ARC Energy Trust releases 2008 year-end reserves information



    CALGARY, Feb. 11 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC")
released today its 2008 year-end reserves information.

    HIGHLIGHTS

    
    -   At year-end 2008, reserves per unit have increased by over nine per
        cent for the proved plus probable category and by five per cent for
        the total proved category relative to year-end 2007.
    -   Added 42.2 mmboe of proved reserves and 59.2 mmboe of proved plus
        probable reserves, including revisions. Included in these numbers are
        the 29 mmboe increase to proved reserves and 43 mmboe increase in
        proved plus probable reserves assigned to the developed portion of
        the Dawson property announced on October 30, 2008.
    -   The combined total 2008 year-end sum of gas reserves and cumulative
        gas production for Dawson and the Montney West Exploratory lands
        represents less than a seven per cent recovery factor on the total
        8.1 Tcf of gas currently classified as Discovered Petroleum
        Initially In Place on these lands.
    -   Replaced 248 per cent of annual production at an all-in annual
        Finding, Development and Acquisition ("FD&A") cost of $10.13 per
        barrel of oil equivalent ("boe") before consideration of future
        development capital ("FDC") for the proved plus probable reserves
        category. This is a 47 per cent reduction from the $19.00 per boe
        FD&A cost before consideration of FDC realized in 2007. Including
        FDC, the 2008 FD&A cost was $17.00 per boe.
    -   The three year average FD&A cost decreased to $14.70 per boe for the
        proved plus probable category before FDC; including FDC, the three
        year average FD&A cost is $19.84 per boe.
    -   Proved reserves increased by eight per cent to 243 mmboe and proved
        plus probable reserves increased by 12 per cent to 322 mmboe,
        compared to year-end 2007 levels.
    -   Proved plus probable reserve life index ("RLI") increased to 13.8
        years and the proved RLI increased to 10.4 years based on 2009
        production guidance of 64,000 boe per day.
    -   29 per cent ($173 million) of ARC's 2008 total $600 million corporate
        expenditures were associated with the purchase of undeveloped lands
        through crown sales and third party transactions. None of these lands
        contributed to reserves or production in 2008.
    -   Net acquisition spending was $51 million, almost all of which was
        spent accumulating undeveloped land in the Dawson area of British
        Columbia.
    -   Based on a 2008 operating netback of $47.75 per boe, the one year
        recycle ratio is 4.7 times, using our $10.13 per boe proved plus
        probable FD&A cost prior to FDC, and 3.3 times using our $14.70 per
        boe three year average FD&A.
    

    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 gross basis (working interest
before deduction of royalties without including any royalty interests) will be
included in ARC's Annual Information Form ("AIF").
    Based on an independent reserves evaluation conducted by GLJ Petroleum
Consultants Ltd. ("GLJ") effective December 31, 2008 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 321.7 mmboe. Reserve additions from
exploration and development activities (including revisions) were 59.1 mmboe
while 0.1 mmboe were added through acquisitions (net of minor dispositions),
bringing the total additions to 59.2 mmboe. This represents 248 per cent of
the 23.8 mmboe produced during 2008. As a result, year-end 2008 reserves are
12.3 per cent higher than the 286.4 mmboe of proved plus probable reserves
recorded at year-end 2007.
    Proved developed producing reserves represent 74 per cent of total proved
reserves and 56 per cent of proved plus probable reserves; total proved
reserves account for 76 per cent of proved plus probable reserves.
Approximately 48 per cent of ARC's proved plus probable reserves are crude oil
and natural gas liquids and 52 per cent are natural gas on a 6:1 boe
conversion basis.

    RESERVES SUMMARY 2008 Using GLJ January 1, 2009 Forecast Prices and Costs

    
    -------------------------------------------------------------------------
    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     2008     2007
                 (mbbl)   (mbbl)   (mbbl)   (mbbl)    (bcf)   (mboe)   (mboe)
    -------------------------------------------------------------------------
    Proved
     Producing  94,922    2,552   97,474    8,692    447.7  180,777  185,364
    Proved
     Developed
     Non-
     Producing   2,188        9    2,197      521     30.5    7,794    6,582
    Proved
     Undeveloped 7,921        0    7,921    2,000    268.8   54,719   33,007
    Total
     Proved    105,031    2,561  107,592   11,214    746.9  243,292  224,953
    Proved
     plus
     Probable  135,199    3,243  138,442   14,578  1,012.2  321,723  286,371
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Gross Interest

                                                                Oil      Oil
             Light and    Heavy    Total             Total     Equi-    Equi-
                Medium    Crude    Crude           Natural   valent   valent
             Crude Oil      Oil      Oil     NGLs      Gas     2008     2007
                 (mbbl)   (mbbl)   (mbbl)   (mbbl)    (bcf)   (mboe)   (mboe)
    -------------------------------------------------------------------------
    Proved
     Producing  94,805    2,357   97,162    8,535    437.8  178,659  183,042
    Proved
     Developed
     Non-
     Producing   2,187        9    2,196      521     30.5    7,793    6,581
    Proved
     Undeveloped 7,919        0    7,919    2,000    268.7   54,700   32,970
    Total
     Proved    104,912    2,366  107,278   11,057    736.9  241,154  222,592
    Proved
     plus
     Probable  135,049    3,006  138,055   14,386  1,000.0  319,114  283,550
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net Interest

                                                                Oil      Oil
             Light and    Heavy    Total             Total     Equi-    Equi-
                Medium    Crude    Crude           Natural   valent   valent
             Crude Oil      Oil      Oil     NGLs      Gas     2008     2007
                 (mbbl)   (mbbl)   (mbbl)   (mbbl)    (bcf)   (mboe)   (mboe)
    -------------------------------------------------------------------------
    Proved
     Producing  80,767    2,370   83,137    6,028    381.7  152,789  159,738
    Proved
     Developed
     Non-
     Producing   1,589        9    1,598      352     21.9    5,604    5,156
    Proved
     Undeveloped 6,448        0    6,448    1,467    200.6   41,350   26,661
    Total
     Proved     88,804    2,379   91,183    7,847    604.3  199,742  191,553
    Proved
     plus
     Probable  113,725    2,978  116,703   10,287    815.6  262,928  243,727
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    RESERVES RECONCILIATION
    -------------------------------------------------------------------------
    Company Interest (Gross + Royalties Receivable)

                               Light and
                                  Medium       Heavy       Total
                               Crude Oil   Crude Oil   Crude Oil        NGLs
                                   (mbbl)      (mbbl)      (mbbl)      (mbbl)
    -------------------------------------------------------------------------
    PROVED PRODUCING
    Opening Balance               98,495       2,436     100,931       9,448
      Exploration Discoveries         55           0          55           1
      Drilling Extensions            851          15         866          40
      Improved Recovery            1,364           0       1,364         137
      Infill Drilling              2,273         210       2,483         232
      Technical Revisions          1,300         287       1,587         213
      Acquisitions                    46           0          46           0
      Dispositions                     0           0           0           0
      Economic Factors               508          70         578          34
      Production                  (9,970)       (466)    (10,436)     (1,413)
    Closing Balance               94,922       2,552      97,474       8,692
    -------------------------------------------------------------------------
    TOTAL PROVED
    Opening Balance              110,805       2,564     113,369      11,418
      Exploration Discoveries         55           0          55          17
      Drilling Extensions            860          15         875         202
      Improved Recovery            1,108           0       1,108          61
      Infill drilling              2,685         160       2,845         758
      Technical Revisions         (1,057)        223        (833)        145
      Acquisitions                    46           7          53           0
      Dispositions                     0           0           0           0
      Economic Factors               498          58         556          27
      Production                  (9,970)       (466)    (10,436)     (1,413)
    Closing Balance              105,031       2,561     107,592      11,214
    -------------------------------------------------------------------------
    PROBABLE
    Opening Balance               29,723         826      30,549       3,005
      Exploration Discoveries         26           0          26           8
      Drilling Extensions            477           5         482         146
      Improved Recovery              300           0         300          10
      Infill Drilling                709        (110)        599         177
      Technical Revisions         (1,000)        (71)     (1,071)         15
      Acquisitions                    15           2          17           0
      Dispositions                     0           0           0           0
      Economic Factors               (82)         30         (52)          4
      Production                       0           0           0           0
    Closing Balance               30,168         682      30,850       3,365
    -------------------------------------------------------------------------
    PROVED PLUS PROBABLE
    Opening Balance              140,528       3,390     143,918      14,423
      Exploration Discoveries         81           0          81          25
      Drilling Extensions          1,337          20       1,357         348
      Improved Recovery            1,408           0       1,408          70
      Infill Drilling              3,394          50       3,444         935
      Technical Revisions         (2,057)        152      (1,904)        160
      Acquisitions                    61           9          70           0
      Dispositions                     0           0           0           0
      Economic Factors               416          88         504          31
      Production                  (9,970)       (466)    (10,436)     (1,413)
    Closing Balance              135,199       3,243     138,442      14,578
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                            Conventional     Natural       Total         Oil
                                 Natural    Gas from     Natural  Equivalent
                                     Gas        Coal         Gas        2008
                                    (bcf)       (bcf)       (bcf)      (mboe)
    -------------------------------------------------------------------------
    PROVED PRODUCING
    Opening Balance                443.0         6.9       449.9     185,364
      Exploration Discoveries        0.4         0.0         0.4         123
      Drilling Extensions            4.6         1.7         6.3       1,957
      Improved Recovery             15.3         0.0        15.4       4,064
      Infill Drilling               29.5         0.5        30.0       7,712
      Technical Revisions           16.0        (0.3)       15.7       4,413
      Acquisitions                   0.0         0.0         0.0          46
      Dispositions                   0.0         0.0         0.0           0
      Economic Factors               1.9        (0.0)        1.9         935
      Production                   (70.6)       (1.3)      (71.9)    (23,836)
    Closing Balance                440.1         7.5       447.7     180,777
    -------------------------------------------------------------------------
    TOTAL PROVED
    Opening Balance                588.7        12.3       601.0     224,953
      Exploration Discoveries        4.3         0.0         4.3         794
      Drilling Extensions           48.2         2.4        50.6       9,504
      Improved Recovery              0.6         0.0         0.6       1,266
      Infill drilling              140.7         0.5       141.2      27,142
      Technical Revisions           20.1        (0.9)       19.2       2,507
      Acquisitions                   0.0         0.0         0.0          54
      Dispositions                   0.0         0.0         0.0           0
      Economic Factors               1.9         0.0         1.9         907
      Production                   (70.6)       (1.3)      (71.9)    (23,836)
    Closing Balance                734.0        13.0       746.9     243,291
    -------------------------------------------------------------------------
    PROBABLE
    Opening Balance                159.8         7.4       167.2      61,418
      Exploration Discoveries        1.9         0.0         1.9         355
      Drilling Extensions           51.5         0.9        52.3       9,351
      Improved Recovery              0.3        (0.0)        0.3         355
      Infill Drilling               37.3         0.1        37.4       7,014
      Technical Revisions            6.7        (1.3)        5.3        (168)
      Acquisitions                   0.0         0.1         0.1          37
      Dispositions                   0.0         0.0         0.0           0
      Economic Factors               0.7        (0.0)        0.7          68
      Production                     0.0         0.0         0.0           0
    Closing Balance                258.2         7.1       265.3      78,432
    -------------------------------------------------------------------------
    PROVED PLUS PROBABLE
    Opening Balance                748.5        19.7       768.2     286,371
      Exploration Discoveries        6.3         0.0         6.3       1,149
      Drilling Extensions           99.7         3.2       102.9      18,856
      Improved Recovery              0.9        (0.0)        0.9       1,621
      Infill Drilling              178.1         0.6       178.7      34,156
      Technical Revisions           26.7        (2.2)       24.5       2,339
      Acquisitions                   0.0         0.1         0.1          91
      Dispositions                   0.0         0.0         0.0           0
      Economic Factors               2.7        (0.0)        2.6         975
      Production                   (70.6)       (1.3)      (71.9)    (23,836)
    Closing Balance                992.1        20.1     1,012.2     321,723
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Additional reserves reconciliation information on a Gross Interest basis
is included at the end of this news release.

    RESERVE LIFE INDEX ("RLI")

    ARC's proved plus probable RLI was 13.8 years at year-end 2008 while the
proved RLI was 10.4 years based upon the GLJ reserves and ARC's 2009
production guidance of 64,000 boe per day. The following table summarizes
ARC's historical RLI.

    Reserve Life Index
                              2008  2007  2006  2005  2004  2003  2002  2001
    -------------------------------------------------------------------------
    Total Proved              10.4   9.8   9.8  10.3   9.7  10.1  10.1   9.8
    Proved Plus Probable
     (Established reserves
     for 2002 and prior
     years)                   13.8  12.5  12.4  12.9  12.2  12.4  11.8  11.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    NET PRESENT VALUE ("NPV") SUMMARY 2008

    ARC's crude oil, natural gas and natural gas liquids reserves were
evaluated using GLJ's product price forecasts effective January 1, 2009 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, 2009 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         7,166       4,760       3,605       2,928       2,480
    Proved
     Developed
     Non-Producing       277         181         133         104          85
    Proved
     Undeveloped       1,500         915         606         419         295
    Total Proved       8,943       5,856       4,344       3,450       2,861
    Probable           3,600       1,648         948         620         438
    Proved plus
     Probable         12,543       7,504       5,292       4,070       3,298
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    At a 10 per cent discount factor, the proved producing reserves make up
68 per cent of the proved plus probable value while total proved reserves
account for 82 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 2008 are presented in the MD&A section
of the year-end financial results news release dated February 11, 2009.

    
    NPV of Cash Flow After Income Taxes Using GLJ January 1, 2009 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         5,933       4,052       3,135       2,589       2,224
    Proved
     Developed
     Non-Producing       210         139         104          82          67
    Proved
     Undeveloped       1,106         663         426         283         188
    Total Proved       7,248       4,854       3,665       2,953       2,479
    Probable           2,611       1,196         687         448         316
    Proved plus
     Probable          9,859       6,050       4,352       3,402       2,795
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    GLJ January 1, 2009 Price Forecast
    -------------------------------------------------------------------------
                             West Texas    Edmonton      Natural
                           Intermediate       Light       Gas at     Foreign
                              Crude Oil   Crude Oil         AECO    Exchange
    Year                       ($US/bbl)  ($Cdn/bbl) ($Cdn/mmbtu)  ($US/$Cdn)
    -------------------------------------------------------------------------
                      2009        57.50       68.61         7.58       0.825
                      2010        68.00       78.94         7.94       0.850
                      2011        74.00       83.54         8.34       0.875
                      2012        85.00       90.92         8.70       0.925
                      2013        92.01       95.91         8.95       0.950
                      2014        93.85       97.84         9.14       0.950
                      2015        95.73       99.82         9.34       0.950
                      2016        97.64      101.83         9.54       0.950
                      2017        99.59      103.89         9.75       0.950
                      2018       101.59      105.99         9.95       0.950
    Escalate thereafter at     +2.0%/yr    +2.0%/yr     +2.0%/yr       0.950
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    ALBERTA GOVERNMENT NEW ROYALTY FRAMEWORK

    On April 10, 2008, the Alberta Government announced revisions to the New
Royalty Framework ("Framework" or "NRF"). The Framework was legislated in
November 2008 and took effect on January 1, 2009.

    The revisions to the Framework include the following:

    -   Increased royalty rates on conventional and non-conventional oil and
        natural gas production in Alberta whereby royalty rates may increase
        to maximum rates of 50 per cent;
    -   Sliding scale royalty calculations based on a broader range of
        commodity prices whereby conventional oil and natural gas royalty
        rates may increase up to maximum prices of approximately Cdn$120 per
        barrel and Cdn$16 per GJ, respectively;
    -   The elimination of royalty incentive and royalty holiday programs
        with the exception of specific programs relating to deep oil and
        natural gas drilling programs, innovative technology and enhanced
        recovery programs;
    

    Subsequent to the legislation of the NRF, the Alberta Government
introduced the Transitional Royalty Plan ("TRP") in response to the
anticipated decrease in Alberta development activity resulting from the
economic downturn and declining commodity prices. The TRP offers reduced
royalty rates for wells drilled on or after November 19, 2008 which meet
certain depth criteria. The TRP is in place for a maximum period of five years
up to December 31, 2013. The Trust does not anticipate a significant benefit
from the TRP in 2009 as the majority of the Trust's wells will convert to the
NRF on January 1, 2009.
    Approximately 65 per cent of the Trust's production is in Alberta;
consequently, the Framework may have a significant impact on the Trust's
Alberta and corporate royalty rates. The Trust has completed an assessment of
the Framework and will provide details in the year-end MD&A. The NRF royalty
program has been incorporated into the GLJ evaluation effective December 31,
2008.

    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.
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 represents the fair
market value of the reserves.

    
    NAV at December 31, 2008(a)
    -------------------------------------------------------------------------
                                                        2008 NAV    2007 NAV
                                                       GLJ Price   GLJ Price
                                                        Forecast    Forecast
    $Millions, except per unit amounts                  (2009-01)   (2008-01)
    -------------------------------------------------------------------------
    Value of NI 51-101 Net interest Proved Plus
     Probable Reserves discounted @ 10%
     (Before Tax)(b)                                      $5,292      $4,651
    Undeveloped Lands(c)                                    $428        $229
    Working Capital Deficit (including current portion
     of debt)(d)                                            $(60)       $(38)
    Reclamation Fund                                         $28         $26
    Risk Management Contracts(e)                              $1        $(36)
    Long-term Debt                                         $(902)      $(715)
    Asset Retirement Obligation(f)                          $(57)       $(26)
    -------------------------------------------------------------------------
    Net Asset Value                                       $4,732      $4,091
    Units Outstanding (000's)(g)                         219,182     213,179
    -------------------------------------------------------------------------
    NAV/Unit                                              $21.59      $19.19
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (a) Financial information is per ARC's 2008 consolidated financial
        statements.
    (b) Excludes estimated future taxes of $904 million for the GLJ Price
        Forecast, based on $2 billion in estimated Trust tax pools as at
        Dec 31, 2008. 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 September 30, 2008 Seaton-
        Jordan and Associates Ltd. external estimate and revised by internal
        estimates to account for fourth quarter 2008 changes to undeveloped
        land values.
    (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, 2008 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
        2008 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 percent of $100.5 million was reduced by $44 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, 2008.
    

    In the absence of adding reserves to the Trust, the NAV per unit will
decline as the reserves are produced out. The cash flow generated by the
production relates directly to the cash distributions paid to unitholders. 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.
    In order to determine the "going concern" value of the Trust, a more
detailed assessment would be required of the upside potential of specific
properties and the ability of the ARC team to continue to make value-adding
capital expenditures. 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 2009 distribution, the Trust has distributed
$23.82 per unit. Despite having distributed more cash than the initial NAV,
the NAV as at December 31, 2008 was $21.59 per unit using GLJ prices. As a
result of ARC's development activities, the NAV per unit using GLJ prices
increased $2.40 per unit during 2008 after distributing $2.67 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      2008     2007     2006     2005     2004     2003     2002
    -------------------------------------------------------------------------
    Value of
     NI 51-101
     Net
     interest
     Proved
     plus
     Probable
     reserves
     (a)        $5,292   $4,651   $4,056   $3,891   $2,389   $1,689   $1,302
    Undeveloped
     lands         428      229      109       59       48       50       20
    Reclamation
     fund           28       26       31       23       21       17       13
    Risk
     Management
     Contracts(b)    1      (36)      (9)      (2)     (12)
    Long
     term-debt,
     net of
     working
     capital      (962)    (753)    (739)    (578)    (265)    (262)    (348)
    Asset
     retirement
     obligation    (57)     (26)     (62)     (35)     (23)     (27)       -
    -------------------------------------------------------------------------
    Net asset
     value      $4,732   $4,091   $3,386   $3,358   $2,158   $1,467     $987
    Units
     out-
     standing
     (000's)   219,182  213,179  207,173  202,039  188,804  182,777  126,444
    -------------------------------------------------------------------------
    NAV per
     unit       $21.59   $19.19   $16.34   $16.62   $11.43    $8.03    $7.81
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (a) Proved plus Probable from 2003 and on is estimated in accordance with
        NI 51-101 while in prior years it represents Established reserves
        (which represents Proved plus Risked Probables).
    (b) Risk management contracts were included in the value of Proved plus
        Probable reserves prior to 2004.
    

    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 2008 ARC spent $548 million of capital on exploration, development
and corporate activities, which added 42.2 mmboe of proved and 59.2 mmboe of
proved plus probable reserves (including revisions). These activities replaced
177 and 248 per cent of ARC's 2008 production. In total, ARC drilled 232 gross
operated wells with a 99.9 per cent per cent drilling success rate.
    The development focus for 2008 was again directed towards resource plays,
primarily in the Montney in northeast British Columbia. In Dawson seven
horizontal and nine vertical Montney gas wells were successfully drilled,
helping to achieve record production of over 48 mmcf per day. The continued
strong results at Dawson were recognized through a substantial reserves
increase for this property, where 43 mmboe of proved plus probable reserves
were added. This number is not materially different from the estimate provided
in the October 30, 2008 news release "ARC Energy Trust announces significant
increase to Montney reserves in the Dawson Area of Northeast British
Columbia". In that news release, ARC also identified an estimate of 3.5 Tcf of
gas, classified as "Discovered Petroleum Initially In Place" for the main
Dawson area and a further 4.6 Tcf of gas on the Montney West Exploratory
Lands, also classified as "Discovered Petroleum Initially In Place. Montney
success was also achieved on the Montney West Exploratory Lands with the
successful drilling of seven vertical and three horizontal exploratory wells
across Sunrise, Saturn, Monias and Sundown. An initial proved plus probable
assignment of 45 Bcf of reserves (7.5 mmboe) is included in the year-end 2008
reserves evaluation for gas wells drilled and tested at Sunrise. The 45 Bcf of
reserves assigned at Sunrise were not included in the reserves recognized in
the October 30, 2008 news release and accounts for less than one per cent of
the 4.6 Tcf of gas classified as Discovered Petroleum Initially In Place that
was recognized by GLJ in the Montney West Exploratory Lands. Further reserves
additions are expected in the future as ARC firms up its development plan for
these lands. In Ante Creek, ARC drilled six vertical and two horizontal oil
wells, all of which were successful. The three well horizontal waterflood
expansion was also completed. Other areas in the north that saw successful
development included Pouce Coupe, Chinchaga and Swan Hills.
    In ARC's shallow gas regions in southeastern Alberta and southwestern
Saskatchewan there where 49 shallow gas wells and five deep oil wells drilled.
    In the central Alberta area, ARC continued to expand on the significant
inventory of Natural Gas from Coal development with the drilling of 48 more
wells. The central area also experienced deeper prospect success with oil and
gas focused development of five new wells in Garrington, Delburne and Smiley.
    The Pembina area development included 29 successful Cardium oil wells in
the North Pembina Cardium Unit, Berrymoor, Lindale, MIPA and the South Pembina
Cardium Unit. ARC also initiated a successful gas program in the Pembina area
with seven wells targeting shallower sand and coal targets.
    At Redwater, ARC drilled eight Leduc oil wells and three Viking
horizontal wells, as well as initiating CO2 injection into the EOR pilot area.
    ARC experienced significant drilling success in southeast Saskatchewan
with 36 new oil wells targeting both Mississippian and Bakken prospects.
    The highlights of activity within the non-operated portfolio included a
successful 34 well infill oil drilling program within the CO(2) flooded
Weyburn unit and a successful 23 well infill drilling program within the
adjacent CO2 flooded Midale Unit, both in southeastern Saskatchewan.
    Excluding changes in future development capital ARC's F&D costs were
$9.28/boe proved plus probable and $13.02/boe total proved.

    ACQUISITIONS AND DISPOSITIONS

    In 2008, ARC spent $51 million, (net of minor dispositions), to purchase
primarily undeveloped land in the Montney prospective areas of northeastern
British Columbia. The acquisitions were made for future development purposes
and yielded only marginal current production and associated reserves. A net
total of 0.1 mmboe of proved plus probable and 0.1 mmboe of total proved
reserves were added for 2008. ARC believes that some of the key lands acquired
in a late 2008 acquisition in the Dawson pool will be assigned reserves in
2009 as they are within the core of the pool and have offset wells planned for
drilling in the 2009 budget.

    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 $10.13 per boe while proved FD&A costs
excluding FDC were $14.22 per boe. In 2008 ARC again focused a large portion
of the budget towards building a long-term inventory of future opportunities
as over $122 million was spent at crown land sales. Including the $51 million
spent on undeveloped lands identified above, ARC's total spending on land in
2008 was a record $173 million.

    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 2008 evaluation.

    
    FD&A Costs - Company Interest Reserves
                                                                      Proved
                                                                        plus
                                                          Proved    Probable
    -------------------------------------------------------------------------

    FD&A Costs Excluding Future
     Development Capital
    ---------------------------
    Exploration and Development Capital
     Expenditures - $thousands                          $548,566    $548,566
    Exploration and Development Reserve
     Additions including Revisions - mboe                 42,120      59,097
    Finding and Development Cost - $/boe                  $13.02       $9.28
    Three Year Average F&D Cost - $/boe                   $16.72      $13.54

    Net Acquisition Capital - $thousands                 $50,988     $50,988
    Net Acquisition Reserve Additions - mboe                  54          91
    Net Acquisition Cost - $/boe                         $951.42     $559.15
    Three Year Average Net Acquisition
     Cost - $/boe                                         $40.09      $29.31

    Total Capital Expenditures including Net
     Acquisitions - $thousands                          $599,554    $599,554
    Reserve Additions including Net
     Acquisitions - mboe                                  42,174      59,188
    Finding Development and Acquisition
     Cost - $/boe                                         $14.22      $10.13
    Three Year Average FD&A Cost - $/boe                  $18.28      $14.70

    FD&A Costs Including Future
     Development Capital
    ---------------------------
    Exploration and Development Capital
     Expenditures - $thousands                          $548,566    $548,566
    Exploration and Development Change
     in FDC - $thousands                                $322,656    $406,840
    Exploration and Development Capital
     including Change in FDC - $thousands               $871,222    $955,406
    Exploration and Development Reserve
     Additions including Revisions - mboe                 42,120      59,097
    Finding and Development Cost - $/boe                  $20.68      $16.17
    Three Year Average F&D Cost - $/boe                   $21.45      $18.89

    Net Acquisition Capital - $thousands                 $50,988     $50,988
    Net Acquisition FDC - $thousands                           -           -
    Net Acquisition Capital including FDC
     - $thousands                                        $50,988     $50,988
    Net Acquisition Reserve Additions - mboe                  54          91
    Net Acquisition Cost - $/boe                         $951.42     $559.15
    Three Year Average Net Acquisition
     Cost - $/boe                                         $42.27      $31.74

    Total Capital Expenditures including
     Net Acquisitions - $thousands                      $599,554    $599,554
    Total Change in FDC - $thousands                    $322,656    $406,840
    Total Capital including Change in FDC
     - $thousands                                       $922,210  $1,006,394
    Reserve Additions including Net
     Acquisitions - mboe                                  42,174      59,188
    Finding Development and Acquisition
     Cost Including FDC - $/boe                           $21.87      $17.00
    Three Year Average FD&A Cost
     Including FDC - $/boe                                $22.85      $19.84
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    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
    -------------------------------------------------------------------------
                        2008    2007    2006    2005    2004    2003    2002
    -------------------------------------------------------------------------
    Annual FD&A
     excluding FDC    $14.22  $20.37  $24.51  $15.60  $16.53  $10.78   $8.87
    Three year
     average FD&A
     excluding FDC    $18.28  $18.51  $17.77  $13.30  $11.05  $10.69   $9.07
    -------------------------------------------------------------------------
    Annual FD&A
     including FDC    $21.87  $20.37  $27.53  $17.64  $20.46  $12.66  $10.03
    Three year
     average FD&A
     including FDC    $22.85  $20.30  $20.31  $15.45  $13.02  $11.96  $10.16
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Historic Company Interest Proved Plus Probable FD&A Costs
    -------------------------------------------------------------------------
                        2008    2007    2006    2005    2004    2003    2002
    -------------------------------------------------------------------------
    Annual FD&A
     excluding FDC    $10.13  $19.00  $22.41  $13.64  $13.76   $8.50   $9.27
    Three Year
     Average FD&A
     excluding FDC    $14.70  $16.57  $15.59  $11.00   $9.30   $9.07   $8.21
    -------------------------------------------------------------------------
    Annual FD&A
     including FDC    $17.00  $20.03  $27.20  $16.09  $19.14  $10.54  $10.79
    Three Year
     Average FD&A
     including FDC    $19.84  $19.19  $18.99  $13.50  $11.65  $10.52   $9.46
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    RESERVES RECONCILIATION
    Gross Interest (Working Interest - Royalties Payable)

                              Light and
                                 Medium       Heavy        Total
                              Crude Oil   Crude Oil    Crude Oil       NGL's
                                  (mbbl)      (mbbl)      (mbbl)      (mbbl)
    -------------------------------------------------------------------------
    PROVED PRODUCING
    Opening Balance               98,381       2,224     100,605       9,280
      Exploration Discoveries         55           0          55           1
      Drilling Extensions            851          15         866          37
      Improved Recovery            1,364           0       1,364         136
      Infill Drilling              2,272         210       2,483         232
      Technical Revisions          1,260         200       1,460         214
      Acquisitions                    46           0          46           0
      Dispositions                     0           0           0           0
      Economic Factors               506          71         577          32
      Production                  (9,930)       (363)    (10,293)     (1,397)
    Closing Balance               94,805       2,358      97,163       8,535
    -------------------------------------------------------------------------
    TOTAL PROVED
    Opening Balance              110,686       2,353     113,039      11,249
      Exploration Discoveries         55           0          55          17
      Drilling Extensions            860          15         875         199
      Improved Recovery            1,108           0       1,108          60
      Infill Drilling              2,685         160       2,845         758
      Technical Revisions         (1,095)        137        (958)        141
      Acquisitions                    46           7          53           0
      Dispositions                     0           0           0           0
      Economic Factors               496          58         554          30
      Production                  (9,930)       (363)    (10,293)     (1,397)
    Closing Balance              104,912       2,366     107,278      11,057
    -------------------------------------------------------------------------
    PROBABLE
    Opening Balance               29,698         781      30,479       2,969
      Exploration Discoveries         26           0          26           8
      Drilling Extensions            477           5         482         145
      Improved Recovery              300           0         300          10
      Infill Drilling                709        (110)        599         177
      Technical Revisions         (1,004)        (68)     (1,073)         17
      Acquisitions                    15           2          17           0
      Dispositions                     0           0           0           0
      Economic Factors               (83)         30         (53)          4
      Production                       0           0           0           0
    Closing Balance               30,138         640      30,777       3,330
    -------------------------------------------------------------------------
    PROVED PLUS PROBABLE
    Opening Balance              140,384       3,134     143,518      14,218
      Exploration Discoveries         81           0          81          25
      Drilling Extensions          1,337          20       1,357         344
      Improved Recovery            1,408           0       1,408          70
      Infill Drilling              3,394          50       3,444         935
      Technical Revisions         (2,099)         68      (2,031)        158
      Acquisitions                    61           9          70           0
      Dispositions                     0           0           0           0
      Economic Factors               413          88         501          34
      Production                  (9,930)       (363)    (10,293)     (1,397)
     Closing Balance             135,049       3,006     138,055      14,386
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                                         Oil
                            Conventional    Natural        Total  Equivalent
                                 Natural   Gas from      Natural        2008
                               Gas (bcf)  Coal (bcf)   Gas (bcf)      (mboe)
    -------------------------------------------------------------------------
    PROVED PRODUCING
    Opening Balance                432.6         6.4       438.9     183,042
      Exploration Discoveries        0.4         0.0         0.4       122.6
      Drilling Extensions            4.5         1.7         6.2       1,935
      Improved Recovery             15.3         0.0        15.4       4,062
      Infill Drilling               29.5         0.4        29.9       7,701
      Technical Revisions           15.3        (0.2)       15.1       4,185
      Acquisitions                   0.0         0.0         0.0          46
      Dispositions                   0.0         0.0         0.0           0
      Economic Factors               1.8        (0.0)        1.8         911
      Production                   (68.7)       (1.2)      (69.9)    (23,345)
    Closing Balance                430.7         7.0       437.8     178,660
    -------------------------------------------------------------------------
    TOTAL PROVED
    Opening Balance                578.3        11.5       589.8     222,592
       Exploration Discoveries       4.3         0.0         4.3         794
       Drilling Extensions          48.1         2.4        50.5       9,486
       Improved Recovery             0.6         0.0         0.6       1,264
       Infill Drilling             140.7         0.5       141.2      27,132
       Technical Revisions          19.3        (0.8)       18.6       2,278
       Acquisitions                  0.0         0.0         0.0          54
       Dispositions                  0.0         0.0         0.0           0
       Economic Factors              1.9         0.0         1.9         898
       Production                  (68.7)       (1.2)      (69.9)    (23,345)
    Closing Balance                724.6        12.4       736.9     241,154
    -------------------------------------------------------------------------
    PROBABLE
    Opening Balance                157.8         7.2       165.1      60,958
      Exploration Discoveries        1.9         0.0         1.9         355
      Drilling Extensions           51.5         0.9        52.3       9,348
      Improved Recovery              0.3        (0.0)        0.3         355
      Infill Drilling               37.3         0.1        37.4       7,012
      Technical Revisions            6.5        (1.3)        5.3        (178)
      Acquisitions                   0.0         0.1         0.1          37
      Dispositions                   0.0         0.0         0.0           0
      Economic Factors               0.7        (0.0)        0.7          73
      Production                     0.0         0.0         0.0           0
    Closing Balance                256.2         6.9       263.1      77,960
    -------------------------------------------------------------------------
    PROVED PLUS PROBABLE
    Opening Balance                736.2        18.7       754.9     283,550
      Exploration Discoveries        6.3         0.0         6.3       1,149
      Drilling Extensions           99.6         3.2       102.8      18,834
      Improved Recovery              0.9        (0.0)        0.8       1,619
      Infill Drilling              178.1         0.5       178.6      34,144
      Technical Revisions           25.9        (2.0)       23.8       2,100
      Acquisitions                   0.0         0.1         0.1          91
      Dispositions                   0.0         0.0         0.0           0
      Economic Factors               2.6        (0.0)        2.6         971
      Production                   (68.7)       (1.2)      (69.9)    (23,345)
    Closing Balance                980.7        19.3     1,000.0     319,114
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    FD&A Costs - Gross Interest Reserves
                                                                      Proved
                                                                        plus
                                                          Proved    Probable
    -------------------------------------------------------------------------

    NI 51-101 Calculation Including
     Future Development Capital
    -------------------------------
    Capital Expenditures excluding Net
     Acquisitions - $thousands                          $548,566    $548,566
    Net Change in FDC excluding Net
     Acquisitions - $thousands                          $316,656    $394,840
    Total Capital including FDC - $thousands            $865,222    $943,406
    Reserve additions excluding Net
     Acquisitions - mboe                                  41,853      58,818
    Finding and Development Cost - $/boe                  $20.67      $16.04
    Three Year Average F&D Cost - $/boe                   $21.65      $18.96

    Capital Expenditures including net
     acquisitions - $thousands                          $599,554    $599,554
    Net Change in FDC including net
     acquisitions - $thousands                          $322,656    $406,840
    Total Capital - $thousands                          $922,210  $1,006,394
    Reserve additions including net
     acquisitions - mboe                                  41,907      58,909
    Finding Development and Acquisition
     Cost - $/boe                                         $22.01      $17.08
    Three Year Average FD&A Cost - $/boe                  $23.12      $20.04
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Historic Gross Interest Proved FD&A Costs
    -------------------------------------------------------------------------
                        2008    2007    2006    2005    2004    2003    2002
    -------------------------------------------------------------------------
    Annual FD&A
     including FDC    $22.01  $20.71  $28.05  $17.81  $21.27  $12.95  $10.97
    Three year
     average FD&A
     including FDC    $23.12  $20.57  $20.63  $15.74  $13.54     n/a     n/a
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Historic Gross Interest Proved Plus Probable FD&A Costs
    -------------------------------------------------------------------------
                        2008    2007    2006    2005    2004    2003    2002
    -------------------------------------------------------------------------
    Annual FD&A
     including FDC    $17.08  $20.29  $27.79  $16.24  $19.74  $10.74  $12.06
    Three Year
     Average FD&A
     including FDC    $20.04  $19.43  $19.28  $13.73  $12.09     n/a     n/a
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    INFORMATION REGARDING DISCLOSURE IN THIS NEWS RELEASE AND OIL AND GAS
    RESERVES, RE

SOURCES 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 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 "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, 2008, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at www.sedar.com. This news release contains references to estimates of 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" 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. Discovered petroleum initially in place is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of this discovered petroleum initially in place except to the extent identified as proved or probable reserves. There are a number of assumptions associated with the development of the lands west of Dawson relating to performance from new and existing wells, future drilling programs, the lack 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. NOTICE TO U.S. READERS The oil and natural gas reserves contained in this press release has 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. Additionally, the SEC prohibits disclosure of oil and gas resources, whereas Canadian issuers may disclose resource volumes. Resources are different than, and should not be construed as, reserves. For a description of the definition of, and the risks and uncertainties surrounding the disclosure of, resources, see above. FORWARD-LOOKING INFORMATION AND STATEMENTS This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends", "strategy" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this news release contains forward-looking information and statements pertaining to the following: the 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 liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; future development, exploration, acquisition and development activities (including drilling plans) and related capital expenditures, future tax treatment of income trusts and future taxes payable by ARC; and ARC's tax pools. 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; 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; 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; changes in the demand for or supply of ARC's products; unanticipated operating results or production declines; 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 $4.1 billion. The Trust currently has an interest in oil and gas production of approximately 65,000 barrels of oil equivalent per day from six core areas in western Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN. ARC RE

SOURCES LTD. John P. Dielwart, Chief Executive Officer %SEDAR: 00001245E %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 5E9


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890