ARC Energy Trust announces second quarter 2007 results

Aug 1, 2007

CALGARY, Aug. 1 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") announces the results for the second quarter ending June 30,
2007.

<<
Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
-------------------------------------------------------------------------
FINANCIAL
($CDN millions, except per unit
and per boe amounts)
Revenue before royalties 305.6 306.7 613.4 625.7
Per unit(1) 1.46 1.51 2.94 3.09
Per boe 54.48 54.54 53.88 54.70
Cash Flow(2) 167.6 194.7 351.4 385.9
Per unit(1) 0.80 0.96 1.68 1.90
Per boe 29.88 34.61 30.87 33.73
Net income 184.9 182.5 268.2 286.6
Per unit(3) 0.90 0.91 1.30 1.43
Distributions 124.1 120.6 247.2 240.5
Per unit(1) 0.60 0.60 1.20 1.20
Per cent of Cash Flow 74 62 70 62
Net debt outstanding(4) 653.9 567.4 653.9 567.4
Total capital expenditures 48.5 58.6 126.0 137.7

OPERATING
Production
Crude oil (bbl/d) 28,099 27,805 28,806 28,723
Natural gas (mmcf/d) 176.7 178.5 179.8 181.7
Natural gas liquids (bbl/d) 4,088 4,247 4,124 4,184
Total (boe/d) 61,637 61,803 62,899 63,194
Average prices
Crude oil ($/bbl) 65.21 71.86 62.96 65.53
Natural gas ($/mcf) 7.38 6.35 7.57 7.39
Natural gas liquids ($/bbl) 52.76 54.44 50.39 53.69
Oil equivalent ($/boe)(5) 54.48 54.54 53.88 54.70
Operating netback ($/boe)
Commodity and other revenue
(before hedging) 54.48 54.54 53.88 54.70
Transportation costs (0.72) (0.66) (0.77) (0.64)
Royalties (9.43) (9.78) (9.54) (10.25)
Operating costs (9.63) (8.20) (9.30) (8.00)
Netback (before hedging) 34.70 35.90 34.27 35.81
-------------------------------------------------------------------------

TRUST UNITS
(millions)
Units outstanding, end of period 207.3 201.5 207.3 201.5
Units issuable for exchangeable
shares 2.9 2.9 2.9 2.9
Total units outstanding and
issuable for exchangeable
shares, end of period 210.2 204.4 210.2 204.4
Weighted average units(6) 209.5 203.7 208.7 203.1
-------------------------------------------------------------------------

TRUST UNIT TRADING STATISTICS
($CDN, except volumes)
based on intra-day trading
High 23.86 28.61 23.86 28.61
Low 20.78 24.35 20.05 24.35
Close 21.74 28.00 21.74 28.00
Average daily volume (thousands) 599 548 629 546
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(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares. Per unit distributions are based on
the number of trust units outstanding at each distribution date.
(2) Cash Flow is a non-GAAP measure. Refer to the non-GAAP measure
section in the MD&A for a reconciliation of Cash Flow to cash flow
from operating activities as prescribed by GAAP.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Net debt excludes unrealized risk management contracts.
(5) Includes other revenue.
(6) Includes trust units issuable for outstanding exchangeable shares at
period end.

ACCOMPLISHMENTS/FINANCIAL UPDATE
--------------------------------

- Production averaged 61,637 boe per day in the second quarter of 2007,
relatively unchanged from 61,803 boe per day achieved in the second
quarter of 2006. The second quarter is normally the low point for the
year as maintenance activities at both ARC operated and third party
operated facilities result in production being shut-in. During the
second quarter of 2007 approximately 2,000 boe per day of production
was shut-in due to maintenance activities and other operational
disruptions. Production in the third quarter is expected to return to
normal levels. The Trust has maintained its full year production
guidance of 63,000 boe per day.

- The Trust drilled eight wells during the quarter including the third
well of a four-well horizontal drilling program at Dawson in
northeast British Columbia, keeping the Trust on track to reach
natural gas production of 40 mmcf/d for this property by the fourth
quarter. Achieving this goal is dependent upon the completion of a
third party gas plant that is currently under construction with an
anticipated start-up date of November 1, 2007.

- Capital expenditures for the quarter were $48.5 million, 86 per cent
of which was funded from Cash Flow with the remainder funded with
proceeds from the distribution re-investment program (DRIP). Year-to-
date capital expenditures are $126 million, all which have been
funded from Cash Flow and the proceeds from the DRIP. The Trust
expects to spend approximately $350 million on capital expenditures
during 2007.

- Prior to hedging activities, ARC's total realized commodity price was
$54.48 per boe in the second quarter of 2007, relatively unchanged
from the $54.54 per boe received prior to hedging in the second
quarter of 2006. The Trust benefited from a balanced production mix,
whereby a 16 per cent increase in natural gas prices offset a nine
per cent decrease in oil prices in the second quarter of 2007
compared to the second quarter of 2006.

- In addition to the fluctuations in the commodity price, the Canadian
dollar appreciated significantly against the U.S. dollar, reaching a
30 year high of CDN/USD $0.94 at the end of the second quarter. The
average CDN/USD for the second quarter of 2007 was $0.91, a seven per
cent increase from CDN/USD $0.85 in the first quarter of 2007. The
Trust has seen a negative impact to revenue, and therefore Cash Flow,
during the quarter because commodity prices are derived from U.S.
dollar posted prices for both oil and natural gas. Future revenues
may be negatively impacted due to the continued strengthening of the
Canadian dollar. In July 2007, the dollar has continued to appreciate
with the latest record high being USD/CDN $0.96 on July 16, 2007.
Conversely, the Trust has benefited from management's decision to
hold a major portion of the Trust's subsidiaries' debt in U.S.
dollars. The Trust has seen a significant decrease in the Canadian
dollar equivalent of its debt balance; however, the majority of this
gain is a non-cash, unrealized gain.

- Net income for the quarter was $184.9 million, effectively unchanged
from $182.5 million in the second quarter of 2006. The Trust has
recorded a $35.6 million one time increase in earnings and a
corresponding decrease to its future income tax liability as a result
of the passage of the previously announced tax on income trusts.

- Cash Flow for the quarter was $167.6 million of which $124.1 million
was distributed to unitholders representing $0.60 per unit based on
the number of trust units outstanding at each record date. The Trust
announced third quarter distributions will remain at $0.20 per unit
per month, a level that has been maintained since October 2005.

- The Trust recorded the sale of its long-term investment during the
second quarter. A gain of $13.3 million dollars was recorded and the
full proceeds of $33.3 million were recorded in cash flow from
investing activities during the quarter. The net debt balance
excluding risk management contract assets and liabilities of
$653.9 million at June 30, 2007 incorporates the proceeds from the
sale.
>>

MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------

This management's discussion and analysis ("MD&A") is dated July 31, 2007
and should be read in conjunction with the June 30, 2007 unaudited interim
consolidated financial statements of ARC Energy Trust ("ARC", "the Trust",
"we", "our"), the March 31, 2007 unaudited interim consolidated financial
statements and MD&A, as well as the audited consolidated financial statements
and MD&A for the year ended December 31, 2006.

Non-GAAP Measures

Management uses Cash Flow and Cash Flow per unit derived from cash flow
from operating activities (before changes in non-cash working capital and
expenditures on site reclamation and restoration) to analyze operating
performance and leverage. Cash Flow as presented does not have any
standardized meaning prescribed by Canadian generally accepted accounting
principles, ("GAAP") and therefore it may not be comparable with the
calculation of similar measures for other entities. Cash Flow as presented is
not intended to represent operating cash flow or operating profits for the
period nor should it be viewed as an alternative to cash flow from operating
activities, net earnings or other measures of financial performance calculated
in accordance with Canadian GAAP. Management uses the non-GAAP measure of Cash
Flow because we feel that it is a more meaningful measure of the true cash
generated in a period from active operations and therefore have concluded that
it is material and relevant to discuss Cash Flow throughout this MD&A.

<<
The following table reconciles the cash flow from operating activities to
Cash Flow, which is used frequently in this MD&A:

-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
Cash flow from operating
activities 179.4 182.2 351.7 371.2
Changes in non-cash working
capital (19.0) 10.6 (12.2) 11.5
Expenditures on site restoration
and reclamation 7.2 1.9 11.9 3.2
-------------------------------------------------------------------------
Cash Flow 167.6 194.7 351.4 385.9
-------------------------------------------------------------------------
Weighted average units including
exchangeable shares 209.5 203.7 208.7 203.1
-------------------------------------------------------------------------
Cash Flow per Unit 0.80 0.96 1.68 1.90
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Management uses certain key performance indicators ("KPIs") and industry
benchmarks such as distributions as a per cent of Cash Flow, operating
netbacks ("netbacks"), total capitalization, finding, development and
acquisition costs, recycle ratio, reserve life index, reserves per unit and
production per unit to analyze financial and operating performance. Management
feels that these KPIs and benchmarks are key measures of profitability and
overall sustainability for the Trust. These KPIs and benchmarks as presented
do not have any standardized meaning prescribed by Canadian GAAP and therefore
may not be comparable with the calculation of similar measures for other
entities.

Update on Legislation Changes Impacting the Trust

Federal Government's Trust Tax Legislation

In April 2007, the Federal Government included the proposed Trust
Taxation in the Federal Budget ("Bill C-52"). Bill C-52 received a third
reading on June 12, 2007 and then Royal Assent on June 22, 2007, thus fully
enacting the tax measures. As a result the Trust has recorded a $35.6 million
one time increase in earnings and a corresponding decrease to its future
income tax liability as a result of timing differences within the Trust that
have not been previously recognized. The initial recognition of $35.6 million
comprises $24.7 million for pre-2007 generated temporary differences and
$10.9 million for temporary differences relating to the current year.
Our Board of Directors and Management continue to review the impact of
this tax on our business strategy. We expect future technical interpretations
and details will further clarify the legislation. At the present time, ARC
believes that if structural or other similar changes are not made, the
after-tax distribution amount in 2011 to taxable Canadian investors will
remain approximately the same, however, the distribution amount in 2011 to
tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and
foreign investors would fall by an estimated 31.5 percent and 26.5 percent,
respectively.

Climate Change Programs

On March 8, 2007, the Alberta government introduced legislation to reduce
greenhouse gas emission intensity. Bill 3 states that facilities emitting more
than 100,000 tonnes of greenhouse gases per year must reduce their emissions
intensity by 12 per cent over the average emissions levels of 2003, 2004 and
2005; if they are not able to do so, these facilities will be required to pay
$15 per tonne for every tonne above the 12 per cent target, beginning on
July 1, 2007. At this time, the Trust has determined that the impact of this
legislation would be minimal based on ARC's existing facilities ownership.
In April 2007, the Federal Government announced a new climate change plan
that calls for greenhouse gas emissions to be reduced by 20 per cent below
current levels by 2020. Firms may employ the following strategies to achieve
the targets. They will be able to:

<<
- make in-house reductions;
- take advantage of domestic emissions trading;
- purchase offsets;
- use the Clean Development Mechanism under the Kyoto Protocol; and,
- invest in a technology fund.
>>

The Trust is waiting for additional information so as to fully assess
what impact, if any, this new legislation will have on our operations.

United States Proposed Changes to Qualifying Dividends

A bill was introduced into United States Congress on March 23, 2007 that
could deny qualified dividend income treatment to the distributions made by
the Trust to its U.S. unitholders. The bill is in the first step of the
legislative process and it is uncertain whether it will eventually be passed
into law in its current form. If the bill is passed in its current form,
distributions received by U.S. unitholders would no longer qualify for the 15
per cent qualified dividend tax rate.

<<
Financial Highlights

-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
(CDN$ millions, except per % %
unit and volume data) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Cash Flow(1) 167.6 194.7 (14) 351.4 385.9 (9)
Cash Flow per unit(1) 0.80 0.96 (17) 1.68 1.90 (12)
Net income 184.9 182.5 1 268.2 286.6 (6)
Distributions per unit(2) 0.60 0.60 - 1.20 1.20 -
Distributions as a per cent
of Cash Flow 74 62 19 70 62 13
Daily production
(boe/d)(3) 61,637 61,803 - 62,899 63,194 (1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Refer to Non-GAAP Measures.
(2) Based on number of trust units outstanding at each cash distribution
date.
(3) Reported production amount is based on company interest, which
includes royalty interest and is before royalty burdens. Where
applicable in this MD&A natural gas has been converted to barrels of
oil equivalent ("boe") based on 6 mcf: 1 bbl. 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 well
head. Use of boe in isolation may be misleading.
>>

Net Income

Net income in the second quarter of 2007 was $184.9 million ($0.90 per
unit), an increase of $2.4 million from $182.5 million ($0.91 per unit) in the
second quarter of 2006. Higher operating costs ($7.9 million), interest costs
($1.7 million) and depletion expense ($4.6 million) in the quarter were almost
entirely offset by an increased gain on foreign exchange ($12.7 million). In
addition, the Trust recorded an increased gain on risk management contracts
($14 million) that was offset by a lower future income tax recovery ($24.5
million) and the recording of a gain on sale of investment ($13.3 million).

Cash Flow

Cash Flow was $167.6 million in the second quarter of 2007 a 14 per cent
decrease from $194.7 million recorded in the second quarter of 2006. The
decrease in second quarter Cash Flow was attributed to an $11 million decrease
in realized cash hedging gains, an $8.5 million increase in cash operating
costs and a $5.7 million increase in cash general and administrative ("G&A")
costs. The increase in operating costs, more fully described later in this
MD&A, were due primarily to turnaround and workovers that occurred in the
quarter and the G&A cost increase is attributed to the cash payout under the
Trust's Whole Unit Plan which occurred in the second quarter.

<<
Following is a summary of variances in Cash Flow from 2006 to 2007:

-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
$ $ Per % $ $ Per %
Millions Unit Variance Millions Unit Variance
-------------------------------------------------------------------------
2006 Cash Flow 194.7 0.96 - 385.9 1.90 -
-------------------------------------------------------------------------
Volume variance (0.8) - - (2.9) (0.01) (1)
Price variance (0.4) - - (9.4) (0.05) (2)
Cash gains on
risk management
contracts(1) (11.0) (0.05) (6) (2.6) (0.01) (1)
Royalties 2.1 0.01 1 8.6 0.04 2
Expenses:
Operating(2) (8.5) (0.04) (4) (15.4) (0.08) (4)
Transportation (0.3) (0.01) - (1.5) (0.01) -
Cash G&A (5.7) (0.03) (3) (6.8) (0.04) (2)
Interest and
cash taxes (1.9) (0.01) (1) (3.7) (0.02) (1)
Realized foreign
exchange (loss) (0.6) (0.01) - (0.9) - -
Other - - - 0.1 - -
Weighted average
trust units - (0.02) - - (0.04) -
-------------------------------------------------------------------------
2007 Cash Flow 167.6 0.80 (14) 351.4 1.68 (9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents cash gains on risk management contracts including cash
settlements on termination of risk management contracts.
(2) Excludes non-cash portion of the Whole Unit Plan expense recorded in
operating costs.
>>

Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

Production

Production volume averaged 61,637 boe per day in the second quarter of
2007, relatively unchanged from 61,803 boe per day during the second quarter
of 2006. The Trust experienced significant production loss during the second
quarter as a result of planned turnarounds and workovers. Of the approximately
2,000 boe per day of volumes that were shut-in during the quarter, the Trust
estimates that 1,000 boe per day was lost due to either unscheduled activities
or where turnarounds took significantly longer than expected. The Trust
expects third quarter production to return to normal levels. We have
maintained our full year 2007 production guidance at 63,000 boe per day.
Throughout the first six months of 2007, the Trust has experienced
production restrictions in the northern Alberta area as a result of gas plant
capacity constraints. A new third party plant is scheduled to be on-line in
the fourth quarter of 2007 to handle existing excess production as well as
additional development production from both Dawson and Pouce South. As of
June 30, the Trust had three horizontal wells in Dawson that were waiting to
be completed. It is anticipated that these wells will be completed during the
third quarter so that they can be brought on production in the fourth quarter
when there is additional processing capacity for the resulting production.
The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During the second quarter of 2007, the Trust
drilled eight gross wells (six net wells) on operated properties with a 100
per cent success rate; six gross oil wells and two gross natural gas wells.
Normally, the second quarter is the least active quarter for drilling as field
operations are restricted during "spring break-up" and do not get back to
normal levels until late in the quarter when field conditions have improved.

<<
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
% %
Production(1) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Crude oil (bbl/d) 28,099 27,805 1 28,806 28,723 -
Natural gas (mcf/d) 176,706 178,504 (1) 179,814 181,721 (1)
NGL (bbl/d) 4,088 4,247 (4) 4,124 4,184 (1)
-------------------------------------------------------------------------
Total production
(boe/d) 61,637 61,803 - 62,899 63,194 (1)
-------------------------------------------------------------------------
% Natural gas
production 48 48 48 48
% Crude oil and
liquids production 52 52 52 52
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.

The following table summarizes the Trust's production by core area:

-------------------------------------------------------------------------
Three Months Ended June 30, 2007

Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,774 1,631 29.0 1,316
Northern AB & BC 19,417 5,599 73.9 1,499
Pembina & Redwater 13,515 9,188 19.1 1,136
S.E. AB & S.W. Sask. 9,915 1,070 53.0 9
S.E. Sask. & MB 11,016 10,611 1.7 128
-------------------------------------------------------------------------
Total 61,637 28,099 176.7 4,088
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Three Months Ended June 30, 2006

Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 8,082 1,501 30.7 1,464
Northern AB & BC 18,345 5,596 67.2 1,554
Pembina & Redwater 13,712 9,293 20.0 1,093
S.E. AB & S.W. Sask. 10,798 1,043 58.4 9
S.E. Sask. & MB 10,866 10,372 2.2 127
-------------------------------------------------------------------------
Total 61,803 27,805 178.5 4,247
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast, S.W. is
southwest.

Commodity Prices Prior to Hedging

-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
% %
Benchmark prices 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
AECO gas (CDN$/mcf)(1) 7.37 6.28 17 7.42 7.78 (5)
WTI oil (US$/bbl)(2) 65.02 70.70 (8) 61.59 67.14 (8)
USD/CAD foreign
exchange rate 0.91 0.89 2 0.88 0.88 -
WTI oil (CDN$/bbl) 71.35 79.08 (10) 69.78 76.28 (9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

The price of oil in U.S. dollars decreased by eight per cent in the
second quarter of 2007 as compared to the second quarter of 2006 while the
price of oil in Canadian dollars decreased by 10 per cent. The strengthening
of the Canadian dollar relative to the U.S. dollar was responsible for the
larger decrease of the price of oil in Canadian dollar terms. ARC's realized
oil price in the second quarter of 2007 was $65.21 per barrel, a nine per cent
decrease over the $71.86 per barrel received in the second quarter of 2006 as
minor changes in differential offset a portion of the decrease due to the
change in foreign exchange.
Natural gas prices recovered in the second quarter of 2007 with the
Alberta AECO Hub monthly posting averaging $7.37 per mcf as compared to $6.28
per mcf for the comparable period of 2006. The Trust's realized price of $7.38
per mcf in the second quarter of 2007 was 16 per cent higher than the $6.35
per mcf price realized by the Trust in the second quarter of 2006. The Trust's
realized gas price is based on prices received at the various markets in which
the Trust sells its natural gas. ARC's natural gas sales portfolio consists of
gas sales priced at the AECO monthly index, the AECO daily spot market,
eastern and mid-west United States markets and a portion to aggregators.
Prior to hedging activities, ARC's total realized commodity price was
$54.48 per boe in the second quarter of 2007, relatively unchanged from the
$54.54 per boe received prior to hedging in the second quarter of 2006. Given
the Trust's balanced production mix, the increases in natural gas prices
offset the decreases in oil prices during the period.

<<
The following is a summary of realized prices:

-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
% %
ARC Realized Prices 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Oil ($/bbl) 65.21 71.86 (9) 62.96 65.63 (4)
Natural gas ($/mcf) 7.38 6.35 16 7.57 7.39 2
NGLs ($/bbl) 52.76 54.44 (3) 50.39 53.70 (6)
-------------------------------------------------------------------------
Total commodity
revenue before
hedging ($/boe) 54.37 54.42 - 53.77 54.58 (1)
Other revenue ($/boe) 0.11 0.12 (8) 0.11 0.12 (8)
-------------------------------------------------------------------------
Total revenue before
hedging ($/boe) 54.48 54.54 - 53.88 54.70 (1)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Revenue

Revenue was relatively unchanged at $305.6 million as compared with $306.7
million for the second quarter of 2006 as increased gas revenues were offset
by a decrease in oil and NGL revenue.

A breakdown of revenue is as follows:

-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
% %
Revenue ($ millions) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Oil revenue 166.8 181.8 (8) 328.3 340.7 (4)
Natural gas revenue 118.6 103.2 15 246.3 242.9 1
NGLs revenue 19.6 21.0 (7) 37.6 40.7 (8)
-------------------------------------------------------------------------
Total commodity
revenue 304.9 306.0 - 612.2 624.3 (2)
Other revenue 0.6 0.7 (14) 1.2 1.4 (14)
-------------------------------------------------------------------------
Total revenue before
hedging 305.6 306.7 - 613.4 625.7 (2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Risk Management and Hedging Activities

The Trust continues to maintain a strong hedging position with an
emphasis on protecting Cash Flow and distributions to unitholders.
During the second quarter ARC realized cash hedging gains of $0.3 million
bringing cash hedging gains for the year-to-date to $7.3 million. Gains on
crude oil puts and foreign exchange positions were offset by settlements on
natural gas basis swaps and premiums paid for natural gas contracts.
In addition to layering into additional natural gas and crude oil
positions during the quarter, ARC also modified positions that were previously
on the books as part of its active hedging program.
ARC optimized its crude oil positions by restructuring the long-term
5,000 barrels per day hedge that was entered into to protect the acquisition
metrics of the 2005 Redwater/NPCU properties. ARC increased the floor price on
the 3-way collar from $55.00 to an average of $61.26. This was achieved at no
cost by lowering the ceiling price on the original structure from $90.00 to
$85.00 and raising the sold floor price from $40.00 to $50.00. This raises the
average floor price for crude oil hedges for 2008 to $63.33 per barrel.
On a forward-looking basis ARC continues to add layers of protection for
both crude oil and natural gas production. During the quarter ARC layered on
additional protection on crude to the end of 2008 and additional natural gas
positions through to Q1 2008.
On crude oil production ARC has protected approximately 40 per cent of
forecast oil production through year-end 2007, 30 per cent of production
through the first half of 2008, and 20 per cent of production for the second
half of 2008. For natural gas production ARC has protected approximately 32.5
per cent of production during the third quarter of 2007, 20 per cent for the
fourth quarter of 2007, and 15 per cent for the first quarter of 2008.

<<
The following is a summary of the Trust's positions for the next twelve
months as at June 30, 2007.

-------------------------------------------------------------------------
Hedge Positions
as at June 29, 2007(1)(2) Q3 2007 Q4 2007
-------------------------------------------------------------------------
Crude oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold call 86.48 8,500 86.48 8,500
Bought put 61.92 13,000 61.92 13,000
Sold put 48.90 12,500 48.90 12,500
-------------------------------------------------------------------------
Natural gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold call 9.08 40,435 11.36 20,986
Bought put 7.24 65,275 7.41 42,981
Sold put 5.19 55,275 5.19 18,625
-------------------------------------------------------------------------
FX CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought put 1.1400 55.8 1.1400 55.8
Sold put 1.1096 54.0 1.1096 54.0
Swap 1.1371 4.2 1.1371 4.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Hedge Positions
as at June 29, 2007(1)(2) Q1 2008 Q2 2008
-------------------------------------------------------------------------
Crude oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold call 84.75 10,000 84.75 10,000
Bought put 63.63 10,000 63.63 10,000
Sold put 50.94 8,000 50.9375 8,000
-------------------------------------------------------------------------
Natural gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold call 11.35 31,652 - -
Bought put 7.58 31,652 - -
Sold put - - - -
-------------------------------------------------------------------------
FX CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought put - - - -
Sold put - - - -
Swap - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The prices and volumes noted above represent averages for several
contracts and the average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. Viewing the average price of a group of options is purely
for indicative purposes. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price. In addition to positions
shown here, ARC has entered into additional basis positions.
(2) Please refer to note 9 in the Trust's unaudited consolidated
financial statements as at June 30, 2007 and 2006 for a detailed
breakdown of the Trust's hedging position as at June 30, 2007.
>>

The above table should be interpreted as follows using the third quarter
2007 crude oil hedges as an example. The Trust has hedged 13,000 barrels per
day at a minimum average price of US$61.92 and participates in prices up to a
maximum average of US$86.48 on 8,500 barrels per day with no limit on the
remaining 4,500 hedged barrels per day and on all other unhedged production
for the period. Finally, ARC's average protected price of $61.92 reduces penny
for penny at an average price below $48.90 on 12,500 barrels per day.
As a result of commodity hedging contracts denominated in U.S. dollars,
ARC systematically enters into foreign exchange agreements to offset this
exposure. In addition, ARC manages these foreign exchange positions by
converting the forwards to U.S. dollar put spreads whereby ARC achieves a
position that is a net asset.
Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

Gain or Loss on Risk Management Contracts

Gain or loss on risk management contracts comprise realized and
unrealized gains or losses on risk management contracts that do not meet the
accounting definition requirements of an effective hedge, even though the
Trust considers all risk management contracts to be effective economic hedges.
Accordingly, gains and losses on such contracts are shown as a separate
category in the statement of income.
The Trust recorded a realized cash gain on risk management contracts of
$0.3 million in the second quarter of 2007 compared to a gain of $11.3 million
recorded in for the same period of 2006. The Trust had a similar hedging
strategy in place for the first quarters of 2007 and 2006; however, 2007
market prices were comparable to the Trust's floor prices for natural gas
resulting in cash hedging losses being the premiums paid in the period. The
$2.2 million cash loss recorded for natural gas was offset by small gains on
the Trust's crude oil and foreign exchange contracts.
The unrealized gain of $10.8 million was due mostly to a weakening of
forward natural gas prices that have resulted in unrealized gains in natural
gas financial positions through the first quarter of 2008 and strengthening of
the Canadian dollar that has resulted in an increase in unrealized gains on
foreign exchange positions partly offset by strengthening crude oil prices
that have reduced the value of crude oil hedge positions.

<<
The following is a summary of the total gain (loss) on risk management
contracts for the second quarter and year to date of 2007:

-------------------------------------------------------------------------
Risk Management Interest &
Contracts Crude Oil Natural Foreign Q2 2007 Q2 2006
($ millions) & Liquids Gas Currency Total Total
-------------------------------------------------------------------------
Realized cash gain
(loss) on contracts(1) 0.8 (2.2) 1.7 0.3 11.3
Unrealized gain (loss)
on contracts(2) (8.6) 16.3 3.1 10.8 (14.2)
-------------------------------------------------------------------------
Total gain (loss) on
risk management
contracts (7.8) 14.1 4.8 11.1 (2.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Risk Management Interest &
Contracts Crude Oil Natural Foreign YTD 2007 YTD 2006
($ millions) & Liquids Gas Currency Total Total
-------------------------------------------------------------------------
Realized cash gain
(loss) on contracts(1) 5.7 1.6 - 7.3 9.9
Unrealized gain (loss)
on contracts(2) (15.3) - 5.2 (10.1) (9.1)
-------------------------------------------------------------------------
Total gain (loss) on
risk management
contracts (9.6) 1.6 5.2 (2.8) 0.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.

Operating Netbacks

The Trust's operating netback, after realized hedging gains, decreased by
eight per cent to $34.75 per boe in the second quarter of 2007 compared to
$37.90 per boe in the same period of 2006. The decrease in netbacks in 2007 is
primarily due to higher operating costs and lower realized hedging gains.
These amounts were partially offset by lower royalty costs.

The components of operating netbacks are shown below:

-------------------------------------------------------------------------
Crude Heavy Q2 2007 Q2 2006
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 66.09 47.50 7.38 52.76 54.37 54.42
Other revenue - - - - 0.11 0.12
-------------------------------------------------------------------------
Total revenue 66.09 47.50 7.38 52.76 54.48 54.54
Royalties (10.48) (4.11) (1.34) (14.43) (9.43) (9.78)
Transportation (0.34) (0.93) (0.19) - (0.72) (0.66)
Operating costs(1) (12.19) (15.47) (1.22) (7.76) (9.63) (8.20)
-------------------------------------------------------------------------
Netback prior to
hedging 43.08 26.99 4.63 30.57 34.70 35.90
Realized gain (loss)
on risk management
contracts 1.04 - (0.14) - 0.05 2.00
-------------------------------------------------------------------------
Netback after
hedging 44.12 26.99 4.49 30.57 34.75 37.90
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Crude Heavy YTD 2007 YTD 2006
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 63.86 45.09 7.57 50.39 53.77 54.58
Other revenue - - - - 0.11 0.12
-------------------------------------------------------------------------
Total revenue 63.86 45.09 7.57 50.39 53.88 54.70
Royalties (10.02) (3.84) (1.47) (13.50) (9.54) (10.25)
Transportation (0.41) (1.23) (0.20) - (0.77) (0.64)
Operating costs(1) (11.46) (13.18) (1.23) (7.73) (9.30) (8.00)
-------------------------------------------------------------------------
Netback prior to
hedging 41.97 26.84 4.67 29.16 34.27 35.81
Realized gain (loss)
on risk management
contracts 1.15 - 0.05 - 0.63 0.86
-------------------------------------------------------------------------
Netback after
hedging 43.12 26.84 4.72 29.16 34.91 36.67
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
>>

Royalties decreased to $9.43 per boe in the second quarter of 2007
compared to $9.78 per boe in the same period of 2006. Royalties as a
percentage of pre-hedged commodity revenue net of transportation costs
decreased to 17.5 per cent compared to 18 per cent in the second quarter of
2006. The decrease in royalty rates is consistent with the changes in the
Trust's production profile as new production brought on-stream impacts the
overall royalty rates.
Transportation costs increased nine per cent to $0.72 per boe in the
second quarter of 2007 compared to $0.66 per boe in the second quarter of
2006. The Trust has experienced challenges in Saskatchewan throughout the
second half of 2006 and the first half of 2007 due to shipping restrictions on
the Enbridge pipeline as it is operating at full capacity. During the first
quarter, the Trust had to truck approximately 900 boe per day of operated oil
production at a cost significantly greater than the cost to transport those
volumes by pipeline. While transportation costs came down in the second
quarter of 2007 as compared to the first quarter of 2007, as a result of a
reduction in trucked volumes, costs were still higher than the second quarter
of 2006. An expansion of the Enbridge pipeline is expected to be completed
sometime in late 2007 or early 2008.
Operating costs increased to $9.63 per boe compared to $8.20 per boe in
the second quarter of 2006. Total operating costs in the second quarter of
2007 increased by $7.9 million compared to the second quarter of 2006. This
increase is due to increased costs for workovers and maintenance ($3 million),
increased labour and LTIP costs ($0.9 million), increased lease rentals for
renewals ($1.5 million), increased property taxes ($1 million), and 13th month
adjustments booked in the quarter ($1.5 million).
In comparing the Trust's total second quarter 2007 operating costs to the
first quarter of 2007, operating costs have increased by $2 million. This
amount includes higher costs for workovers and maintenance ($3 million) net of
a reduction in processing fees recorded in the period ($1 million).

General and Administrative Expenses and Incentive Compensation

Cash G&A before incentive compensation and net of overhead recoveries on
operated properties was relatively unchanged at $8.9 million in the second
quarter of 2007 from $8.8 million in the same period of 2006. Increases in
cash G&A expenses for 2007 were due to additional staff and higher
compensation costs. On a per boe basis, second quarter cash G&A costs
increased two per cent to $1.59 per boe in 2007 from $1.56 per boe in 2006 as
a result of higher cash G&A costs and a slight decrease in production volumes.
During the second quarter the Trust made a payment under the Whole Unit
Plan that included the first payment for performance units issued under the
Plan in 2004. The cash payment made in April 2007 was $10.5 million of which
$8.3 million was recorded in G&A with the remainder $2.2 million being
recorded to operating costs and capital projects. These amounts were fully
accrued at the end of the first quarter of 2007, however, cash flow from
operating activities in the second quarter of 2007 has been decremented for
the full amount of the cash payment.

<<
The following is a breakdown of G&A and Incentive compensation expense:

-------------------------------------------------------------------------
G&A and Incentive Three Months Ended Six Months Ended
Compensation Expense June 30 June 30
% %
($ thousands) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
G&A expenses 12.7 11.4 11 26.2 21.7 21
Operating recoveries (3.8) (2.6) 46 (8.5) (5.2) 63
-------------------------------------------------------------------------
Cash G&A expenses before
Whole Unit Plan 8.9 8.8 1 17.7 16.5 7
-------------------------------------------------------------------------
Cash expense -
Whole Unit Plan 8.3 2.7 207 8.3 2.7 207
-------------------------------------------------------------------------
Cash G&A expenses
including Whole
Unit Plan 17.2 11.5 50 26.0 19.2 35
-------------------------------------------------------------------------
Accrued compensation -
Rights Plan - 0.8 - 2.5
Accrued compensation -
Whole Unit Plan (4.3) 1.2 458 (4.0) 5.0 180
-------------------------------------------------------------------------
Total G&A and trust
unit compensation
expense 12.9 13.5 (4) 22.0 26.7 (18)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
G&A and Incentive Three Months Ended Six Months Ended
Compensation Expense June 30 June 30
% %
($ per boe) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Cash G&A expenses before
Whole Unit Plan 1.59 1.56 2 1.55 1.45 7
Cash G&A expenses
including Whole
Unit Plan 3.07 2.05 50 2.28 1.68 36
Total G&A and trust
unit compensation
expense 2.29 2.39 (4) 1.93 2.33 (17)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

A non-cash incentive compensation expense ("non-cash compensation
expense") of $(4.3) million was recorded in the second quarter of 2007 which
represents the estimated costs of the Whole Unit Plan for the period net of
the accrual reversal for the cash amount paid in April 2007.

Rights Plan

The Rights Plan that provides employees, officers and independent
directors the right to purchase trust units at a specified price is being
discontinued. All rights were fully vested and expensed as of March 31, 2007.
At June 30, 2007, 0.2 million rights were outstanding at an average exercise
price of $8.95 per unit.

Whole Unit Incentive Plan ("Whole Unit Plan")

Please refer to our MD&A for the year ended December 31, 2006 for a
detailed description of the Whole Unit Plan that was put in place in 2004 as a
replacement to the Rights Plan. From an accounting perspective, the full cost
of the Whole Unit Plan is reflected in the cash G&A expenses while the cost of
the Rights Plan was represented as a non-cash charge against earnings.

<<
The following table shows the changes during the quarter of RTUs and PTUs
outstanding:

-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and Number of Number of Total
$ millions except per unit) RTUs PTUs RTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 648 683 1,331
Granted in the period 204 164 368
Vested in the period (191) (111) (302)
Forfeited in the period (25) (25) (50)
-------------------------------------------------------------------------
Balance, end of period(1) 636 711 1,347
-------------------------------------------------------------------------
Estimated distributions to
vesting date(2) 171 175 346
-------------------------------------------------------------------------
Estimated units upon vesting
after distributions 807 886 1,693
Performance multiplier(3) - 1.6 -
-------------------------------------------------------------------------
Estimated total units upon
vesting 807 1,388 2,195
Trust unit price at
June 30, 2007 $21.74 $21.74 $21.74
Estimated total value upon
vesting $17.5 $30.2 $47.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on underlying units before performance multiplier and accrued
distributions.
(2) Represents estimated additional units to be issued equivalent to
estimated distributions accruing to vesting date.
(3) The performance multiplier only applies to PTUs and was estimated to
be 1.6 at June 30, 2007 based on a weighted average calculation of
all outstanding grants. The performance multiplier is assessed at
each period end based on management's best estimate of the
performance multiplier at the time of vesting.

The value associated with the RTUs and PTUs is expensed in the statement
of income over the vesting period with the expense amount being determined by
the trust unit price, the number of PTUs to be issued on vesting, and
distributions. Therefore, the expense recorded in the statement of income
fluctuates over time.

Below is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier:

-------------------------------------------------------------------------
Value of Whole Unit Plan
as at June 30, 2007 Performance Multiplier
(units thousands and ---------------------------------------
$ millions except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 807 807 807
PTUs - 886 1,771
-------------------------------------------------------------------------
Total units(1) 807 1,693 2,578
-------------------------------------------------------------------------
Trust unit price(2) 21.74 21.74 21.74
Trust unit distributions
per month(2) 0.20 0.20 0.20
-------------------------------------------------------------------------
Value of Whole Unit Plan
upon vesting 17.5 38.6 59.6
-------------------------------------------------------------------------
Officers 2.0 12.1 22.2
Directors 1.4 1.4 1.4
Staff 14.1 25.1 36.0
-------------------------------------------------------------------------
Total Payments Under Whole
Unit Plan(3) 17.5 38.6 59.6
-------------------------------------------------------------------------
2007 2.4 2.4 2.4
2008 7.8 15.4 23.1
2009 5.3 13.8 22.2
2010 2.0 7.0 11.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes an estimate of additional units to be issued for accrued
distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumed
future trust unit price of $21.74 per trust unit and distributions of
$0.20 per trust unit per month based on current levels.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in April
and October of each year and at that time is reflected as a reduction
of cash flow from operating activities.
>>

Due to the variability in the future payments under the plan, the Trust
estimates that payments could range from $17.5 million to $59.6 million from
2007 through 2010 based on the current trust unit price, distribution levels
and a performance multiplier ranging from zero to two.

Interest Expense

Interest expense increased to $9.3 million in the second quarter of 2007
from $7.6 million in the second quarter of 2006 due to an increase in
short-term interest rates, and higher debt balances. Interest expense for the
first six months of 2007 was $19.2 million, an increase of $4 million from
$15.2 million in the first six months of 2006.
The Trust's debt balance as reflected in Canadian dollars has decreased
significantly since December 31, 2006. This is a result of the nine per cent
appreciation in the Canadian dollar as compared to the U.S. dollar. The Trust
had US$420 million in outstanding debt at December 31 of which US$380 million
was still outstanding at June 30, 2007. The Canadian dollar equivalent of the
US$380 million debt balance has decreased by $38.7 million as a result of the
appreciation of the Canadian dollar against the U.S. dollar from December 31,
2006 to June 30, 2007.
Once the foreign exchange impact is taken into consideration, the Trust's
debt balance has remained relatively unchanged from year-end as a result of
funding 100 per cent of the year to date capital program with Cash Flow and
proceeds from the Distribution Reinvestment Program ("DRIP"). See "Non-GAAP
Measures" section.
As at June 30, 2007, the Trust had $644.8 million of debt outstanding, of
which $238.3 million was fixed at a weighted average rate of 5.06 per cent and
$406.5 million was floating at current market rates plus a credit spread of 60
basis points. 63 per cent of the Trust's debt is denominated in U.S. dollars.

Foreign Exchange Gains and Losses

The Trust recorded a gain of $35.5 million on foreign exchange
transactions compared to a gain of $22.8 million for the second quarter of
2006. These amounts include both realized and unrealized foreign exchange
gains and losses. Unrealized foreign exchange gains and losses are due to
revaluation of U.S. denominated debt balances. The volatility of the Canadian
dollar during the reporting period has a direct impact on the unrealized
component of the foreign exchange gain or loss. During the second quarter of
2007, the Canadian dollar reached a 30 year high when compared to the U.S.
dollar. The dollar closed the quarter at $1.06 per U.S. dollar.
The unrealized gain/loss impacts net income but does not impact Cash Flow
as it is a non-cash amount. Realized foreign exchange gains or losses arise
from U.S. denominated transactions such as interest payments, debt repayments
and hedging settlements.
Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

Taxes

In the second quarter of 2007, a future income tax recovery of
$46.4 million was included in income compared to a $70.9 million recovery in
the second quarter of 2006. The second quarter 2006 recovery resulted from the
future tax reductions recorded in the 2006 Federal budget that reduced the
Trust's expected future income tax rate to 29.7 percent from the previous rate
of 33.7 per cent. The corporate income tax rate applicable to 2007 is 32.1 per
cent as compared to the expected future tax rate of 28.9 per cent.
ARC does not anticipate any material cash income taxes will be paid for
fiscal 2007. Due to the Trust's structure, currently, both income tax and
future tax liabilities are passed on to the unitholders by means of royalty
and interest payments made by ARC Resources to the Trust.
The Trust is currently assessing various alternatives with respect to the
potential implications of the proposed Trust taxation, therefore the Trust has
not arrived at a final conclusion with respect to future organizational
structure and implications to the Trust. As a result of the enactment of bill
C-52, the Trust has recorded a reduction in future income taxes of
$35.6 million related to ARC Energy Trust, as tax pools were in excess of the
net book value of the assets. The initial recognition of $35.6 million
comprises $24.7 million for pre-2007 generated temporary differences and
$10.9 million for temporary differences relating to the current year.
Capital taxes were eliminated effective January 1, 2006 pursuant to the
Federal Government budget of May 2, 2006.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate increased to
$16.31 per boe in the second quarter of 2007 from $15.43 per boe in the second
quarter of 2006. Year-to-date, the DD&A rate has increased six percent to
$16.33 per boe as compared to $15.38 in 2006. The higher DD&A rate is driven
by an increase in the property, plant and equipment ("PP&E") value on the
Trust's balance sheet along with an increase in the future development costs
and a slight decrease in proved reserves recorded in the Trust's January 1,
2007 reserve report.

<<
A breakdown of the DD&A rate is as follows:

-------------------------------------------------------------------------
DD&A Expense Three Months Ended Six Months Ended
June 30 June 30
($ millions except % %
per boe amounts) 2007 2006 Change 2007 2006 Change
-------------------------------------------------------------------------
Depletion of oil &
gas assets(1) 88.5 84.2 5 180.1 170.7 6
Accretion of asset
retirement
obligation(2) 2.9 2.6 12 5.8 5.2 12
-------------------------------------------------------------------------
Total DD&A 91.4 86.8 5 185.9 175.9 6
-------------------------------------------------------------------------
DD&A expense per boe 16.31 15.43 6 16.33 15.38 6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the PP&E balance and is being
depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.

Capital Expenditures and Acquisitions

Total capital expenditures, excluding acquisitions and dispositions,
totaled $48.5 million in the second quarter of 2007 compared to $58.6 million
in the second quarter of 2006. This amount was incurred on drilling and
completions, geological, geophysical and facilities expenditures, and the
purchase of undeveloped acreage. The Trust also spent $14.6 million on minor
property acquisitions in the second quarter of 2007 as compared to
$5.2 million for the same period in 2006.

A breakdown of capital expenditures and net acquisitions is shown below:

-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
Capital Expenditures ($ millions) 2007 2006 2007 2006
-------------------------------------------------------------------------
Geological and geophysical 4.1 2.8 9.0 5.5
Land 1.7 14.3 1.9 19.2
Drilling and completions 25.8 29.8 80.9 85.1
Plant and facilities 16.3 10.9 33.1 26.5
Other capital 0.6 0.8 1.1 1.4
-------------------------------------------------------------------------
Total capital expenditures 48.5 58.6 126.0 137.7
-------------------------------------------------------------------------
Producing property acquisitions(1) 14.6 5.2 14.8 39.0
Producing property dispositions(1) (4.6) (2.4) (4.6) (8.6)
-------------------------------------------------------------------------
Total capital expenditures and
net acquisitions 58.5 61.4 136.2 168.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.

Approximately 86 per cent of the $48.5 million capital program was
financed with Cash Flow in the second quarter of 2007 compared to 100 per cent
in the same period of 2006. The remainder of the program was financed through
proceeds from the 2007 distribution reinvestment program and employee rights
plan. See "Non-GAAP Measures" section.

-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30, 2007 June 30, 2006
-------------------------------------------------------------------------
Devel- Net Total Devel- Net Total
opment Acquis- Expend- opment Acquis- Expend-
Capital itions itures Capital itions itures
-------------------------------------------------------------------------
Expenditures 48.5 10.0 58.5 58.6 2.8 61.4
-------------------------------------------------------------------------
Per cent funded by:
Cash Flow(1) 86% - 71% 100% 100% 100%
Proceeds from DRIP
and Rights Plan 14% 100% 29% - - -
Debt - - - - - -
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Six Months Ended Six Months Ended
June 30, 2007 June 30, 2006
-------------------------------------------------------------------------
Devel- Net Total Devel- Net Total
opment Acquis- Expend- opment Acquis- Expend-
Capital itions itures Capital itions itures
-------------------------------------------------------------------------
Expenditures 126.0 10.2 136.2 137.7 30.4 168.1
-------------------------------------------------------------------------
Per cent funded by:
Cash Flow(1) 79% - 73% 100% 4% 83%
Proceeds from DRIP
and Rights Plan 21% 100% 27% - 96% 17%
Debt - - - - - -
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) See Non-GAAP Measures Section
>>

Long-Term Investment

During the second quarter, the Trust sold its investment in the shares of
a private company that was involved in the acquisition of oil sands leases.
The transaction closed on June 25, 2007. The Trust recorded a cash gain of
$13.3 million with total proceeds of $33.3 million recorded as part of cash
flow from investing activities.

Asset Retirement Obligation and Reclamation Fund

At June 30, 2007, the Trust has recorded an Asset Retirement Obligation
("ARO") of $168.8 million as compared to $177.3 million at December 31, 2006
for future abandonment and reclamation of the Trust's properties. The ARO
balance has been reduced by $11.9 million for reclamation spending in the
first half of 2007 ($7.2 million for the second quarter of 2007). This amount
has been offset by accretion of $5.8 million ($2.9 million for the second
quarter of 2007). In addition, a net decrease to the liability of $2.4 million
was recorded relating to a change in estimate net of development activities in
the period. The Trust did not record a gain or loss on actual abandonment
expenditures incurred as the costs closely approximated the liability value
included in the ARO.
Reclamation spending in the second quarter of 2007 was 25 per cent funded
by the reclamation fund. The remaining 75 per cent ($5.4 million) was funded
temporarily through working capital. On a year-to-date basis, reclamation
spending has been 43 per cent funded through the reclamation fund and the
remaining 57 per cent has been funded temporarily through working capital. On
an annual basis, the Trust will adjust the balance of the reclamation fund for
the full amount of reclamation spending in the period.

<<
Capitalization, Financial Resources and Liquidity

A breakdown of the Trust's capital structure is as follows as at June 30,
2007 and December 31, 2006:

-------------------------------------------------------------------------
Capital Structure and Liquidity June 30, December 31,
($ millions except per unit and per cent amounts) 2007 2006
-------------------------------------------------------------------------
Revolving credit facilities 406.5 426.1
Senior secured notes 238.3 261.0
Working capital deficit excluding
short-term debt(1) 9.1 52.0
-------------------------------------------------------------------------
Net debt obligations 653.9 739.1

Trust units outstanding and issuable for
exchangeable shares (millions) 210.2 207.2
Market price per unit at end of period 21.74 22.30
Market value of trust units and exchangeable
shares at end of period 4,569.7 4,620.0
Total capitalization(2) 5,223.6 5,359.1
-------------------------------------------------------------------------
Net debt as a percentage of total
capitalization 12.5% 13.8%
Net debt obligations 653.9 739.1
Cash Flow(3) 351.4 760.6
Net debt to annualized Cash Flow 0.9 1.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The working capital deficit excludes the balances for risk management
contracts.
(2) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by the Trust.
(3) See "Non-GAAP Measures" Section
>>

Net debt levels at June 30, 2007 have decreased since December 31, 2006
as a result of funding 100 per cent of the 2007 year to date quarter capital
program with Cash Flow and proceeds of the DRIP program. Lastly, the Trust's
net balance has decreased significantly as a result of the appreciation in the
Canadian dollar, which generated an unrealized gain of $40.5 million for the
six months ended June 30, 2007. As at June 30, 2007, the Trust had $380
million in U.S. denominated debt.
The Trust has a syndicated three year revolving credit facility allowing
for maximum borrowing of up to $800 million. This was increased from
$572 million at year-end 2006. The debt is secured by all the Trust's oil and
gas properties and is subject to the same major covenants as the prior credit
facility described in the MD&A as at December 31, 2006.
In addition to the $800 million credit facility, the Trust has issued
senior secured notes that do not reduce the available borrowings under the
credit facility. As at June 30, 2007, the Trust had $394.3 million of
available borrowings under the current credit facility.
The Trust intends to finance its $350 million 2007 capital program with
Cash Flow and the proceeds of the distribution reinvestment program with any
remainder being financed with debt.

Unitholders' Equity

At June 30, 2007, there were 210.2 million units issued and issuable for
exchangeable shares, an increase from 207.2 million units from December 31,
2006. The increase in number of units outstanding is mainly attributable to
the 2.8 million units issued pursuant to the DRIP during 2007 at an average
price of $20.43 per unit.
The Trust had 0.2 million rights outstanding as of June 30, 2007 under an
employee plan where further rights issuances were discontinued in 2004. The
remaining rights may be exercised at an average adjusted exercise price of
$8.95 per unit as at June 30, 2007. All of the rights were fully vested at
March 31, 2007. The contractual life of the rights varies by series but all
will expire on or before March 22, 2009.
The Whole Unit Plan introduced in 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any trust
units being issued from treasury. The Trust has made provisions whereby
employees may elect to have trust units purchased for them at prevailing
prices on the market with the cash received upon vesting.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so at a
five per cent discount to the prevailing market price with no additional fees
or commissions. During the second quarter of 2007, the Trust raised proceeds
of $29.1 million and issued 1.4 million trust units pursuant to the DRIP.

Distributions

ARC declared distributions of $124.1 million ($0.60 per unit),
representing 74 per cent of second quarter 2007 Cash Flow compared to
distributions of $120.6 million ($0.60 per unit), representing 62 per cent of
Cash Flow in the second quarter of 2006. The remaining 26 per cent of second
quarter 2007 Cash Flow ($43.5 million) was used to fund 86 per cent of ARC's
2007 year to date capital expenditures and make contributions, including
interest, to the reclamation funds ($1.8 million).
Monthly distributions for the second quarter of 2007 were $0.20 per unit.
Revisions, if any, to the monthly distribution are normally announced on a
quarterly basis in the context of prevailing and anticipated commodity prices
at that time.
The items that may be deducted from Cash Flow to arrive at distributions
to unitholders and the methodology used to determine distributions is detailed
in the Trust's December 31, 2006 MD&A.

<<
Cash Flow and distributions in total and per unit were as follows:

-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30 June 30
% %
Cash Flow and 2007 2006 Change 2007 2006 Change
Distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash Flow 167.6 194.7 (14) 0.80 0.96 (17)
Reclamation fund
contributions(1) (1.8) (4.7) (62) (0.01) (0.02) (50)
Capital expenditures
funded with
Cash Flow (41.7) (68.1) (39) (0.20) (0.33) (39)
Discretionary debt
repayments - (1.3) - - - -
Other(2) - - - 0.01 (0.01) 200
-------------------------------------------------------------------------
Distributions 124.1 120.6 3 0.60 0.60 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Six Months Ended Six Months Ended
June 30 June 30
% %
Cash Flow and 2007 2006 Change 2007 2006 Change
Distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash Flow 351.4 385.9 (9) 1.68 1.90 (12)
Reclamation fund
contributions(1) (5.1) (6.4) (20) (0.02) (0.03) (33)
Capital expenditures
funded with
Cash Flow (99.1) (137.7) (28) (0.47) (0.68) (31)
Discretionary debt
repayments - (1.3) - - - -
Other(2) - - - 0.01 0.01 -
-------------------------------------------------------------------------
Distributions 247.2 240.5 3 1.20 1.20 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit Cash Flow, reclamation fund contributions and capital
expenditures funded with Cash Flow are based on weighted average
outstanding trust units in the year plus trust units issuable for
exchangeable shares at year end.

Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

2007 Monthly Distributions

Actual distributions paid and payable in 2007 along with relevant payment
dates are as follows:

-------------------------------------------------------------------------
Ex-distribution Distribution Total
Date Record Date Payment Date Distribution
-------------------------------------------------------------------------
January 29, 2007 January 31, 2007 February 15, 2007 0.20
February 26, 2007 February 28, 2007 March 15, 2007 0.20
March 28, 2007 March 31, 2007 April 16, 2007 0.20
April 26, 2007 April 30, 2007 May 15, 2007 0.20
May 29, 2007 May 31, 2007 June 15, 2007 0.20
June 27, 2007 June 30, 2007 July 16, 2007 0.20
July 27, 2007 July 31, 2007 August 15, 2007 0.20
August 29, 2007 August 31, 2007 September 17, 2007 0.20(*)
September 26, 2007 September 30, 2007 October 15, 2007 0.20(*)
October 29, 2007 October 31, 2007 November 15, 2007
November 28, 2007 November 30, 2007 December 17, 2007
December 27, 2007 December 31, 2007 January 15, 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(*) Estimated

Please refer to the Trust's website at www.arcenergytrust.com for details
on distributions dates for 2007.

Taxation of Distributions

Distributions comprise a return of capital portion (tax deferred) and a
return on capital portion (taxable). The return of capital component reduces
the cost basis of the trust units held. For 2007, it is estimated that
distributions paid in the calendar year will be in the range of 95 to 100 per
cent return on capital (taxable) and zero to five per cent return of capital
(tax deferred). For a more detailed breakdown, please visit our website at
www.arcenergytrust.com.

Contractual Obligations and Commitments

The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments, sales commitments, royalty obligations, and lease
rental obligations. These obligations are of a recurring and consistent nature
and impact Cash Flow in an ongoing manner. The Trust also has contractual
obligations and commitments that are of a less routine nature as disclosed in
the following table.

Following is a summary of the Trust's contractual obligations and
commitments as at June 30, 2007:

-------------------------------------------------------------------------
Payments Due By Period
-------------------------------------------------------------------------
2008- 2010- There-
($ millions) 2007 2009 2011 after Total
-------------------------------------------------------------------------
Debt repayments(1) 7.3 23.8 454.2 159.5 644.8
Interest payments(2) 6.0 22.9 19.3 22.1 70.3
Reclamation fund contributions(3) 6.0 11.1 9.5 76.2 102.8
Purchase commitments 8.6 8.2 3.1 6.3 26.2
Operating leases 2.6 9.0 4.5 - 16.1
Derivative contract premiums(4) 19.8 8.1 - - 27.9
Retention bonuses 1.0 - - - 1.0
-------------------------------------------------------------------------
Total contractual obligations 51.3 83.1 490.6 264.1 889.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
>>

The above noted debt repayments include the revolving credit facility.
The lenders review the credit facility each year and determine whether they
will extend the revolving periods for another year. In the event that the
credit facility is not extended at any time before the maturity date, the loan
balance will become payable on the maturity date which is April 15, 2010.
The above noted derivative contract premiums are part of the Trust's
commitments related to its risk management program. In addition to the above
premiums, the Trust has other commitments related to its risk management
program. As the premiums are part of the underlying derivative contract, they
have been recorded at fair market value at June 30, 2007 on the balance sheet
as part of risk management contracts.
The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At any given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2007 capital budget has
been approved by the Board at $360 million and subsequently revised downward
to $350 million due to anticipated cost savings. This commitment has not been
disclosed in the commitment table as it is of a routine nature and is part of
normal course of operations for active oil and gas companies and trusts.
The above noted operating leases include amounts for the Trust's head
office lease. The current lease expires in May 2010. The Trust expects to
commit to a new lease within the next 12 months that will then be reflected in
the commitments table.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the following table does not include any
commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table as
it is of a routine nature and is part of normal course of operations.

Off Balance Sheet Arrangements

The Trust has certain lease agreements, all of which are reflected in the
Contractual Obligations and Commitments table above, which were entered into
in the normal course of operations. All leases have been treated as operating
leases whereby the lease payments are included in operating expenses or G&A
expenses depending on the nature of the lease. No asset or liability value has
been assigned to these leases in the balance sheet as of June 30, 2007.

Critical Accounting Estimates

The Trust has continuously evolved and documented its management and
internal reporting systems to provide assurance that accurate, timely internal
and external information is gathered and disseminated.
The Trust's financial and operating results incorporate certain estimates
including:

<<
- estimated revenues, royalties and operating costs on production as at
a specific reporting date but for which actual revenues and costs
have not yet been received;
- estimated capital expenditures on projects that are in progress;
- estimated depletion, depreciation and accretion that are based on
estimates of oil and gas reserves that the Trust expects to recover
in the future;
- estimated fair values of derivative contracts that are subject to
fluctuation depending upon the underlying commodity prices and
foreign exchange rates;
- estimated value of asset retirement obligations that are dependent
upon estimates of future costs and timing of expenditures; and
- estimated future recoverable value of property, plant and equipment
and goodwill.
>>

The Trust has hired individuals and consultants who have the skills
required to make such estimates and ensures that individuals or departments
with the most knowledge of the activity are responsible for the estimates.
Further, past estimates are reviewed and compared to actual results, and
actual results are compared to budgets in order to make more informed
decisions on future estimates.
The ARC leadership team's mandate includes ongoing development of
procedures, standards and systems to allow ARC staff to make the best
decisions possible and ensuring those decisions are in compliance with the
Trust's environmental, health and safety policies.

Internal Controls Update

ARC is required to comply with Multilateral Instrument 52-109
"Certification of Disclosure in Issuers' Annual and Interim Filings",
otherwise referred to as Canadian SOX ("C-Sox"). The 2007 certificate requires
that the Trust disclose in the interim MD&A any changes in the Trust's
internal control over financial reporting that occurred during the period that
has materially affected, or is reasonably likely to materially affect the
Trust's internal control over financial reporting. The Trust confirms that no
such changes were made to the internal controls over financial reporting
during the first six months of 2007.

Financial Reporting Update

During 2007, the Trust completed the implementation of the new CICA
Handbook Section 3855, Financial Instruments - Recognition and Measurement,
Section 1530, Comprehensive Income, and Section 3865, Hedges that deal with
the recognition and measurement of financial instruments at fair value and
comprehensive income. See notes 2 and 9 in the Notes to the Unaudited
Consolidated Financial Statements for further details.
During the second quarter of 2006, presentation changes were made to
combine the previously reported accumulated earnings and accumulated cash
distribution figures on the balance sheet into a single deficit balance.
Numbers presented for comparative purposes have been restated to reflect this
change in presentation.

Accounting Changes

Section 1506 permits voluntary changes in accounting policy only if they
result in financial statements that provide more reliable and relevant
information. Changes in policy are applied retrospectively unless it is
impractical to determine the period or cumulative impact of the change.
Corrections of prior period errors are applied retrospectively and changes in
accounting estimates are applied prospectively by including these changes in
net income. In addition, disclosure is required for all future accounting
changes when an entity has not applied a new source of GAAP that has been
issued but is not yet effective.

Future Accounting Changes

On December 1, 2006, the CICA issued three new accounting standards:
Handbook Section 1535, Capital Disclosures, Section 3862, Financial
instruments - Disclosures, and Section 3863, Financial instruments -
Presentation. These new standards will be effective on January 1, 2008.
Section 1535 specifies the disclosure of an entity's objectives, policies
and processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such
non-compliance. This Section is expected to have minimal impact on the Trust's
financial statements.
Sections 3862 and 3863 specify a revised and enhanced disclosure on
financial instruments. Increased disclosure will be required on the nature and
extent of risks arising from financial instruments and how the entity manages
those risks.

Objectives and 2007 Outlook

Sustainability

The Trust believes that maintenance of production and reserves per unit
on an ongoing basis are two key factors to assess the sustainability of an oil
and gas royalty trust. On a quarterly basis, the Trust reviews changes in our
production per unit measures while reserves per unit is analyzed on an annual
basis. The Trust acquires, develops and optimizes oil and natural gas
properties in predominantly mature areas to generate a Cash Flow stream. Due
to the risks inherent in the oil and gas business, including particularly the
volatility of commodity prices, there can be no assurance that with the
present or even increased levels of capital expenditures, the Trust will be
successful in achieving sustainability.
Due to natural production declines, the Trust must continually develop
its reserves and/or acquire new reserves in an effort to maintain reserves,
production and Cash Flow levels on which distributions are paid. The Trust
facilitates this by utilizing a portion of Cash Flow to fund a portion of
ongoing capital development activities and maintaining moderate debt levels.
Oil and gas royalty trusts hold assets that are depleting and unitholders
should expect production, revenue, Cash Flow and distributions to decline over
the long-term if reserves cannot be economically replaced. The Trust has an
inventory of internal development prospects that ARC believes will maintain
production at approximately current levels for a minimum period of two years.
The Trust anticipates employing a conservative distribution policy to provide
for cash funding of a portion of ongoing capital development programs and
maintaining low debt levels to facilitate further growth. The Trust measures
its sustainability and success in terms of per unit distributions, production,
reserves, and Cash Flow in addition to the ability to maintain low debt levels
and the annual replacement of reserves.

<<
Following is a summary of the historical quarterly production per unit,
Cash Flow and distributions as a per cent of Cash Flow:

-------------------------------------------------------------------------
Q2 Q1 Q4 Q3 Q2 Trailing 5
Per Trust Unit Ratios 2007 2007 2006 2006 2006 Quarters
-------------------------------------------------------------------------
Production per unit(1):
Unadjusted 0.29 0.31 0.31 0.30 0.30 -
Debt-adjusted(2) 0.26 0.27 0.27 0.28 0.27 -
Normalized(3) 0.303 0.31 0.31 0.32 0.326 -
-------------------------------------------------------------------------
Cash Flow per unit 0.80 0.88 0.85 0.98 0.96 -
Distributions per unit 0.60 0.60 0.60 0.60 0.60 3.00
Distributions as a per
cent of Cash Flow 74 67 70 61 62 66
Per cent of Cash Flow
retained 26 33 30 39 38 34
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents daily average boe of production per thousand units.
Calculated based on annual daily average production divided by
weighted average trust units outstanding including trust units
issuable for exchangeable shares.
(2) Debt-adjusted indicates that all years as presented have been
adjusted to reflect a nil net debt to capitalization. It is assumed
that additional trust units were issued at a period end price for the
reserves per unit calculation and at an annual average price for the
production per unit calculation in order to reduce the net debt
balance to zero in each year. The debt-adjusted amounts are presented
to enable comparability of annual per unit values.
(3) Normalized indicates that all years as presented have been adjusted
to reflect a net debt to capitalization of 15 per cent. It is assumed
that additional units were issued (or repurchased) at a quarterly
average price for the production per unit calculation in order to
reduce the net debt balance to 15 per cent of total capitalization
each quarter. The normalized amounts are presented to enable
comparability of annual per unit values.
>>

Please refer to the Trust's 2006 year end MD&A for a summary of the
annual historical debt-adjusted and normalized reserves per unit and reserve
life index on which the Trust assesses performance and sustainability.
Since the second quarter of 2006, the Trust's normalized production per
unit has decreased modestly from 0.326 to 0.303 boe of daily average
production per thousand trust units. The second quarter of 2007 production per
unit of 0.303 was negatively impacted by maintenance activities and shut-in
production. Production per unit of 0.303 was achieved and the Trust paid
$611.5 million in distributions ($3.00 per trust unit and 66 per cent of Cash
Flow) over a five quarter time period. The normalized production per unit is a
key measure as it indicates the ability to generate Cash Flow from core
operations, which in turn impacts the level of cash that may be distributed to
unitholders. The Trust expects to replace production during the rest of 2007
from internal development opportunities.
To compare the Trust's results with oil and gas companies that retain all
of their Cash Flow to grow production and reserves, the Trust looks at
normalized and distribution-adjusted production per unit that calculates the
total production per initial investment with the assumption that distributions
are reinvested through the DRIP plan. Consequently, the production per initial
investment increases over time as the investor's number of trust units
increases with distribution reinvestment. Unitholders can replicate this by
participating in the DRIP so that the number of trust units they own increases
over time.
The Trust's distribution policy centres on the goal of providing a
consistent and sustainable level of distributions to unitholders and to
provide for future growth. The distributions as a per cent of Cash Flow is
indicative of the Trust's commitment to fund a portion of ongoing development
activities with Cash Flow to enable long-term sustainability. On an annual
basis, the Trust's distributions as a per cent of Cash Flow has declined over
time as the Trust has addressed the issue of long-term sustainability while
setting distribution levels. This has allowed the Trust to maintain stable
distributions during the last five quarters.
Another possible measure of sustainability is the comparison of net
income to distributions. Net income is an accounting measure that incorporates
all costs including depletion expense and other non-cash expenses whereas Cash
Flow measures the cash generated in a given period before the cost of the
associated reserves. As net income is sensitive to fluctuations in commodity
prices, it is expected that there will be deviations between annual net income
and distributions. The following table illustrates the annual excess or
shortfall of distributions to net income.

<<
-------------------------------------------------------------------------
Net Income and
Distributions
($ millions except Q2 Q1 Q4 Q3 Q2 Trailing 5
per cent) 2007 2007 2006 2006 2006 Quarters
-------------------------------------------------------------------------
Net income 184.9 83.3 56.6 116.9 182.5 624.2
Distributions 124.1 123.1 122.3 121.4 120.6 611.5
-------------------------------------------------------------------------
Excess (shortfall) 60.8 (39.8) (65.7) (4.5) 61.9 12.7
Excess (shortfall)
as per cent of net income 33 (48) (116) (4) 34 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

2007 Guidance

Following is a summary of the Trust's 2007 Guidance issued by way of news
release on November 2, 2006, revised 2007 guidance and actual results for the
second quarter of 2007:

-------------------------------------------------------------------------
2007 Revised 2007 Previous Actual to
Guidance Guidance June 30, 2007
-------------------------------------------------------------------------
Production (boe/d) 63,000 63,000 62,899
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 9.25 8.95 9.30
Transportation 0.70 0.70 0.77
G&A expenses - cash(1) 2.15 2.25 2.28
G&A expenses - stock
compensation plans(1) 0.10 0.20 (0.35)
Interest(1) 1.70 1.50 1.69
Taxes 0.00 0.00 0.00
Annual capital expenditures
($ millions) 350 360 126.0
Weighted average trust units
and trust units issuable
(millions)(1) 210 208 209
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Guidance for the noted items were revised in the first quarter of
2007. See the Trust's first quarter 2007 MD&A for further details.

Variances in the 2007 actual results as compared to guidance are as
follows:

- With operating costs higher than guidance for the six months ended
June 30, 2007 we have revised guidance to $9.25 per boe for the full
year 2007. The Trust is continually pursuing cost control
initiatives in order to address ongoing pressures in the service
industry.

- Transportation costs were higher than guidance due to an increase in
oil volumes being trucked in Saskatchewan in response to the Enbridge
pipeline restrictions. Annual costs are still expected to be in line
with our guidance of $0.70 per boe.

- Cash G&A expenses were higher than guidance due to the fact that the
Trust paid its April LTIP payment in the second quarter. The cash
expense is offset by a reversal of the non-cash expense in the
quarter. The Trust expects cash G&A to be in-line with guidance for
the full year of 2007.

- The Trust is revising its 2007 guidance for annual capital
expenditures to $350 million as a result of cost savings anticipated
in drilling costs due to a general slow down of Canadian drilling
activity.

- See the "Objectives and 2007 Outlook" section in the Trust's annual
2006 MD&A for additional discussion on the Trust's key objectives.
>>

Assessment of Business Risks

The ARC management team is focused on long-term strategic planning and
has identified the key risks, uncertainties and opportunities associated with
the Trust's business that can impact the financial results. See "Assessment of
Business Risks" in the Trust's 2006 Annual Report MD&A for a detailed
assessment.

Forward-Looking Statement

This discussion and analysis contains forward-looking statements as to
the Trusts internal projections, expectations or beliefs relating to future
events or future performance within the meaning of the "safe harbour"
provisions of the United States Private Securities Litigation Reform Act of
1995 and the Securities Act (Ontario). In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions. These
statements represent management's expectations or beliefs concerning, among
other things, future operating results and various components thereof or the
economic performance of ARC Energy Trust ("ARC" or "the Trust"). The
projections, estimates and beliefs contained in such forward-looking
statements are based on management's assumptions relating to the production
performance of ARC's oil and gas assets, the cost and competition for services
throughout the oil and gas industry in 2007 and the continuation of the
current regulatory and tax regime in Canada, and necessarily involve known and
unknown risks and uncertainties, including the business risks discussed in
this MD&A, which may cause actual performance and financial results in future
periods to differ materially from any projections of future performance or
results expressed or implied by such forward-looking statements. Accordingly,
readers are cautioned that events or circumstances could cause results to
differ materially from those predicted. The Trust does not undertake to update
any forward looking information in this document whether as to new
information, future events or otherwise.

Additional Information

Additional information relating to ARC can be found on SEDAR at
www.sedar.com.

<<
-------------------------------------------------------------------------
QUARTERLY HISTORICAL REVIEW
(CDN $ millions, except per
Unit amounts) 2007 2006
-------------------------------------------------------------------------
FINANCIAL Q2 Q1 Q4 Q3
Revenue before royalties 305.6 307.8 292.5 312.3
Per unit(1) 1.46 1.48 1.42 1.52
Cash Flow(2) 167.6 183.8 174.4 200.3
Per unit - basic(1) 0.80 0.88 0.85 0.98
Per unit - diluted 0.80 0.88 0.84 0.97
Net income 184.9 83.3 56.6 116.9
Per unit - basic(3) 0.90 0.41 0.28 0.58
Per unit - diluted 0.89 0.41 0.28 0.58
Distributions 124.1 123.1 122.3 121.4
Per unit(4) 0.60 0.60 0.60 0.60
Total assets 3,432.8 3,450.1 3,479.0 3,335.8
Total liabilities 1,415.3 1,526.6 1,550.6 1,371.3
Net debt outstanding(5) 653.9 729.7 739.1 579.7
Weighted average units(6) 209.5 207.9 206.5 205.1
Units outstanding and issuable(6) 210.2 208.7 207.2 205.7
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 4.1 4.9 3.7 2.2
Land 1.7 0.2 11.8 1.4
Drilling and completions 25.8 55.1 79.1 76.2
Plant and facilities 16.3 16.8 26.5 24.6
Other capital 0.6 0.5 0.8 0.5
Total capital expenditures 48.5 77.5 121.9 104.9
Property acquisitions
(dispositions) net 10.0 0.2 76.4 8.4
Corporate acquisitions(7) - - 16.6 -
Total capital expenditures and
net acquisitions 58.5 77.7 214.9 113.3
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,099 29,520 29,605 29,108
Natural gas (mmcf/d) 176.7 183.0 179.5 173.4
Natural gas liquids (bbl/d) 4,088 4,161 4,144 4,166
Total (boe per day 6:1) 61,637 64,175 63,663 62,178
Average prices
Crude oil ($/bbl) 65.21 60.79 58.26 71.84
Natural gas ($/mcf) 7.38 7.75 6.99 6.10
Natural gas liquids ($/bbl) 52.76 48.04 46.51 56.60
Oil equivalent ($/boe) 54.48 53.29 49.94 54.59
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)

Unit prices
High 23.86 23.02 29.22 30.74
Low 20.78 20.05 19.20 25.25
Close 21.74 21.25 22.30 27.21
Average daily volume (thousands) 599 658 1,125 614
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
QUARTERLY HISTORICAL REVIEW
(CDN $ millions, except per
Unit amounts) 2006 2005
-------------------------------------------------------------------------
FINANCIAL Q2 Q1 Q4 Q3
Revenue before royalties 306.7 318.9 365.3 310.2
Per unit(1) 1.51 1.58 1.89 1.62
Cash Flow(2) 194.7 191.2 207.6 168.1
Per unit - basic(1) 0.96 0.94 1.07 0.88
Per unit - diluted 0.95 0.94 1.07 0.87
Net income 182.5 104.1 130.5 114.6
Per unit - basic(3) 0.91 0.52 0.68 0.61
Per unit - diluted 0.91 0.52 0.68 0.59
Distributions 120.6 119.9 115.7 92.6
Per unit(4) 0.60 0.60 0.60 0.49
Total assets 3,277.8 3,279.7 3,251.2 2,483.5
Total liabilities 1,339.9 1,434.1 1,415.5 912.2
Net debt outstanding(5) 567.4 598.9 578.1 357.6
Weighted average units(6) 203.7 202.5 193.4 191.7
Units outstanding and issuable(6) 204.4 203.1 202.0 192.1
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 2.8 2.7 3.0 2.3
Land 14.3 4.9 5.5 2.0
Drilling and completions 29.8 55.4 60.3 63.6
Plant and facilities 10.9 15.6 17.0 14.8
Other capital 0.8 0.5 2.0 0.3
Total capital expenditures 58.6 79.1 87.8 83.0
Property acquisitions
(dispositions) net 2.8 27.6 3.0 5.9
Corporate acquisitions(7) - - 462.8 -
Total capital expenditures and
net acquisitions 61.4 106.7 553.6 88.9
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 27,805 29,651 25,534 23,513
Natural gas (mmcf/d) 178.5 185.0 177.9 168.2
Natural gas liquids (bbl/d) 4,247 4,120 3,943 4,047
Total (boe per day 6:1) 61,803 64,600 59,120 55,592
Average prices
Crude oil ($/bbl) 71.86 59.53 62.12 69.37
Natural gas ($/mcf) 6.35 8.40 12.05 9.08
Natural gas liquids ($/bbl) 54.44 52.91 57.14 50.43
Oil equivalent ($/boe) 54.54 54.86 67.16 60.66
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 28.61 27.51 27.58 24.20
Low 24.35 25.09 20.45 19.94
Close 28.00 27.36 26.49 24.10
Average daily volume (thousands) 548 546 653 599
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) See Non-GAAP Measures section.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes unrealized risk management contracts asset and
liability.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.

CONSOLIDATED BALANCE SHEETS
As at June 30 and December 31 (unaudited)

($CDN millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 35.0 $ 2.8
Accounts receivable 114.3 129.8
Prepaid expenses 14.9 18.4
Risk management contracts (Note 9) 31.3 25.7
-------------------------------------------------------------------------
195.5 176.7
Reclamation funds (Note 3) 32.1 30.9
Property, plant and equipment 3,047.6 3,093.8
Long-term investment (Note 4) - 20.0
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,432.8 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 5) $ 131.8 $ 162.1
Distributions payable 41.5 40.9
Risk management contracts (Note 9) 39.9 34.4
-------------------------------------------------------------------------
213.2 237.4
Long-term debt (Note 6) 644.8 687.1
Accrued long-term incentive compensation
(Note 15) 9.1 14.6
Asset retirement obligations (Note 7) 168.8 177.3
Future income taxes (Note 8) 379.4 434.2
-------------------------------------------------------------------------
Total liabilities 1,415.3 1,550.6
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 17)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 10) 41.6 40.0

UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 2,409.4 2,349.2
Contributed surplus (Note 14) 1.8 2.4
Deficit (Note 12) (442.2) (463.2)
Accumulated other comprehensive income
(Note 2) 6.9 -
-------------------------------------------------------------------------
Total unitholders' equity 1,975.9 1,888.4
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,432.8 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
For the three and six months ended June 30 (unaudited)

Three Months Ended Six Months Ended
($CDN millions, except June 30 June 30
per unit amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------

Revenues
Oil, natural gas and natural
gas liquids $ 305.6 $ 306.7 $ 613.4 $ 625.7
Royalties (52.8) (55.0) (108.6) (117.3)
-------------------------------------------------------------------------
252.8 251.7 504.8 508.4
Gain (loss) on risk management
contracts (Note 9)
Realized 0.3 11.3 7.3 9.9
Unrealized 10.8 (14.2) (10.1) (9.1)
-------------------------------------------------------------------------
263.9 248.8 502.0 509.2
-------------------------------------------------------------------------

Expenses
Transportation 4.0 3.7 8.7 7.3
Operating 54.0 46.1 105.9 91.5
General and administrative 12.9 13.5 22.0 26.7
Interest on long-term debt
(Note 6) 9.3 7.6 19.2 15.2
Depletion, depreciation
and accretion 91.4 86.8 185.9 175.9
Gain on foreign exchange (35.5) (22.8) (40.5) (17.2)
-------------------------------------------------------------------------
136.1 134.9 301.2 299.4
-------------------------------------------------------------------------
Operating income 127.8 113.9 200.8 209.8

Gain on sale of investment (Note 4) 13.3 - 13.3 -
Capital and other taxes - 0.3 - (0.3)
Future income tax recovery (Note 8) 46.4 70.9 57.8 81.2
-------------------------------------------------------------------------
Net income before non-controlling
interest 187.5 185.1 271.9 290.7
Non-controlling interest (Note 10) (2.6) (2.6) (3.7) (4.1)
-------------------------------------------------------------------------
Net Income $ 184.9 $ 182.5 $ 268.2 $ 286.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Deficit, beginning of period $ (503.0) $ (454.9) $ (463.2) $ (439.1)
Distributions paid or declared
(Note 13) (124.1) (120.6) (247.2) (240.5)
-------------------------------------------------------------------------
Deficit, end of period (Note 12) $ (442.2) $ (393.0) $ (442.2) $ (393.0)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 16)
Basic $ 0.90 $ 0.91 $ 1.30 $ 1.43
Diluted $ 0.89 $ 0.91 $ 1.30 $ 1.43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME AND ACCUMULATED
OTHER COMPREHENSIVE INCOME
For the three and six months ended June 30 (unaudited)

Three Months Ended Six Months Ended
June 30 June 30
($CDN millions) 2007 2006 2007 2006
-------------------------------------------------------------------------

Other comprehensive income,
net of tax
Gain on financial instruments
designated as cash flow hedges $ 1.8 $ - $ 3.0 $ -
Loss on financial instruments
designated as cash flow hedges
in prior periods realized
in net income in the
current period (0.6) - (0.7) -
Net unrealized losses on
available-for-sale reclamation
funds' investments (0.3) - (0.3) -
-------------------------------------------------------------------------
Other comprehensive income $ 0.9 $ - $ 2.0 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other comprehensive
income, beginning of period $ 6.0 $ - $ - $ -
Application of initial adoption - - 4.9 -
-------------------------------------------------------------------------
Accumulated other comprehensive
income, end of period $ 6.9 $ - $ 6.9 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three and six months ended June 30 (unaudited)

Three Months Ended Six Months Ended
June 30 June 30
($CDN millions) 2007 2006 2007 2006
-------------------------------------------------------------------------

CASH FLOW FROM OPERATING ACTIVITIES
Net Income $ 184.9 $ 182.5 $ 268.2 $ 286.6
Add items not involving cash:
Non-controlling interest (Note 10) 2.6 2.6 3.7 4.1
Future income tax recovery
(Note 8) (46.4) (70.9) (57.8) (81.2)
Depletion, depreciation and
accretion 91.4 86.8 185.9 175.9
Non-cash (gain) loss on risk
management contracts (Note 9) (10.8) 14.2 10.1 9.1
Non-cash (gain) on
foreign exchange (35.6) (22.2) (40.8) (16.5)
Non-cash trust unit incentive
compensation (Notes 14 and 15) (5.2) 1.7 (4.6) 7.9
Gain on sale of investment (13.3) - (13.3) -
Expenditures on site restoration
and reclamation (7.2) (1.9) (11.9) (3.2)
Change in non-cash working capital 19.0 (10.6) 12.2 (11.5)
-------------------------------------------------------------------------
179.4 182.2 351.7 371.2
-------------------------------------------------------------------------

CASH FLOW FROM FINANCING ACTIVITIES
Issuance of long-term debt under
revolving credit facilities, net (7.8) 0.9 - 17.7
Issue of trust units 1.2 5.8 2.3 8.6
Trust unit issue costs - - - (0.2)
Cash distributions paid (Note 13) (95.2) (99.0) (191.4) (198.7)
Change in non-cash working capital (1.9) (2.6) (0.2) 1.4
-------------------------------------------------------------------------
(103.7) (94.9) (189.3) (171.2)
-------------------------------------------------------------------------

CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of petroleum and
natural gas properties (11.2) (3.6) (14.7) (32.4)
Proceeds on disposition of petroleum
and natural gas properties 1.2 0.8 4.6 2.0
Capital expenditures (47.8) (57.9) (125.2) (136.5)
Long-term investment (Note 4) 33.3 (20.0) 33.3 (20.0)
Net reclamation fund contributions
(Note 3) (0.3) (3.2) (1.5) (3.7)
Changes in non-cash working capital (15.9) (12.1) (26.7) (9.4)
-------------------------------------------------------------------------
(40.7) (96.0) (130.2) (200.0)
-------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 35.0 (8.7) 32.2 -
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD - 8.7 2.8 -
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 35.0 $ - $ 35.0 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2007 and 2006 (unaudited)
(all tabular amounts in $CDN millions, except per unit and volume
amounts)

1. SUMMARY OF ACCOUNTING POLICIES

The unaudited interim consolidated financial statements follow the
same accounting policies as the most recent annual audited financial
statements, except as highlighted in Note 2. The interim consolidated
financial statement note disclosures do not include all of those
required by Canadian generally accepted accounting principles
("GAAP") applicable for annual consolidated financial statements.
Accordingly, these interim consolidated financial statements should
be read in conjunction with the audited consolidated financial
statements included in the Trust's 2006 annual report.

2. NEW ACCOUNTING POLICIES

Effective January 1, 2007, the Trust adopted three new accounting
standards that were issued by the Canadian Institute of Chartered
Accountants ("CICA"): Handbook Section 1530, Comprehensive Income,
Section 3855, Financial Instruments - Recognition and Measurement,
Section 3865, Hedges, and Section 1506, Accounting Changes. These new
accounting standards have been adopted prospectively and,
accordingly, comparative amounts for prior periods have not been
restated. The standards provide requirements for the recognition and
measurement of financial instruments and the use of hedge accounting.

Comprehensive Income
Section 1530 introduces Comprehensive Income, which consists of Net
Income and Other Comprehensive Income ("OCI"). OCI represents changes
in Unitholders' Equity from transactions and other events with non-
owner sources, and includes unrealized gains and losses on financial
assets classified as available-for-sale and changes in the fair value
of the effective portion of cash flow hedging instruments that
qualify for hedge accounting. These items are excluded from Net
Income calculated in accordance with GAAP. We have included in our
Interim Consolidated Financial Statements a Consolidated Statement of
Other Comprehensive Income for the changes in these items during the
first six months of 2007, while the cumulative changes in OCI are
included in Accumulated Other Comprehensive Income ("AOCI"), which is
presented as a new category within Unitholders' Equity on the
Consolidated Balance Sheet.

Financial Instruments - Recognition and Measurement
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial
derivatives. Under this standard, all financial instruments are
required to be measured at fair value on initial recognition.
Measurement in subsequent periods depends on whether the financial
instrument has been classified as held-for-trading, available-for-
sale, held-to-maturity, loans and receivables, or other financial
liabilities. Transaction costs are expensed as incurred for financial
instruments classified or designated as held-for-trading. For other
financial instruments, transaction costs are capitalized on initial
recognition. Financial assets and liabilities held-for-trading are
measured at fair value with changes in those fair values recognized
in Net Income. Financial assets held-to-maturity, loans and
receivables, and other financial liabilities are measured at
amortized cost using the effective interest method of amortization.
Available-for-sale financial assets are measured at fair values with
unrealized gains and losses recognized in OCI. Investments in equity
instruments classified as available-for-sale that do not have a
quoted market price in an active market are measured at cost.

Derivative instruments are recorded on the Consolidated Balance Sheet
at fair value, including those derivatives that are embedded in
financial or non-financial contracts that are not closely related to
the host contracts. Changes in fair values of derivative instruments
are recognized in Net Income with the exception of derivatives
designated as effective cash flow hedges.

Hedges
Section 3865 specifies the criteria that must be satisfied in order
for hedge accounting to be applied and the accounting for fair value
and cash flow hedges. Hedge accounting is discontinued prospectively
when the derivative no longer qualifies as an effective hedge, or the
derivative is terminated or sold, or upon the sale or early
termination of the hedged item. The Trust has currently designated
its financial electricity contracts as an effective cash flow hedge.

In a cash flow hedging relationship, the effective portion of the
change in the fair value of the hedging derivative is recognized in
OCI while the ineffective portion is recognized in Net Income. When
hedge accounting is discontinued, the amounts previously recognized
in AOCI are reclassified to Net Income during the periods when the
variability in the cash flows of the hedged item affects Net Income.
Gains and losses on derivatives are reclassified immediately to Net
Income when the hedged item is sold or early terminated.

Impact
As a result of these changes in accounting policies, on January 1,
2007 the Trust has recorded $4.9 million in application of initial
adoption in AOCI to reflect the opening fair value of its cash flow
hedges, net of tax, which was previously not recorded on the
consolidated financial statements. The Trust has also recorded an
increase of $7 million to its risk management asset and an increase
of $2.1 million to its future income tax liability.

Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if
they result in financial statements that provide more reliable and
relevant information. Changes in policy are applied retrospectively
unless it is impractical to determine the period or cumulative impact
of the change. Corrections of prior period errors are applied
retrospectively and changes in accounting estimates are applied
prospectively by including these changes in Net Income. In addition,
disclosure is required for all future accounting changes when an
entity has not applied a new source of GAAP that has been issued but
is not yet effective.

Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards:
Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures, and Section 3863, Financial Instruments -
Presentation. These new standards will be effective on January 1,
2008.

Section 1535 specifies the disclosure of an entity's objectives,
policies and processes for managing capital, quantitative data about
what the entity regards as capital, whether the entity has complied
with any capital requirements, and if it has not complied, the
consequences of such non-compliance. This Section is expected to have
minimal impact on the Trust's financial statements.

Sections 3862 and 3863 specify a revised and enhanced disclosure on
financial instruments. These Sections will require the Trust to
increase disclosure on the nature and extent of risks arising from
financial instruments and how the entity manages those risks.

3. RECLAMATION FUNDS

June 30, 2007 December 31, 2006
---------------------------------------------------------------------
Un- Un-
restricted Restricted restricted Restricted
---------------------------------------------------------------------
Balance, beginning
of period $ 24.8 $ 6.1 $ 23.5 $ -
Contributions 4.5 - 6.0 6.1
Reimbursed
expenditures(1) (3.0) (0.6) (5.7) -
Interest earned on
funds 0.5 0.1 1.0 -
Net unrealized losses
on available-for-sale
investments (0.3) - - -
---------------------------------------------------------------------
Balance, end of
period $ 26.5 $ 5.6 $ 24.8 $ 6.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by the Trust due
to timing differences and discretionary reimbursements.

4. LONG-TERM INVESTMENT

During the second quarter of 2007, the Trust sold its equity
investment in a private oil sands company for proceeds of
$33.3 million, resulting in a gain on sale of investment of
$13.3 million. The original investment was purchased for $20 million.
The investment in the shares of the private company was considered to
be a related party transaction due to common directorships of the
Trust, the private company and the manager of a private equity fund
that held shares in the private company. The $20 million investment
was part of a $325 million private placement of the private company.
In addition, certain directors and officers of the Trust had minor
direct and indirect shareholdings in the private company.

5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
June 30, December 31,
2007 2006
---------------------------------------------------------------------
Trades payable $ 33.9 $ 39.0
Accrued liabilities 83.2 108.8
Current portion of accrued long-term
incentive compensation 12.1 11.5
Interest payable 1.6 1.8
Retention bonuses 1.0 1.0
---------------------------------------------------------------------
Total accounts payable and accrued
liabilities $ 131.8 $ 162.1
---------------------------------------------------------------------
---------------------------------------------------------------------

The current portion of accrued long-term incentive compensation
represents the current portion of the Trust's estimated liability for
the Whole Unit Plan as at June 30, 2007 (see Note 15). This amount is
payable in 2007 and 2008.

6. LONG-TERM DEBT

June 30, December 31,
2007 2006
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility
- CDN denominated $ 239.9 $ 196.6
Syndicated credit facility
- U.S. denominated 165.9 228.4
Working capital facility 0.8 1.1
Senior secured notes
5.42% USD Note 79.7 87.4
4.94% USD Note 25.5 28.0
4.62% USD Note 66.5 72.8
5.10% USD Note 66.5 72.8
---------------------------------------------------------------------
Total long term debt outstanding $ 644.8 $ 687.1
---------------------------------------------------------------------
---------------------------------------------------------------------

Various borrowing options exist under the credit facility including
prime rate advances, bankers' acceptances and LIBOR based loans
denominated in either Canadian or U.S. dollars. All drawings under
the facility are subject to stamping fees that vary between 60 bps
and 110 bps depending on certain consolidated financial ratios.

The following represents the significant financial covenants
governing the credit facility:

- Long-term debt and letters of credit not to exceed three times
net income before non-cash items and interest expense;
- Long-term debt, letters of credit, and subordinated debt not to
exceed four times net income before non-cash items and interest
expense; and
- Long-term debt and letters of credit not to exceed 50 per cent
of unitholders' equity and long-term debt, letters of credit,
and subordinated debt.

In the event that the Trust enters into a material acquisition
whereby the purchase price exceeds 10 per cent of the book value of
the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times, respectively for a maximum period of
two fiscal quarters following the closing of the material
acquisition. As at June 30, 2007, the Trust was in compliance with
all covenants and had $4.7 million in letters of credit and no
subordinated debt.

The weighted average effective interest rate under the credit
facility was 5.4 percent for the three months ended June 30, 2007
(5.4 per cent in 2006) and 5.5 per cent for the six months ended
June 30, 2007 (5.0 per cent in 2006).

Amounts due under the senior secured notes in the next 12 months of
US$6 million have not been included in current liabilities as
management has the ability and intent to refinance this amount
through the syndicated credit facility.

Interest paid during the period did not differ significantly from
interest expense.

7. ASSET RETIREMENT OBLIGATIONS

The following table reconciles the Trust's asset retirement
obligations:

June 30, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $ 177.3 $ 165.1
Increase in liabilities relating to
corporate acquisitions - 4.9
Increase in liabilities relating to
development activities 0.6 2.8
(Decrease) Increase in liabilities
relating to change in estimate (3.0) 4.0
Settlement of liabilities during the year (11.9) (10.6)
Accretion expense 5.8 11.1
---------------------------------------------------------------------
Balance, end of period $ 168.8 $ 177.3
---------------------------------------------------------------------
---------------------------------------------------------------------

The Trust's weighted average credit adjusted risk free rate as at
June 30, 2007 was 6.4 per cent (6.5 per cent as at December 31,
2006).

8. INCOME TAXES

On June 12, 2007, Bill C-52 ("Bill") received third reading in the
House of Commons and, therefore, was considered "substantively
enacted" for Canadian GAAP. The Bill enacts the October 31, 2006
proposals to impose a new tax on distributions from publicly traded
income trusts. As a result, the future tax position of the Trust, the
parent entity, is now required to be reflected in the consolidated
future income tax calculation.

The tax provision differs from the amount computed by applying the
combined Canadian federal and provincial statutory income tax rates
to income before future income tax recovery as follows:

June 30, June 30,
2007 2006
---------------------------------------------------------------------
Income before future income tax expense
and recovery $ 214.1 $ 209.5
---------------------------------------------------------------------
Expected income tax expense at
statutory rates 67.2 72.2
Effect on income tax of:
Net income of the Trust (76.8) (79.3)
Non-taxable portion of gains/losses (8.5) -
Effect of change in corporate tax rate (7.3) (58.5)
Resource allowance - (5.5)
Change in estimated pool balances (7.0) (6.4)
Non-deductible crown charges - 0.5
Capital Tax - 0.1
Other non-deductible items (0.7) (4.3)
Initial recognition of Trust tax pools (24.7) -
---------------------------------------------------------------------
Future income tax recovery $ (57.8) $ (81.2)
---------------------------------------------------------------------
---------------------------------------------------------------------

The net future income tax liability is comprised of the following:

June 30, June 30,
2007 2006
---------------------------------------------------------------------
Future tax liabilities:
Capital assets in excess of tax value $ 437.6 $ 494.0
Long-term debt 9.7 -
Other comprehensive income 3.0 -
Future tax assets:
Non-capital losses (4.3) (1.6)
Asset retirement obligations (48.7) (42.3)
Accrued long-term incentive compensation (6.1) -
Risk management contracts (5.4) (3.9)
Attributed Canadian royalty income (4.6) (11.5)
Deductible share issue costs (1.8) -
---------------------------------------------------------------------
Net future income tax liability $ 379.4 $ 434.7
---------------------------------------------------------------------
---------------------------------------------------------------------

The following is a summary of the Trust's estimated consolidated tax
pools, as of June 30, 2007:

---------------------------------------------------------------------
Canadian oil and gas property expenses $ 735.6
Canadian development expenses 298.5
Canadian exploration expenses 43.5
Undepreciated capital cost 405.9
Non-capital losses 13.8
Provincial tax pools 161.1
Other 13.5
---------------------------------------------------------------------
Estimated tax basis $ 1,671.9
---------------------------------------------------------------------
---------------------------------------------------------------------

9. FINANCIAL INSTRUMENTS

The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices and foreign exchange
rates. The Trust considers all of these transactions to be effective
economic hedges, however, the majority of the Trust's contracts do
not qualify as effective hedges for accounting purposes.

Following is a summary of all risk management contracts in place as
at June 30, 2007:

Financial WTI Crude Oil Contracts

Bought Sold Sold
Volume put put call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Jul 07 - Dec 07 Put Spread 1,000 75.00 60.00 -
Jul 07 - Dec 07 3-Way Collar 2,500 65.00 52.50 80.00
Jul 07 - Dec 07 Put Spread 2,500 65.00 52.50 -
Jul 07 - Dec 07 Put Spread 1,000 65.00 55.00 -
Jul 07 - Dec 07 3-Way Collar 1,000 65.00 52.50 85.00
Jul 07 - Dec 07 3-Way Collar 5,000 55.00 40.00 90.00
Jan 08 - Jun 08 3-Way Collar 1,000 65.00 52.50 85.00
Jan 08 - Jun 08 3-Way Collar 1,000 65.00 52.50 82.50
Jan 08 - Jun 08 Collar 1,000 65.00 - 85.00
Jan 08 - Dec 08 3-Way Collar 1,000 67.50 52.50 85.00
Jan 08 - Dec 08 Collar 1,000 67.50 - 85.00
Jan 08 - Dec 08 3-Way Collar 2,000 61.50 50.00 85.00
Jan 08 - Dec 08 3-Way Collar 1,000 61.30 50.00 85.00
Jan 08 - Dec 08 3-Way Collar 2,000 61.00 50.00 85.00
Jan 08 - Dec 09 3-Way Collar 5,000 55.00 40.00 90.00
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial AECO Natural Gas Contracts

Bought Sold Sold
Volume put put call
Term Contract GJ/d CDN$/GJ CDN$/GJ CDN$/GJ
---------------------------------------------------------------------
Jul 07 - Aug 07 Collar 10,000 7.75 - 10.00
Jul 07 - Aug 07 3-Way Collar 10,000 7.50 5.50 9.50
Jul 07 - Aug 07 3-Way Collar 10,000 7.25 5.25 9.00
Jul 07 - Aug 07 3-Way Collar 30,000 7.00 5.00 8.65
Sep 07 - Oct 07 Bought Put 10,000 7.75 - -
Sep 07 - Oct 07 Put Spread 10,000 7.50 5.50 -
Sep 07 - Oct 07 Put Spread 10,000 7.25 5.25 -
Sep 07 - Oct 07 Put Spread 30,000 7.00 5.00 -
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial NYMEX Natural Gas Contracts

Bought Sold Sold
put put call
Volume US$/ US$/ US$/
Term Contract mmbtu/d mmbtu mmbtu mmbtu
---------------------------------------------------------------------
Jul 07 - Oct 07 Put Spread 5,000 8.25 6.75 -
Nov 07 - Mar 08 Collar 20,000 8.50 - 12.50
Nov 07 - Mar 08 Collar 10,000 9.25 - 12.50
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial Basis Swap Contract: receive NYMEX (Last 3 Day); pay AECO
(Monthly)

Basis
Swap
Volume US$/
Term Contract mmbtu/d mmbtu
---------------------------------------------------------------------
Jul 07 - Oct 08 Basis Swap 50,000 (1.1930)
Nov 08 - Oct 10 Basis Swap 50,000 (1.0430)
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial Foreign Exchange Contracts

Bought Sold
Notional Swap Swap Put Put
Volume CDN$/ US$/ CDN$/ CDN$/
Term Contract MM US$ US$ CDN$ US$ US$
---------------------------------------------------------------------
USD Sales Contracts
Jul 07 - Dec 07 Swap 8.4 1.1371 (0.8794) - -

USD Option Contracts
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1220 1.0970
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1180 1.0980
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1320 1.1020
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1380 1.1030
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1332 1.1032
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1400 1.1050
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1380 1.1080
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1300 1.1100
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1400 1.1100
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1420 1.1120
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1520 1.1120
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1440 1.1140
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1460 1.1160
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1480 1.1180
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1545 1.1195
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1765 1.1465
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1280 1.0980
Jul 07 - Dec 07 Put Spread 6.0 - - 1.1250 1.1000
Jul 07 - Dec 07 Bought Put 6.0 - - 1.1600 -
---------------------------------------------------------------------
---------------------------------------------------------------------

Financial Electricity Contracts(1)
Swap
Volume CDN$/
Term Contract MWh MWh
---------------------------------------------------------------------
Jul 07 - Dec 07 Swap 20.0 64.63
Jan 08 - Dec 08 Swap 15.0 60.17
Jan 09 - Dec 09 Swap 15.0 59.33
Jan 10 - Dec 10 Swap 5.0 63.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Contracted volume is based on a 24/7 term.

Financial Interest Rate Contracts(2)
Fixed
Annual
Principal Rate Spread on
Term Contract MM US$ (%) 3 Mo. LIBOR
---------------------------------------------------------------------
Jul 07 - Apr 14 Swap 30.5 4.62 38 bps
Jul 07 - Apr 14 Swap 32.0 4.62 (25.5 bps)
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) Starting in 2009, the notional amount of the contracts decreases
annually until 2014. The Trust pays the floating interest rate
based on a three month LIBOR plus a spread and receives the fixed
interest rate.

The Trust has designated all fixed price electricity contracts as
effective accounting hedges on their respective contract dates. A
realized loss of $0.1 million and $0.7 million for the three months
and six months ended June 30, 2007 respectively ($0.4 million and
$0.5 respectively in 2006) on the electricity contracts has been
included in operating costs. The unrealized fair value gain on the
electricity contracts of $10.2 million has been recorded on the
consolidated balance sheet at June 30, 2007 with the movement in fair
value recorded in OCI, net of tax.

The Trust has entered into interest rate swap contracts to manage the
Company's interest rate exposure on debt instruments. Prior to 2007,
these contracts were designated as effective accounting hedges on the
contract date. At January 1, 2007 the Trust elected to cease applying
hedge accounting to these contracts. As a result, the unrealized fair
value loss on the interest rate swap contracts of $2.4 million has
been reflected in the income statement for the six months ended
June 30, 2007.

The following table reconciles the movement in the fair value of the
Trust's financial risk management contracts that have not been
designated as effective accounting hedges:

June 30, June 30,
2007 2006
---------------------------------------------------------------------
Fair value, beginning of period(1) $ (8.7) $ (4.0)
Fair value, end of period(1) (18.8) (13.1)
---------------------------------------------------------------------
Change in fair value of contracts
in the period (10.1) (9.1)
Realized gains in the period 7.3 9.9
---------------------------------------------------------------------
(Loss) gain on risk management
contracts(1) $ (2.8) $ 0.8
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) For 2007 the fixed price electricity contracts that were
accounted for as effective accounting hedges were excluded. For
2006 the fixed price electricity contract and interest rate swap
contracts that were accounted for as effective accounting hedges
were excluded.

The following table reconciles the movement in the fair value of the
Trust's financial electricity contracts that have been designated as
effective accounting hedges:

June 30, June 30,
2007 2006
---------------------------------------------------------------------
Fair value, beginning of period(2) $ 7.0 $ -
Fair value, end of period 10.2 -
---------------------------------------------------------------------
Change in fair value of contracts
in the period 3.2 -
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) Fair value of fixed price electricity contracts recognized
prospectively on January 1, 2007.

At June 30, 2007, the fair value of the contracts that were not
designated as accounting hedges was a loss of $18.8 million. The
Trust recorded a loss on risk management contracts of $2.8 million in
the statement of income for the first six months of 2007
($0.8 million gain in 2006). This amount includes the realized and
unrealized gains and losses on risk management contracts that do not
qualify as effective accounting hedges.

10. EXCHANGEABLE SHARES

June 30, December 31,
ARL EXCHANGEABLE SHARES (thousands) 2007 2006
---------------------------------------------------------------------
Balance, beginning of period 1,433 1,595
Exchanged for trust units(1) (72) (162)
---------------------------------------------------------------------
Balance, end of period 1,361 1,433
Exchange ratio, end of period 2.12420 2.01251
---------------------------------------------------------------------
Trust units issuable upon conversion,
end of period 2,892 2,884
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first six months of 2007, 71,741 ARC Resources
exchangeable shares ("ARL exchangeable shares") were converted to
trust units at an average exchange ratio of 2.07802.

Following is a summary of the non-controlling interest for June 30,
2007 and December 31, 2006:
June 30, December 31,
2007 2006
---------------------------------------------------------------------
Non-controlling interest,
beginning of period $ 40.0 $ 37.5
Reduction of book value for conversion
to Trust units (2.1) (4.1)
Current period net income attributable
to non-controlling interest 3.7 6.6
---------------------------------------------------------------------
Non-controlling interest, end of period $ 41.6 $ 40.0
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 31.0 $ 27.3
---------------------------------------------------------------------
---------------------------------------------------------------------

11. UNITHOLDERS' CAPITAL

June 30, 2007 December 31, 2006
---------------------------------------------------------------------
Number of Number of
Trust Units Trust Units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning of period 204,289 2,349.2 199,104 2,230.8
Issued for cash - - 1 -
Issued on conversion of ARL
exchangeable shares (Note 10) 149 2.1 310 4.1
Issued on exercise of
employee rights (Note 14) 122 2.0 978 18.4
Distribution reinvestment
program 2,749 56.1 3,896 96.1
Trust unit issue costs - - - (0.2)
---------------------------------------------------------------------
Balance, end of period 207,309 2,409.4 204,289 2,349.2
---------------------------------------------------------------------
---------------------------------------------------------------------

12. DEFICIT

The deficit balance is composed of the following items:

June 30, December 31,
2007 2006
---------------------------------------------------------------------
Accumulated earnings $ 1,964.0 $ 1,695.8
Accumulated distributions (2,406.2) (2,159.0)
---------------------------------------------------------------------
Deficit $ (442.2) $ (463.2)
---------------------------------------------------------------------
---------------------------------------------------------------------

13. RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS

Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operations adjusted for
changes in non-cash working capital and expenditures on site
restoration and reclamation, is reduced by reclamation fund
contributions including interest earned on the funds and a portion of
capital expenditures, and debt repayments. The portion of cash flow
withheld to fund capital expenditures and to make debt repayments is
at the discretion of the Board of Directors.

Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
---------------------------------------------------------------------
Cash flow from operating
activities $ 179.4 $ 182.2 $ 351.7 $ 371.2
Change in non-cash
working capital (19.0) 10.6 (12.2) 11.5
Expenditures on site
reclamation and restoration 7.2 1.9 11.9 3.2
---------------------------------------------------------------------
Cash flow from operating
activities after the above
adjustments 167.6 194.7 351.4 385.9
Deduct:
Cash withheld to fund
current period
capital expenditures (41.7) (68.1) (99.1) (137.7)
Reclamation fund
contributions and interest
earned on fund balances (1.8) (4.7) (5.1) (6.4)
Discretionary debt repayments - (1.3) - (1.3)
---------------------------------------------------------------------
Distributions(1) 124.1 120.6 247.2 240.5
Accumulated distributions,
beginning of period 2,282.1 1,794.7 2,159.0 1,674.8
---------------------------------------------------------------------
Accumulated distributions,
end of period $2,406.2 $1,915.3 $2,406.2 $1,915.3
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per unit(2) $ 0 .60 $ 0.60 $ 1.20 $ 1.20
Accumulated distributions
per unit, beginning
of period(3) $ 19.23 $ 16.83 $ 18.63 $ 16.23
---------------------------------------------------------------------
Accumulated distributions
per unit, end of period(3) $ 19.83 $ 17.43 $ 19.83 $ 17.43
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include non-cash amounts of $28 million and
$54 million for the three and six months ended June 30, 2007,
respectively ($21 million and $42 million for the same periods in
2006, respectively) relating to the distribution reinvestment
program.
(2) Distributions per trust unit reflect the sum of the per trust
unit amounts declared monthly to unitholders.
(3) Accumulated distributions per unit reflect the sum of the per
trust unit amounts declared monthly to unitholders since the
inception of the Trust in July 1996.

14. TRUST UNIT INCENTIVE RIGHTS PLAN

A summary of the changes in rights outstanding under the plan is as
follows:

Weighted
Number Average
of Rights Exercise
(thousands) Price ($)
---------------------------------------------------------------------
Balance, beginning of period 369 9.47
Exercised (122) 10.86
---------------------------------------------------------------------
Balance before reduction of exercise price 247 9.40
Reduction of exercise price(1) - (0.45)
---------------------------------------------------------------------
Balance, end of period 247 8.95
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The holder of the right has the option to exercise rights held at
the original grant price or a reduced exercise price.

The Trust recorded nominal compensation expense for the first
six months of 2007 ($2.5 million in the first six months of 2006) for
the cost associated with the rights. The compensation expense was
based on the fair value of all outstanding rights in the second
quarter of 2007 and is amortized over the remaining vesting period of
such rights. Of the 3,013,569 rights issued on or after January 1,
2003 that were subject to recording compensation expense, 357,999
rights have been cancelled and 2,410,269 rights have been exercised
to June 30, 2007.

The following table reconciles the movement in the contributed
surplus balance:

June 30, December 31,
CONTRIBUTED SURPLUS 2007 2006
---------------------------------------------------------------------
Balance, beginning of period $ 2.4 $ 6.4
Compensation expense - 2.5
Net benefit on rights exercised(1) (0.6) (6.5)
---------------------------------------------------------------------
Balance, end of period $ 1.8 $ 2.4
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to unitholders' capital.

15. WHOLE UNIT INCENTIVE PLAN

The Trust recorded compensation expense of $4.3 million and
$0.6 million to general and administrative and operating expenses,
respectively, and capitalized $0.8 million to property, plant and
equipment in the six months ended June 30, 2007 for the estimated
cost of the plan ($7.8 million, $1.4 million and $1.6 million for the
six months ended June 30, 2006). The compensation expense was based
on the June 30, 2007 unit price of $21.74 ($28.00 at June 30, 2006),
accrued distributions, a weighted average performance multiplier of
1.6 (2.0 in 2006), and the number of units to be issued on maturity.

The following table summarizes the Restricted Trust Unit ("RTU") and
Performance Trust Unit ("PTU") movement for the six months ended
June 30, 2007:

---------------------------------------------------------------------
Number of Number of
RTUs PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of period 648 683
Vested (191) (111)
Granted 204 164
Forfeited (25) (25)
---------------------------------------------------------------------
Balance, end of period 636 711
---------------------------------------------------------------------
---------------------------------------------------------------------

The following table reconciles the change in total accrued long-term
incentive compensation liability relating to the Whole Unit Plan:

June 30, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $ 26.1 $ 15.0
Change in liabilities in the period
General and administrative expense (4.1) 8.2
Operating expense (0.5) 1.1
Property, plant and equipment (0.3) 1.8
---------------------------------------------------------------------
Balance, end of period $ 21.2 $ 26.1
---------------------------------------------------------------------
Current portion of liability 12.1 11.5
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 9.1 $ 14.6
---------------------------------------------------------------------
---------------------------------------------------------------------

16. BASIC AND DILUTED PER UNIT CALCULATIONS

Net income per trust unit has been determined based on the following:

Three Months Ended Six Months Ended
June 30 June 30
2007 2006 2007 2006
---------------------------------------------------------------------
Weighted average trust
units(1) 206,562 200,814 205,780 200,202
---------------------------------------------------------------------
Trust units issuable on
conversion of exchangeable
shares(2) 2,892 2,895 2,892 2,895
Dilutive impact of rights(3) 179 740 212 817
---------------------------------------------------------------------
Diluted trust units 209,633 204,449 208,884 203,914
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Weighted average trust units excludes trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding
exchangeable shares at the period end exchange ratio.
(3) All outstanding rights were dilutive and therefore all have been
included in the diluted trust unit calculation for both 2007 and
2006.

Basic net income per unit has been calculated based on net income
after non-controlling interest divided by weighted average trust
units outstanding. Diluted net income per unit has been calculated
based on net income before non-controlling interest divided by
diluted trust units.

17. COMMITMENTS AND CONTINGENCIES

Following is a summary of the Trust's contractual obligations and
commitments as at June 30, 2007:
---------------------------------------------------------------------
Payments Due By Period
---------------------------------------------------------------------
2008- 2010- There-
($ millions) 2007 2009 2011 after Total
---------------------------------------------------------------------
Debt repayments(1) 7.3 23.8 454.2 159.5 644.8
Interest payments(2) 6.0 22.9 19.3 22.1 70.3
Reclamation fund
contributions(3) 6.0 11.1 9.5 76.2 102.8
Purchase commitments 8.6 8.2 3.1 6.3 26.2
Operating leases 2.6 9.0 4.5 - 16.1
Derivative contract
premiums(4) 19.8 8.1 - - 27.9
Retention bonuses 1.0 - - - 1.0
---------------------------------------------------------------------
Total contractual
obligations 51.3 83.1 490.6 264.1 889.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.

In addition to the above, the Trust has commitments related to its
risk management program (See Note 9).

The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending
litigation will not have a material adverse impact on the Trust's
financial position or results of operations.
>>

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.

Note: Barrels of oil equivalent (boe) 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.

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

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, ARC Resources Ltd., Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E9