ARC Energy Trust announces second quarter 2008 results

CALGARY, Aug. 1 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") announces record cash flow from operating activities for the
second quarter and six months ended June 30, 2008.

<<
Three Months Ended Six Months Ended
June 30 June 30
2008 2007 2008 2007
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FINANCIAL
($Cdn millions, except per unit
and per boe amounts)
Revenue before royalties 512.0 305.6 919.9 613.4
Per unit(1) 2.38 1.46 4.29 2.94
Per boe 88.04 54.48 77.24 53.88
Cash flow from operating
activities(2) 273.4 179.4 483.4 351.7
Per unit(1) 1.27 0.86 2.25 1.69
Per boe 47.02 31.98 40.59 30.89
Net income 57.3 184.9 138.6 268.2
Per unit(3) 0.27 0.90 0.65 1.30
Distributions 144.7 124.1 271.5 247.2
Per unit(1) 0.68 0.60 1.28 1.20
Per cent of cash flow from
operating activities(2) 53 69 56 70
Net debt outstanding(4) 756.1 653.9 756.1 653.9

OPERATING
Production
Crude oil (bbl/d) 27,541 28,099 28,302 28,806
Natural gas (mmcf/d) 194.7 176.7 199.5 179.8
Natural gas liquids (bbl/d) 3,906 4,088 3,882 4,124
Total (boe/d) 63,896 61,637 65,436 62,899
Average prices
Crude oil ($/bbl) 118.32 65.21 103.63 62.96
Natural gas ($/mcf) 10.41 7.38 9.07 7.57
Natural gas liquids ($/bbl) 82.29 52.76 75.46 50.39
Oil equivalent ($/boe) 87.73 54.37 76.95 53.77
Operating netback ($/boe)
Commodity and other revenue
(before hedging)(5) 88.04 54.48 77.24 53.88
Transportation costs (0.79) (0.72) (0.76) (0.77)
Royalties (15.79) (9.43) (13.77) (9.54)
Operating costs (10.71) (9.63) (10.11) (9.30)
Netback (before hedging) 60.75 34.70 52.60 34.27
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TRUST UNITS
(millions)
Units outstanding, end of period(6) 215.8 207.3 215.8 207.3
Weighted average units(7) 215.2 209.5 214.5 208.7
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TRUST UNIT TRADING STATISTICS
($Cdn, except volumes)
based on intra-day trading
High 33.95 23.86 33.95 23.86
Low 25.19 20.78 20.00 20.05
Close 33.95 21.74 33.95 21.74
Average daily volume (thousands) 659 599 764 629
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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 record
date.
(2) Cash flow from operating activities is a GAAP measure. Historically,
management has disclosed Cash Flow, as a non-GAAP measure calculated
using cash flow from operating activities less the change in non-cash
working capital and the expenditures on site restoration and
reclamation as they appear on the Consolidated Statements of Cash
Flows. Cash Flow for the second quarter of 2008 would be
$257.5 million ($1.20 per unit) and $484.9 million ($2.26 per unit)
year-to-date. Distributions as a percentage of Cash Flow would be
56 per cent for the second quarter of 2008 (56 per cent year-to-
date). Second quarter Cash Flow was lower than cash flow
from operating activities primarily due to the provision for non-
recoverable accounts receivable of $18 million. Please refer to the
non-GAAP measures section in the MD&A for further details.
(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 current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(5) Includes other revenue.
(6) Includes 1.1 million exchangeable shares exchangeable into 2.36758
trust units each for an aggregate 2.7 million trust units.
(7) Includes trust units issuable for outstanding exchangeable shares at
period end.

HIGHLIGHTS AND ACCOMPLISHMENTS
------------------------------

- On June 26, 2008, the Board of Directors re-affirmed our base
distribution of $0.20 per unit and approved an increase in the top-up
distribution from $0.04 per unit to $0.08 per unit per month.
Including our base distribution of $0.20, this increases the total
monthly distribution to $0.28 per unit. This distribution payment
will be effective beginning with the August 15, 2008 payment. The
"top-up" distribution will be reviewed on a quarterly basis but is
expected to stay in place as long as commodity prices maintain their
current strength.

- ARC also announced on June 26, 2008 that the Board of Directors
approved an increase in the 2008 capital budget to $550 million. A
substantial portion of the 2008 budget is targeted at developing
ARC's extensive land position in the Montney play in northeast
British Columbia and the engineering design of a new ARC operated gas
plant proposed for the Dawson area.

- Production for the quarter of 63,896 boe per day was up 2,259 boe per
day (four per cent) over the second quarter of 2007 with the growth
in production at Dawson accounting for most of the increase in
production. When compared to the first quarter 2008 volumes of
66,976, the second quarter volumes were negatively impacted by
scheduled turnarounds including the major turnaround at Redwater. The
Redwater turnaround was completed within the budgeted time frame and
production returned to normal levels within three days after the
turnaround. The Trust has revised its full year production guidance
upwards to between 64,000 and 65,000 boe per day.

- Cash flow from operating activities for the quarter was a record for
the Trust at $273.4 million ($1.27 per unit). Using the more
traditional non-GAAP measure of Cash Flow that excludes changes in
non-cash working capital and site restoration spending for the
quarter, Cash Flow was $257.5 million ($1.20 per unit). This
represents a 54 per cent increase in Cash Flow over the
$167.6 million reported in the second quarter of 2007. The increase
is primarily a result of a 61 per cent increase in the Trust's total
realized commodity price for the quarter and a four per cent increase
in production volumes. With oil increasing to all time highs and
averaging WTI US$124 per barrel during the second quarter, the Trust
posted realized risk management hedging losses of $34.7 million on
its oil volumes ($44.7 million on total contracts) that negatively
impacted cash flow in the quarter; however, the Trust was also able
to participate in the market prices on 53 per cent of its total
production during the second quarter.

- On July 22, 2008, a counterparty that markets a portion of the
Trust's production filed for protection under the Companies'
Creditors Arrangement Act ("CCAA"). As a result, the Trust recorded
a provision for non-recoverable accounts receivable of $18 million
($13.5 million net of tax). Management believes that some portion
of the $18 million owed by SemCanada is recoverable; however, it is
indeterminable at this time and therefore the provision has been
recorded for the full amount. The Trust may record an additional
provision in the third quarter for July production delivered to
SemCanada to the date of the CCAA filing based on a maximum
estimated July exposure of $15 million ($11.3 million net of tax),
bringing the total exposure to $33 million including the June
receivable amount. The Trust believes it has no additional
exposure to SemCanada for deliveries of production after July 22,
2008 as all production has now been re-assigned to new
counterparties.

- During the second quarter, the Trust drilled 10 wells (9 net). In the
north, the Trust drilled two horizontal injection wells at Ante Creek
and a fourth horizontal well at Dawson. Five wells were drilled in
southeast Saskatchewan including the Trust's first Bakken wells at
Lost Horse Hills and Midale. The Lost Horse Hills well has been put
on production at 200 barrels of oil per day and the Midale well was
put on production in the third quarter at 400 barrels of oil per day.
Two wells were drilled at Pembina bringing year-to-date development
in that area up to 13 gross wells (9 net), all of which have been
successfully completed. Subsequent to quarter end, the Trust has 11
rigs currently under contract for what is anticipated to be ARC's
most active summer drilling program to date.

- Total capital spending for the quarter, including undeveloped land
purchases of $57.8 million and net property acquisitions of
$0.3 million, was $131.6 million. This amount was funded 100 per cent
by the Trust's cash flow from operating activities and proceeds from
the distribution re-investment program ("DRIP").

- Commodity prices continued to increase in the second quarter of 2008
increasing the value of all oil and gas entities including ARC.
Future oil prices are more than 50 per cent higher and future natural
gas prices are more than 20 per cent higher than those prices used by
GLJ in their independent evaluation of the Trust's oil and natural
gas reserves as at December 31, 2007.

- Montney Resource Play Development

ARC's four well horizontal drilling program on the main Dawson field
has been completed. Three of the wells have been completed and tested
at rates between seven and 14 mmcf per day while the fourth
well is scheduled to be completed and brought on production during
the fourth quarter. Production from the field remains steady at
approximately 45 mmcf per day, which is the maximum capacity of our
contracted processing facility.

The Trust has expanded its land base in the Montney through pooling
with other companies, purchases at crown land sales and purchases
from other producers. During the first half of 2008, ARC has spent
$78.2 million to acquire land in the Montney play in British
Columbia, bringing our total undeveloped land to approximately 141
gross sections (120 net), up from 96 gross (87 net) at December 31,
2007. The recent values paid at government land sales for
prospective land in the Montney play in northeast British Columbia
may indicate that there is significant unrecognized value in ARC's
undeveloped land. At the July 16 land sale, record prices of
approximately $32,500 per hectare were paid for large blocks of land
in northeastern BC. In addition, the Trust has an average working
interest of 98.6 per cent in 44 sections that have recoverable
reserves assigned to them at year-end 2007.

The Trust now has three rigs drilling delineation wells at Dawson,
West Dawson and Sunrise with a fourth rig expected shortly for a
location on the Alberta side of the border at Pouce Coupe. In the
last half of the year, ARC expects to drill eight vertical infill and
stepout wells at Dawson, two horizontal delineation wells at West
Dawson, two horizontal delineation wells at Sunrise and ten vertical
exploratory wells on its extensive undeveloped land holdings in this
area. In addition, ARC will participate in two partner operated
horizontal wells during the last half of 2008.

ARC has applied for approval to construct a 10 mmcf per day gas line
from the Dawson field to Fourth Creek in Alberta. Assuming that
approvals are received early in the third quarter, ARC would expect
to have the new line on stream by late fourth quarter 2008. ARC's
Board of Directors has also approved the construction of an ARC
operated gas plant in the Dawson area for the processing of gas from
the Dawson and West Dawson fields. Engineering design is expected to
start this summer with the first 30 mmcf per day targeted for startup
in early 2010 and production of up to 60 mmcf per day targeted for
early 2011. This is incremental to our existing production of
approximately 45 mmcf per day. In the absence of acquisitions or
dispositions, this projected growth in production in the Dawson and
West Dawson areas could take ARC's total production to approximately
70,000 boe per day in 2011.

- Enhanced Oil Recovery Initiatives

The Trust spent $17.8 million during the second quarter of 2008 on
enhanced oil recovery ("EOR") initiatives, including development
capital for the Weyburn and Midale CO(2) floods in Saskatchewan. The
Trust effectively completed the construction of the CO(2) pilot
project injection facilities at Redwater during the second quarter.
Subsequent to quarter end, final approval to inject CO(2) was
received from the Energy Resources Conservation Board and
commissioning of the facility began during the last week of July. The
Trust expects that it will take 12 to 18 months before it will be
known if the pilot has been successful in increasing oil production
and has shown potential for a commercial scale EOR scheme.

In July of 2008, the Provincial government announced a $4 billion
spending program targeted at reducing green-house gas emissions with
$2 billion specifically allocated towards carbon capture and storage.
The Trust is actively pursuing opportunities to access this and other
government funding for our existing CO(2) carbon capture and storage
initiatives.
>>

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

This management's discussion and analysis ("MD&A") is the Trust
management's analysis of its financial performance and significant trends or
external factors that may affect future performance. It is dated July 31, 2008
and should be read in conjunction with the unaudited Consolidated Financial
Statements for the period ended June 30, 2008, the MD&A and the unaudited
Consolidated Financial Statements for the period ended March 31, 2008, and the
audited Consolidated Financial Statements and MD&A for the period ended
December 31, 2007 as well as the Trust's 2007 Annual Information Form that is
filed on SEDAR at www.sedar.com.
The MD&A contains forward-looking statements and readers are cautioned
that the MD&A should be read in conjunction with the Trust's disclosure under
"Forward-Looking Statements" included at the end of this MD&A.

Executive Overview

ARC Energy Trust ("ARC") is one of the top 20 producers of conventional
oil and gas in western Canada. ARC as at June 30, 2008 held interests in
excess of 18,000 wells with approximately 5,500 wells operated by ARC and the
remainder operated primarily by other major oil and gas companies. ARC's
production has averaged between 61,000 and 67,000 boe per day in each quarter
for the last three years. The total capitalization of ARC Energy Trust, which
trades on the Toronto Stock Exchange, as at June 30, 2008 was $7.3 billion as
shown on Table 21.
ARC's objective as an energy company is to provide superior and
sustainable long-term returns to unitholders. Key attributes to the business
plan include:

<<
- Concentrated activities in three major areas: conventional oil and
natural gas assets, resource plays and enhanced oil recovery
initiatives. In addition to these major initiatives, ARC continually
reviews acquisition and disposition opportunities to high grade its
asset base and provide future growth opportunities.

- Pay a portion of cash flow to unitholders annually. Currently the
Trust distributes $0.28 per unit per month. The remainder of the cash
flow is used to fund reclamation costs and a portion of capital
expenditures and land acquisitions. Since the Trust's inception in
July 1996 to June 30, 2008, the Trust has distributed $22.31 per
unit.

- Annual replacement of production and reserves through drilling new
wells and associated oil and natural gas development activities. The
vast majority of the annual capital budget is being deployed on a
balanced drilling program of low and moderate risk wells, well tie-
ins and other related costs, and the acquisition of undeveloped land.
The Trust continues to focus on major properties with significant
upside, with the objective to replace production declines through
internal development opportunities.

Table 1 illustrates ARC's production and reserves per unit that have
been achieved while making distributions since January 1, 2006, of
$6.08 per unit or $1.3 billion.

Table 1
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Q2 YTD
Per Trust Unit 2008 2008 2007 2006
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Normalized production per unit(1) 0.32 0.33 0.30 0.31
Normalized reserves per unit(1)(2) - - 1.35 1.40
Distributions per unit $0.68 $1.28 $2.40 $2.40
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(1) 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 trust units were issued (or
repurchased) 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 achieve a net debt balance of
15 per cent of total capitalization each year. The normalized
amounts are presented to enable comparability of annual per unit
values.
(2) Reserves per unit are only calculated on an annual basis when the
Trust has a full independent reserve evaluation prepared.

- The periodic strategic acquisition of producing and undeveloped
properties to enhance current production or provide the potential for
future drilling locations and if successful, additional production
and reserves. Acquisitions are evaluated internally to determine the
value and potential of the property; acquisition amounts in excess of
$25 million are subject to Board approval.

- Using prudent production practices to maximize the recovery of oil
and natural gas from the reservoirs.

- Controlling costs for both routine operating expenditures and costs
incurred for capital projects. ARC expects that the aggregate amount
of operating costs will increase over time as ARC adds approximately
300 wells per year to its operating base to replace the natural
decline on existing producing wells.

ARC's business plan and operating practices also include the following
strategies and action plans that are being undertaken to increase ARC's
competitiveness and future profitability:

- Continual development of staff expertise and the hiring and retention
of some of the industry's best and most qualified personnel.

- Building relationships with suppliers, joint venture partners,
government and other stakeholders and conducting business in a fair
and equitable manner.

- Promoting the use of proven and effective technologies to enhance the
recoverable resources in place and reduce costs.

- Being an industry leader in health, safety and environmental
performance.

- Actively supporting local initiatives and charities in the
communities in which we live and work.

The effectiveness of ARC's business plan can best be measured by
historical results as shown in Table 2. Investors and unitholders will
appreciate that commodity prices are a significant factor in determining
profitability and market returns of the units, however the combination of
appreciating commodity prices and the successful execution of ARC's business
plan has resulted in the following returns to unitholders:

Table 2
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Total Returns Trailing Trailing Trailing
($ per unit except for per cent) One Year Three Year Five Year
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Distributions per unit $ 2.48 $ 7.17 $ 10.77
Capital appreciation per unit $ 11.75 $ 13.14 $ 21.30
Total return per unit $ 14.23 $ 20.31 $ 32.07
Annualized total return per unit 73.1% 31.7% 35.5%
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2008 Guidance

Table 3 is a summary of the Trust's 2008 Revised Guidance issued by way of
news release on June 26, 2008 (posted on www.sedar.com) and a review of 2008
actual results compared to guidance:

Table 3
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June 2008 Actual
Guidance 2008 YTD
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Production (boe/d) 64,000 - 65,000 65,436
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Expenses ($/boe):
Operating costs 10.20 10.11
Transportation 0.80 0.76
G&A expenses(1) 3.15 3.67
Interest 1.50 1.44
Capital expenditures ($ millions)(2) 550 242.6
Weighted average trust units and
units issuable (millions) 216 214.5
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(1) The components of the $3.15 per boe G&A guidance for the full year
are as follows: cash G&A - $1.71 per boe; cash component of LTIP -
$1.00 per boe; non-cash LTIP component - $0.44 per boe.
(2) 2008 Capital Expenditure Guidance has been revised to reflect
additional monies allocated to land expenditures and resource play
development in the Dawson area.

The 2008 Guidance provides unitholders with information as to management's
expectations for results of operations for 2008. Readers are cautioned that
the 2008 Guidance may not be appropriate for other purposes. ARC has announced
a $550 million capital expenditure budget for 2008 that comprises a robust
drilling and development program on its diverse asset base, funding of EOR
projects and an allocation of funds to purchase undeveloped lands.
Actual results for the first half of 2008 were in line with 2008 guidance
with some minor exceptions as follows:

- G&A expenses of $3.67 per boe were greater than guidance due to the
strong increase in the Trust's unit price at quarter-end, which
increased the Trust's non-cash LTIP expense accrual. Full year G&A
costs are still expected to be approximately $3.15 per boe.

- Production of 65,436 boe per day was greater than guidance due to
better than expected drilling results. With additional scheduled
turnarounds in the third quarter, the Trust expects full year
production to be between 64,000 and 65,000 boe per day.
>>

Non-GAAP Measures

Historically, management used the non-GAAP measure Cash Flow or cash flow
from operations to analyze operating performance, leverage and liquidity. We
have now chosen to use the GAAP measure cash flow from operating activities
instead of Cash Flow or cash flow from operations. There are two differences
between the two measures and cash flow from operating activities; positive or
negative changes in non-cash working capital and the deduction of expenditures
on site restoration and reclamation as they appear on the Consolidated
Statements of Cash Flows. Although management feels that Cash Flow, or cash
flow from operations, is a valued measure of funds generated by the Trust
during the reported quarter, we have changed our disclosure to only discuss
the GAAP measure in the MD&A in order to avoid any potential confusion by
readers of our financial information and in our opinion, to more fully comply
with the intent of certain regulatory requirements.
Our historical measure of Cash Flow reflected revenues and costs for the
three months reported in the quarter. This amount, however, comprised accruals
for at least one month of revenue and approximately two months of costs. The
oil and gas industry is designed such that revenues are typically collected on
the 25th day of the month following the actual production month. Royalties are
typically paid two months following the actual production month and operating
costs are paid as the invoices are received. This can take several months;
however, most invoices for operated properties are paid within approximately
two months of the production month. In the event that commodity prices and or
volumes have changed significantly from the last month of the previous
reporting period over the last month of the current reporting period, a
difference could occur between cash flow from operating activities and our
historical non-GAAP measure of Cash Flow or cash flow from operations.
Additionally, periods where the Trust spends a significant amount on site
restoration and reclamation would result in a difference between cash flow
from operating activities and Cash Flow or cash flow from operations.
At the time of writing this MD&A, substantially all revenues have been
collected for the production period of June 2008. Management performs analysis
on the amounts collected to ensure that the amounts accrued for June are
accurate. See "Provision for Non-recoverable Accounts Receivable" section in
this MD&A for details of a write-off recorded by the Trust for impaired
accounts receivable as at June 30, 2008. Analysis is also performed regularly
on royalties and operating costs to ensure that amounts have been accurately
accrued.
Management uses certain key performance indicators ("KPIs") and industry
benchmarks such as distributions as a per cent of cash flow from operating
activities, 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.

<<
2008 Second Quarter Financial and Operational Results

Financial Highlights
Table 4
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Three Months Ended Six Months Ended
June 30 June 30
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(Cdn $ millions, except % %
per unit and volume data) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 273.4 179.4 52 483.4 351.7 37
Cash flow from operating
activities per unit(1) 1.27 0.86 48 2.25 1.69 33
Net income 57.3 184.9 (69) 138.6 268.2 (48)
Net income per unit(2) 0.27 0.90 (70) 0.65 1.30 (50)
Distributions per unit(3) 0.68 0.60 13 1.28 1.20 7
Distributions as a per cent
of cash flow from
operating activities 53 69 - 56 70 -
Average daily production
(boe/d)(4) 63,896 61,637 4 65,436 62,899 4
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(1) Per unit amounts are based on weighted average trust units
outstanding plus trust units issuable for exchangeable shares at
year-end.
(2) Based on net income after non-controlling interest divided by
weighted average trust units outstanding excluding trust units
issuable for exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Reported production amount is based on company interest 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 the term boe in isolation may be
misleading.
>>

Net Income

Net income in the second quarter of 2008 was $57.3 million ($0.27 per
unit), a decrease of $127.6 million from $184.9 million ($0.90 per unit) in
2007. Although cash flow from operating activities increased $94 million in
the second quarter of 2008 compared to the same period in 2007 (see table 6
for details), there were several non-cash items that negatively impacted the
Trust's net income in the current quarter. In the second quarter of 2008, the
Trust posted a $142.8 million unrealized loss on risk management contracts, a
$153.6 million decrease compared to an unrealized gain of $10.8 million for
the same period of 2007. As well, the Trust recorded a $32.4 million lower
foreign exchange gain on its U.S. denominated debt as a result of the movement
in the Canadian dollar in relation to the U.S. dollar. In addition, the Trust
recorded a $31.1 million income tax recovery for the second quarter of 2008
which was $15.3 million lower than the recovery of $46.4 million booked for
the second quarter of 2007. Finally, an $18 million provision for
non-recoverable accounts receivable was recorded in the second quarter of 2008
(see "Provision for Non-recoverable Accounts Receivable" section in this MD&A
for additional information). In total, the $219.3 million additional losses on
non-cash items more than offset the $94 million increase in cash flow from
operating activities. In addition to the above non-cash items, the Trust's
2007 second quarter net income was increased by recording a $13.3 million cash
gain on the sale of the Trust's long-term investment. The full proceeds of the
long-term investment sale were recorded as part of cash flow from investing
activities.
A measure of sustainability is the comparison of net income to
distributions. Net income incorporates all costs including depletion expense
and other non-cash expenses whereas cash flow from operating activities
measures the cash generated in a given period before the cost of acquiring or
replacing the associated reserves produced. Therefore, net income may be more
representative of the profitability of the entity and thus a relevant measure
against which to measure distributions to illustrate sustainability. As net
income is sensitive to fluctuations in commodity prices and the impact of risk
management contracts, currency fluctuations and other non-cash items, it is
expected that there will be deviations between annual net income and
distributions. Table 5 illustrates the annual shortfall of distributions to
net income as a measure of long-term sustainability.

<<
Table 5
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Net income and Distributions
Q2 YTD
($ millions except per cent) 2008 2008 2007 2006
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Net income 57.3 138.6 495.3 460.1
Distributions 144.7 271.5 498.0 484.2
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(Shortfall) (87.4) (132.9) (2.7) (24.1)
(Shortfall) as per cent of net income (153%) (96%) (1%) (5%)
Distributions as a per cent of cash
flow from operating activities 53% 56% 71% 66%
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Cash Flow from Operating Activities

Cash flow from operating activities increased by 52 per cent in the second
quarter of 2008 to $273.4 million from $179.4 million in the second quarter of
2007. The increase in second quarter 2008 cash flow from operating activities
is detailed in Table 6.

Table 6
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($ per
($ millions) trust unit) (% variance)
-------------------------------------------------------------------------
Q2 2007 Cash flow from Operating
Activities 179.4 0.86 -
-------------------------------------------------------------------------
Volume variance 11.2 0.05 6
Price variance 195.1 0.93 108
Cash losses on risk management
contracts (45.0) (0.22) (26)
Royalties (39.0) (0.19) (22)
Expenses:
Transportation (0.6) - -
Operating(1) (7.3) (0.03) (3)
Cash G&A (7.1) (0.03) (3)
Interest 1.0 - -
Realized foreign exchange gain/loss (0.4) - -
Weighted average trust units - (0.03) (3)
Non-cash and other items(2) (13.9) (0.07) (8)
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Q2 2008 Cash flow from Operating
Activities 273.4 1.27 -
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(1) Excludes non-cash portion of LTIP expense recorded in operating
costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.

Year-to-date cash flow from operating activities increased by 37 per cent
in 2008 to $483.4 million from $351.7 million in the first half of 2007. The
increase in 2008 cash flow from operating activities is detailed in Table 6a.

Table 6a
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($ per
($ millions) trust unit) (% variance)
-------------------------------------------------------------------------
YTD 2007 Cash flow from Operating
Activities 351.7 1.69 -
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Volume variance 28.3 0.14 8
Price variance 278.2 1.33 79
Cash losses on risk management
contracts (81.5) (0.40) (24)
Royalties (55.4) (0.27) (16)
Expenses:
Transportation (0.3) - -
Operating(1) (12.2) (0.06) (4)
Cash G&A (7.5) (0.04) (2)
Interest 2.1 0.01 1
Realized foreign exchange gain/loss (0.2) - -
Weighted average trust units - (0.06) (4)
Non-cash and other items(2) (19.8) (0.09) (5)
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YTD 2008 Cash flow from Operating
Activities 483.4 2.25 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes non-cash portion of LTIP expense recorded in operating
costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.

2008 Cash Flow from Operating Activities Sensitivity

Table 7 illustrates sensitivities to pre-hedged operating income items
with operational changes and changes to the business environment:

Table 7
-------------------------------------------------------------------------
Impact on Annual
Cash flow from operating activities(2)
-------------------------------------------------------------------------
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 114.00 $ 1.00 $ 0.04
Natural gas price (Cdn $AECO/mcf)(1) $ 9.20 $ 0.10 $ 0.03
Cdn$/US$ exchange rate $ 1.00 $ 0.01 $ 0.05
Interest rate on floating rate debt % 4.0 % 1.0 $ 0.03
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.05
Natural gas production volumes (mmcf/d) 195.5 % 1.0 $ 0.02
Operating expenses per boe $ 10.20 % 1.0 $ 0.01
Cash G&A expenses per boe $ 2.71 % 10.0 $ 0.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Analysis does not include the effect of hedging contracts.
(2) Assumes constant working capital.

Production

Table 8
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
% %
Production 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Light & medium crude
oil (bbl/d) 26,288 26,766 (2) 27,003 27,427 (2)
Heavy oil (bbl/d) 1,253 1,333 (6) 1,299 1,379 (6)
Natural gas (mmcf/d) 194.7 176.7 10 199.5 179.8 11
NGL (bbl/d) 3,906 4,088 (4) 3,882 4,124 (6)
-------------------------------------------------------------------------
Total production
(boe/d)(1) 63,896 61,637 4 65,436 62,899 4
% Natural gas production 51 48 51 48
% Crude oil and liquids
production 49 52 49 52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>

Production volumes averaged 63,896 boe per day in the second quarter of
2008 up four per cent from the same period in 2007. The volumes were in line
with management's expectations based on the planned turnarounds that were
completed during the quarter including a major turnaround at Redwater that
shut in production of 4,100 boe per day for approximately eight days. The
Trust continues to record strong volumes in Dawson despite a turnaround
completed in the second quarter. Subsequent to quarter end, the West Doe third
party processing facility has experienced some operational issues that have
caused restricted volumes in the area. A mid-year forecast was completed
during the quarter and the Trust has now revised the full year production
guidance to between 64,000 and 65,000 boe per day.
Table 9 summarizes the Trust's second quarter production by core area:

<<
Table 9
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30, 2008 June 30, 2007
-------------------------------------------------------------------------
Production
Core Total Oil Gas NGL Total Oil Gas NGL
Area(1) (boe/d) (bbl/d)(mmcf/d)(bbl/d) (boe/d) (bbl/d)(mmcf/d)(bbl/d)
-------------------------------------------------------------------------
Central AB 7,450 1,376 29.2 1,203 7,774 1,631 29.0 1,316
Northern AB
& BC 22,481 5,406 92.9 1,607 19,417 5,599 73.9 1,499
Pembina &
Redwater 12,822 8,883 18.4 873 13,515 9,188 19.1 1,136
S.E. AB &
S.W. Sask. 9,811 1,011 52.7 11 9,915 1,070 53.0 9
S.E. Sask.
& MB 11,332 10,865 1.5 212 11,016 10,611 1.7 128
-------------------------------------------------------------------------
Total 63,896 27,541 194.7 3,906 61,637 28,099 176.7 4,088
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is
southwest.

Table 9a summarizes the Trust's production by core area for the first half
of 2008:

Table 9a
-------------------------------------------------------------------------
Six Months Ended Six Months Ended
June 30, 2008 June 30, 2007
-------------------------------------------------------------------------
Production
Core Total Oil Gas NGL Total Oil Gas NGL
Area(1) (boe/d) (bbl/d)(mmcf/d)(bbl/d) (boe/d) (bbl/d)(mmcf/d)(bbl/d)
-------------------------------------------------------------------------
Central AB 7,610 1,418 29.8 1,234 8,131 1,706 30.4 1,353
Northern AB
& BC 22,978 5,656 94.5 1,554 19,770 5,834 74.3 1,553
Pembina &
Redwater 13,410 9,172 20.0 906 13,620 9,361 19.0 1,091
S.E. AB &
S.W. Sask. 9,926 998 53.5 13 10,116 1,094 54.1 8
S.E. Sask.
& MB 11,512 11,058 1.7 175 11,262 10,811 2.0 119
-------------------------------------------------------------------------
Total 65,436 28,302 199.5 3,882 62,899 28,806 179.8 4,124
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is
southwest.
>>

Revenue

Revenue increased to a historical high of $512 million for the second
quarter of 2008. The increase in revenue was attributable to both higher
realized oil and natural gas prices and increased production volumes. Prior to
hedging activities, ARC's total realized commodity price was $88.04 per boe in
the second quarter of 2008, a 62 per cent increase from the $54.48 per boe
received prior to hedging in 2007. For the six months ended June 30, 2008, the
Trust realized $77.24 per boe, a 43 per cent increase over the realized price
of $53.88 per boe received in the comparable period in 2007. Both of these
amounts are prior to hedging losses.
A breakdown of revenue is as follows in Table 10:

<<
Table 10
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
Revenue June 30 June 30
-------------------------------------------------------------------------
% %
($ millions) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Oil revenue 296.5 166.8 78 533.9 328.3 63
Natural gas revenue 184.4 118.6 55 329.3 246.3 34
NGL revenue 29.3 19.6 49 53.3 37.6 42
-------------------------------------------------------------------------
Total commodity revenue 510.2 305.0 67 916.5 612.2 50
Other revenue 1.8 0.6 200 3.4 1.2 183
-------------------------------------------------------------------------
Total revenue 512.0 305.6 68 919.9 613.4 50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

The oil and natural gas prices realized by the Trust are based upon
quality and transportation differentials from major North American commodity
postings. The Trust's realized oil price was 94 per cent of the Edmonton
posted oil prices, slightly higher than the comparable quarter of 2007 where
ARC received 91 per cent. The Trust has not experienced any significant change
in the quality composition of its oil production hence the increase in price
relative to Edmonton posted prices is due to the strengthening of prices for
Light Sour Blend and Medium Sour Blend Cromer postings relative to Edmonton
posted prices. Approximately 45 per cent of ARC's crude oil sales are at
Edmonton posted prices and approximately 40 per cent of ARC's crude oil sales
are at Light Sour and Medium Sour Blend Cromer posted prices. The Trust's
natural gas price of $10.41 per mcf was higher than the AECO monthly average
in the quarter of $9.35 per mcf as a result of volumes sold at the AECO daily
index that on average was higher than the monthly index for the second quarter
of 2008.

<<
Table 11
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Average Benchmark Prices
AECO gas ($/mcf)(1) 9.35 7.37 27 8.24 7.42 11
WTI oil (US$/bbl)(2) 124.00 65.02 91 110.98 61.59 80
Cdn$/US$ foreign
exchange rate 0.99 0.91 9 0.99 0.88 13
Edmonton Posted oil
(Cdn$/bbl) 125.78 71.97 75 111.56 69.54 60
-------------------------------------------------------------------------
ARC Realized Prices
Prior to Hedging
Oil ($/bbl) 118.32 65.21 82 103.63 62.96 65
Natural gas ($/mcf) 10.41 7.38 41 9.07 7.57 20
NGL ($/bbl) 82.29 52.76 56 75.46 50.39 50
-------------------------------------------------------------------------
Total commodity revenue
before hedging ($/boe) 87.73 54.37 61 76.95 53.77 43
Other revenue ($/boe) 0.31 0.11 182 0.29 0.11 164
-------------------------------------------------------------------------
Total revenue before
hedging ($/boe) 88.04 54.48 62 77.24 53.88 43
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

Risk Management and Hedging Activities

ARC continues to maintain an ongoing risk management program to reduce
the volatility of revenues in order to increase the certainty of
distributions, protect acquisition economics, and fund capital expenditures.
The risk management program and Board approved parameters are discussed in the
Trust's 2007 Annual Report filed on SEDAR.
From a corporate perspective the high commodity prices had a significant
positive impact on the Trust's revenue; however, these strong prices resulted
in realized losses recorded on the Trust's oil and natural gas risk management
contracts. In addition, the high forward prices for both oil and natural gas
at the end of the quarter resulted in the recording of large unrealized losses
for both products.
Table 12 is a summary of the total gain (loss) on risk management
contracts for the second quarter of 2008 as compared to the same period in
2007.

<<
Table 12
-------------------------------------------------------------------------

Risk Management Crude Foreign
Contracts Oil & Natural Curr- Q2 2008 Q2 2007
($ millions) Liquids Gas ency(3) Interest Total Total
-------------------------------------------------------------------------
Realized cash
(loss) gain on
contracts(1) (34.7) (10.6) 0.2 0.4 (44.7) 0.3
Unrealized (loss)
gain on
contracts(2) (120.5) (14.1) (5.8) (2.4) (142.8) 10.8
-------------------------------------------------------------------------
Total gain (loss)
on risk management
contracts (155.2) (24.7) (5.6) (2.0) (187.5) 11.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
(3) Unrealized gain on foreign currency contracts includes a $6.3 million
dollar loss on contracts related to repayments of the Trust's U.S.
denominated long-term debt as well as a $0.5 million gain for foreign
currency contracts related the Trust's crude oil contracts. See the
Foreign Exchange Gains and Losses section of this MD&A for further
details on the debt related contracts.

Table 12a
-------------------------------------------------------------------------

Risk Management Crude Foreign YTD YTD
Contracts Oil & Natural Curr- 2008 2007
($ millions) Liquids Gas ency(3) Interest Total Total
-------------------------------------------------------------------------
Realized cash
(loss) gain on
contracts(1) (51.1) (10.3) 0.3 (13.1) (74.2) 7.3
Unrealized (loss)
gain on
contracts(2) (136.3) (26.4) 0.9 0.3 (161.5) (10.1)
-------------------------------------------------------------------------
Total gain (loss)
on risk management
contracts (187.4) (36.7) 1.2 (12.8) (235.7) (2.8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
(3) Unrealized gain on foreign currency contracts includes a $0.7 million
dollar gain on contracts related to repayments of the Trust's U.S.
denominated long-term debt as well as a $0.2 million gain for foreign
currency contracts related the Trust's crude oil contracts. See the
Foreign Exchange Gains and Losses section of this MD&A for further
details on the debt related contracts.
>>

The volatility in the price of oil and natural gas can lead to
significant changes in the mark-to-market position of the Trust's oil and
natural gas contracts. Unrealized losses at June 30, 2008 were calculated
using forward strip prices as of that date. Subsequent to quarter end, prices
have receded, causing a decrease in the Trust's mark-to-market loss position.
Using forward prices as at July 31, 2008, the total mark-to-market position
for oil and natural gas contracts improved $80.5 million to a loss of $150
million as compared to a loss of $230.5 million as at June 30, 2008.
The most significant change of ARC's total unrealized mark-to-market
position at quarter end was a $98.1 million loss relating to the Redwater and
NPCU hedged oil volumes of 5,000 bbl per day, which limits US$ WTI price
potential to $85 and $90 per barrel in 2008 and 2009 respectively. When these
properties were acquired in 2005, the acquisition economics were based on
crude oil prices of approximately US$57.50 per barrel.
For the remainder of 2008 the Trust has unlimited participation on
approximately 70 per cent of forecasted production for the third and fourth
quarters, respectively. The remaining production volumes are capped at average
prices of $90 per barrel on crude oil and Cdn$8.88 per GJ on natural gas.
Table 13 is an indicative summary of the Trust's positions for crude oil,
natural gas and related foreign exchange for the next twelve months as at June
30, 2008:

<<
Table 13
-------------------------------------------------------------------------
Hedge Positions Summary
As at June 30, 2008 (1)(2)
-------------------------------------------------------------------------
Q3 2008 Q4 2008
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 90.00 10,000 90.00 10,000
Bought Put 68.13 10,000 68.13 10,000
Sold Put 51.07 7,000 51.07 7,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 8.47 61,101 9.40 48,570
Bought Put 6.82 61,101 7.20 48,570
Sold Put 5.06 31,101 5.13 10,480
-------------------------------------------------------------------------
Foreign Exchange Cdn$/US$ $ million Cdn$/US$ $ million
-------------------------------------------------------------------------
Bought Put 1.075 3.00 1.075 3.00
Sold Put 1.030 3.00 1.030 3.00
Swap 1.015 12.00 1.015 12.00
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Hedge Positions Summary
As at June 30, 2008 (1)(2)
-------------------------------------------------------------------------
Q1 2009 Q2 2009
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 90.00 5,000 90.00 5,000
Bought Put 55.00 5,000 55.00 5,000
Sold Put 40.00 5,000 40.00 5,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 10.10 42,202 - -
Bought Put 7.51 42,202 - -
Sold Put - - - -
-------------------------------------------------------------------------
Foreign Exchange Cdn$/US$ $ million Cdn$/US$ $ 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 Notes to the Consolidated Financial
Statements for full details of the Trust's hedging positions as at
June 30, 2008.

Table 13 should be interpreted as follows using the third quarter 2008
crude oil hedges as an example. To accurately analyze the Trust's hedge
position, contracts need to be modeled separately as using average prices and
volumes may be misleading.

- If the market price is below $51.07, ARC will receive $68.13 less the
difference between $51.07 and the market price on 7,000 barrels per
day. For example if the market price is $51.06, ARC will receive
$68.12 on 7,000 barrels per day.
- If the market price is between $51.07 and $68.13, ARC will receive
$68.13 on 10,000 barrels per day.
- If the market price is between $68.13 and $90, ARC will receive
the market price on 10,000 barrels per day.
- If the market price exceeds $90, ARC will receive $90 on 10,000
barrels per day.
>>

Operating Netbacks

The Trust's operating netback, after realized commodity and related
foreign exchange hedging losses increased 53 per cent to $53.08 per boe in the
second quarter of 2008 compared to $34.75 per boe in the same period of 2007.
The increase in netbacks in 2008 is primarily due to a 62 per cent increase in
the Trust's weighted average sales price. The large increase in revenue was
partially offset by an increase in royalties and operating costs. In addition,
the Trust's realized hedging loss of $7.67 per boe in the second quarter of
2008 decreased the netback as compared to a realized hedging gain of $0.05 per
boe that was recorded in the second quarter of 2007 as an increase to the
netback.
The components of operating netbacks are shown in Tables 14 and 14a:

<<
Table 14
-------------------------------------------------------------------------
Light and
Medium
Crude Heavy Natural Q2 2008 Q2 2007
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 119.03 103.38 10.41 82.29 87.73 54.37
Other revenue - - - - 0.31 0.11
-------------------------------------------------------------------------
Total revenue 119.03 103.38 10.41 82.29 88.04 54.48
Royalties (18.51) (11.38) (2.15) (22.96) (15.79) (9.43)
Transportation (0.19) (1.06) (0.23) - (0.79) (0.72)
Operating costs(1) (15.50) (10.63) (1.18) (8.40) (10.71) (9.63)
-------------------------------------------------------------------------
Netback prior to
hedging 84.82 80.32 6.84 50.93 60.75 34.70
Realized gain (loss)
on risk management
contracts (14.36) - (0.60) - (7.67) 0.05
-------------------------------------------------------------------------
Netback after
hedging 70.46 80.32 6.24 50.93 53.08 34.75
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.

Table 14a

-------------------------------------------------------------------------
Light and
Medium YTD YTD
Crude Heavy Natural 2008 2007
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 104.62 83.20 9.07 75.46 76.95 53.77
Other revenue - - - - 0.29 0.11
-------------------------------------------------------------------------
Total revenue 104.62 83.20 9.07 75.46 77.24 53.88
Royalties (16.23) (8.96) (1.85) (21.31) (13.77) (9.54)
Transportation (0.11) (1.19) (0.23) - (0.76) (0.77)
Operating costs(1) (13.67) (10.76) (1.23) (8.35) (10.11) (9.30)
-------------------------------------------------------------------------
Netback prior to
hedging 74.61 62.29 5.76 45.80 52.60 34.27
Realized gain (loss)
on risk management
contracts(2) (10.33) - (0.28) - (6.23) 0.64
-------------------------------------------------------------------------
Netback after
hedging 64.28 62.29 5.48 45.80 46.37 34.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.
(2) Realized loss on risk management contracts excludes the settlement
amount for the treasury interest rate lock contracts that were
unwound during the first quarter of 2008.
>>

Royalties as a percentage of pre-hedged commodity revenue net of
transportation costs increased slightly from 17.5 per cent of revenue to
18.1 per cent for the second quarters of both 2007 and 2008 respectively at
$9.43 per boe and $15.79 per boe, respectively.
On April 10, 2008, the Alberta Government announced revisions to the New
Royalty Framework ("Framework") that will take effect on January 1, 2009. The
revisions to the Framework include a deep resource program that will provide
royalty relief for high cost oil and natural gas development. The program only
applies to oil wells greater than 2,000 meters in depth and natural gas wells
greater than 2,500 meters in depth. The Trust does not perceive that this
revision will benefit the Trust given its current drilling portfolio.
The Trust's current estimate, using forward prices as of the date of this
MD&A, is that under the Framework, the corporate average royalty rate for the
Trust will increase from 18 per cent to approximately 23 per cent of revenue
based on current commodity prices. This estimate will vary based on prices,
production decline of existing wells and performance and location of new wells
drilled. The Trust is actively working with its production accounting system
provider to ensure that the proper infrastructure will be in place to allow
the Trust to accurately calculate royalties in accordance with the new
Framework starting on January 1, 2009.
Operating costs increased to $10.71 per boe in the second quarter of 2008
compared to $9.63 per boe in the second quarter of 2007. The Trust completed
significant scheduled turnarounds in the second quarter including a large
scale turnaround at ARC's Redwater oil field which resulted in higher total
operating costs and lower volumes for the period. Costs for this third quarter
are expected to remain high as turnarounds continue throughout the summer
months. For 2008, the Trust has budgeted $10.20 per boe based on production of
between 64,000 and 65,000 barrels per day. Total operating costs are projected
to be approximately $235 million for the full year of 2008.
Transportation costs were constant year over year and averaged $0.79 per
boe in the second quarter of 2008.

General and Administrative Expenses and Trust Unit Incentive Compensation

Cash G&A expenses net of overhead recoveries on operated properties,
excluding cash costs of the Whole Trust Unit Incentive Plan ("Whole Unit
Plan"), increased 10 per cent to $9.8 million in the second quarter of 2008
from $8.9 million in the same period of 2007. Increases in G&A expenses for
2008 were due to increased staff levels and higher compensation costs.
A cash payment occurred under the Whole Unit Plan in April 2008 and
included a payout for the performance units issued in April of 2005. The
actual payment for April was $18.3 million of which $14.4 million was recorded
in G&A with the remainder of $3.9 million being recorded to operating costs
and capital projects. These amounts were fully accrued at the end of the first
quarter in 2008; however, the cash flow from operating activities for the
second quarter has been decremented for the full amount of the cash payment.
Payments under this plan are directly related to ARC's unit price and total
return performance relative to its peers. For the three year period to April
2008, ARC was a top quartile performer. The next payment under the Whole Unit
Plan will take place in the fourth quarter of this year.
The Trust recorded a non-cash expense of $(1.7) million during the second
quarter, which represents the estimated costs of the Whole Unit Plan for the
period net of the accrual reversal for the cash payment amount made in April
2008.
In a news release issued on June 26, 2008, the Trust revised its full
year guidance for G&A to $3.15 per boe, an increase of $0.15 per boe from
previously released guidance numbers. The increase is to reflect the increased
costs for the Whole Unit Plan, which is impacted by the increase in
distributions as well as the appreciation in the trust unit price and relative
performance amongst the Trust's peers.
Table 15 is a breakdown of G&A and trust unit incentive compensation
expense:

<<
Table 15
-------------------------------------------------------------------------
G&A and Trust Unit
Incentive Compensation Three Months Ended Six Months Ended
Expense June 30 June 30
-------------------------------------------------------------------------
($ millions except % %
per boe) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
G&A expenses 13.8 12.7 9 27.0 26.2 3
Operating recoveries (4.0) (3.8) 5 (7.9) (8.5) (7)
Whole Unit Plan - cash 14.4 8.3 73 14.4 8.3 73
- accrued (1.7) (4.3) (60) 10.2 (4.0) 355
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense 22.5 12.9 75 43.7 22.0 99
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense per boe 3.88 2.29 69 3.67 1.93 90
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Whole Unit Plan

The Whole Unit Plan results in each employee, officer and director (the
"plan participants") receiving cash compensation in relation to the value of a
specified number of underlying trust units. The Whole Unit Plan consists of
Restricted Trust Units ("RTUs") for which the number of units is fixed and
will vest over a period of three years and Performance Trust Units ("PTUs")
for which the number of units is variable and will vest at the end of three
years.
Upon vesting, the plan participant is entitled to receive a cash payment
based on the fair value of the underlying trust units plus accrued
distributions. The cash compensation issued upon vesting of the PTUs is
dependent upon the performance of the Trust compared to its peers and
indicated by the performance multiplier. The performance multiplier is based
on the percentile rank of the Trust's total unitholder return compared to its
peers. Total return is calculated as the sum of the change in the market price
of the trust units in the period plus the amount of distributions in the
period. The performance multiplier ranges from zero, if ARC's performance
ranks in the bottom quartile, to two for top quartile performance.
Table 16 shows the changes during the first six months of 2008 for RTUs
and PTUs outstanding:

<<
Table 16
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and $ millions Number Number Total RTUs
except per unit) of RTUs of PTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 746 903 1,649
Granted in the period 199 173 372
Vested in the period (193) (183) (376)
Forfeited in the period (30) (30) (60)
-------------------------------------------------------------------------
Balance, end of period(1) 722 863 1,585
-------------------------------------------------------------------------
Estimated distributions to vesting date(2) 190 304 494
Estimated units upon vesting after
distributions 912 1,167 2,079
Performance multiplier(3) - 1.6 -
-------------------------------------------------------------------------
Estimated total units upon vesting 912 1,842 2,754
-------------------------------------------------------------------------
Trust unit price at June 30, 2008 $33.95 $33.95 $33.95
Estimated total value upon vesting 31.0 62.5 93.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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, 2008 based on a weighted average calculation of
all outstanding grants. The performance multiplier is assessed each
period end based on actual results of the Trust relative to its
peers.
>>

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 unit price, the number of PTUs to be issued on vesting, and distributions.
In periods where substantial unit price fluctuation occurs, the Trust's G&A
expense is subject to significant volatility.
Table 17 is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier and units
outstanding as at June 30, 2008:

<<
Table 17
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
June 30, 2008 Performance multiplier
-------------------------------------------------------------------------
(units thousands and $ millions
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated units to vest
RTUs 912 912 912
PTUs - 1,167 2,333
-------------------------------------------------------------------------
Total units(1) 912 2,079 3,245
-------------------------------------------------------------------------
Trust unit price(2) $33.95 $33.95 $33.95
Trust unit distributions per month(2) $0.28 $0.28 $0.28
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting 31.0 70.6 110.2
-------------------------------------------------------------------------
Officers 3.6 22.7 41.8
Directors 2.0 2.0 2.0
Staff 25.4 45.9 66.4
-------------------------------------------------------------------------
Total payments under Whole Unit Plan(3) 31.0 70.6 110.2
-------------------------------------------------------------------------
2008 6.3 9.5 12.7
2009 12.8 25.2 37.6
2010 8.9 25.0 41.1
2011 3.0 10.9 18.8
-------------------------------------------------------------------------
(1) Includes additional estimated 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. Assumes
future trust unit price of $33.95 per trust unit and distributions of
$0.28 per 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 March
and April for the spring grants, and September and October for the
fall grants 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 between $31 million and $110.2 million will be paid out from
2008 through 2011 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.

Provision for Non-recoverable Accounts Receivable

On July 22, 2008, a counterparty that markets a portion of the Trust's
production filed for protection under the Companies' Creditors Arrangement Act
("CCAA"). As a result, the Trust recorded a provision for non-recoverable
accounts receivable of $18 million ($13.5 million net of tax). Management
believes that some portion of the $18 million owed by SemCanada is
recoverable; however, it is indeterminable at this time and therefore the
provision has been recorded for the full amount. The Trust may record an
additional provision in the third quarter for July production delivered to
SemCanada to the date of the CCAA filing based on a maximum estimated July
exposure of $15 million ($11.3 million net of tax), bringing the total
exposure to $33 million including the June receivable amount. The Trust
believes it has no additional exposure to SemCanada for deliveries of
production after July 22, 2008 as all production has now been re-assigned to
new counterparties.

Interest Expense

Interest expense decreased to $8.3 million in the second quarter of 2008
from $9.3 million in the second quarter of 2007 due to a decrease in
short-term interest rates. As at June 30, 2008, the Trust had $687 million of
debt outstanding, of which $222.1 million was fixed at a weighted average rate
of five per cent and $464.9 million was floating at current market rates plus
a credit spread of 60 basis points. The Canadian market interest rates have
declined to approximately 3.8 per cent in the second quarter of 2008 as
compared to approximately 4.6 per cent in the same period of 2007. U.S. London
Inter-Bank Offer Rate ("LIBOR") interest rates have declined to approximately
3.1 per cent in the second quarter of 2008 as compared to approximately six
per cent in the same period of 2007. The decrease in both Canadian and U.S.
LIBOR market interest rates have resulted in lower borrowing costs for the
Trust. Fifty-six per cent of the Trust's debt is denominated in U.S. dollars.

Foreign Exchange Gains and Losses

In the second quarter of 2008, the Trust recorded a gain of $3.1 million
on foreign exchange transactions compared to a gain of $35.5 million in the
same period of 2007. These amounts include both realized and unrealized
foreign exchange gains and losses.
Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements.
Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The movement of the Canadian dollar at the end
of the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain/loss impacts net income but
does not impact cash flow from operating activities as it is a non-cash
amount. From March 31, 2008 to June 30, 2008, the Cdn$/US$ exchange rate
increased from 0.97 to 0.98 creating an unrealized gain of $3.6 million on
U.S. dollar denominated debt. ARC has entered into forward contracts to lock
in exchange rates for principal repayments on US$127.2 million of the
US$218 million debt outstanding. The forward contracts had a mark-to-market
gain position at June 30, 2008 of $3.3 million. These contracts have been
included in the unrealized risk management contracts on the Consolidated
Statement of Income and Deficit.

Taxes

In the second quarter of 2008 the Trust recorded a future income tax
recovery of $31.1 million versus an income tax recovery of $46.4 million in
the second quarter of 2007. The recovery recorded in the second quarter of
2007 related to the substantive enactment of bill C-52 that included the trust
taxation legislation. The Trust recorded a reduction of 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. In 2008, the Trust's future tax recovery is a
result of the current unrealized mark-to-market loss on risk management
contracts. The Trust has recorded a current future income tax asset of
$52.4 million as at June 30, 2008 relating to the current portion of
mark-to-market losses on risk management contracts. The net future tax
liability on the balance sheet reflects the estimated tax liability associated
with the Trust's income tax pools being less than the net book value of the
Trust's assets. Each quarter as the Trust makes distributions it effectively
passes the taxable income in the current period on to its unitholders.
On February 26, 2008, the Federal Government announced as part of the
Federal budget that the provincial component of the tax on the Trust is to be
calculated based on the general provincial rate in each province in which the
Trust has a permanent establishment. This is the same way a corporation would
calculate its provincial tax rate, and is different than the original
calculation of the tax on the Trust, which had a deemed provincial rate of 13
per cent rather than Alberta's provincial rate of 10 per cent. At the time of
writing this MD&A, the Federal budget had been substantively enacted; however,
the specific rules for determining the provincial rates for trusts were not
released in draft legislation until July 14 and therefore have not been
substantively enacted at June 30, 2008. As a result, a reduction in the tax
rate used for the Trust's future income tax calculation has not been
reflected.
On July 14, 2008, the Department of Finance released proposed amendments
(the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the
conversion of existing income trusts into corporations. In general, the
proposed amendments will permit a conversion to be tax deferred for both the
unitholders and the income trust. However, the Conversion Rules provide
alternative approaches to completing a tax deferred conversion. The Department
of Finance has requested comments on the Conversion Rules by September 15,
2008 and it is anticipated that there will be further amendments to the
Conversion Rules. Management and the Board of Directors continue to review the
impact of the Trust tax on our business strategy and while there has not been
a decision as to ARC's future direction, at this time we are of the opinion
that the conversion from a trust into a corporation may be the most logical
and tax efficient alternative for ARC unitholders. 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 relative after-tax distribution amount in 2011 to taxable Canadian
investors will remain approximately the same, however, will decline for both
tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and
foreign investors.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate decreased to
$15.98 per boe in the second quarter of 2008 from $16.31 per boe in the second
quarter of 2007. Total depletion of oil and gas assets increased by $2 million
due to an increase in the Trust's production volumes for the quarter.
A breakdown of the DD&A rate is a follows:

<<
Table 18
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
DD&A Rate June 30 June 30
-------------------------------------------------------------------------
($ millions except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Depletion of oil & gas
assets(1) 90.7 88.5 2 185.4 180.1 3
Accretion of asset
retirement obligation(2) 2.3 2.9 (20) 4.6 5.8 (21)
-------------------------------------------------------------------------
Total DD&A expense 93.0 91.4 2 190.0 185.9 2
DD&A rate per boe 15.98 16.31 (2) 15.95 16.33 (2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 Net Acquisitions

During the second quarter of 2008, the Trust spent $131.3 million on
capital expenditures that includes $57.8 million for purchases of undeveloped
land at land sales. In addition, $0.3 million was spent on net acquisitions of
both producing properties and undeveloped land. Year-to-date, the Trust has
spent $242.6 million on capital expenditures, including $86.6 million on
undeveloped land, as well as $10.4 million on minor producing property and
undeveloped land property acquisitions.
The following summarizes the Trust's year-to-date spending as it relates
to our strategic focus areas:

Resource Plays

Total spending for projects in the Montney resource play, the Bakken
resource play, as well as the Trust's natural gas from coal ("NGC") projects,
was $125.9 million including land purchases of $84.3 million.
ARC spent a total of $32.5 million ($110.6 million including crown land
purchases and purchases from other companies) during the period on Montney
related activities in the Dawson area. Included in these costs were, $15
million for costs to drill four horizontal and two vertical wells, $11 million
for completion and facilities costs as well as $6.5 million for seismic in the
Sunrise area. Of the four horizontal wells drilled during the first half of
the year, three wells have been completed and tested; the remaining well is
expected to be completed in the fourth quarter.
During the second quarter, the Trust purchased undeveloped Bakken land
for $19.9 million and spent $2.4 million drilling its first Bakken well at
Lost Horse Hills which is the first well in an eight well Bakken program.
In addition, $6.8 million was spent on NGC projects year-to-date.

Tertiary EOR Initiatives

Total spending of $30.6 million included $8.5 million spent on the
Redwater CO(2) injection pilot project during the first six months of 2008.
Subsequent to quarter end, the Trust received final approvals from the Energy
Resources Conservation Board for the pilot project and will begin injecting
CO(2) during the third quarter. In addition, $10.6 million has been spent at
Weyburn where the Trust participates in the CO(2) flooding project that is
operated by EnCana. Finally, the Trust spent $11.5 million on projects at
Midale where the Trust participates in the CO(2) flooding project that is
operated by Apache.

Conventional Assets

Total spending of $86.1 million, including land purchases, for various
projects including drilling and completing 13 oil wells (9 net) in the Pembina
Cardium area, 12 of which were brought on production during the first half of
the year. In southwest Saskatchewan, 24 shallow gas wells were completed and
brought on production. In addition, the Trust spent approximately $3 million
on seismic in Ante Creek and other core areas as well as $6 million on three
horizontal water injection wells at Ante Creek as part of a water flood
project expected to increase oil reserves recovered.

Acquisitions and Dispositions

The Trust completed minor net property acquisitions in the second quarter
for $0.3 million and $10.4 million year-to-date. Included in the year-to-date
amount is an acquisition of undeveloped property for $13.7 million that is
included in the Montney resource play land purchases discussed above.
A breakdown of capital expenditures and net acquisitions is shown in
Table 19:

<<
Table 19
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
Capital Expenditures June 30 June 30
-------------------------------------------------------------------------
% %
($ millions) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Geological and
geophysical 16.4 4.1 300 21.9 9.0 144
Drilling and completions 32.6 25.8 26 97.0 80.9 20
Plant and facilities 24.1 16.3 48 35.7 33.1 8
Undeveloped land 57.8 1.7 3,300 86.6 9.0 863
Other capital 0.4 0.6 (33) 1.4 1.1 27
-------------------------------------------------------------------------
Total capital
expenditures 131.3 48.5 171 242.6 126.0 93
-------------------------------------------------------------------------
Producing property
acquisitions(1) 0.4 14.6 (97) 0.3 14.8 (98)
Undeveloped land property
acquisitions - - - 13.9 - 100
Producing property
dispositions(1) (0.1) (4.6) (98) (0.1) (4.6) (98)
Undeveloped land property
dispositions - - - (3.7) - 100
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 131.6 58.5 125 253.0 136.2 86
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.

Approximately 96 per cent of the $131.3 million capital program in the
second quarter of 2008 was financed with cash flow from operating activities
compared to 100 per cent in the same period of 2007. Property acquisitions
were financed through proceeds from the DRIP and rights plan. On a
year-to-date basis, the Trust has funded 85 per cent of the capital
expenditures with cash flow from operating activities as compared to 79
percent for the first six months of 2007.

Table 20
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30, 2008 June 30, 2007
-------------------------------------------------------------------------
Develop- Net Total Develop- Net Total
ment Acquisi- Expendi- ment Acquisi- Expendi-
Capital tions tures Capital tions tures
-------------------------------------------------------------------------
Expenditures 131.3 0.3 131.6 48.5 10.0 58.5
-------------------------------------------------------------------------
Cash flow from
operating
activities 96% - 95% 100% 50% 91%
Proceeds from
DRIP and
Rights Plan 4% 100% 5% - 50% 9%
Debt - - - - - -
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Table 20a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
YTD June 30, 2008 YTD June 30, 2007
-------------------------------------------------------------------------
Develop- Net Total Develop- Net Total
ment Acquisi- Expendi- ment Acquisi- Expendi-
Capital tions tures Capital tions tures
-------------------------------------------------------------------------
Expenditures 242.6 10.4 253.0 126.0 10.2 136.2
-------------------------------------------------------------------------
Cash flow from
operating
activities 85% - 81% 79% - 73%
Proceeds from
DRIP and
Rights Plan 15% 100% 19% 21% 100% 27%
Debt - - - - - -
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Asset Retirement Obligation and Reclamation Fund

The Asset Retirement Obligation ("ARO") increased by $2 million in the
first half of 2008 to $142 million ($140 million at December 31, 2007) for
future abandonment and reclamation of the Trust's properties.
Included in the June 30, 2008 ARO balance is a $3.4 million increase
related to development activities in the first half of 2008 as well as changes
in estimates for the existing liability. The ARO liability was also increased
by $4.6 million for accretion expense in the period and was reduced by
$6 million for actual abandonment expenditures incurred in the first half of
2008.
The Trust maintains two reclamation funds that together held
$25.4 million at June 30, 2008, one exclusively for the reclamation of the
Redwater property and the other for all of the Trust's other properties.
In total, ARC contributed $6 million cash to its reclamation funds in the
first half of 2008 and earned interest of $0.6 million on the fund balances.
The fund balances were reduced by $7.4 million for cash-funded abandonment
expenditures in the first six months of 2008.

Capitalization, Financial Resources and Liquidity

A breakdown of the Trust's capital structure is detailed in Table 21 as
at June 30, 2008 and December 31, 2007:

<<
Table 21
-------------------------------------------------------------------------
Capital Structure and Liquidity June 30, December 31,
($ millions except per cent and ratio amounts) 2008 2007
-------------------------------------------------------------------------
Net debt obligations(1) 756.1 752.7
Market value of trust units and exchangeable
shares(2) 7,326.4 4,349.3
-------------------------------------------------------------------------
Total capitalization(3) 8,082.5 5,102.0
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 9.4% 14.8%
Net debt to annualized cash flow from operating
activities 0.8 1.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net debt is a non-GAAP measure and is calculated as long-term debt
plus current liabilities less the current assets as they appear on
the Consolidated Balance Sheets. Net debt excludes current unrealized
amounts pertaining to risk management contracts and the current
portion of future income taxes.
(2) Calculated using the total units outstanding at June 30, 2008
including the total number of units issuable for exchangeable shares
at June 30, 2008 multiplied by the closing trust unit price of
$33.95.
(3) 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.
>>

The Trust's current credit facilities comprise US$218 million in senior
secured notes currently outstanding, a Cdn$800 million syndicated bank credit
facility, of which $452.4 million was outstanding at June 30, 2008 and a
Cdn$25 million demand working capital facility, of which $12.5 million was
outstanding at June 30, 2008. On April 15, 2008 ARC extended the credit
facility to April 2011 under the same terms. The credit facility syndicate
includes 11 domestic and international banks. The Trust's debt agreements
contain a number of covenants all of which were met as at June 30, 2008; these
agreements are available at www.SEDAR.com. The major financial covenants are
described below:

<<
- Long-term debt is not to exceed three times annualized cash flow from
operating activities prior to interest expense, expenditures on site
restoration and reclamation and changes in non-cash working capital.
- Long-term debt is not to exceed 50 per cent of unitholders equity
plus long-term debt.
>>

As at June 30, 2008 ARC has approximately $348 million available under
its bank credit facility and the ability to issue an additional $100 million
of long-term notes under an agreement with one lender. This option, which will
expire in May 2009, would allow the Trust to issue long-term notes at a rate
equal to the related U.S. treasuries corresponding to the term of the notes
plus an appropriate credit risk adjustment at the time of issuance.

Unitholders' Equity

At June 30, 2008, there were 215.8 million trust units issued and
issuable for exchangeable shares, an increase of 2.6 million trust units from
December 31, 2007. The increase in number of trust units outstanding is mainly
attributable to the 2.3 million trust units issued pursuant to the DRIP during
the six months of 2008 at an average price of $24.07 per unit.
The Trust had five thousand rights outstanding as of June 30, 2008 under
an employee plan where further rights issuances were discontinued in 2004. The
rights have a five-year term and vested equally over three years from the date
of grant. The remaining rights may be exercised to purchase trust units at an
average adjusted exercise price of $10.81 per unit as at June 30, 2008. All of
the rights were fully vested at December 31, 2007 and will expire on or before
December 31, 2008.
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 first half of 2008, the Trust raised proceeds of
$55 million and issued 2.3 million trust units pursuant to the DRIP.

Distributions

ARC declared distributions of $144.7 million ($0.68 per unit),
representing 53 per cent of 2008 second quarter cash flow from operating
activities compared to distributions of $124.1 million ($0.60 per unit), and
representing 69 per cent of cash flow from operating activities in the second
quarter of 2007. This includes two months of the "top-up" distribution
announced in May 2008 where the distributions declared for May and June 2008
were $0.24 per unit. Year-to-date 2008 distributions totaled $271.5 million
($1.28 per unit) as compared to $247.2 million ($1.20 per unit) for the same
period in 2007.
In June 2008, the Trust announced an increase in the monthly distribution
"top-up" to $0.08 per unit. For distributions declared in July 2008, the total
distribution will be $0.28 per unit. The "top-up" distribution will be
reviewed on a quarterly basis but is expected to stay in place as long as
commodity prices maintain their current strength. Revisions to distribution
amounts are approved at the discretion of the Board of Directors and are
normally announced on a quarterly basis in the context of prevailing and
anticipated commodity prices at that time. The following items, outlined in
Table 22, may be deducted from cash flow from operating activities to arrive
at distributions to unitholders: the portion of capital expenditures that are
funded with cash flow from operating activities, an annual contribution to the
reclamation funds, debt principal repayments from time to time as determined
by the board of directors and income taxes that are not passed on to
unitholders.
Cash flow from operating activities and distributions in total and per
unit are detailed in Table 22 and Table 22a:

<<
Table 22
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30 June 30
($millions) ($ per unit)
Cash flow from
operating activities % %
and distributions 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 273.4 179.4 52 1.27 0.86 48
Reclamation fund
contributions(1) (3.3) (1.8) 83 (0.02) (0.01) 100
Capital expenditures funded
with cash flow from
operating activities (125.4) (53.5) 134 (0.58) (0.26) 123
Other(2) - - - 0.01 0.01 -
-------------------------------------------------------------------------
Distributions 144.7 124.1 17 0.68 0.60 13
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Table 22A
-------------------------------------------------------------------------
YTD June 30 YTD June 30
($millions) ($ per unit)
Cash flow from
operating activities % %
and distributions 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 483.4 351.7 37 2.25 1.69 33
Reclamation fund
contributions(1) (6.6) (5.1) 29 (0.03) (0.02) 47
Capital expenditures funded
with cash flow from
operating activities (205.3) (99.4) 107 (0.96) (0.48) (94)
Other(2) - - - 0.02 0.01 100
-------------------------------------------------------------------------
Distributions 271.5 247.2 10 1.28 1.20 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operating activities are based on weighted average outstanding trust
units in the year plus trust units issuable for exchangeable shares
at period-end.
>>

Please refer to the Trust's website at www.arcenergytrust.com for details
on 2008 monthly distributions and distribution dates for 2008.

Environmental Legislation Impacting the Trust

On July 8, 2008 the Alberta government announced two new funds totaling
$4 billion to reduce greenhouse gas emissions. The province will create a
$2 billion fund to advance carbon capture and storage projects while a second
$2 billion fund will propel energy-saving public transit in Alberta. The Trust
is actively working to gain an understanding of how the carbon capture funds
will be allocated as it may allow the Trust access to additional funding for
its ongoing carbon capture and storage projects at Redwater and may increase
the possibility of achieving commercial viability of the CO(2) injection
program if proper infrastructure is put in place to capture and deliver CO(2)
to the Redwater area.
On February 19, 2008 the British Columbia government introduced a
consumer-based carbon tax. Effective July 1, 2008, ARC is required to pay tax
on all fuel used in the course of operations in that province. At present, the
Trust has assessed that the above mentioned legislation will negatively impact
the Trust by less than $1 million per year.

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, regulatory
fees, and lease rental obligations and employee agreements. These obligations
are of a recurring and consistent nature and impact the Trust's cash flows 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, 2008:

<<
Table 23
-------------------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------------------
2009- 2011- There-
($ millions) 2008 2010 2012 after Total
-------------------------------------------------------------------------
Debt repayments(1) 18.6 43.0 505.5 119.9 687.0
Interest payments(2) 5.6 20.5 15.8 14.0 55.9
Reclamation fund contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase commitments 5.0 5.3 4.3 6.2 20.8
Operating leases 4.2 8.6 12.3 88.1 113.2
Derivative contract premiums(4) 6.2 2.9 - - 9.1
-------------------------------------------------------------------------
Total contractual obligations 45.4 90.5 546.8 300.1 982.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 risk management contract premiums noted in Table 23 are part of the
Trust's commitments related to its risk management program. In addition to
these premiums, the Trust has additional commitments related to its risk
management program that fluctuate based on market conditions. As the premiums
are part of the underlying risk management contract, they have been recorded
at fair market value at June 30, 2008 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 a 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 2008 capital budget has
been approved by the Board at $550 million. This commitment has not been
disclosed in the commitment table (Table 23) as it is of a routine nature and
is part of normal course of operations for active oil and gas companies and
trusts.
The operating leases noted in Table 23 include amounts for the Trust's
head office lease. The current lease expires in May 2010. In December 2007,
the Trust entered into a 13 year lease commitment beginning in 2010 for office
space in a new building that is under construction in downtown Calgary. The
new lease commitment is reflected in Table 23. In addition to the lease
commitments included in Table 23, the Trust will incur additional costs to
design and construct the office space. No material commitments have been
entered into at this time, however the Trust has currently committed to costs
of less than $1 million for consulting costs related to the build out of the
office space.
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 commitment 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 (Table 23), 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,
2008.

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, interest
rates, 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 over Financial Reporting and Disclosure Controls and
Procedures

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 2008 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 2008.

Financial Reporting Update

Current Year Accounting Changes

Effective January 1, 2008, the Trust adopted three new accounting
standards that were issued by the Canadian Institute of Chartered Accountants
("CICA"): Handbook Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures and Section 3863, Financial Instruments -
Presentation.

<<
A. Capital Disclosures

Section 1535 establishes standards for disclosing information regarding an
entity's capital and how it is managed.

B. Financial Instruments - Disclosures, Financial Instruments -
Presentation

Sections 3862 and 3863 establish standards for enhancing financial
statements users' understanding of the significance of financial instruments
to an entity's financial position, performance and cash flows. They require
that entities provide disclosures regarding the nature and extent of risks
arising from financial instruments to which they are exposed both during the
reporting period and at the balance sheet date, as well as how the entities
manage those risks.
These standards were adopted prospectively.

Future Accounting Changes

A. Goodwill and Intangible Assets

In February 2008, the CICA issued Section 3064, Goodwill and Intangible
Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
Section 3450, Research and Development Costs. The new Section will be
effective on January 1, 2009. Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. Standards concerning
goodwill are unchanged from the standards included in the previous Section
3062. The Trust is currently evaluating the impact of the adoption of this new
Section, however does not expect a material impact on its consolidated
financial statements.

B. International Financial Reporting Standards ("IFRS")

>>

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a
strategic plan for the direction of accounting standards in Canada. As part of
that plan, the AcSB confirmed in February 2008 that International Financial
Reporting Standards ("IFRS") will replace Canadian GAAP in 2011 for profit
oriented Canadian publicly accountable enterprises. The Trust is currently
evaluating the impacts of its conversion to IFRS. At this time, the Trust has
appointed internal staff to lead the conversion project along with sponsorship
from the senior leadership team. In addition, an external advisor has been
retained to assist the Trust in scoping its conversion project.

Forward-Looking Statements

This discussion and analysis contains forward-looking statements as to
the Trust's 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 and, in
particular, includes the material under the heading "2008 Guidance". 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 2008, the continuation of ARC's
historical experience with expenses and production, changes in the capital
expenditure budgets relating to undeveloped land or reserve acquisitions 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, and related to management's assumptions
set forth herein, 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
actual results to differ materially from those predicted. Other than the 2008
Guidance which is updated and discussed quarterly, the Trust does not
undertake to update any forward looking information in this document whether
as to new information, future events or otherwise except as required by
securities laws and regulations.

Additional Information

Additional information relating to ARC can be found in the Trust's Annual
Information Form filed on SEDAR at www.sedar.com.

<<

QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit amounts) 2008 2007
-------------------------------------------------------------------------
FINANCIAL Q2 Q1 Q4 Q3
Revenue before royalties 512.0 407.9 338.0 300.2
Per unit(1) 2.38 1.91 1.59 1.42
Cash flow from operating
activities(2) 273.4 209.9 173.7 179.6
Per unit - basic(1) 1.27 0.98 0.82 0.85
Per unit - diluted 1.27 0.98 0.82 0.85
Net income 57.3 81.3 106.3 120.8
Per unit - basic(3) 0.27 0.39 0.51 0.58
Per unit - diluted 0.27 0.38 0.51 0.58
Distributions 144.7 126.8 125.8 125.0
Per unit - basic(4) 0.68 0.60 0.60 0.60
Total assets 3,664.3 3,592.6 3,533.0 3,460.8
Total liabilities 1,689.6 1,560.4 1,491.3 1,421.4
Net debt outstanding(5) 756.1 770.1 752.7 699.8
Weighted average trust units(6) 215.2 213.8 212.5 210.9
Trust units outstanding and
issuable(6) 215.8 214.7 213.2 211.7
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 16.4 5.5 3.0 2.9
Land 57.8 28.8 42.6 33.0
Drilling and completions 32.6 64.4 75.2 73.4
Plant and facilities 24.1 11.6 17.9 21.1
Other capital 0.4 1.0 0.6 1.5
Total capital expenditures 131.3 111.3 139.3 131.9
Property acquisitions
(dispositions) net 0.3 10.1 5.0 27.3
Corporate acquisitions(7) - - - -
Total capital expenditures and
net acquisitions 131.6 121.4 144.3 159.2
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 27,541 29,064 28,682 28,437
Natural gas (mmcf/d) 194.7 204.3 187.4 173.3
Natural gas liquids (bbl/d) 3,906 3,856 4,067 3,795
Total (boe per day 6:1) 63,896 66,976 63,989 61,108
Average prices
Crude oil ($/bbl) 118.32 89.72 77.53 73.40
Natural gas ($/mcf) 10.41 7.80 6.32 5.52
Natural gas liquids ($/bbl) 82.29 68.54 62.75 55.64
Oil equivalent ($/boe) 87.73 66.67 57.26 53.28
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
unit prices
High 33.95 27.06 21.55 22.60
Low 25.19 20.00 18.90 19.00
Close 33.95 26.38 20.40 21.17
Average daily volume (thousands) 659 863 624 503
-------------------------------------------------------------------------
-------------------------------------------------------------------------

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 from operating
activities(2) 179.4 172.3 159.4 203.4
Per unit - basic(1) 0.86 0.83 0.77 0.99
Per unit - diluted 0.86 0.83 0.77 0.98
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 - basic(4) 0.60 0.60 0.60 0.60
Total assets 3,432.8 3,540.1 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 trust units(6) 209.5 207.9 206.5 205.1
Trust 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) 54.37 53.18 49.82 54.45
-------------------------------------------------------------------------
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
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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) This is a GAAP measure and a change from the non-GAAP measure
reported in prior reports. Refer to non-GAAP 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 the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(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(unaudited)
As at June 30 and December 31

(Cdn$ millions) 2008 2007
-------------------------------------------------------------------------

ASSETS
Current assets
Cash $ - $ 7.0
Accounts receivable (Note 3) 178.4 162.5
Prepaid expenses 16.3 15.0
Risk management contracts (Notes 3 and 9) 10.4 13.1
Future income taxes (Note 9) 52.4 4.0
-------------------------------------------------------------------------
257.5 201.6
Reclamation funds (Note 4) 25.4 26.1
Risk management contracts (Notes 3 and 9) 9.8 4.7
Property, plant and equipment 3,214.0 3,143.0
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,664.3 $ 3,533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 5) $ 212.6 $ 180.6
Distributions payable 51.2 42.1
Risk management contracts (Notes 3 and 9) 191.9 57.6
-------------------------------------------------------------------------
455.7 280.3
Risk management contracts (Notes 3 and 9) 49.0 28.2
Long-term debt (Note 6) 687.0 714.5
Accrued long-term incentive compensation (Note 15) 19.6 12.1
Asset retirement obligations (Note 7) 142.0 140.0
Future income taxes 336.3 316.2
-------------------------------------------------------------------------
Total liabilities 1,689.6 1,491.3
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 16)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 10) 39.2 43.1

UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 2,530.7 2,465.7
Contributed surplus (Note 14) - 1.7
Deficit (Note 12) (598.8) (465.9)
Accumulated other comprehensive income (loss)
(Note 12) 3.6 (2.9)
-------------------------------------------------------------------------
Total unitholders' equity 1,935.5 1,998.6
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,664.3 $ 3,533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements

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

Three Months Ended Six Months Ended
(Cdn$ millions, except per June 30 June 30
unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and natural gas
liquids $ 512.0 $ 305.6 $ 919.9 $ 613.4
Royalties (91.8) (52.8) (164.0) (108.6)
-------------------------------------------------------------------------
420.2 252.8 755.9 504.8
(Loss) gain on risk management
contracts (Note 9)
Realized (44.7) 0.3 (74.2) 7.3
Unrealized (142.8) 10.8 (161.5) (10.1)
-------------------------------------------------------------------------
232.7 263.9 520.2 502.0
-------------------------------------------------------------------------

EXPENSES
Transportation 4.6 4.0 9.0 8.7
Operating 62.3 54.0 120.5 105.9
General and administrative 22.5 12.9 43.7 22.0
Provision for non-recoverable
accounts receivable (Note 3) 18.0 - 18.0 -
Interest on long-term debt
(Note 6) 8.3 9.3 17.1 19.2
Depletion, depreciation and
accretion 93.0 91.4 190.0 185.9
(Gain) loss on foreign exchange (3.1) (35.5) 11.9 (40.5)
-------------------------------------------------------------------------
205.6 136.1 410.2 301.2
-------------------------------------------------------------------------

Gain on sale of investment - 13.3 - 13.3
Future income tax recovery 31.1 46.4 30.6 57.8
-------------------------------------------------------------------------
Net income before non-controlling
interest 58.2 187.5 140.6 271.9
Non-controlling interest (Note 10) (0.9) (2.6) (2.0) (3.7)
-------------------------------------------------------------------------
Net income $ 57.3 $ 184.9 $ 138.6 $ 268.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Deficit, beginning of period $ (511.4) $ (503.0) $ (465.9) $ (463.2)
Distributions paid or declared
(Note 13) (144.7) (124.1) (271.5) (247.2)
-------------------------------------------------------------------------
Deficit, end of period (Note 12) $ (598.8) $ (442.2) $ (598.8) $ (442.2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 11)
Basic $ 0.27 $ 0.90 $ 0.65 $ 1.30
Diluted $ 0.27 $ 0.89 $ 0.65 $ 1.30
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

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

Three Months Ended Six Months Ended
(Cdn$ millions, except June 30 June 30
per unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Net income $ 57.3 $ 184.9 $ 138.6 $ 268.2

Other comprehensive income (loss),
net of tax
Gain (loss) on financial
instruments designated as
cash flow hedges(1) 0.9 1.8 (2.0) 3.0
De-designation of cash flow
hedge(2) (Note 9) - - 10.0 -
Gains and losses on financial
instruments designated as cash
flow hedges in prior periods
realized in net income in the
current period(3) (Note 9) (1.1) (0.6) (1.5) (0.7)
Net unrealized losses on
available-for-sale reclamation
funds' investments(4) (0.2) (0.3) - (0.3)
-------------------------------------------------------------------------
Other comprehensive income (loss) (0.4) 0.9 6.5 2.0
-------------------------------------------------------------------------
Comprehensive income $ 56.9 $ 185.8 $ 145.1 $ 270.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other comprehensive
income (loss), beginning of period 4.0 6.0 (2.9) -
Application of initial adoption - - - 4.9
Other comprehensive income (loss) (0.4) 0.9 6.5 2.0
-------------------------------------------------------------------------
Accumulated other comprehensive
income, end of period (Note 12) $ 3.6 $ 6.9 $ 3.6 $ 6.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amounts are net of tax of $0.3 million for the three months ended
June 30, 2008 and net of tax of $0.7 million for the six months ended
June 30, 2008 (net of tax of $0.4 million and $0.7 million,
respectively, for the three and six months ended June 30, 2007).
(2) Amount is net of tax of $3.6 million for the three and six months
ended June 30, 2008.
(3) Amount is net of tax of $0.4 million and $0.5 million, respectively,
for the three and six months ended June 30, 2008 (net of tax of
$0.2 million for the three and six months ended June 30, 2007).
(4) Amount is net of tax of $0.1 million for the three months ended
June 30, 2008 (net of tax of $0.1 million for the three and six
months ended June 30, 2007).

See accompanying notes to the consolidated financial statements

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

Three Months Ended Six Months Ended
June 30 June 30
(Cdn$ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 57.3 $ 184.9 $ 138.6 $ 268.2
Add items not involving cash:
Non-controlling interest (Note 10) 0.9 2.6 2.0 3.7
Future income tax recovery (31.1) (46.4) (30.6) (57.8)
Depletion, depreciation and
accretion 93.0 91.4 190.0 185.9
Non-cash loss (gain) on risk
management contracts (Note 9) 142.8 (10.8) 161.5 10.1
Non-cash (gain) loss on foreign
exchange (3.6) (35.6) 11.4 (40.8)
Non-cash trust unit incentive
compensation (Notes 14 and 15) (1.8) (5.2) 12.0 (4.6)
Gain on sale of investment - (13.3) - (13.3)
Expenditures on site restoration
and reclamation (Note 7) (2.3) (7.2) (6.0) (11.9)
Change in non-cash working capital 18.2 19.0 4.5 12.2
-------------------------------------------------------------------------
273.4 179.4 483.4 351.7
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of long-term debt under
revolving credit facilities, net (29.7) (7.8) (39.0) -
Issue of trust units 1.0 1.2 3.8 2.3
Cash distributions paid (Note 13) (107.4) (95.2) (208.7) (191.4)
Change in non-cash working capital (1.5) (1.9) (0.6) (0.2)
-------------------------------------------------------------------------
(137.6) (103.7) (244.5) (189.3)
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of petroleum and
natural gas properties (0.4) (11.2) (10.5) (14.7)
Proceeds on disposition of petroleum
and natural gas properties 0.1 1.2 0.2 4.6
Capital expenditures (131.0) (47.8) (240.4) (125.2)
Long-term investment - 33.3 - 33.3
Net reclamation fund withdrawals
(contributions) (Note 4) 0.6 (0.3) 0.8 (1.5)
Change in non-cash working capital (7.5) (15.9) 4.0 (26.7)
-------------------------------------------------------------------------
(138.2) (40.7) (245.9) (130.2)
-------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH (2.4) 35.0 (7.0) 32.2
CASH, BEGINNING OF PERIOD 2.4 - 7.0 2.8
-------------------------------------------------------------------------
CASH, END OF PERIOD $ - $ 35.0 $ - $ 35.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
June 30, 2008 and 2007
(all tabular amounts in Cdn$ millions, except per unit 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 2007 annual
report.

2. NEW ACCOUNTING POLICIES

Current Year Accounting Changes

Effective January 1, 2008, the Trust adopted three new accounting
standards that were issued by the Canadian Institute of Chartered
Accountants ("CICA"): Handbook Section 1535, Capital Disclosures,
Section 3862, Financial Instruments - Disclosures and Section 3863,
Financial Instruments - Presentation.

A. Capital Disclosures

Section 1535 establishes standards for disclosing information
regarding an entity's capital and how it is managed.

B. Financial Instruments - Disclosures, Financial Instruments -
Presentation

Sections 3862 and 3863 establish standards for enhancing financial
statements users' understanding of the significance of financial
instruments to an entity's financial position, performance and cash
flows. They require that entities provide disclosures regarding the
nature and extent of risks arising from financial instruments to
which they are exposed both during the reporting period and at the
balance sheet date, as well as how the entities manage those risks.
These standards were adopted prospectively.

Future Accounting Changes

A. Goodwill and Intangible Assets

In February 2008, the CICA issued Section 3064, Goodwill and
Intangible Assets, replacing Section 3062, Goodwill and Other
Intangible Assets and Section 3450, Research and Development Costs.
The new Section will be effective on January 1, 2009. Section 3064
establishes standards for the recognition, measurement, presentation
and disclosure of goodwill and intangible assets subsequent to its
initial recognition. Standards concerning goodwill are unchanged from
the standards included in the previous Section 3062. The Trust is
currently evaluating the impact of the adoption of this new Section,
however does not expect a material impact on its consolidated
financial statements.

B. International Financial Reporting Standards ("IFRS")

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted
a strategic plan for the direction of accounting standards in Canada.
As part of that plan, the AcSB confirmed in February 2008 that IFRS
will replace Canadian GAAP in 2011 for profit oriented Canadian
publicly accountable enterprises. The Trust is currently evaluating
the impacts of this change and developing its plan accordingly.

3. FINANCIAL ASSETS AND CREDIT RISK

Credit risk is the risk of financial loss to the Trust if a partner
or counterparty to a financial instrument fails to meet its
contractual obligations. The Trust is exposed to credit risk with
respect to its accounts receivable and risk management contracts.
Most of the Trust's accounts receivable relate to oil and natural gas
sales and are exposed to typical industry credit risks. The Trust
manages this credit risk by entering into sales contracts with only
established credit worthy entities and reviewing its exposure to
individual entities on a quarterly basis. The Trust minimizes credit
risk on risk management contracts by entering into agreements with
counterparties that, at the time of transaction are not less than
investment grade.

Receivables from oil and natural gas marketers are normally collected
on the 25th day of the month following production. The Trust
historically has not experienced any collection issues with its oil
and natural gas marketers. Joint venture receivables are typically
collected within one to three months of the joint interest billing
being issued to the partner. Subsequent to June 30, 2008 a
counterparty that markets a portion of the Trust's production filed
for protection under the Companies' Creditors Arrangement Act. As a
result the Trust recorded an allowance for doubtful accounts of $18
million with a corresponding decrease to net income, after a future
income tax recovery, of $13.5 million. Management believes that
some portion of the $18 million is recoverable; however, it is
indeterminable at this time and therefore the allowance has been
recorded for the full amount. The Trust's allowance for doubtful
accounts was nil as at December 31, 2007.

When determining whether amounts that are past due are collectable,
management assesses the creditworthiness and past payment history of
the partner/counterparty, as well as the nature of the past due
amount. ARC considers all amounts greater than 90 days to be past
due. As at June 30, 2008 $4 million of accounts receivable are past
due, all of which are considered to be collectable.

Maximum credit risk is calculated as the total value of accounts
receivable and risk management contracts at the balance sheet date
less any liability amounts where there is a legal right to offset.
The Trust only records amounts net on the consolidated balance sheet
if the balances are intended to be net settled. The following table
details the Trust's maximum credit risk as at June 30, 2008 and
December 31, 2007:

---------------------------------------------------------------------
June 30, December 31,
2008 2007
---------------------------------------------------------------------
Accounts receivable $ 170.0 $ 159.5
Risk management contracts 20.2 6.8
---------------------------------------------------------------------
Maximum credit exposure $ 190.2 $ 166.3
---------------------------------------------------------------------
---------------------------------------------------------------------

In order to mitigate concentration of credit risk, the Trust reviews
counterparty exposure on a quarterly basis. The majority of the
$170 million and $159.5 million credit exposure on accounts
receivable pertains to the revenue accrual for June 2008 and December
2007 production volumes, respectively. The Trust markets its
production to a variety of counterparties of which, at June 30, 2008,
no one counterparty owed more than 20 per cent of the total exposure.

4. RECLAMATION FUNDS

---------------------------------------------------------------------
June 30, 2008 December 31, 2007
---------------------------------------------------------------------
Unrestricted Restricted Unrestricted Restricted
---------------------------------------------------------------------
Balance,
beginning of
period $ 14.4 $ 11.7 $ 24.8 $ 6.1
Contributions 5.8 0.2 6.2 5.9
Reimbursed
expenditures(1) (6.4) (1.0) (17.5) (0.6)
Interest earned
on funds 0.4 0.2 1.1 0.3
Net unrealized
gains and
losses on
available-for-
sale sale
investments 0.1 - (0.2) -
---------------------------------------------------------------------
Balance, end of
period(2) $ 14.3 $ 11.1 $ 14.4 $ 11.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by the Trust due
to timing differences and discretionary reimbursements.
(2) As at June 30, 2008 the unrestricted reclamation fund held
$0.9 million in cash and cash equivalents ($1.5 million at
December 31, 2007), with the balance held in investment grade
assets.

For the six and twelve months ended June 30, 2008 and December 31,
2007, respectively, nominal amounts relating to available-for-sale
reclamation fund assets were classified from accumulated other
comprehensive income into the statement of income. As at June 30,
2008 and December 31, 2007 the fair value of reclamation fund assets
designated as available-for-sale and held-to-maturity approximated
carrying value. Fair values are obtained from third parties,
determined directly by reference to quoted market prices.

5. FINANCIAL LIABILITIES AND LIQUIDITY RISK

Liquidity risk is the risk that the Trust will not be able to meet
its financial obligations as they become due. The Trust actively
manages its liquidity through cash, distribution policy, and debt and
equity management strategies. Such strategies include continuously
monitoring forecasted and actual cash flows from operating, financing
and investing activities, available credit under existing banking
arrangements and opportunities to issue additional Trust units. The
Trust actively maintains credit and working capital facilities to
ensure that it has sufficient available funds to meet its financial
requirements at a reasonable cost.

The following table details the Trust's financial liabilities as at
June 30, 2008:

---------------------------------------------------------------------
2 - 3 4 - 5 Beyond
($ millions) 1 year years years 5 years Total
---------------------------------------------------------------------
Accounts payable
and accrued
liabilities(1) 220.9 - - - 220.9
Distributions
payable 51.2 - - - 51.2
Risk management
contracts(2) 189.8 49.8 0.7 - 240.3
Senior secured
notes and
interest 27.8 62.6 80.3 107.3 278.0
Syndicated
credit
facilities - 464.9 - - 464.9
Accrued long-
term incentive
compensation(1) - 57.6 - - 57.6
---------------------------------------------------------------------
Total financial
liabilities 489.7 634.9 81.0 107.3 1,312.9
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Liabilities under the Whole Trust Unit Incentive Plan represent
the total amount expected to be paid out on vesting.
(2) Amounts payable for the risk management contracts have been
included at their intrinsic value.

Management believes that future cash flows from operating activities
and availability under existing banking arrangements will be adequate
to settle these financial liabilities. Refer to Note 6 for further
details on available amounts under existing banking arrangements and
Note 8 for further details on capital management.

6. LONG-TERM DEBT

---------------------------------------------------------------------
June 30, December 31,
2008 2007
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility - Cdn$
denominated $ 293.5 $ 344.9
Syndicated credit facility - US$
denominated 158.9 154.1
Working capital facility(1) 12.5 -
Senior secured notes
5.42% US$ Note 76.4 74.1
4.94% US$ Note 18.3 17.8
4.62% US$ Note 63.7 61.8
5.10% US$ Note 63.7 61.8
---------------------------------------------------------------------
Total long-term debt outstanding $ 687.0 $ 714.5
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount borrowed under the working capital facility includes
$12.2 million of outstanding cheques in excess of bank balance.

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 are the significant financial covenants governing the
revolving credit facilities:

- 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, while the third covenant is increased
to 55 per cent for the subsequent six month period. As at June 30,
2008, the Trust had $2 million in letters of credit ($4.8 million
as at December 31, 2007), no subordinated debt, and was in compliance
with all covenants.

During the second quarter of 2008, the weighted-average effective
interest rate under the credit facility was 3.9 per cent (5.4 per
cent in 2007) and 4.2 per cent for the six months ended June 30, 2008
(5.5 per cent in 2007).

In April 2008 the Trust renewed its syndicated credit facility,
extending the maturity date to April 15, 2011. All other terms under
the renewed facility remain unchanged from those disclosed in the
December 31, 2007 annual financial statements.

Amounts due under the working capital facility and the senior secured
notes in the next 12 months of $12.5 million and US$6 million,
respectively, have not been included in current liabilities as
management has the ability and intent to refinance this amount
through the syndicated credit facility. The fair value of senior
secured notes as at June 30, 2008 is $232.5 million ($226.1 million
as at December 31, 2007), and is calculated as the present value of
principal and interest payments discounted at the Trust's credit
adjusted risk free rate.

Interest paid during 2008 was $1.3 million more than interest
expense. The difference between interest paid and interest expense in
2007 was nominal.

7. ASSET RETIREMENT OBLIGATIONS

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

---------------------------------------------------------------------
June 30, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of period $ 140.0 $ 177.3
Increase in liabilities relating to
development activities 1.0 3.8
Increase (decrease) in liabilities
relating to change in estimate 2.4 (34.4)
Settlement of liabilities during the
period (6.0) (18.2)
Accretion expense 4.6 11.5
---------------------------------------------------------------------
Balance, end of period $ 142.0 $ 140.0
---------------------------------------------------------------------
---------------------------------------------------------------------

The Trust's weighted average credit adjusted risk free rate as at
June 30, 2008 was 6.6 per cent (6.6 per cent as at December 31,
2007).

8. CAPITAL MANAGEMENT

The Trust's objectives when managing its capital is to maintain a
conservative capital structure which will allow the Trust to:

- Fund its development and exploration program;
- Provide financial flexibility to execute on strategic
opportunities;
- Maintain a level of distributions that, in the opinion of
Management and the Board of Directors, is sustainable for a
minimum period of six months in order to normalize the effect of
volatility of commodity prices to unitholders rather than to pass
on that volatility in the form of fluctuating distributions; and
- Maintain a level of distributions which will transfer tax
liability to unitholders and minimize taxes paid by the Trust.

The Trust manages the following capital:

- Trust units and exchangeable shares;
- Long-term debt; and
- Working capital (defined as current assets less current
liabilities excluding risk management contracts).

When evaluating the Trust's capital structure, management's objective
is to limit net debt to under 2.0 times annualized cash flow from
operating activities and 20 per cent of total capitalization. As at
June 30, 2008 the Trust's net debt to annualized cash flow from
operating activities ratio is 0.8 and its net debt to total
capitalization ratio is 9.4 per cent.

---------------------------------------------------------------------
($ millions except per unit June 30, December 31,
and per cent amounts) 2008 2007
---------------------------------------------------------------------
Long-term debt 687.0 714.5
Accounts payable and accrued liabilities 212.6 180.6
Distributions payable 51.2 42.1
Cash, accounts receivable and prepaid expenses (194.7) (184.5)
---------------------------------------------------------------------
Net debt obligations(1) 756.1 752.7
---------------------------------------------------------------------

Trust units outstanding and issuable for
exchangeable shares (millions) 215.8 213.2
Trust unit price 33.95 20.40
---------------------------------------------------------------------
Market capitalization(1) 7,326.4 4,349.3
Net debt obligations(1) 756.1 752.7
---------------------------------------------------------------------
Total capitalization(1) 8,082.5 5,102.0
---------------------------------------------------------------------

Net debt as a percentage of total
capitalization 9.4% 14.8%
Net debt obligations to annualized cash flow
from operating activities 0.8 1.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Market capitalization, net debt obligations and total
capitalization 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.

The Trust manages its capital structure and makes adjustments to it
in response to changes in economic conditions and the risk
characteristics of the underlying assets. The Trust is able to effect
change to its capital structure by issuing new trust units,
exchangeable shares, new debt or changing its distribution policy.

Monthly distributions were increased during the quarter from
$0.20 per unit to $0.24 per unit. This $0.04 per unit increase is
considered a top-up distribution and will be reviewed on an ongoing
basis in the context of commodity prices and other factors. The
Trust's base distribution of $0.20 per unit has been held constant
since October 2005. No current taxes have been paid by the Trust in
the six months ended June 30, 2008.

In addition to internal capital management the Trust is subject to
various covenants under its credit facilities. Compliance with these
covenants is monitored on a quarterly basis and as at June 30, 2008
the Trust is in compliance with all covenants. Refer to Note 6 for
further details.

9. MARKET RISK MANAGEMENT

The Trust is exposed to a number of market risks that are part of its
normal course of business. The Trust has a risk management program in
place that includes financial instruments as disclosed in the risk
management section of this note. ARC's risk management program is
overseen by its Risk Committee based on guidelines approved by the
Board of Directors. The objective of the risk management program is
to mitigate the Trust's exposure to commodity price risk, interest
rate risk and foreign exchange risk.

In the sections below, management has prepared sensitivity analyses
in an attempt to demonstrate the effect of changes in these market
risk factors on the Trust's net income. For the purposes of the
sensitivity analyses, the effect of a variation in a particular
variable is calculated independently of any change in another
variable. In reality, changes in one factor may contribute to changes
in another, which may magnify or counteract the sensitivities. For
instance, trends have shown a correlation between the movement in the
foreign exchange rate of the Canadian dollar to the U.S. dollar and
the West Texas Intermediate posting ("WTI").

Commodity price risk

The Trust's operational results and financial condition, and
therefore the amount of distributions paid to unitholders, are
partially dependent on the commodity prices received for oil and
natural gas production. Commodity prices have fluctuated widely
during recent years and are determined by weather, economic and, in
the case of oil prices, geopolitical factors. Any movement in
commodity prices could have an effect on the Trust's financial
condition and therefore on the distributions to unitholders.

ARC manages the risks associated with changes in commodity prices by
entering into a variety of risk management contracts (see risk
management contracts below). The following table illustrates the
effects of movement in commodity prices on net income due to changes
in the fair value of risk management contracts in place at June 30,
2008. The sensitivity is based on a $20 increase and $20 decrease in
WTI and $2 increase and $2 decrease in AECO. The commodity price
assumptions are based on management's assessment of reasonably
possible changes in oil and natural gas prices that could occur
between June 30, 2008 and the Trust's next reporting date
(September 30, 2008).

---------------------------------------------------------------------
Increase in Commodity Price Decrease in Commodity Price
---------------------------------------------------------------------
($ millions) Crude oil Natural gas Crude oil Natural gas
---------------------------------------------------------------------
Net income
(decrease)
increase (53.7) (6.4) 49.5 6.1
---------------------------------------------------------------------
---------------------------------------------------------------------

As noted above, the sensitivities are hypothetical and based on
management's assessment of reasonably possible changes in commodity
prices between the balance sheet date and the Trust's next reporting
date. The results of the sensitivity should not be considered to be
predictive of future performance. Changes in the fair value of risk
management contracts cannot generally be extrapolated because the
relationship of change in certain variables to a change in fair value
may not be linear.

Interest Rate Risk

The Trust has both fixed and variable interest rates on its debt.
Changes in interest rates could result in a significant increase or
decrease in the amount the Trust pays to service variable interest
rate debt, potentially impacting distributions to unitholders.
Changes in interest rates could also result in fair value risk on the
Trust's senior secured notes. Fair value risk of the senior secured
notes is mitigated due to the fact that the Trust does not intend to
settle its fixed rate debt prior to maturity.

If interest rates applicable to floating rate debt and interest rate
swaps were to have increased by 100 bps (1 per cent) it is estimated
that the Trust's net income for the six months ended June 30, 2008
would decrease by $4.4 million, of which $1.7 million is the result
of increased interest expense and $2.7 million is due to the change
in fair value of risk management contracts in place at June 30, 2008.
An opposite change in interest rates will result in an opposite
impact on net income.

Foreign Exchange Risk

North American oil and natural gas are based upon U.S. dollar
denominated commodity prices. As a result, the price received by
Canadian producers is affected by the Canadian/U.S. dollar exchange
rate that may fluctuate over time. In addition the Trust has U.S.
denominated debt of which future cash repayments are directly
impacted by the exchange rate in effect on the repayment date.
Variations in the exchange rate of the Canadian dollar could also
have a significant positive or negative impact on distributions to
unitholders.

ARC has entered into certain risk management contracts to mitigate
these risks (see risk management contracts below). The following
table demonstrates the effect of exchange rate movement on net income
due to changes in the fair value of risk management contracts in
place at June 30, 2008 as well as the unrealized gain or loss on
revaluation of outstanding U.S. denominated debt. The sensitivity is
based on a $0.03 Cdn$/US$ increase and $0.03 Cdn$/US$ decrease in the
foreign exchange rate.

---------------------------------------------------------------------
Cdn$/US$ Exchange Rate
---------------------------------------------------------------------
($ millions) Increase in Decrease in
Cdn$/US$ rate Cdn$/US$ rate
---------------------------------------------------------------------
Increase gain/decrease loss
(increase loss/decrease gain) on
risk management contracts 2.1 (2.3)
Increase gain/decrease loss
(increase loss/decrease gain) on
foreign exchange (8.4) 8.4
---------------------------------------------------------------------
Net income (decrease) increase (6.3) 6.1
---------------------------------------------------------------------
---------------------------------------------------------------------

As with the other noted risk variables, the sensitivity is based on
management's assessment of reasonably possible changes in the foreign
exchange rate that could occur between June 30, 2008 and the Trust's
next reporting date (September 30, 2008). The results of the
sensitivity should not be considered to be predictive of future
changes in rates or performance.

Risk Management Contracts

The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices, foreign exchange,
interest rates and power. 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, 2008 that do not qualify for hedge accounting:

---------------------------------------------------------------------
Financial WTI Crude Oil Contracts
---------------------------------------------------------------------
Bought Sold Sold
Volume put put call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Jul 08 - Dec 08 3 - Way Collar 1,000 70.00 55.00 90.00
Jul 08 - Dec 08 3 - Way Collar 1,000 67.50 52.50 85.00
Jul 08 - Dec 08 Collar 1,000 67.50 - 85.00
Jul 08 - Dec 08 Collar 2,000 85.00 - 107.50
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial WTI Crude Oil Contracts In Conjunction with 2005 Redwater
and North Pembina Cardium Unit Acquisition
---------------------------------------------------------------------
Bought Sold Sold
Volume put put call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Jul 08 - Dec 08 3 - Way Collar 2,000 61.50 50.00 85.00
Jul 08 - Dec 08 3 - Way Collar 1,000 61.30 50.00 85.00
Jul 08 - Dec 08 3 - Way Collar 2,000 61.00 50.00 85.00
Jan 09 - Dec 09 3 - Way Collar 5,000 55.00 40.00 90.00
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial AECO Natural Gas Option Contracts
---------------------------------------------------------------------
Bought Sold Sold
Volume put put call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
Jul 08 - Oct 08 Collar 10,000 6.75 - 8.25
Jul 08 - Oct 08 3 - Way Collar 10,000 7.00 5.75 9.00
Jul 08 - Oct 08 Collar 10,000 7.00 - 9.00
Jul 08 - Oct 08 Collar 10,000 7.25 - 8.50
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial NYMEX Natural Gas Contracts
---------------------------------------------------------------------
Bought Sold Sold
put put call
Volume US$/ US$/ US$/
Term Contract mmbtu/d mmbtu mmbtu mmbtu
---------------------------------------------------------------------
Jul 08 - Oct 08 3 - Way Collar 10,000 7.80 6.20 9.50
Jul 08 - Oct 08 3 - Way Collar 10,000 8.00 6.00 9.60
Nov 08 - Mar 09 Collar 20,000 8.50 - 11.00
Nov 08 - Mar 09 Collar 10,000 9.00 - 12.00
Nov 08 - Mar 09 Collar 10,000 9.25 - 12.00
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial Basis Swap Contract: receive NYMEX Last Day (Ld) or Last 3
Day (L3d); pay AECO Monthly (7a)
---------------------------------------------------------------------
Basis
Swap
Volume US$/
Term Contract mmbtu/d mmbtu
---------------------------------------------------------------------
Jul 08 - Oct 08 Basis Swap-L3d 50,000 (1.1930)
Nov 08 - Oct 10 Basis Swap-L3d 50,000 (1.0430)
Nov 10 - Oct 11 Basis Swap-Ld 20,000 (0.4850)
Nov 11 - Oct 12 Basis Swap-Ld 20,000 (0.4050)
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial Basis Swap Contract: pay NYMEX Last Day (Ld) or Last 3 Day
(L3d); receive AECO Monthly (7a)
---------------------------------------------------------------------
Basis
Swap
Volume US$/
Term Contract mmbtu/d mmbtu
---------------------------------------------------------------------
Jul 08 - Jul 08 Basis Swap-L3d 20,000 (1.8700)
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Bought Sold
Notional Swap Put Put
Volume CDN$/ CDN$/ CDN$/
Term Contract MM US$ US$ US$ US$
---------------------------------------------------------------------
Jul 08 - Dec 08 Swap 24.0 1.0150 - -
USD Option Contracts
Jul 08 - Dec 08 Put Spread 6.0 - 1.0750 1.0300
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Bought Sold
Notional Swap Put Put
Volume CDN$/ CDN$/ CDN$/
Settlement Date Contract MM US$ US$ US$ US$
---------------------------------------------------------------------
December 17, 2012 Forward 9.38 0.9324 - -
April 27, 2013 Forward 10.42 0.9454 - -
April 27, 2013 Forward 12.50 0.9430 - -
December 15, 2013 Forward 9.38 0.9520 - -
April 27, 2014 Forward 10.42 0.9743 - -
April 27, 2014 Forward 12.50 0.9615 - -
December 15, 2014 Forward 9.38 0.9825 - -
April 27, 2015 Forward 12.50 0.9825 - -
December 15, 2015 Forward 9.40 0.9980 - -
April 27, 2016 Forward 12.50 1.0180 - -
December 15, 2017 Forward 9.40 1.0184 - -
December 15, 2016 Collar 9.40 - 1.0600 1.0000
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial Interest Rate Contracts(1)(2)
---------------------------------------------------------------------
Fixed
Annual
Principal Rate Spread on
Term Contract MM US$ (%) 3 Mo. LIBOR
---------------------------------------------------------------------
Jul 08 - Apr 14 Swap 30.5 4.62 38 bps
Jul 08 - Apr 14 Swap 32.0 4.62 (25.5 bps)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) 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.
(2) Starting in 2009, a mutual put exists where both parties have the
right to call on the other party to pay the then current
mark-to-market value of the contract.

Following is a summary of all risk management contracts in place as
at June 30, 2008 that qualify for hedge accounting:

---------------------------------------------------------------------
Financial Electricity Contracts (3)(4)
---------------------------------------------------------------------
Volume Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
Jul 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
---------------------------------------------------------------------
(3) Contracted volume is based on a 24/7 term.
(4) Includes margin provision on 5MWh per year if contract value
exceeds $30 million. If exercised, a letter of credit would be
issued for values in excess of $30 million.

---------------------------------------------------------------------
Financial Electricity Heat Rate Contracts: Alberta Power Pool
(monthly average 24x7), AECO Monthly (5a)
---------------------------------------------------------------------
Heat
Volume AESO Power AECO 5(a) multiplied Rate
Term Contract MWh $/MWh $/GJ by GJ/MWh
---------------------------------------------------------------------
Jan 09 - Heat Rate
Dec 10 Swap 5.0 Receive AESO Pay AECO X 9.0
Jan 10 - Heat Rate
Dec 12 Swap 10.0 Receive AESO Pay AECO X 9.0
Jan 11 - Heat Rate
Dec 13 Swap 5.0 Receive AESO Pay AECO X 9.0
---------------------------------------------------------------------

At June 30, 2008, the fair value of the contracts that were not
designated as accounting hedges was a loss of $226.1 million. The
Trust recorded a loss on risk management contracts of $235.7 million
in the statement of income for the six months ended June 30, 2008
($2.8 million loss in 2007). This amount includes the realized and
unrealized gains and losses on risk management contracts that do not
qualify as effective accounting hedges. In addition, as at June 30,
2008 a $52.4 million current future tax asset was recorded relating
to the current net mark-to-market loss on the risk management
contracts.

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, 2008 June 30, 2007
---------------------------------------------------------------------
Fair value, beginning of period $ (64.6) $ (8.7)
Fair value, end of period(1) (226.1) (18.8)
---------------------------------------------------------------------
Change in fair value of contracts
in the period (161.5) (10.1)
Realized (losses) gains in the period (74.2) 7.3
---------------------------------------------------------------------
Loss on risk management contracts $ (235.7) $ (2.8)
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $222.1 million at
June 30, 2008 ($17.6 million loss at June 30, 2007).

During 2007 the Trust entered into treasury rate lock contracts in
order to manage the Trust's interest rate exposure on future debt
issuances. In the first quarter of 2008 it was determined that the
previously anticipated debt issuance was no longer expected to occur
and the associated rate lock contracts were unwound at a cost of
$13.6 million. These contracts were designated as effective
accounting hedges on their respective contract dates and hedge
accounting was applied. As at June 30, 2008 the $13.6 million loss
was reclassified from Other Comprehensive Income ("OCI"), net of tax
and recognized in net income.

The Trust's electricity contracts are intended to manage price risk
on electricity consumption. All electricity contracts were designated
as effective accounting hedges on their respective contract dates. A
realized gain of $1.5 million and $2 million for the three and six
months ended June 30, 2008 (loss of $0.1 million and $0.7 million
respectively in 2007) on the electricity contracts has been included
in operating costs. The unrealized fair value gain on the electricity
contracts of $5.4 million has been recorded on the consolidated
balance sheet at June 30, 2008 with the movement in fair value
recorded in OCI, net of tax. The fair value movement for the six
months ended June 30, 2008 amounts to an unrealized gain of $1.4
million. $3.4 million of the unrealized fair value gain is expected
to be recognized in income over the next 12 months.

The following table reconciles the movement in the fair value of the
Trust's financial electricity contracts and treasury rate lock
contracts:

---------------------------------------------------------------------
June 30, 2008 June 30, 2007
---------------------------------------------------------------------
Fair value, beginning of period(1) $ (3.4) $ 7.0
Change in fair value of financial
electricity contracts 1.4 3.2
Change in fair value of treasury rate
lock contracts prior to de-designation (6.2) -
Reclassification of loss on treasury
rate lock contracts to net income 13.6 -
---------------------------------------------------------------------
Fair value, end of period(2) $ 5.4 $ 10.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes $7.4 million unrealized loss on treasury rate lock
contracts and $4 million unrealized gain on electricity
contracts.
(2) Intrinsic value of risk management contracts designated as
effective accounting hedges equals a gain of $5.3 million at
June 30, 2008 ($10.2 million gain at June 30, 2007).

The fair values of all risk management contracts are determined using
published price quotations in an active market through a valuation
model. Significant inputs into this model include forward curves on
commodity prices, interest rates and foreign exchange rates.

10. EXCHANGEABLE SHARES

---------------------------------------------------------------------
ARL EXCHANGEABLE SHARES
(thousands) June 30, 2008 December 31, 2007
---------------------------------------------------------------------
Balance, beginning of period 1,310 1,433
Exchanged for trust units(1) (173) (123)
---------------------------------------------------------------------
Balance, end of period 1,137 1,310
Exchange ratio, end of period 2.36758 2.24976
Trust units issuable upon
conversion, end of period 2,693 2,947
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first six months of 2008, 172,502 ARL exchangeable
shares were converted to trust units at an average exchange ratio
of 2.31006.

Following is a summary of the non-controlling interest for June 30,
2008 and December 31, 2007:

---------------------------------------------------------------------
June 30, 2008 December 31, 2007
---------------------------------------------------------------------
Non-controlling interest,
beginning of period $ 43.1 $ 40.0
Reduction of book value for
conversion to trust units (5.9) (3.7)
Current period net income
attributable to non-controlling
interest 2.0 6.8
---------------------------------------------------------------------
Non-controlling interest, end of
period 39.2 43.1
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 36.1 $ 34.1
---------------------------------------------------------------------
---------------------------------------------------------------------

11. UNITHOLDERS' CAPITAL

---------------------------------------------------------------------
June 30, 2008 December 31, 2007
---------------------------------------------------------------------
Number of Number of
trust units trust units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning
of period 210,232 2,465.7 204,289 2,349.2
Issued on conversion
of ARL exchangeable
shares (Note 10) 405 5.9 261 3.7
Issued on exercise
of employee rights
(Note 14) 233 4.1 131 2.1
Distribution
reinvestment program 2,285 55.0 5,551 110.7
---------------------------------------------------------------------
Balance, end of period 213,155 2,530.7 210,232 2,465.7
---------------------------------------------------------------------
---------------------------------------------------------------------

Net income per trust unit has been determined based on the following:
---------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
---------------------------------------------------------------------
2008 2007 2008 2007
---------------------------------------------------------------------
Weighted average trust
units(1) 212,539 206,562 211,783 205,780
Trust units issuable on
conversion of
exchangeable shares(2) 2,693 2,892 2,693 2,892
Dilutive impact of
rights(3) 11 179 96 212
---------------------------------------------------------------------
Diluted trust units and
exchangeable shares 215,243 209,633 214,572 208,884
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Weighted average trust units exclude 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 have been
included in the diluted unit calculation for both 2008 and 2007.

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

12. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE INCOME

The deficit balance is composed of the following items:

---------------------------------------------------------------------
June 30, 2008 December 31, 2007
---------------------------------------------------------------------
Accumulated earnings $ 2,329.7 $ 2,191.1
Accumulated distributions (2,928.5) (2,657.0)
---------------------------------------------------------------------
Deficit $ (598.8) $ (465.9)
Accumulated other comprehensive
income (loss) 3.6 (2.9)
---------------------------------------------------------------------
Deficit and accumulated other
comprehensive income (loss) $ (595.2) $ (468.8)
---------------------------------------------------------------------
---------------------------------------------------------------------

The accumulated other comprehensive income (loss) balance is composed
of the following items:

---------------------------------------------------------------------
June 30, 2008 December 31, 2007
---------------------------------------------------------------------
Unrealized gains and losses on
financial instruments designated
as cash flow hedges $ 3.7 $ (2.8)
Net unrealized gains and losses on
available-for-sale reclamation
funds' investments (0.1) (0.1)
---------------------------------------------------------------------
Accumulated other comprehensive
income (loss), end of period $ 3.6 $ (2.9)
---------------------------------------------------------------------
---------------------------------------------------------------------

13. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
DISTRIBUTIONS

Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operating activities is
reduced by reclamation fund contributions including interest earned
on the funds, a portion of capital expenditures and, when applicable,
debt repayments. The portion of cash flow from operating activities
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
---------------------------------------------------------------------
2008 2007 2008 2007
---------------------------------------------------------------------
Cash flow from
operating activities $ 273.4 $ 179.4 $ 483.4 $ 351.7
Deduct:
Cash withheld to fund
current period
capital expenditures (125.4) (53.5) (205.3) (99.4)
Reclamation fund
contributions and
interest earned on
fund balances (3.3) (1.8) (6.6) (5.1)
---------------------------------------------------------------------
Distributions(1) 144.7 124.1 271.5 247.2
Accumulated
distributions,
beginning of period 2,783.8 2,282.1 2,657.0 2,159.0
---------------------------------------------------------------------
Accumulated
distributions,
end of period $ 2,928.5 $ 2,406.2 $ 2,928.5 2,406.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per
unit(2) $ 0.68 $ 0.60 $ 1.28 $ 1.20
Accumulated
distributions per
unit, beginning of
period $ 21.63 $ 19.23 $ 21.03 $ 18.63
Accumulated
distributions per
unit, end of
period(3) $ 22.31 $ 19.83 $ 22.31 $ 19.83
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include accrued and non-cash amounts of $38 million
and $63 million for the three and six months ended June 30, 2008,
respectively ($28 million and $54 million for the same periods in
2007) 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 for the
period ending June 30, 2008 is as follows:

---------------------------------------------------------------------
Number of Rights Weighted Average
(thousands) Exercise Price ($)
---------------------------------------------------------------------
Balance, beginning of period 238 8.50
Exercised 233 10.37
---------------------------------------------------------------------
Balance before reduction of
exercise price 5 11.29
Reduction of exercise price(1) - (0.48)
---------------------------------------------------------------------
Balance, end of period 5 10.81
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The holder of the right has the option to exercise rights held at
the original grant price or a reduced exercise price.

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 2,651,170 rights have been exercised to June 30, 2008.

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

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CONTRIBUTED SURPLUS June 30, 2008 December 31, 2007
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Balance, beginning of period $ 1.7 $ 2.4
Net benefit on rights exercised(1) (1.7) (0.7)
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Balance, end of period $ - $ 1.7
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(1) Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to unitholders' capital.

15. WHOLE TRUST UNIT INCENTIVE PLAN

The following table summarizes the Restricted Trust Unit ("RTU") and
Performance Trust Unit ("PTU") movement for the six months ended
June 30, 2008:

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Number of RTUs Number of PTUs
(thousands) (thousands)
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Balance, beginning of period 746 903
Vested (193) (183)
Granted 199 173
Forfeited (30) (30)
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Balance, end of period 722 863
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Non-cash compensation expense was based on the June 30, 2008 unit
price of 33.95 ($21.74 at June 30, 2007), accrued distributions, a
weighted average performance multiplier of 1.6 (1.6 at June 30,
2007), and the number of units to be issued on maturity.

The change in the net accrued long-term incentive compensation
liability relating to the Whole Trust Unit Incentive Plan can be
reconciled as follows:

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June 30, 2008 December 31, 2007
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Balance, beginning of period $ 30.3 $ 26.1
Change in net liabilities in the
period
General and administrative expense 10.2 3.2
Operating expense 1.8 0.3
Property, plant and equipment 2.2 0.7
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Balance, end of period(1) $ 44.5 $ 30.3
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Current portion of liability 25.8 18.2
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Accrued long-term incentive
compensation $ 19.6 $ 12.1
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(1) Includes $0.9 million of recoverable amounts recorded in accounts
receivable as at June 30, 2008 (nil for 2007).

16. COMMITMENTS AND CONTINGENCIES

Following is a summary of the Trust's contractual obligations and
commitments as at June 30, 2008:

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Payments Due by Period
---------------------------------------------------------------------
2009- 2011- There-
($ millions) 2008 2010 2012 after Total
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Debt repayments(1) 18.6 43.0 505.5 119.9 687.0
Interest payments(2) 5.6 20.5 15.8 14.0 55.9
Reclamation fund
contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase commitments 5.0 5.3 4.3 6.2 20.8
Operating leases 4.2 8.6 12.3 88.1 113.2
Derivative contract
premiums(4) 6.2 2.9 - - 9.1
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Total contractual
obligations 45.4 90.5 546.8 300.1 982.8
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(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 $7.4 billion. The
Trust expects full year 2008 oil and gas production to average approximately
64,000 to 65,000 barrels of oil equivalent per day from six core areas in
western Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN and
its exchangeable shares trade under the symbol ARX.

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 2008 and beyond; the
sources, deployment and allocation of expected capital in 2008; and the
success of future development drilling prospects. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause ARC's actual performance and financial results in future periods to
differ materially from any estimates or projections of future performance or
results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,
President and Chief Executive Officer