ARC Energy Trust releases 2007 year-end reserves information

Feb 14, 2008

CALGARY, Feb. 14 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC")
released today its 2007 year-end reserves information.

<<
HIGHLIGHTS

- Replaced 101 per cent of annual production at an all-in annual
Finding, Development and Acquisition ("FD&A") cost of $19.00 per
barrel of oil equivalent ("boe") before consideration of future
development capital ("FDC") for the proved plus probable reserves
category. This is a 15 per cent reduction from the $22.42 per boe
FD&A cost realized in 2006. Including FDC, the FD&A cost was $20.03
per boe.
- The three year average FD&A cost is $16.57 per boe for the proved
plus probable category before FDC; including FDC, the three year
average FD&A cost is $19.19 per boe.
- 2007 year-end reserves are within one per cent of the year-end
2006 levels with proved reserves of 225 mmboe, and proved plus
probable reserves of 286 mmboe.
- Proved plus probable reserve life index ("RLI") increased to
12.5 years and the proved RLI remained constant at 9.8 years based on
2008 production guidance of 63,000 boe per day.
- $87 million (20 per cent) of the $440 million expenditures in 2007
were devoted to the purchase of highly prospective crown mineral
rights and the acquisition of third party undeveloped acreage
primarily in the Dawson area of northern British Columbia. These
lands have not been given any value in the 2007 Reserves evaluation.
Excluding these extraordinary expenditures reduces the proved plus
probable FD&A to $15.24/boe ($16.28 including FDC).
- Net acquisition activity represented $42.5 million, or 10 per cent of
2007 corporate spending and resulted in 1.7 mmboe of proved plus
probable reserves acquired at an average cost of $24.29 per boe
(excluding FDC).
- Based on our operating netback of $34.82 per boe, the one year
recycle ratio is 1.8 times, using our $19.00 per boe proved plus
probable FD&A cost prior to FDC.
>>

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 report contains several cautionary statements that are
specifically required by NI 51-101. In addition to the detailed information
disclosed in this news release more detailed information on a net basis
(working interest share after deduction of royalty obligations, plus royalty
interests) and 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, 2007 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 286.4 mmboe(1). Reserve additions from
exploration and development activities (including revisions) were 21.4 mmboe
while 1.7 mmboe were added through acquisitions (net of minor dispositions),
bringing the total additions to 23.1 mmboe. This represents 101 per cent of
the 22.9 mmboe produced during 2007. As a result, year-end 2007 reserves are
slightly higher than the 286.1 mmboe of proved plus probable reserves recorded
at year-end 2006.
Proved developed producing reserves represent 85 per cent of total proved
reserves and 65 per cent of proved plus probable reserves; total proved
reserves account for 79 per cent of proved plus probable reserves.
Approximately 55 per cent of ARC's proved plus probable reserves are crude oil
and natural gas liquids and 45 per cent are natural gas on a 6:1 boe
conversion basis.

<<
---------------------------
(1) BOEs may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a BOE conversion ratio for natural gas of
6 Mcf: 1 bbl has been used, which is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.

RESERVES SUMMARY 2007 Using GLJ January 1, 2008 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 2007 2006
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 98,495 2,436 100,931 9,448 449.9 185,364 187,501
Proved
Developed
Non-
Producing 1,175 117 1,292 486 28.8 6,582 4,707
Proved
Undevel-
oped 11,134 11 11,145 1,484 122.3 33,007 34,055
Total
Proved 110,805 2,564 113,369 11,418 601.0 224,953 226,264
Proved
plus
Probable 140,528 3,390 143,918 14,423 768.2 286,371 286,125
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-------------------------------------------------------------------------

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Gross

Oil Oil
Light and Heavy Total Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2007 2006
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 98,381 2,224 100,605 9,280 438.9 183,042 184,959
Proved
Developed
Non-
Producing 1,174 117 1,291 486 28.8 6,581 4,706
Proved
Undevel-
oped 11,131 11 11,142 1,484 122.1 32,970 34,017
Total
Proved 110,686 2,353 113,039 11,249 589.8 222,592 223,681
Proved
plus
Probable 140,384 3,134 143,518 14,218 754.9 283,550 283,015
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Net

Light and Heavy Total Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2007 2006
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 88,697 2,258 90,955 6,670 372.7 159,738 161,498
Proved
Developed
Non-
Producing 1,042 108 1,150 342 22.0 5,156 3,790
Proved
Undevel-
oped 9,566 11 9,577 1,054 96.2 26,661 27,975
Total
Proved 99,305 2,377 101,682 8,065 490.8 191,553 193,263
Proved
plus
Probable 125,553 3,146 128,699 10,241 628.7 243,727 243,994
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------------------ RESERVES RECONCILIATION
------------------ Company Interest ------------------ PROVED PRODUCING
Opening Balance Exploration Discoveries Drilling Extensions Improved Recovery Infill Drilling Technical Revisions Acquisitions Dispositions Economic Factors Production Closing Balance ------------------ TOTAL PROVED
Opening Balance Exploration Discoveries Drilling Extensions Improved Recovery Infill drilling Technical Revisions Acquisitions Dispositions Economic Factors Production Closing Balance ------------------ PROBABLE
Opening Balance Exploration Discoveries Drilling Extensions Improved Recovery Infill Drilling Technical Revisions Acquisitions Dispositions Economic Factors Production Closing Balance ------------------ PROVED PLUS PROBABLE
Opening Balance Exploration Discoveries Drilling Extensions Improved Recovery Infill Drilling Technical Revisions Acquisitions Dispositions Economic Factors Production Closing Balance ------------------ ------------------ -------------------------------------------------------
-------------------------------------------------------
(Gross + Royalties Receivable)
Light and
Medium Heavy Total
Crude Oil Crude Oil Crude Oil NGLs
(mbbl) (mbbl) (mbbl) (mbbl)
-------------------------------------------------------
99,543 2,759 102,302 9,627
0 0 0 0
651 15 666 82
1,769 30 1,798 184
2,307 0 2,307 307
2,343 20 2,363 621
912 0 912 90
(162) 0 (162) (24)
1,164 49 1,213 32
(10,032) (437) (10,469) (1,470)
98,495 2,436 100,931 9,448
-------------------------------------------------------
112,780 2,773 115,553 11,768
0 0 0 5
370 129 499 112
1,891 16 1,907 56
2,298 0 2,298 322
1,510 34 1,544 527
1,020 0 1,020 97
(162) 0 (162) (24)
1,128 49 1,177 25
(10,032) (437) (10,469) (1,470)
110,805 2,564 113,368 11,418
-------------------------------------------------------
30,966 904 31,870 3,002
0 0 0 1
388 92 480 33
408 (16) 392 13
510 0 510 43
(2,379) (157) (2,536) (86)
248 0 248 15
(23) 0 (23) (5)
(394) 2 (392) (12)
0 0 0 0
29,723 826 30,549 3,005
-------------------------------------------------------
143,746 3,677 147,423 14,770
0 0 0 7
758 221 979 145
2,299 0 2,299 69
2,809 0 2,809 365
(869) (122) (991) 441
1,267 0 1,267 113
(185) 0 (185) (30)
734 51 785 13
(10,032) (437) (10,469) (1,470)
140,528 3,390 143,917 14,423
-------------------------------------------------------
-------------------------------------------------------

Oil
Conventional Natural Total Equivalent
Natural Gas from Natural 2007
Gas (bcf) Coal (bcf) Gas (bcf) (mboe)
-------------------------------------------------------------------------
PROVED PRODUCING
Opening Balance 449.4 4.0 453.4 187,501
Exploration Discoveries 0.0 0.0 0.0 0
Drilling Extensions 6.2 2.8 8.9 2,235
Improved Recovery 3.3 0.9 4.3 2,691
Infill Drilling 29.2 0.0 29.2 7,480
Technical Revisions 18.5 (0.2) 18.4 6,042
Acquisitions 2.4 0.3 2.7 1,446
Dispositions (0.4) 0.0 (0.4) (245)
Economic Factors (0.8) 0.0 (0.8) 1,107
Production (64.9) (0.9) (65.7) (22,894)
Closing Balance 443.0 6.9 449.9 185,364
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TOTAL PROVED
Opening Balance 585.7 8.0 593.7 226,264
Exploration Discoveries 0.9 0.0 0.9 156
Drilling Extensions 10.6 4.8 15.4 3,172
Improved Recovery 1.4 0.4 1.8 2,257
Infill drilling 22.8 0.0 22.8 6,422
Technical Revisions 31.0 (0.5) 30.5 7,155
Acquisitions 2.5 0.5 3.0 1,625
Dispositions (0.4) 0.0 (0.4) (245)
Economic Factors (1.0) 0.0 (1.0) 1,040
Production (64.9) (0.9) (65.7) (22,894)
Closing Balance 588.7 12.3 601.0 224,953
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PROBABLE
Opening Balance 144.5 5.4 149.9 59,861
Exploration Discoveries 0.2 0.0 0.2 31
Drilling Extensions 4.4 1.3 5.8 1,472
Improved Recovery 0.3 0.1 0.4 465
Infill Drilling 7.9 0.0 7.9 1,874
Technical Revisions 2.6 0.1 2.7 (2,166)
Acquisitions 0.4 0.5 0.9 408
Dispositions (0.1) 0.0 (0.1) (41)
Economic Factors (0.5) 0.0 (0.5) (487)
Production 0.0 0.0 0.0 -
Closing Balance 159.8 7.4 167.2 61,418
-------------------------------------------------------------------------
PROVED PLUS PROBABLE
Opening Balance 730.2 13.4 743.6 286,125
Exploration Discoveries 1.1 0.0 1.1 187
Drilling Extensions 15.0 6.1 21.1 4,645
Improved Recovery 1.7 0.4 2.1 2,723
Infill Drilling 30.7 0.0 30.7 8,296
Technical Revisions 33.6 (0.4) 33.2 4,989
Acquisitions 2.9 1.0 3.9 2,032
Dispositions (0.4) 0.0 (0.4) (285)
Economic Factors (1.5) 0.0 (1.5) 554
Production (64.9) (0.9) (65.7) (22,894)
Closing Balance 748.5 19.7 768.2 286,371
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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 12.5 years at year-end 2007 while the
proved RLI was 9.8 years based upon the GLJ reserves and ARC's 2008 production
guidance of 63,000 boe per day. The following table summarizes ARC's
historical RLI.

Reserve Life Index
2007 2006 2005 2004 2003 2002 2001 2000
-------------------------------------------------------------------------

Total Proved 9.8 9.8 10.3 9.7 10.1 10.1 9.8 10.4
Proved Plus Probable
(Established reserves
for 2002 and prior
years) 12.5 12.4 12.9 12.2 12.4 11.8 11.5 12.1
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NET PRESENT VALUE ("NPV") SUMMARY 2007

ARC's crude oil, natural gas and natural gas liquids reserves were
evaluated using GLJ's product price forecasts effective January 1, 2008 prior
to provision for interest, debt service charges and general and administrative
expenses. It should not be assumed that the discounted future net production
revenues estimated by GLJ represent the fair market value of the reserves.

NPV of Cash Flow Before Income Taxes Using GLJ January 1, 2008 Forecast
Prices and Costs

Dis- Dis- Dis- Dis-
Undis- counted counted counted counted
NI 51-101 Net interest counted at 5% at 10% at 15% at 20%
$MM $MM $MM $MM $MM
-------------------------------------------------------------------------

Proved Producing 6,401 4,433 3,471 2,894 2,506
Proved Developed
Non-Producing 216 148 113 91 76
Proved Undeveloped 946 578 384 268 192
Total Proved 7,563 5,159 3,968 3,253 2,774
Probable 2,428 1,146 684 464 340
Proved plus Probable 9,991 6,305 4,651 3,717 3,113
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-------------------------------------------------------------------------

At a 10 per cent discount factor, the proved producing reserves make up 75
per cent of the proved plus probable value while total proved reserves account
for 85 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 2007 are presented in the MD&A section
of the year-end financial results news release dated February 14, 2008.

NPV of Cash Flow After Income Taxes Using GLJ January 1, 2008 Forecast
Prices and Costs

Proved Producing 5,479 3,920 3,140 2,662 2,335
Proved Developed
Non-Producing 173 122 95 78 66
Proved Undeveloped 724 445 296 205 145
Total Proved 6,376 4,487 3,530 2,945 2,545
Probable 1,781 855 517 355 263
Proved plus Probable 8,157 5,342 4,048 3,300 2,809
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GLJ January 1, 2008 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)
-------------------------------------------------------------------------
2008 92.00 91.10 6.75 1.00
2009 88.00 87.10 7.55 1.00
2010 84.00 83.10 7.60 1.00
2011 82.00 81.10 7.60 1.00
2012 82.00 81.10 7.60 1.00
2013 82.00 81.10 7.60 1.00
2014 82.00 81.10 7.80 1.00
2015 82.00 81.10 7.97 1.00
2016 82.02 81.12 8.14 1.00
2017 83.66 82.76 8.31 1.00
Escalate thereafter at +2.0%/yr +2.0%/yr +2.0%/yr 1.00
-------------------------------------------------------------------------
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The reserves have also been evaluated using constant prices and costs
effective December 31, 2007. Following are the values determined using this
constant price analysis.

NPV of Cash Flow Before Income Taxes Using December 31, 2007 Constant
Prices and Costs

Proved Producing 6,866 4,742 3,691 3,059 2,634
Proved Developed
Non-Producing 197 139 106 86 72
Proved Undeveloped 888 554 373 262 189
Total Proved 7,950 5,435 4,171 3,408 2,894
Probable 2,189 1,110 689 477 354
Proved plus Probable 10,139 6,545 4,860 3,885 3,248
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-------------------------------------------------------------------------

At a 10 per cent discount factor, the proved producing reserves make up 76
per cent of the proved plus probable value while total proved reserves account
for 86 per cent of the proved plus probable value. The same comments apply to
the after tax NPV of cash flow using constant prices and costs as for forecast
pricing.

NPV of Cash Flow After Income Taxes Using December 31, 2007 Constant
Prices and Costs

Dis- Dis- Dis- Dis-
NI 51-101 Net interest Undis- counted counted counted counted
$Millions counted at 5% at 10% at 15% at 20%
-------------------------------------------------------------------------
Proved Producing 5,823 4,151 3,305 2,787 2,432
Proved Developed
Non-Producing 158 114 90 74 63
Proved Undeveloped 682 428 288 200 142
Total Proved 6,663 4,692 3,683 3,061 2,637
Probable 1,613 831 523 367 275
Proved plus Probable 8,276 5,523 4,205 3,428 2,911
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Constant Prices at December 31, 2007
-------------------------------------------------------------------------
West Texas Edmonton Natural
Intermediate Light Gas at Foreign
Crude Oil Crude Oil AECO Exchange
Year ($US/bbl) ($Cdn/bbl)($Cdn/mmbtu) ($US/$Cdn)
-------------------------------------------------------------------------
2008 and thereafter 95.95 93.39 6.63 1.012
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ALBERTA NEW ROYALTY FRAMEWORK

In October 2007, the Alberta government announced its intent to increase
crown royalties beginning on January 1, 2009. As of December 31, 2007, the
province had not introduced the enabling legislation nor had they provided
enough clarity on a number of issues for GLJ to provide a precise calculation
of net reserves and NPV under the new royalty regime. However, GLJ did provide
analyses which estimate that under the proposed royalty regime as currently
understood, the NPV at a 10 per cent discount rate using GLJ January 2008
price forecast would be between two and three per cent less than stated in the
previous tables. The new royalty provisions have a relatively modest impact on
ARC's NPV as 37 per cent of ARC's 2008 production is expected to come from
outside the Province of Alberta and due to the relatively low production rates
for many of ARC's wells that are not impacted as significantly as high rate
wells.

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 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 discounted future net production revenues estimated by GLJ
represent the fair market value of the reserves.

NAV at December 31, 2007(a)
-------------------------------------------------------------------------
2007 NAV 2006 NAV
GLJ Price GLJ Price
$Millions, except per unit amounts Forecast Forecast
-------------------------------------------------------------------------
NI 51-101 Net interest Proved Plus
Probable Reserves discounted @ 10% (Before
Tax)(b) $4,651 $4,056
Undeveloped Lands(c) $229 $109
Working Capital Deficit (including current
portion of debt)(d) $(38) $(52)
Reclamation Fund $26 $31
Risk Management Contracts(e) $(30) $(9)
Long-term Debt $(715) $(687)
Asset Retirement Obligation(f) $(26) $(62)
-------------------------------------------------------------------------
Net Asset Value $4,097 $3,386
Units Outstanding (000's)(g) 213,179 207,173
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NAV/Unit $19.22 $16.34
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(a) Financial information is per ARC's 2007 consolidated financial
statements.
(b) Excludes estimated future taxes of $603 million for the GLJ Price
Forecast, based on $1.8 billion in estimated Trust tax pools as at
December 31, 2007. 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.
(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, 2007 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
2007 consolidated financial statements due to differing future
pricing assumptions.
(f) The Asset Retirement Obligation ("ARO") is calculated based on the
same methodology that was used to calculate the ARO on ARC's year-end
financial statements, with the exception that future expected ARO
costs were discounted at 10 per cent. The total discounted ARO at
10 per cent of $70 million was reduced by $44 million and $35 million
respectively, relating to well abandonment costs that were
incorporated in 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, 2007.

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 2008 distribution, the Trust has distributed
$21.03 per unit. Despite having distributed more cash than the initial NAV,
the NAV as at December 31, 2007 was $19.22 per unit using GLJ prices. NAV per
unit using GLJ prices increased $2.88 per unit during 2007 after distributing
$2.40 per unit to unitholders as a result of increases in commodity prices as
well as ARC's development activities. 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 2007 2006 2005 2004 2003 2002 2001
------------------------------------------------------------------------
NI 51-101 Net
interest Proved
plus Probable
reserves(a) $4,651 $4,056 $3,891 $2,389 $1,689 $1,302 $1,216
Undeveloped lands 229 109 59 48 50 20 22
Reclamation fund 26 31 23 21 17 13 10
Risk Management
Contracts(b) $(30) (9) (2) (12)
Long term-debt,
net of working
capital $(753) (739) (578) (265) (262) (348) (289)
Asset retirement
obligation $(26) (62) (35) (23) (27) - -
-------------------------------------------------------------------------
Net asset value $4,097 $3,386 $3,358 $2,158 $1,467 $987 $959
Units outstanding
(000's) 213,179 207,173 202,039 188,804 182,777 126,444 111,692
-------------------------------------------------------------------------
NAV per unit $19.22 $16.34 $16.62 $11.43 $8.03 $7.81 $8.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 represent 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 2007 ARC spent $397 million of capital on exploration and
development activities, which added 20.2 mmboe of proved and 21.4 mmboe of
proved plus probable reserves (including revisions). These activities replaced
88 and 93 per cent of ARC's 2007 production. In total, ARC drilled 278 gross
operated wells with a 99 per cent per cent drilling success rate.
The largest percentage of capital was again devoted towards development
opportunities in northern Alberta and British Columbia. In Dawson the
successful drilling of six horizontal and six vertical Montney gas wells
helped grow production by over 80 per cent. With the commissioning of new
third party processing facilities in the fourth quarter of 2007, a record exit
rate of 44 mmcf per day was achieved. Significant funds and efforts were also
focused in the Dawson area with successful exploration and step-out drilling
and a substantial increase in highly prospective undeveloped land. It should
be noted that no reserves have been booked for the ARC Sunrise 9-13 Montney
gas discovery drilled in the fourth quarter of 2007. ARC would expect to book
reserves at year-end 2008 for this well and the surrounding acreage if
commercial gas rates are confirmed during the year. In Ante Creek, ARC drilled
11 successful oil wells, and acquired undeveloped acreage. A 16 km gas
pipeline was installed to the previously acquired processing facility and
water-flood injectivity was improved in the oil area. These factors combined
to help boost production to record levels of approximately 5,100 boe per day.
Other areas in the north that saw successful development included Valhalla,
Pouce Coupe, Chinchaga, Swan Hills and Prestville. Exploration efforts in the
Junior Tees area of Northern British Columbia were unsuccessful in realizing
economic productive capability.
The most active drilling areas in 2007 were in ARC's shallow gas regions
in southeastern Alberta and southwestern Saskatchewan where 144 shallow gas
wells and six deep oil wells were drilled.
In the central Alberta area, ARC continued to expand on the significant
inventory of Natural Gas from Coal development with the drilling of 17 more
wells. The central area also experienced deeper prospect success with oil and
gas focused development of 11 new wells in Garrington, Med River, Delburne and
Smiley.
The Pembina area development included 28 successful Cardium oil wells in
the North Pembina Cardium Unit, Berrymoor, Lindale, MIPA and Buck Creek.
At Redwater, ARC drilled eight successful oil wells on small highs
identified by a 3D seismic program that had been acquired specifically to
pinpoint the location of a CO(2) enhanced oil recovery pilot project. ARC also
enjoyed continued success with the ongoing Leduc well reactivation program and
a four well Viking drilling program that included ARC's first ever Viking
Horizontal well.
ARC experienced continued drilling success in southeast Saskatchewan with
20 new oil wells, primarily horizontal light oil producers.
The highlights of activity within the non-operated portfolio included a
successful 60 well infill oil drilling program within the CO(2) flooded
Weyburn unit and a successful 10 well infill drilling program within the
adjacent CO(2) flooded Midale Unit, both in southeastern Saskatchewan.
Excluding changes in future development capital ARC's F&D costs were
$18.57 per boe proved plus probable and $19.66 per boe total proved. Excluding
the extraordinary $78 million spent at crown land sales ARC's F&D numbers are
reduced to $14.94 per boe proved plus probable and $15.82 per boe total
proved.

ACQUISITIONS AND DISPOSITIONS

ARC was not very active on the acquisition front during 2007 spending
only $42.5 million, (net of minor dispositions), to purchase 1.7 mmboe of
proved plus probable reserves. The majority of this was spent on the purchase
of light oil producing properties in southeast Saskatchewan near existing
properties. The remaining spending was focused on the purchase of additional
developed and undeveloped acreage within the Dawson and Ante Creek assets.
As part of its active asset management program, ARC disposed of a few
minor properties that no longer met the long-term needs of the Trust. The
properties were sold to consolidate ARC's asset base, reduce future
abandonment obligations, decrease corporate operating costs and exit areas
with limited future development opportunities.

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 $19.00 per boe while proved FD&A costs
were $20.37 per boe. In 2007 ARC again focused a large portion of the budget
towards building a long-term inventory of future opportunities. The
$78 million spent on crown land in 2007 is 50 per cent higher than the
combined land spending over the previous 11 years that the Trust has been in
existence. The following table outlines the resulting impact on FD&A due to
these expenditures

<<
FD&A Costs - Impacts due to growth oriented spending
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Crown Undeveloped
Base Land Land
FD&A Purchases Acquisitions Total
-------------------------------------------------------------------------
Expenditures ($Millions) $ 352.7 $ 77.5 $ 9.4 $ 439.6
-------------------------------------------------------------------------
Total Proved ($/boe) $ 16.34 $ 3.59 $ 0.44 $ 20.37
-------------------------------------------------------------------------
Proved Plus Probable
($/boe) $ 15.24 $ 3.35 $ 0.41 $ 19.00
-------------------------------------------------------------------------

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 current level of
activity has resulted in relatively flat capital costs throughout the industry
that are now reflected in the estimates of future development costs effective
December 31, 2007.

FD&A Costs - Company Interest Reserves(2)
Proved
plus
Proved Probable
-------------------------------------------------------------------------

FD&A Costs Excluding Future Development Capital
-----------------------------------------------
Exploration and Development Capital Expenditures
- $thousands $397,163 $397,163
Exploration and Development Reserve Additions
Including Revisions - mboe 20,202 21,393
Finding and Development Cost - $/boe $19.66 $18.57
Three Year Average F&D Cost - $/boe $20.14 $19.35

Net Acquisition Capital - $thousands $42,454 $42,454
Net Acquisition Reserve Additions - mboe 1,381 1,748
Net Acquisition Cost - $/boe $30.74 $24.29
Three Year Average Net Acquisition Cost - $/boe $16.70 $13.90

Total Capital Expenditures including Net Acquisitions
- $thousands $439,616 $439,616
Reserve Additions including Net Acquisitions - mboe 21,583 23,141
Finding Development and Acquisition Cost - $/boe $20.37 $19.00
Three Year Average FD&A Cost - $/boe $18.51 $16.57

FD&A Costs Including Future Development Capital
------------------------------------------------
Exploration and Development Capital Expenditures
- $thousands $397,163 $397,163
Exploration and Development Change in FDC
- $thousands ($3,000) $21,000
Exploration and Development Capital Including Change
in FDC - $thousands $394,163 $418,163
Exploration and Development Reserve Additions
Including Revisions - mboe 20,202 21,393
Finding and Development Cost - $/boe $19.51 $19.55
Three Year Average F&D Cost - $/boe $21.91 $22.92

Net Acquisition Capital - $thousands $42,454 $42,454
Net Acquisition FDC - $thousands $3,000 $3,000
Net Acquisition Capital Including FDC - $thousands $45,454 $45,454
Net Acquisition Reserve Additions - mboe 1,381 1,748
Net Acquisition Cost - $/boe $32.91 $26.01
Three Year Average Net Acquisition Cost - $/boe $18.52 $15.61

Total Capital Expenditures including Net Acquisitions
- $thousands $439,616 $439,616
Total Change in FDC - $thousands - $24,000
Total Capital Including Change in FDC - $thousands $439,616 $463,616
Reserve Additions including Net Acquisitions - mboe 21,583 23,141
Finding Development and Acquisition Cost Including
FDC - $/boe $20.37 $20.03
Three Year Average FD&A Cost Including FDC - $/boe $20.30 $19.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note: 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.

--------------------------------
(2) In all cases, the F&D, or FD&A number is calculated by dividing the
identified capital expenditures by the applicable reserves additions.
BOEs may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a BOE conversion ratio for natural gas of
6 Mcf: 1 bbl has been used which is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.

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

2007 2006 2005 2004 2003 2002 2001
-------------------------------------------------------------------------

Annual FD&A
excluding FDC $20.37 $24.51 $15.60 $16.53 $10.78 $8.87 $11.35
Three year
average FD&A
excluding FDC $18.51 $17.77 $13.30 $11.05 $10.69 $9.07 $8.06
-------------------------------------------------------------------------

Annual FD&A
including FDC $20.37 $27.53 $17.64 $20.46 $12.66 $10.03 $11.93
Three year
average FD&A
including FDC $20.30 $20.31 $15.45 $13.02 $11.96 $10.16 $9.09
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

2007 2006 2005 2004 2003 2002 2001
-------------------------------------------------------------------------

Annual FD&A
excluding FDC $19.00 $22.41 $13.64 $13.76 $8.50 $9.27 $9.75
Three Year
Average FD&A
excluding FDC $16.57 $15.59 $11.00 $9.30 $9.07 $8.21 $6.94
-------------------------------------------------------------------------
Annual FD&A
including FDC $20.03 $27.20 $16.09 $19.14 $10.54 $10.79 $10.41
Three Year
Average FD&A
including FDC $19.19 $18.99 $13.50 $11.65 $10.52 $9.46 $8.04
-------------------------------------------------------------------------
-------------------------------------------------------------------------

RESERVES RECONCILIATION
Gross Interest

Light and
Medium Heavy Total
Crude Oil Crude Oil Crude Oil NGLs
(mbbl) (mbbl) (mbbl) (mbbl)
-------------------------------------------------------------------------
PROVED PRODUCING
Opening Balance 99,418 2,503 101,921 9,627
Exploration Discoveries 0 0 0 0
Drilling Extensions 651 15 666 82
Improved Recovery 1,770 30 1,800 184
Infill Drilling 2,308 0 2,308 307
Technical Revisions 2,299 (33) 2,266 433
Acquisitions 898 0 898 89
Dispositions (162) 0 (162) (24)
Economic Factors 1,162 49 1,211 32
Production (9,964) (339) (10,303) (1,450)
Closing Balance 98,381 2,225 100,605 9,280
-------------------------------------------------------------------------
TOTAL PROVED
Opening Balance 112,647 2,517 115,164 11,768
Exploration Discoveries 0 0 0 5
Drilling Extensions 370 129 499 112
Improved Recovery 1,896 16 1,912 56
Infill Drilling 2,298 0 2,298 322
Technical Revisions 1,473 (19) 1,454 339
Acquisitions 1,002 0 1,002 96
Dispositions (162) 0 (162) (24)
Economic Factors 1,126 49 1,175 25
Production (9,964) (339) (10,303) (1,450)
Closing Balance 110,686 2,353 113,038 11,249
-------------------------------------------------------------------------
PROBABLE
Opening Balance 30,936 844 31,780 3,002
Exploration Discoveries 0 0 0 1
Drilling Extensions 388 92 480 33
Improved Recovery 413 (16) 397 13
Infill Drilling 510 0 510 43
Technical Revisions (2,373) (141) (2,514) (120)
Acquisitions 243 0 243 14
Dispositions (23) 0 (23) (5)
Economic Factors (396) 2 (394) (12)
Production 0 0 0 0
Closing Balance 29,698 782 30,479 2,969
-------------------------------------------------------------------------
PROVED PLUS PROBABLE
Opening Balance 143,583 3,361 146,944 14,770
Exploration Discoveries 0 0 0 7
Drilling Extensions 758 221 979 145
Improved Recovery 2,309 0 2,309 69
Infill Drilling 2,808 0 2,808 365
Technical Revisions (900) (160) (1,059) 219
Acquisitions 1,245 0 1,245 111
Dispositions (185) 0 (185) (30)
Economic Factors 730 51 781 13
Production (9,964) (339) (10,303) (1,450)
Closing Balance 140,384 3,134 143,518 14,218
-------------------------------------------------------------------------

Conventional Natural Total Oil
Natural Gas from Natural Equivalent
Gas Coal Gas 2007
(bcf) (bcf) (bcf) (mboe)
-------------------------------------------------------------------------
PROVED PRODUCING
Opening Balance 437.9 3.7 441.6 185,146
Exploration Discoveries 0.0 0.0 0.0 0.0
Drilling Extensions 6.2 2.7 8.8 2,220
Improved Recovery 3.3 0.9 4.2 2,682
Infill Drilling 29.2 0.0 29.2 7,480
Technical Revisions 17.3 (0.3) 17.0 5,534
Acquisitions 2.4 0.3 2.6 1,426
Dispositions (0.4) 0.0 (0.4) (245)
Economic Factors (0.8) 0.0 (0.8) 1,110
Production (62.6) (0.8) (63.4) (22,312)
Closing Balance 432.6 6.4 438.9 183,042
-------------------------------------------------------------------------
TOTAL PROVED
Opening Balance 574.2 7.4 581.6 223,869
Exploration Discoveries 0.9 0.0 0.9 156
Drilling Extensions 10.6 4.6 15.2 3,142
Improved Recovery 1.4 0.3 1.7 2,254
Infill Drilling 22.8 0.0 22.8 6,421
Technical Revisions 29.8 (0.6) 29.2 6,665
Acquisitions 2.5 0.5 3.0 1,598
Dispositions (0.4) 0.0 (0.4) (245)
Economic Factors (0.9) 0.0 (0.9) 1,043
Production (62.6) (0.8) (63.4) (22,312)
Closing Balance 578.3 11.5 589.8 222,592
-------------------------------------------------------------------------
PROBABLE
Opening Balance 142.3 5.3 147.6 59,378
Exploration Discoveries 0.2 0.0 0.2 31
Drilling Extensions 4.4 1.3 5.7 1,465
Improved Recovery 0.3 0.0 0.4 468
Infill Drilling 7.9 0.0 7.9 1,874
Technical Revisions 2.9 0.1 3.0 (2,128)
Acquisitions 0.4 0.4 0.9 401
Dispositions (0.1) 0.0 (0.1) (41)
Economic Factors (0.5) 0.0 (0.5) (490)
Production 0.0 0.0 0.0 0.0
Closing Balance 157.8 7.2 165.1 60,958
-------------------------------------------------------------------------
PROVED PLUS PROBABLE
Opening Balance 716.5 12.7 729.2 283,248
Exploration Discoveries 1.1 0.0 1.1 187
Drilling Extensions 15.0 5.9 20.9 4,607
Improved Recovery 1.7 0.4 2.1 2,722
Infill Drilling 30.7 0.0 30.7 8,294
Technical Revisions 32.7 (0.5) 32.3 4,537
Acquisitions 2.9 1.0 3.9 1,999
Dispositions (0.4) 0.0 (0.4) (285)
Economic Factors (1.5) 0.0 (1.4) 553
Production (62.6) (0.8) (63.4) (22,312)
Closing Balance 736.2 18.7 754.9 283,550
-------------------------------------------------------------------------

FD&A Costs - Gross Reserves
Proved
plus
Proved Probable
-------------------------------------------------------------------------
NI 51-101 Calculation Including Future
Development Capital
--------------------------------------
Capital Expenditures excluding Net Acquisitions
- $thousands $397,163 $397,163
Net Change in FDC excluding Net Acquisitions
- $thousands ($3,000) $21,000
Total Capital including FDC - $thousands $394,163 $418,163
Reserve additions excluding Net Acquisitions - mboe 19,869 21,133
Finding and Development Cost - $/boe $19.84 $19.79
Three Year Average F&D Cost - $/boe $23.49 $24.55

Capital Expenditures including net acquisitions
- $thousands $439,616 $439,616
Net Change in FDC including net acquisitions
- $thousands $ - $24,000
Total Capital - $thousands $439,616 $463,616
Reserve additions including net acquisitions - mboe 21,223 22,847
Finding Development and Acquisition Cost - $/boe $20.71 $20.29
Three Year Average FD&A Cost - $/boe $20.57 $19.43
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Historic Gross Proved FD&A Costs
-------------------------------------------------------------------------

2007 2006 2005 2004 2003 2002
-------------------------------------------------------------------------
Annual FD&A including
FDC $20.71 $28.05 $17.81 $21.27 $12.95 $10.97
Three year average FD&A
including FDC $20.57 $20.63 $15.74 $13.54 n/a n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Historic Gross Proved Plus Probable FD&A Costs
-------------------------------------------------------------------------

2007 2006 2005 2004 2003 2002
-------------------------------------------------------------------------
Annual FD&A including
FDC $20.29 $27.79 $16.24 $19.74 $10.74 $12.06
Three Year Average FD&A
including FDC $19.43 $19.28 $13.73 $12.09 n/a n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $5.7 billion. The
Trust expects full year 2008 oil and gas production to average approximately
63,000 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 and its
exchangeable shares trade under the symbol ARX.

ADVISORY - In the interests of providing ARC unitholders and potential
investors with information regarding ARC, including management's assessment of
ARC's future plans and operations, certain information contained in this
document are forward-looking statements within the meaning of the "safe
harbour" provisions of the United States Private Securities Litigation Reform
Act of 1995 and the Ontario Securities Commission. Forward-looking statements
in this document include, but are not limited to, ARC's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; the production and growth potential of its various assets,
estimated total production and production growth for 2008 and beyond; the
sources, deployment and allocation of expected capital in 2008; and the
success of future development drilling prospects. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause ARC's actual performance and financial results in future periods to
differ materially from any estimates or projections of future performance or
results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,
President and Chief Executive Officer

For further information: about ARC Energy Trust, please visit our website www.arcenergytrust.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