ARC Energy Trust releases 2006 year-end reserves information

CALGARY, Feb. 22 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC")
released today its 2006 year-end reserves information.

<<
HIGHLIGHTS

- Replaced 96 per cent of annual production at an all-in annual Finding,
Development and Acquisition ("FD&A") cost of $22.41 per barrel of oil
equivalent ("boe") before consideration of future development capital
("FDC") for the proved plus probable reserves category; including FDC,
the FD&A cost was $27.20 per boe.
- The three year average FD&A cost is $15.59 per boe for the proved plus
probable category before FDC; including FDC, the three year average
FD&A cost is $18.99 per boe
- Reserves per trust unit decreased slightly from 2005 to 2006 from 1.42
to 1.38 boe per unit on a proved plus probable basis and from 1.13 to
1.09 boe per unit on a proved basis.
- 2006 year end Reserves are within one per cent of the year end 2005
levels with proved reserves of 226 mmboe, and proved plus probable
reserves of 286 mmboe.
- Proved plus probable reserve life index ("RLI") is 12.4 years, and the
proved RLI is 9.8 years based on 2007 production guidance of 63,000
boe per day.
- $75 million (15 per cent) of the $496 million capital expenditures in
2006 were devoted to growth oriented exploration and development
projects. This included significant undeveloped land acquisitions in
Dawson and Redwater. Significant funds were also devoted to early
investment in enhanced oil recovery projects in Midale and Instow,
Saskatchewan. While these expenditures did not contribute to any
reserve additions in 2006, they are expected to add reserves and value
in the future.
- Net acquisition activity represented $132 million, or 26 per cent of
2006 corporate spending and resulted in 5.8 mmboe of proved plus
probable reserves acquired at an average cost of $22.55 per boe
(excluding 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 press 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, 2006 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 mmboe(1). Reserve additions from
exploration and development activities (including revisions) were 16 mmboe
while 6 mmboe were added through acquisitions (net of minor dispositions),
bringing the total additions to 22 mmboe. This represents 96 per cent of the
23 mmboe produced during 2006. As a result, year-end 2006 reserves are one
percent lower than the 287 mmboe of proved plus probable reserves recorded at
year-end 2005.
Proved developed producing reserves represent 66 per cent of proved plus
probable reserves, while total proved reserves account for 79 per cent of
proved plus probable reserves. Approximately 57 per cent of ARC's proven plus
probable reserves are crude oil and natural gas liquids and 43 per cent are
natural gas on a 6:1 boe conversion basis.

<<
------------------
(1) BOE's 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 2006 Using GLJ January 1, 2007 Forecast Prices and Costs
-------------------------------------------------------------------------
Company (Gross + Royalties Receivable)

Oil Oil
Light and Heavy Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2006 2005
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 99,543 2,759 102,302 9,627 453.4 187,501 189,179
Proved
Developed
Non-
Producing 1,370 14 1,384 313 18.1 4,707 4,818
Proved
Undevel-
oped 11,867 0 11,867 1,827 122.2 34,055 35,036
Total
Proved 112,780 2,773 115,553 11,768 593.7 226,264 229,033
Proved
plus
Probable 143,746 3,677 147,423 14,770 743.6 286,125 286,997
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Gross

Oil Oil
Light and Heavy Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2006 2005
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 99,418 2,503 101,921 9,440 441.6 184,959 186,435
Proved
Developed
Non-
Producing 1,369 14 1,383 313 18.1 4,706 4,816
Proved
Undevel-
oped 11,861 0 11,861 1,827 122.0 34,017 35,023
Total
Proved 112,647 2,517 115,164 11,580 581.6 223,681 226,273
Proved
plus
Probable 143,583 3,361 146,944 14,537 729.2 283,015 283,795
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net
Oil Oil
Light and Heavy Total Equi- Equi-
Medium Crude Crude Natural valent valent
Crude Oil Oil Oil NGLs Gas 2006 2005
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe) (mboe)
-------------------------------------------------------------------------
Proved
Producing 89,460 2,540 92,000 6,811 376.1 161,498 161,509
Proved
Developed
Non-Produ-
cing 1,226 13 1,239 218 14.0 3,790 3,944
Proved
Undevel-
oped 10,393 0 10,393 1,282 97.8 27,975 29,183
Total
Proved 101,079 2,554 103,633 8,310 487.9 193,263 194,637
Proved
plus
Probable 128,402 3,369 131,771 10,480 610.5 243,994 243,482
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-------------------------------------------------------------------------

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

Oil
Light and Heavy Total Equi-
Medium Crude Crude Natural valent
Crude Oil Oil Oil NGLs Gas 2006
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe)
-------------------------------------------------------------------------
PROVED
PRODUCING
Opening
Balance 98,934 2,971 101,905 10,393 461.3 189,179
Exploration
Discoveries 9 0 9 16 0.6 120
Drilling
Extensions 177 30 207 122 8.3 1,711
Improved
Recovery 3,545 9 3,554 84 3.4 4,201
Infill
Drilling 2,130 7 2,136 338 33.6 8,068
Technical
Revisions 727 118 845 101 5.8 1,907
Acquisitions 2,847 0 2,847 38 1.8 3,192
Dispositions (252) 0 (252) (3) (0.3) (296)
Economic
Factors 1,527 124 1,651 59 4.3 2,435
Production (10,101) (499) (10,600) (1,522) (65.4) (23,015)
Closing
Balance 99,543 2,759 102,302 9,627 453.4 187,501
-------------------------------------------------------------------------
TOTAL PROVED
Opening
Balance 114,562 3,011 117,573 12,172 595.7 229,033
Exploration
Discoveries 9 0 9 16 0.6 120
Drilling
Extensions 206 30 236 130 10.9 2,179
Improved
Recovery 1,194 9 1,202 13 0.7 1,335
Infill
drilling 2,161 21 2,181 655 29.3 7,721
Technical
Revisions 17 78 95 146 12.1 2,255
Acquisitions 3,599 0 3,599 112 6.3 4,757
Dispositions (334) 0 (334) (11) (1.4) (574)
Economic
Factors 1,469 124 1,593 58 4.8 2,452
Production (10,101) (499) (10,600) (1,522) (65.4) (23,015)
Closing
Balance 112,780 2,773 115,553 11,768 593.7 226,264
-------------------------------------------------------------------------
PROBABLE
Opening
Balance 29,966 776 30,742 2,898 145.9 57,964
Exploration
Discoveries 4 0 4 7 0.2 51
Drilling
Extensions 437 56 493 33 3.6 1,131
Improved
Recovery 1,570 2 1,572 4 0.2 1,607
Infill
Drilling 648 10 657 115 (2.0) 438
Technical
Revisions (1,908) 36 (1,871) (171) (3.2) (2,568)
Acquisitions 1,227 0 1,227 132 5.3 2,236
Dispositions (311) 0 (311) (13) (1.5) (574)
Economic
Factors (668) 24 (644) (2) 1.3 (424)
Production 0 0 0 0 0.0 0
Closing
Balance 30,966 904 31,870 3,003 149.9 59,861
-------------------------------------------------------------------------
PROVED PLUS
PROBABLE
Opening
Balance 144,528 3,787 148,315 15,070 741.7 286,997
Exploration
Discoveries 13 0 13 23 0.8 172
Drilling
Extensions 643 86 729 162 14.5 3,310
Improved
Recovery 2,763 11 2,774 17 0.9 2,942
Infill
Drilling 2,808 30 2,838 770 27.3 8,159
Technical
Revisions (1,891) 114 (1,777) (25) 8.9 (313)
Acquisitions 4,826 0 4,826 243 11.5 6,993
Dispositions (645) 0 (645) (24) (2.9) (1,148)
Economic
Factors 801 148 949 56 6.1 2,028
Production (10,101) (499) (10,600) (1,522) (65.4) (23,015)
Closing
Balance 143,746 3,677 147,423 14,770 743.6 286,125
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>>

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

RESERVE LIFE INDEX ("RLI")

ARC's proved plus probable RLI was 12.4 years at year-end 2006 while the
proved RLI was 9.8 years based upon the GLJ reserves and ARC's 2007 production
guidance of 63,000 boe per day. The following table summarizes ARC's
historical RLI.

<<
Reserve Life Index

2006 2005 2004 2003 2002 2001 2000 1999
-------------------------------------------------------------------------
Total Proved 9.8 10.3 9.7 10.1 10.1 9.8 10.4 10.1
Proved Plus Probable
(Established reserves
for 2002 and prior
years) 12.4 12.9 12.2 12.4 11.8 11.5 12.1 12.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

NET PRESENT VALUE ("NPV") SUMMARY 2006

ARC's crude oil, natural gas and natural gas liquids reserves were
evaluated using GLJ's product price forecasts effective January 1, 2007 prior
to provision for income taxes, interest, debt service charges and general and
administrative expenses. Note that this presentation is on a before tax basis,
if the tax measures announced on October 31st are substantially enacted than
the after tax values could be different than the pre-tax number presented. 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 Using GLJ January 1, 2007 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 5,609 3,900 3,037 2,517 2,169
Proved Developed Non-Producing 152 107 82 67 57
Proved Undeveloped 841 509 332 224 153
Total Proved 6,603 4,516 3,451 2,809 2,379
Probable 2,112 1,018 605 407 295
Proved plus Probable 8,715 5,534 4,056 3,215 2,674
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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. GLJ's price
forecast utilized in the evaluation is summarized below.

<<
GLJ January 1, 2007 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)
-------------------------------------------------------------------------
2007 62.00 70.25 7.20 0.87
2008 60.00 68.00 7.45 0.87
2009 58.00 65.75 7.75 0.87
2010 57.00 64.50 7.80 0.87
2011 57.00 64.50 7.85 0.87
2012 57.50 65.00 8.15 0.87
2013 58.50 66.25 8.30 0.87
2014 59.75 67.75 8.50 0.87
2015 61.00 69.00 8.70 0.87
2016 62.25 70.50 8.90 0.87
2017 63.50 71.75 9.10 0.87
Escalate thereafter at +2.0%/yr +2.0%/yr +2.0%/yr 0.87
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The reserves have also been evaluated using constant prices and costs
effective December 31, 2006. Following are the values determined using
this constant price analysis.

NPV of Cash Flow Using December 31, 2006 Constant Prices and Costs

NI 51-101 Undis- Discounted Discounted Discounted Discounted
Net Interest counted at 5% at 10% at 15% at 20%
$Millions
-------------------------------------------------------------------------
Proved Producing 4,779 3,408 2,687 2,241 1,936
Proved Developed
Non-Producing 116 85 68 56 48
Proved
Undeveloped 614 376 242 157 99
Total Proved 5,508 3,870 2,996 2,453 2,084
Probable 1,536 799 496 341 250
Proved plus
Probable 7,044 4,669 3,492 2,795 2,334
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

At a 10 per cent discount factor, the proved producing reserves make up
77 per cent of the proved plus probable value while total proved reserves
account for 86 per cent of the proved plus probable value. The prices utilized
in the constant price evaluation are summarized below.

<<
Constant Prices at December 31, 2006
-------------------------------------------------------------------------
Natural
West Texas Edmonton Gas at
Intermediate Light AECO Foreign
Year Crude Oil Crude Oil ($Cdn/ Exchange
($US/bbl) ($Cdn/bbl) mmbtu) ($US/$Cdn)
-------------------------------------------------------------------------
2006 and thereafter $60.85 $67.58 $6.07 0.8581
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

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.

<<
NAV at December 31, 2006(a)
-------------------------------------------------------------------------
GLJ Constant
Price Price
$Millions, except per unit amounts Forecast Forecast
-------------------------------------------------------------------------
Value of NI 51-101 Net interest Proved Plus
Probable Reserves discounted at 10% $4,056 $3,492
Undeveloped Lands(b) $109 $109
Working Capital Deficit (including current
portion of debt)(c) $(52) $(52)
Reclamation Fund $31 $31
Commodity and Foreign Currency Contracts(d) $(9) $1
Long-term Debt $(687) $(687)
Asset Retirement Obligation(e) $(62) $(69)
-------------------------------------------------------------------------
Net Asset Value $3,386 $2,826
Units Outstanding (000's)(f) 207,173 207,173
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NAV/Unit $16.34 $13.64
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-------------------------------------------------------------------------
(a) Financial information is per ARC's 2006 consolidated financial
statements.
(b) Internal estimate.
(c) Working capital deficit excludes commodity and foreign currency
contracts.
(d) Commodity and foreign currency contracts represent the fair market
value of such contracts as at December 31, 2006 based on the GLJ
future pricing used to arrive at the value of Proved plus Probable
reserves. This amount differs from the value of commodity and
foreign currency contracts in the 2006 consolidated financial
statements due to differing future pricing assumptions.
(e) 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 $103 million was reduced by $41 million and
$34 million respectively, 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 and constant
price cases as per NI 51-101.
(f) Represents total trust units outstanding and trust units issuable
for exchangeable shares as at December 31, 2006.
>>

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 15, 2007 distribution, the Trust has
distributed $18.63 per unit. Despite having distributed more cash than the
initial NAV, the NAV as at December 31, 2006 was $16.34 per unit using GLJ
prices and $13.64 per unit using constant prices and costs. NAV per unit using
GLJ prices decreased $0.28 per unit during 2006 after distributing
$2.40 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 2006 2005 2004 2003 2002 2001 2000
-------------------------------------------------------------------------
Value of NI 51-101
Net interest Proved
plus Probable
reserves(a) $4,056 $3,891 $2,389 $1,689 $1,302 $1,216 $945
Undeveloped lands 109 59 48 50 20 22 6
Reclamation fund 31 23 21 17 13 10 10
Commodity and
Foreign Currency
Contracts(b) (9) (2) (12)
Long-term debt,
net of working
capital (739) (578) (265) (262) (348) (289) (109)
Asset retirement
obligation (62) (35) (23) (27) - - -
-------------------------------------------------------------------------
Net asset value $3,386 $3,358 $2,158 $1,467 $987 $959 $852
Units outstanding
(000's) 207,173 202,039 188,804 182,777 126,444 111,692 72,524
-------------------------------------------------------------------------
NAV per unit $16.34 $16.62 $11.43 $8.03 $7.81 $8.59 $11.74
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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) Commodity and foreign currency 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 2006 ARC spent $365 million of capital on exploration and
development activities, which added 16 mmboe of proved and 16.3 mmboe of
proved plus probable reserves (including revisions). These activities replaced
71 per cent of ARC's 2006 production. In total, ARC drilled 294 gross operated
wells with a 99 per cent per cent drilling success rate.
In 2006 the largest percentage of capital was again devoted towards
development opportunities in the Northern core area. In Ante Creek, ARC
drilled 14 successful oil wells, and acquired undeveloped acreage and a new
processing facility. Historical facility constraints should be alleviated in
early 2007 with the connection of the new 10-36 plant to the existing ARC core
infrastructure. ARC was also very active at Dawson, with the drilling of four
successful horizontal Montney gas wells building on the success of the 2005
horizontal pilot. Dawson also saw six new vertical Montney gas wells brought
on production. In Valhalla, ARC successfully drilled five Montney oil wells
and implemented a new waterflood project. Other areas in the north that saw
development included Prestville, Chinchaga and Swan Hills
The most active drilling areas in 2006 were in ARC's shallow gas regions
in southeastern Alberta and southwestern Saskatchewan where 159 shallow gas
wells and 5 deep oil and gas wells were drilled.
In the central Alberta area, ARC brought on line its first commercial
scale NGC development program with 33 successful wells producing to the new
ARC operated infrastructure. The central area also experienced deeper prospect
success with oil and gas focused development of eight new wells in Youngstown,
Garrington, Medicine River and Westerose.
The Pembina area development for 2006 included 22 successful Cardium oil
wells in Berrymoor, Lindale, MIPA and the North Pembina Cardium Unit.
Two Viking wells were drilled and many large blocks of undeveloped
mineral rights were acquired though acquisition and crown sales in Redwater,
Alberta. ARC experienced production growth in the Redwater area after
implementing a very successful inactive well reactivation program. This
program will continue into 2007.
ARC experienced continued drilling success in southeast Saskatchewan with
21 new oil wells, primarily horizontal light oil producers.
ARC's non-operated properties saw significant development activities
especially southeast Saskatchewan where the implementation of a CO(2) enhanced
oil recovery project at Midale continued as did infill drilling in the Weyburn
Unit CO(2) commercial enhanced oil recovery project. ARC also has an interest
in the new Alkali-Surfactant-Polymer ("ASP") flood for enhanced oil recovery
being implemented for a 2007 start date in the Instow field.
Excluding FDC, ARC's proved plus probable F&D costs for 2006 were
$22.36 per boe. On a proved basis, ARC's F&D costs were $22.69 per boe.

ACQUISITIONS AND DISPOSITIONS

ARC was reasonably active on the acquisition front during 2006 spending
$132 million, (net of minor dispositions), to purchase 5.8 mmboe of proved
plus probable reserves. ARC's acquisitions were primarily focused on adding to
our core northern properties with the purchase of additional Ante Creek and
Dawson assets. These two acquisitions helped ARC to consolidate infrastructure
and build upon the existing inventory of future development potential in these
core areas.
ARC also acquired high netback, light oil producing properties in the
Goodlands and Virden areas of southern Manitoba. This deal represents ARC's
first production from Manitoba.
As part of its active asset management program, ARC took advantage of the
strong demand for producing assets by disposing 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 an area with limited future development
opportunities.

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

Incorporating the net acquisitions during the year, ARC's proved FD&A
costs excluding FDC were $24.51 per boe while proved plus probable FD&A costs
were $22.41 per boe. The following table outlines the impacts of the
significant capital devoted towards future growth opportunities

<<
FD&A Costs - Impacts due to growth oriented spending
-------------------------------------------------------------------------

Undeveloped EOR(a)
Land Pre-
Base Acquis- invest-
FD&A itions ment Seismic Total
-------------------------------------------------------------------------
Expenditures
($Millions) $ 420.8 $ 55.9 $ 13.2 $ 6.1 $ 496.3
-------------------------------------------------------------------------
Total Proved ($/boe) $ 20.80 $ 2.76 $ 0.65 $ 0.30 $ 24.51
-------------------------------------------------------------------------
Proved Plus
Probable ($/boe) $ 19.03 $ 2.52 $ 0.59 $ 0.27 $ 22.41
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(a) Enhanced oil recovery (EOR) Pre-investment relates to capital
expended in 2006 on projects where the expected reserve uplift has
not yet been booked.
>>

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
high level of activity has resulted in increased capital costs throughout the
industry that are now reflected in the estimates of future development costs
effective December 31, 2006.

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

FD&A Costs Excluding Future Development Capital
-----------------------------------------------
Exploration and Development Capital Expenditures
- $thousands $364,482 $364,482
Exploration and Development Reserve Additions
Including Revisions - mboe 16,062 16,298
Finding and Development Cost - $/boe $22.69 $22.36
Three Year Average F&D Cost - $/boe $18.06 $16.72
Net Acquisition Capital - $thousands $131,820 $131,820
Net Acquisition Reserve Additions - mboe 4,184 5,845
Net Acquisition Cost - $/boe $31.51 $22.55
Three Year Average Net Acquisition Cost - $/boe $17.47 $14.49
Total Capital Expenditures including Net
Acquisitions - $thousands $496,302 $496,302
Reserve Additions including Net Acquisitions
- mboe 20,246 22,143
Finding Development and Acquisition Cost - $/boe $24.51 $22.41
Three Year Average FD&A Cost - $/boe $17.77 $15.59

FD&A Costs Including Future Development Capital
------------------------------------------------
Exploration and Development Capital Expenditures
- $thousands $364,482 $364,482
Exploration and Development Change in FDC
-$thousands $51,780 $90,370
Exploration and Development Capital Including
Change In FDC- $thousands $416,262 $454,852
Exploration and Development Reserve Additions
Including Revisions - mboe 16,062 16,298
Finding and Development Cost - $/boe $25.92 $27.91
Three Year Average F&D Cost - $/boe $21.03 $21.64
Net Acquisition Capital - $thousands $131,820 $131,820
Net Acquisition FDC - $thousands $9,221 $15,630
Net Acquisition Capital Including FDC - $thousands $141,041 $147,450
Net Acquisition Reserve Additions - mboe 4,184 5,845
Net Acquisition Cost - $/boe $33.71 $25.22
Three Year Average Net Acquisition Cost - $/boe $19.53 $16.43
Total Capital Expenditures including Net
Acquisitions - $thousands $496,302 $496,302
Total Change in FDC -$thousands $61,000 $106,000
Total Capital Including Change in FDC - $thousands $557,302 $602,302
Reserve Additions including Net Acquisitions
- mboe 20,246 22,143
Finding Development and Acquisition Cost Including
FDC- $/boe $27.53 $27.20
Three Year Average FD&A Cost Including FDC- $/boe $20.31 $18.99
-------------------------------------------------------------------------
-------------------------------------------------------------------------

------------------
(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
-------------------------------------------------------------------------

2006 2005 2004 2003 2002 2001 2000
-------------------------------------------------------------------------
Annual FD&A
excluding FDC $24.51 $15.60 $16.53 $10.78 $8.87 $11.35 $5.73
Three year
average FD&A
excluding FDC $17.77 $13.30 $11.05 $10.69 $9.07 $8.06 $5.68
-------------------------------------------------------------------------

Annual FD&A
including FDC $27.53 $17.64 $20.46 $12.66 $10.03 $11.93 $7.56
Three year
average FD&A
including FDC $20.31 $15.45 $13.02 $11.96 $10.16 $9.09 $7.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

2006 2005 2004 2003 2002 2001 2000
-------------------------------------------------------------------------
Annual FD&A
excluding FDC $22.41 $13.64 $13.76 $8.50 $9.27 $9.75 $5.16
Three Year
Average FD&A
excluding FDC $15.59 $11.00 $9.30 $9.07 $8.21 $6.94 $4.95
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Annual FD&A
including FDC $27.20 $16.09 $19.14 $10.54 $10.79 $10.41 $7.21
Three Year
Average FD&A
including FDC $18.99 $13.50 $11.65 $10.52 $9.46 $8.04 $6.54
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RESERVES RECONCILIATION
Net Interest (Working Interest + Royalties Receivable -
Royalties Payable)
Light
and Oil
Medium Heavy Total Equiv-
Crude Crude Crude Natural alent
Oil Oil Oil NGL's Gas 2006
(mbbl) (mbbl) (mbbl) (mbbl) (bcf) (mboe)
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PROVED PRODUCING
Opening Balance 88,083 2,725 90,808 7,358 380.1 161,509
Exploration
Discoveries 8 0 8 10 0.3 75
Drilling
Extensions 161 28 189 83 6.3 1,329
Improved
Recovery 3,142 9 3,151 62 2.7 3,662
Infill
Drilling 1,168 7 1,174 248 28.4 6,160
Technical
Revisions 1,979 107 2,086 119 6.2 3,244
Acquisitions 2,476 0 2,476 28 1.5 2,758
Dispositions (250) 0 (250) (2) (0.2) (291)
Economic Factors 1,363 115 1,478 30 3.8 2,141
Production (8,671) (450) (9,121) (1,125) (53.1) (19,089)
Closing Balance 89,460 2,540 92,000 6,811 376.1 161,498
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TOTAL PROVED
Opening Balance 101,674 2,758 104,432 8,621 489.5 194,637
Exploration
Discoveries 8 0 8 10 0.3 75
Drilling
Extensions 181 28 209 88 8.5 1,706
Improved
Recovery 1,020 9 1,029 11 0.6 1,143
Infill Drilling 1,301 20 1,321 455 23.5 5,692
Technical
Revisions 1,489 73 1,563 155 10.7 3,507
Acquisitions 3,153 0 3,153 80 4.9 4,051
Dispositions (332) 0 (332) (11) (1.3) (568)
Economic Factors 1,256 115 1,371 27 4.3 2,108
Production (8,671) (450) (9,121) (1,125) (53.1) (19,089)
Closing Balance 101,079 2,554 103,632 8,310 487.9 193,262
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PROBABLE
Opening Balance 26,139 699 26,838 2,092 119.5 48,845
Exploration
Discoveries 3 0 3 4 0.1 32
Drilling
Extensions 366 54 420 21 2.9 928
Improved
Recovery 1,393 2 1,395 3 0.2 1,424
Infill Drilling 1,131 9 1,141 78 (1.7) 941
Technical
Revisions (1,798) 28 (1,771) (106) (2.2) (2,242)
Acquisitions 1,070 0 1,070 93 4.0 1,828
Dispositions (309) 0 (309) (13) (1.5) (573)
Economic Factors (672) 23 (649) (3) 1.2 (451)
Production 0 0 0 0 0.0 -
Closing Balance 27,324 816 28,139 2,170 122.5 50,732
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PROVED PLUS
PROBABLE
Opening Balance 127,813 3,458 131,271 10,713 609.0 243,482
Exploration
Discoveries 11 0 11 14 0.5 107
Drilling
Extensions 547 82 629 109 11.4 2,634
Improved
Recovery 2,413 11 2,424 14 0.8 2,567
Infill Drilling 2,432 29 2,462 533 21.8 6,633
Technical
Revisions (309) 101 (208) 49 8.5 1,265
Acquisitions 4,223 0 4,223 173 8.9 5,879
Dispositions (641) 0 (641) (24) (2.9) (1,140)
Economic Factors 584 138 722 24 5.5 1,657
Production (8,671) (450) (9,121) (1,125) (53.1) (19,089)
Closing Balance 128,402 3,369 131,771 10,480 610.5 243,994
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-------------------------------------------------------------------------

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

NI 51-101 Calculation Including Future Development
--------------------------------------------------
Capital
-------
Capital Expenditures excluding Net Acquisitions
- $thousands $364,482 $364,482
Net Change in FDC excluding Net Acquisitions
-$thousands $51,780 $90,370
Total Capital including FDC- $thousands $416,262 $454,852
Reserve additions excluding Net Acquisitions
- mboe 15,681 15,832
Finding and Development Cost - $/boe $26.55 $28.73
Three Year Average F&D Cost - $/boe $22.73 $23.21
Capital Expenditures including net acquisitions
- $thousands $496,302 $496,302
Net Change in FDC including net acquisitions
-$thousands $61,000 $106,000
Total Capital - $thousands $557,302 $602,302
Reserve additions including net acquisitions
- mboe 19,865 21,677
Finding Development and Acquisition Cost - $/boe $28.05 $27.79
Three Year Average FD&A Cost - $/boe $20.63 $19.28
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-------------------------------------------------------------------------

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

2006 2005 2004 2003 2002
-------------------------------------------------------------------------

Annual FD&A including FDC $28.05 $17.81 $21.27 $12.95 $10.97
Three year average FD&A
including FDC $20.63 $15.74 $13.54 n/a n/a
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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

2006 2005 2004 2003 2002
-------------------------------------------------------------------------

Annual FD&A including FDC $27.79 $16.24 $19.74 $10.74 $12.06
Three Year Average FD&A
including FDC $19.28 $13.73 $12.09 n/a n/a
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>>

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $5.4 billion. The
Trust currently has an interest in oil and gas production of approximately
63,000 barrels of oil equivalent per day from six core areas in western
Canada. The royalty trust structure allows net cash flow to be distributed to
unitholders in a tax efficient manner. ARC Energy Trust trades on the TSX
under the symbol AET.UN.

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 2007 and beyond; the
sources, deployment and allocation of expected capital in 2007; 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