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

<<
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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 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
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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
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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 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
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RESERVES RECONCILIATION
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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
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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
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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
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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
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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
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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
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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
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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
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>>

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
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>>

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 $MM
-------------------------------------------------------------------------
Proved
Producing 5,933 4,052 3,135 2,589 2,224
Proved
Developed
Non-Producing 210 139 104 82 67
Proved
Undeveloped 1,106 663 426 283 188
Total Proved 7,248 4,854 3,665 2,953 2,479
Probable 2,611 1,196 687 448 316
Proved plus
Probable 9,859 6,050 4,352 3,402 2,795
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GLJ January 1, 2009 Price Forecast
-------------------------------------------------------------------------
West Texas Edmonton Natural
Intermediate Light Gas at Foreign
Crude Oil Crude Oil AECO Exchange
Year ($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
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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)
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Net Asset Value $4,732 $4,091
Units Outstanding (000's)(g) 219,182 213,179
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NAV/Unit $21.59 $19.19
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(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
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(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, 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 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 RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer
>>

%SEDAR: 00001245E %CIK: 0001029509