011        83.00       86.42         6.79        0.95
                      2012        86.00       89.58         6.89        0.95
                      2013        89.00       92.74         6.95        0.95
                      2014        92.00       95.90         7.05        0.95
                      2015        93.84       97.84         7.16        0.95
                      2016        95.72       99.81         7.42        0.95
                      2017        97.64      101.83         7.95        0.95
                      2018        99.59      103.88         8.52        0.95
                      2019       101.58      105.98         8.69        0.95
    Escalate thereafter at     +2.0%/yr    +2.0%/yr     +2.0%/yr
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NET ASSET VALUE

The following net asset value ("NAV") table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of the Trust's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of the Trust. The value is a snapshot in time and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. It should not be assumed that the net present values estimated by GLJ represent the fair market value of the reserves.

    
    NAV at December 31, 2009(a)
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                                                       2009 NAV     2008 NAV
                                                      GLJ Price    GLJ Price
                                                       Forecast     Forecast
    $Millions, except per unit amounts                 (2010-01)    (2009-01)
    -------------------------------------------------------------------------
    Value of NI 51-101 Net interest Proved Plus
     Probable Reserves discounted at 10% (Before
     Tax)(b)                                             $5,805       $5,292
    Undeveloped Lands(c)                                   $359         $428
    Working Capital Deficit(d)                             $(56)        $(60)
    Reclamation Fund                                        $33          $28
    Risk Management Contracts(e)                           $(15)          $1
    Long-term Debt                                        $(846)       $(902)
    Asset Retirement Obligation(f)                         $(27)        $(57)
    -------------------------------------------------------------------------
    Net Asset Value                                      $5,253       $4,732
    Units Outstanding (000's)(g)                        238,984      219,182
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    NAV/Unit                                             $21.98       $21.59
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    (a) Financial information is per ARC's 2009 Consolidated Financial
        Statements.
    (b) Excludes future income taxes estimated at $1  billion for the GLJ
        price forecast using a 10% discount rate and after deducting ARC's
        accumulated federal tax pools of $2.1 billion and $0.1 billion of
        provincial pools as at Dec 31, 2009 and the pools associated with the
        future development capital. The estimated future taxes were
        calculated assuming ARC would be subject to the equivalent of
        corporate income tax on its income beginning in 2011. Estimated
        future taxes do not take into account any corporate tax deductions
        such as interest or general and administrative expenses.
    (c) Internal estimate taking into account the December 31, 2009 Seaton-
        Jordan and Associates Ltd. evaluation.
    (d) Working capital deficit excludes risk management contracts and future
        income tax asset.
    (e) Risk management contracts represent the fair market value of such
        contracts as at December 31, 2009 based on the GLJ future pricing
        used to arrive at the value of Proved plus Probable reserves. This
        amount differs from the value of risk management contracts in the
        2009 Consolidated Financial Statements due to differing future
        pricing assumptions.
    (f) The Asset Retirement Obligation ("ARO") is calculated based on the
        same methodology that was used to calculate the ARO on ARC's year-end
        financial statements, with the exception that future expected ARO
        costs were discounted at 10 per cent. The total discounted ARO at 10
        per cent of $75 million was reduced by $48 million, relating to well
        abandonment costs, which were incorporated in the Value of the Proved
        Plus Probable reserves discounted at 10 per cent pursuant to the
        escalated price case as per NI 51-101.
    (g) Represents total trust units outstanding and trust units issuable for
        exchangeable shares as at December 31, 2009.
    

In the absence of adding reserves to the Trust, the NAV per unit will decline as the reserves are produced out. The evaluation includes future capital expenditure expectations required to bring undeveloped reserves on production. ARC works continuously to add value, improve profitability and increase reserves, which enhances the Trust's NAV.

At inception of the Trust on July 16, 1996, the NAV was determined to be $11.42 per unit based on a 10 per cent discount rate; since that time, including the January 2010 distribution, the Trust has distributed $25.08 per unit. After having distributed more cash than the initial NAV, the NAV as at December 31, 2009 was $21.98 per unit using GLJ prices. As a result of ARC's development activities, the NAV per unit using GLJ prices increased $0.39 per unit during 2009 after distributing $1.28 per unit to unitholders. Following is a summary of historical NAVs calculated at each of the Trust's year-ends utilizing the then current GLJ price forecasts and other assumptions and values utilized at such times.

    
    Historical NAV - Discounted at 10 Per Cent
    -------------------------------------------------------------------------
    $Millions, except
     per unit
     amounts          2009      2008      2007      2006      2005      2004
    -------------------------------------------------------------------------
    Value of NI
     51-101 Net
     interest
     Proved plus
     Probable
     reserves       $5,805    $5,292    $4,651    $4,056    $3,891    $2,389
    Undeveloped
     lands             359       428       229       109        59        48
    Reclamation fund    33        28        26        31        23        21
    Risk Management
     Contracts         (15)        1       (36)       (9)       (2)      (12)
    Long term-debt,
     net of working
     capital          (902)     (962)     (753)     (739)     (578)     (265)
    Asset retirement
     obligation        (27)      (57)      (26)      (62)      (35)      (23)
    -------------------------------------------------------------------------
    Net asset
     value          $5,253    $4,732    $4,091    $3,386    $3,358    $2,158
    Units
     outstanding
     (000's)       238,984   219,182   213,179   207,173   202,039   188,804
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    NAV per unit    $21.98    $21.59    $19.19    $16.34    $16.62    $11.43
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FINDING, DEVELOPMENT AND ACQUISITION ("FD&A") COSTS

Under NI 51-101, the methodology to be used to calculate FD&A costs includes incorporating changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. For continuity, ARC has presented herein FD&A costs calculated both excluding and including FDC.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

FINDING AND DEVELOPMENT COSTS ("F&D")

During 2009 ARC spent $360 million on exploration, development and corporate activities and participated in 218 gross (132 net) wells. On ARC's operated lands, we drilled 146 gross (120 net) wells with a 99.3 per cent success rate. Positive results from the capital program and continued strong production results at Dawson resulted in ARC adding 66 mmboe of proved plus probable reserves in 2009 prior to acquisitions. This represents a 285 per cent replacement of 2009 production of 23 mmboe prior to acquisitions and dispositions. This is the second year in a row that ARC has been able to replace greater than 200 per cent of production from drilling and development activities. Excluding changes in future development capital ARC's F&D costs were $5.45/boe for proved plus probable reserves and $8.67/boe for total proved reserves.

ARC's 2009 capital program was focused on resource play development with the Montney in northeastern British Columbia accounting for 53 per cent of the spending. At Dawson, record average production of 52 mmcf per day of gas and 230 bbl per day of liquids was achieved in 2009. A total of 22 horizontal wells were drilled and significant progress was made towards the completion of the 60 mmcf per day Dawson Phase One gas plant, which is currently expected to be onstream early in May of 2010. Only eight of the 22 wells drilled in 2009 were on production at year-end, with the remaining 14 horizontal wells ready to be brought on production with the completion of the gas plant. The 2010 capital budget calls for the drilling of three step out vertical wells along with the drilling of 30 Montney horizontal wells and the substantial completion of an additional Phase Two 60 mmcf per day gas plant at Dawson. ARC will also be testing the Lower Montney zone that has proven to be productive elsewhere.

In the West Montney assets, ARC participated in a partner operated four well Montney horizontal drilling program at Sunrise, drilled one vertical well at Sunset and one in Sundown in 2009. The four Sunrise horizontal wells have recently been brought on production and are expected to average 10 mmcf per day net to ARC's 50 per cent interest in the first quarter of 2010. ARC's 2010 drilling plans in the West Montney include the drilling of nine gross horizontal wells with a portion of funds specifically targeted towards the assessment of the Lower Montney zone. Spending will also be devoted to the initial procurement of equipment for a new Sunrise gas plant, currently planned for early 2012.

In Ante Creek, ARC drilled four horizontal Montney wells targeting a mixture of oil and gas production. With the success of these wells and a late year acquisition of approximately 1,000 boe per day, ARC was able to grow Ante Creek production to a record 7,000 boe per day at year-end 2009. ARC has allocated $70 million of capital to this field for 2010 and expects to drill 14 horizontal and two vertical wells. With the expansion of ARC's liquid handling facilities, the upgrade of a third party operated gas plant and further successful drilling, ARC expects production to grow to approximately 8,500 boe per day by early 2011.

At Redwater, ARC drilled three horizontal wells, only two of which were on production prior to year-end. Carbon dioxide injection into the enhanced oil recovery ("EOR") pilot area continued successfully through the end of 2009 with plans to continue optimization and evaluation of the pilot into 2010.

The Pembina area development included nine successful Cardium drills, including four horizontal wells coming on at stable one month production rates averaging over 150 boe per day per well. The 2010 capital budget will build on 2009 success with 17 more planned horizontal Cardium wells.

In the central Alberta area, ARC continued to develop the Natural Gas from Coal prospects with the drilling of 38 more wells. The other key strategic investment in 2009 was the drilling of two horizontal Cardium wells in the Garrington area, which should be on production in early 2010.

In ARC's shallow gas regions in southeastern Alberta and southwestern Saskatchewan there were 44 shallow gas wells drilled with 23 of them coming on production before year-end.

ARC experienced significant drilling success in southeast Saskatchewan and Manitoba with 15 new horizontal oil wells. Some of the key areas that will receive continued development focus into 2010 are Elmore, Lougheed, Midale, Weyburn and Goodlands.

MONTNEY UPDATE

The Dawson gas field was the center piece of the Star Oil and Gas purchase made by ARC in April of 2003, at that time production was approximately 17 mmcf per day and the proved plus probable reserves were just 110 Bcf. Since then ARC has added to its land base in the area, drilled 77 vertical wells and 41 horizontal wells and increased production to 55 mmcf per day. As a result of the development activities, advances in technology and knowledge gained through the longer production history, proved plus probable reserves have increased to 593 Bcf. See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information". The majority of the reserve additions have come in the past two years - 254 Bcf were added in 2008 and a further 205 Bcf were added in 2009, as successful development with horizontal wells lead to the implementation of a major development project at Dawson. Despite this success, ARC still believes that there are significant volumes of gas that can be added to reserves in the future assuming continued successful development of the field.

This discussion on the Montney resource at Dawson and West Montney is subject to a number of cautionary statements, assumptions and risks, some of which are included below and others under "Information Regarding Disclosure on Oil and Gas Resources and Operational Information".

DAWSON

ARC has 105 net sections of land at Dawson on which GLJ have assigned a best estimate of 3.4 Tcf of gas identified as Discovered Petroleum Initially In Place ("DPIIP") net to ARC in the Upper Montney as at December 31, 2009. ARC has booked 78 proved drilling locations and 35 probable locations on the 58 net sections of land to which reserves have been assigned. The assigned reserves of 0.6 Tcf and cumulative production of 0.1 Tcf represent 30 per cent of the 2.3 Tcf of DPIIP associated with the 58 sections and 20 per cent of the total DPIIP of 3.4 Tcf. Assigned reserves and cumulative production on the 58 sections range from three per cent to greater than 50 per cent of the DPIIP for such sections, dependent upon drilling density, production history and certain reservoir factors. There are currently no reserves assigned to the remaining 47 sections. It is management's belief that with drilling success on the undeveloped acreage consistent with historical success, further development and completion refinements and changing economic circumstances, that ARC will recognize significant additional reserves over time. See "Information Regarding Disclosure on Oil and Gas Resources and Operational Information" and "Forwarding Looking Statements".

WEST MONTNEY

In the West Montney area, the Upper Montney section thickens and a second porous and permeable zone referred to as the Montney B is present. To date, all of the production has come from the Montney A. While gas has been tested from the Montney B by ARC, current development plans are focused on the Montney A. There is a deeper zone, referred to as the Lower Montney that also has shown development potential in the region, but DPIIP has not been evaluated in the Lower Montney zone due to insufficient data on ARC lands.

    
    Sunrise/Sunset Area (Sunrise)
    ------------------------------
    

In the greater Sunrise / Sunset area ARC has 32 net sections of land on which GLJ have assigned a best estimate of 2.9 Tcf of gas classified as DPIIP net to ARC as at December 31, 2009, with 1.3 Tcf in the Montney A and 1.6 Tcf in the Montney B. GLJ has booked 24.5 net proved undeveloped locations and 24.5 net probable locations on the 16 net sections of land to which Montney A reserves have been assigned. These reserves represent 26 per cent of the 0.7 Tcf of DPIIP associated with the Montney A in the 16 booked sections and seven per cent of the total A and B DPIIP of 2.9 Tcf. It is management's belief that with drilling success on the undeveloped acreage consistent with historical success, further development and completion refinements and changing economic circumstances, that ARC will recognize significant additional reserves over time. ARC will be drilling and completing several wells into other Montney intervals in 2010 to gain a better understanding of the production potential of these zones.

    
    Saturn/Monias (Septimus) and Sundown
    -------------------------------------
    

ARC also owns 19 net sections of land in the Septimus area and 18 net sections of land in the Sundown area on which GLJ have assigned a best estimate of 2.1 Tcf of gas currently classified as DPIIP net to ARC in the Upper Montney. Approximately 60 per cent of the DPIIP are attributed to the Septimus area where considerable industry activity is taking place. A very small amount of reserves have been assigned at Septimus, with no reserves currently assigned to the Sundown property. Additional drilling will be required to explore and delineate these properties before it will be possible to define the timing of potential development projects.

All estimates of DPIIP of GLJ are as at December 31, 2009. A recovery project has not been defined for the volumes of DPIIP, which are not classified as reserves. At this time, there is no certainty that it will be technically feasible or commercially viable to produce any of the resources.

ARC's belief that it will recognize significant additional reserves in Dawson and the West Montney assets is based on a combination of historic recoveries of the more fully developed Montney acreage, abundant well log and production test data, and the application of drilling densities of ARC and third parties in the area and assume continuous development through multi-year exploration and development programs, changing economic circumstances and further development and completion refinements. The principal risks of not achieving the reserve additions relate to the potential for variations in the quality of the Montney formation where no current well data exists, access to capital, low gas prices that would impact the economics of development, and the future performance of wells. Unless otherwise indicated, all reserves are proved plus probable.

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.

ACQUISITIONS AND DISPOSITIONS

In 2009, ARC spent $158 million on acquisitions net of dispositions. The two primary transactions were the purchase of assets in the Ante Creek Area of Alberta for $178 million and the disposition of scattered Bakken assets in southeast Saskatchewan for $34 million. A net total of 14 mmboe of proved plus probable and 8 mmboe of total proved reserves were added from these activities. The net acquisition costs for the 2009 transactions were $10.97 per boe for proved plus probable reserves and $19.87 per boe for total proved reserves prior to including FDC. Including FDC the net acquisition costs were $16.25 per boe proved plus probable and $24.67 per proved boe.

FINDING DEVELOPMENT AND ACQUISITION COSTS ("FD&A")

Incorporating the net acquisitions during the year, ARC's proved plus probable FD&A costs excluding FDC were $6.44 per boe while proved FD&A costs excluding FDC were $10.48 per boe. These results represent the third year in a row that ARC has reduced the cost of adding reserves. The three year average costs have dropped to $9.57 per boe for proved plus probable reserves and $13.76 per boe for total proved excluding FDC.

FUTURE DEVELOPMENT CAPITAL ("FDC")

NI 51-101 requires that FD&A costs be calculated including changes in FDC. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. The increased level of undeveloped reserves now booked in the Montney acreage has yielded an increased capital cost expectation in the 2009 evaluation.

    
    FD&A Costs - Company Interest Reserves
                                                                 Proved plus
                                                         Proved     Probable
    -------------------------------------------------------------------------
    FD&A Costs Excluding Future Development Capital
    -----------------------------------------------
    Exploration and Development Capital
     Expenditures - $thousands                         $359,561     $359,561
    Exploration and Development Reserve Additions
     including Revisions - mboe                          41,460       65,984
    Finding and Development Cost - $/boe                  $8.67        $5.45
    Three Year Average F&D Cost - $/boe                  $12.58        $8.91
    Net Acquisition Capital - $thousands               $158,440     $158,440
    Net Acquisition Reserve Additions - mboe              7,975       14,438
    Net Acquisition Cost - $/boe                         $19.87       $10.97
    Three Year Average Net Acquisition Cost - $/boe      $26.77       $15.47
    Total Capital Expenditures including Net
     Acquisitions - $thousands                         $518,001     $518,001
    Reserve Additions including Net
     Acquisitions - mboe                                 49,435       80,422
    Finding Development and Acquisition Cost - $/boe     $10.48        $6.44
    Three Year Average FD&A Cost - $/boe                 $13.76        $9.57

    FD&A Costs  Including Future Development Capital
    ------------------------------------------------
    Exploration and Development Capital
     Expenditures - $thousands                         $359,561     $359,561
    Exploration and Development Change in FDC
     - $thousands                                      $150,181     $335,803
    Exploration and Development Capital including
     Change in FDC- $thousands                         $509,741     $695,364
    Exploration and Development Reserve Additions
     including Revisions - mboe                          41,460       65,984
    Finding and Development Cost - $/boe                 $12.29       $10.54
    Three Year Average F&D Cost - $/boe                  $17.10       $14.12

    Net Acquisition Capital - $thousands               $158,440     $158,440
    Net Acquisition FDC - $thousands                    $38,321      $76,236
    Net Acquisition Capital including FDC
     - $thousands                                      $196,761     $234,677
    Net Acquisition Reserve Additions - mboe              7,975       14,438
    Net Acquisition Cost - $/boe                         $24.67       $16.25
    Three Year Average Net Acquisition Cost - $/boe      $31.16       $20.34

    Total Capital Expenditures including Net
     Acquisitions - $thousands                         $518,001     $518,001
    Total Change in FDC - $thousands                   $188,501     $412,040
    Total Capital Including Change in FDC
     - $thousands                                      $706,502     $930,041
    Reserve Additions including Net Acquisitions
     - mboe                                              49,435       80,422
    Finding Development and Acquisition Cost
     including FDC - $/boe                               $14.29       $11.56
    Three Year Average FD&A Cost Including FDC
     - $/boe                                             $18.27       $14.75
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    In all cases, the F&D, or FD&A number is calculated by dividing the
    identified capital expenditures by the applicable reserves additions.


    Historic Company Interest Proved FD&A Costs
    -------------------------------------------------------------------------

                      2009      2008      2007      2006      2005      2004
    -------------------------------------------------------------------------
    Annual FD&A
     excluding FDC  $10.48    $14.22    $20.37    $24.51    $15.60    $16.53
    Three year
     average FD&A
     excluding FDC  $13.76    $18.28    $18.51    $17.77    $13.30    $11.05
    -------------------------------------------------------------------------

    Annual FD&A
     including FDC  $14.29    $21.87    $20.37    $27.53    $17.64    $20.46
    Three year
     average FD&A
     including FDC  $18.27    $22.85    $20.30    $20.31    $15.45    $13.02
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Historic Company Interest Proved Plus Probable FD&A Costs
    -------------------------------------------------------------------------

                      2009      2008      2007      2006      2005      2004
    -------------------------------------------------------------------------
    Annual FD&A
     excluding FDC   $6.44    $10.13    $19.00    $22.41    $13.64    $13.76
    Three Year
     Average FD&A
     excluding FDC   $9.57    $14.70    $16.57    $15.59    $11.00     $9.30
    -------------------------------------------------------------------------
    Annual FD&A
     including FDC  $11.56    $17.00    $20.03    $27.20    $16.09    $19.14
    Three Year
     Average FD&A
     including FDC  $14.75    $19.84    $19.19    $18.99    $13.50    $11.65
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    RESERVES RECONCILIATION
    Company Gross (Company Interest - Royalties Payable)

                 Light and     Heavy     Total               Total       Oil
                    Medium     Crude     Crude             Natural     Equiv-
                 Crude Oil       Oil       Oil     NGLs        Gas     alent
                     (mbbl)    (mbbl)    (mbbl)    (mbbl)    (mmcf)    (mboe)
    -------------------------------------------------------------------------
    PROVED
     PRODUCING
    Opening
     Balance        94,805     2,357    97,162     8,535   437,774   178,659
      Exploration
       Discoveries       0         0         0         0         0         0
      Drilling
       Extensions      500         0       500       128    32,101     5,978
      Improved
       Recovery      3,845         7     3,852       192     8,666     5,489
      Infill
       Drilling      1,432        12     1,444       301    52,041    10,418
      Technical
       Revisions     1,714       121     1,835       202     8,466     3,448
      Acquisitions     612         0       612       294    14,504     3,324
      Dispositions    -241         0      -241        -1       -90      -257
      Economic
       Factors         -70        36       -34       -19    -3,152      -579
      Production    -9,607      -335    -9,942    -1,333   -69,252   -22,817
    Closing
     Balance        92,988     2,199    95,187     8,299   481,057   183,663
    -------------------------------------------------------------------------
    TOTAL PROVED
    Opening
     Balance       104,912     2,366   107,278    11,057   736,916   241,154
      Exploration
       Discoveries      11         0        11         3     1,267       225
      Drilling
       Extensions      449         0       449       371   110,941    19,310
      Improved
       Recovery      1,862        16     1,878        14       794     2,024
      Infill
       Drilling      1,961        12     1,973       456    61,394    12,661
      Technical
       Revisions     2,112       117     2,229       202    31,016     7,600
      Acquisitions   1,366         0     1,366       606    37,517     8,225
      Dispositions    -241         0      -241        -1       -90      -257
      Economic
       Factors         -69        36       -33       -19    -3,187      -583
      Production    -9,607      -335    -9,942    -1,333   -69,252   -22,817
    Closing
     Balance       102,756     2,212   104,968    11,355   907,316   267,543
    -------------------------------------------------------------------------
    PROBABLE
    Opening
     Balance        30,137       640    30,777     3,329   263,119    77,959
      Exploration
       Discoveries       4         0         4         1       435        77
      Drilling
       Extensions      572         0       572       218   109,531    19,045
      Improved
       Recovery        360         2       362         5        86       382
      Infill
       Drilling        432         2       434       295    33,251     6,271
      Technical
       Revisions    -1,510       -31    -1,541         5     3,541      -945
      Acquisitions   1,841         0     1,841       440    26,194     6,646
      Dispositions    -183         0      -183         0       -24      -186
      Economic
       Factors         -46         8       -38       -11    -1,192      -248
      Production         0         0         0         0         0         0
    Closing
     Balance        31,607       622    32,229     4,281   434,941   109,000
    -------------------------------------------------------------------------
    PROVED PLUS
     PROBABLE
    Opening
     Balance       135,049     3,006   138,055    14,386 1,000,035   319,113
      Exploration
       Discoveries      15         0        15         4     1,702       302
      Drilling
       Extensions    1,021         0     1,021       588   220,472    38,355
      Improved
       Recovery      2,222        18     2,240        19       880     2,406
      Infill
       Drilling      2,393        14     2,407       750    94,645    18,932
      Technical
       Revisions       602        86       688       207    34,557     6,655
      Acquisitions   3,207         0     3,207     1,046    63,711    14,871
      Dispositions    -424         0      -424        -1      -114      -443
      Economic
       Factors        -115        44       -71       -30    -4,379      -831
      Production    -9,607      -335    -9,942    -1,333   -69,252   -22,817
    Closing
     Balance       134,363     2,834   137,197    15,637 1,342,257   376,543
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    FD&A Costs - Company Gross Reserves
                                                                 Proved plus
                                                         Proved     Probable
    -------------------------------------------------------------------------
    NI 51-101 Calculation Including Future Development
    Capital
    --------------------------------------------------
    Capital Expenditures excluding
     Net Acquisitions - $thousands                     $359,561     $359,561
    Net Change in FDC excluding
     Net Acquisitions - $thousands                     $150,181     $335,803
    Total Capital including FDC - $thousands           $509,741     $695,364
    Reserve additions excluding
     Net Acquisitions - mboe                             41,238       65,818
    Finding and Development Cost - $/boe                 $12.36       $10.57
    Three Year Average F&D Cost - $/boe                  $17.18       $14.11

    Capital Expenditures including
     net acquisitions - $thousands                     $518,001     $518,001
    Net Change in FDC including
     net acquisitions - $thousands                     $188,501     $412,040
    Total Capital - $thousands                         $706,502     $930,041
    Reserve additions including
     net acquisitions - mboe                             49,206       80,246
    Finding Development and Acquisition Cost - $/boe     $14.36       $11.59
    Three Year Average FD&A Cost - $/boe                 $18.41       $14.81
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Historic Company Gross Proved FD&A Costs
    -------------------------------------------------------------------------
                  2009     2008     2007     2006     2005     2004     2003
    -------------------------------------------------------------------------
    Annual FD&A
     including
     FDC        $14.36   $22.01   $20.71   $28.05   $17.81   $21.27   $12.95
    Three year
     average
     FD&A
     including
     FDC        $18.41   $23.12   $20.57   $20.63   $15.74   $13.54      n/a
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Historic Company Gross Proved Plus Probable FD&A Costs
    -------------------------------------------------------------------------
                  2009     2008     2007     2006     2005     2004     2003
    -------------------------------------------------------------------------
    Annual FD&A
     including
     FDC        $11.59   $17.08   $20.29   $27.79   $16.24   $19.74   $10.74
    Three Year
     Average
     FD&A
     including
     FDC        $14.81   $20.04   $19.43   $19.28   $13.73   $12.09      n/a
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

INFORMATION REGARDING DISCLOSURE ON OIL AND GAS RESERVES, RESOURCES AND OPERATIONAL INFORMATION

All amounts in this news release are stated in Canadian dollars unless otherwise specified. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (and all information derived therefrom) are based on "company interest reserves" using forecast prices and costs. "Company interest reserves" consist of "company gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian securities regulators ("NI 51-101") plus ARC's royalty interests in reserves. "Company interest reserves" are not a measure defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Accordingly, our company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2009, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com. In relation to the disclosure of estimates in the Montney Resource Discussion, such estimates for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

This news release contains references to estimates of gas classified as discovered petroleum initially in place in the area west of Dawson in British Columbia which are not, and should not be confused with, oil and gas reserves. "Discovered petroleum initially in place" ("DPIIP") is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources and the remainder as at evaluation date is by definition unrecoverable. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP.

ARC has not categorized the resources disclosed as DPIIP into all of the subcategories of discovered resources as projects have not been defined to develop them as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, ARC's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of ARC on gas prices, the results of exploration and development activities of ARC and others in the area and possible infrastructure capacity constraints.

ARC's belief that it will establish significant additional reserves over time in the discussion of the Montney Resource Development is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed below under the heading "Forward Looking Statements".

Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, resources, see above.

NOTICE TO U.S. READERS

The oil and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects of United States or other foreign disclosure standards. For example, the United States Securities and Exchange Commission (the "SEC") generally permits oil and gas issuers, in their filings with the SEC, to disclose only proved reserves (as defined in SEC rules). Canadian securities laws require oil and gas issuers, in their filings with Canadian securities regulators, to disclose not only proved reserves (which are defined differently from the SEC rules) but also probable reserves, each as defined in NI 51-101. Accordingly, proved reserves disclosed in this news release may not be comparable to U.S. standards, and in this news release, ARC has disclosed reserves designated as "probable reserves" and "proved plus probable reserves". Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. The SEC's guidelines strictly prohibit reserves in these categories from being included in filings with the SEC that are required to be prepared in accordance with U.S. disclosure requirements. In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross (or, as noted above, "company interest") volumes, which are volumes prior to deduction of royalty and similar payments. The practice in the United States is to report reserves and production using net volumes, after deduction of applicable royalties and similar payments. Moreover, ARC has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC generally requires that prices and costs be held constant at levels in effect at the date of the reserve report. As a consequence of the foregoing, ARC's reserve estimates and production volumes in this news release may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant additional reserves under the heading "Montney Resource Discussion", 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; the amount of future asset retirement obligations; future results from operations and operating metrics; and future development, exploration, acquisition and development activities (including drilling plans) and related production expectations.

The forward-looking information and statements contained in this news release reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities consistent with past results; the continued and timely development of infrastructure in areas of new production; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserve and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its plans expenditures. There are a number of assumptions associated with the development of the lands at Dawson and the lands west of Dawson 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 potential for variation in the quality of the Montney formation, changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; unanticipated results from ARC's exploration and development activities; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of ARC or by third party operators of ARC's properties, increased debt levels or debt service requirements; inaccurate estimation of ARC's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in ARC's public disclosure documents (including, without limitation, those risks identified in this news release and in ARC's Annual Information Form).

The forward-looking information and statements contained in this news release speak only as of the date of this news release, and none of ARC or its subsidiaries assumes any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with a current enterprise value of approximately $6 billion. The Trust currently has an interest in oil and gas production of approximately 65,000 barrels of oil equivalent per day from seven core areas in western Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN.

    
    ARC RESOURCES LTD.

    John P. Dielwart,
    Chief Executive Officer
    

%SEDAR: 00015954E %CIK: 0001029509

For further information: For further information: about ARC Energy Trust, please visit our website www.arcresources.com or contact: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E


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