ARC Energy Trust announces second quarter 2009 results

CALGARY, Aug. 6 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") announces the results for the second quarter ended June 30, 2009.

<<
Three Months Ended Six Months Ended
June 30 June 30
2009 2008 2009 2008
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FINANCIAL
(Cdn$ millions, except per
unit and per boe amounts)
Revenue before royalties 235.2 512.0 460.4 919.9
Per unit(1) 0.99 2.38 1.98 4.29
Per boe 40.4 88.04 39.5 77.24
Cash flow from operating
activities(2) 104.3 273.4 228.6 483.4
Per unit(1) 0.44 1.27 0.98 2.25
Per boe 17.9 47.02 19.6 40.59
Net income 66.1 57.3 88.4 138.6
Per unit(3) 0.28 0.27 0.38 0.65
Distributions 75.0 144.7 157.0 271.5
Per unit(1) 0.32 0.68 0.68 1.28
Per cent of cash flow
from operating
activities(2) 72 53 69 56
Net debt outstanding(4) 737.6 756.1 737.6 756.1
OPERATING
Production
Crude oil (bbl/d) 26,917 27,541 27,857 28,302
Natural gas (mmcf/d) 200.2 194.7 197.0 199.5
Natural gas liquids
(bbl/d) 3,679 3,906 3,721 3,882
Total (boe/d) 63,969 63,896 64,418 65,436
Average prices
Crude oil ($/bbl) 62.74 118.32 54.36 103.63
Natural gas ($/mcf) 3.73 10.41 4.45 9.07
Natural gas liquids ($/bbl) 38.89 82.29 38.88 75.46
Oil equivalent ($/boe) 40.32 87.73 39.36 76.95
Operating netback ($/boe)
Commodity and other
revenue (before
hedging)(5) 40.41 88.04 39.49 77.24
Transportation costs (0.85) (0.79) (0.90) (0.76)
Royalties (4.72) (15.79) (5.52) (13.77)
Operating costs (11.02) (10.71) (10.57) (10.11)
Netback (before hedging) 23.82 60.75 22.49 52.60
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TRUST UNITS
(millions)
Units outstanding, end of
period(6) 237.1 215.8 237.1 215.8
Weighted average trust
units(7) 236.6 215.2 232.8 214.5
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TRUST UNIT TRADING STATISTICS
(Cdn$, except volumes) based
on intra-day trading
High 19.25 33.95 20.90 33.95
Low 14.12 25.19 11.73 20.00
Close 17.81 33.95 17.81 33.95
Average daily volume
(thousands) 988 659 1,113 764
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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 2009 would be
$120.5 million ($0.51 per unit) and $237.1 million ($1.02 per unit)
year-to-date. Distributions as a percentage of Cash Flow would be
62 per cent for the second quarter of 2009 (66 per cent year-to-
date).
(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) For the second quarter of 2009, includes 0.9 million (1.1 million in
2008) exchangeable shares exchangeable into 2.634 trust units (2.517
in 2008) each for an aggregate 2.5 million (2.7 million in 2008)
trust units.
(7) Includes trust units issuable for outstanding exchangeable shares at
period end.

ACCOMPLISHMENTS/FINANCIAL UPDATE
--------------------------------
- Production for the quarter was ahead of budget at 63,969 boe per day
with higher than anticipated production at Dawson, Ante Creek and
Goodlands despite completing 37 oil and natural gas facility
turnarounds during the quarter on the Trust's operated properties.
The higher production at Goodlands and Ante Creek was the result of
better than anticipated results from horizontal development wells
that were drilled during the winter. ARC plans on following up these
successes with four horizontal wells at Goodlands and four horizontal
wells at Ante Creek prior to year-end. Preliminary results from two
horizontal wells in the Pembina area have also been encouraging. Each
of the two wells averaged 300 boe per day during their first month on
production. The Trust expects full year corporate production to
average between 63,000 and 64,000 boe per day at an operating cost of
approximately $10.70 per boe.

- Cash flow from operating activities was $104.3 million, or $0.44 per
unit, a significant decline from the $273.4 million ($1.27 per unit),
achieved in the comparable quarter in 2008. This decline was as a
result of a 54 per cent decline in commodity prices. The more
commonly used Cash Flow, a non-GAAP measure, was $120.5 million or
$0.51 per unit. Net income for the quarter of $66.1 million was
comparable to last year's $57.3 million as the current year decline
in commodity revenue was offset by the recording of a $39.7 million
non-cash foreign exchange gain on the Trust's U.S. denominated debt
and a decrease in non-cash losses on the Trust's risk management
contracts when compared to the second quarter of 2008. In response
to the decreased cash flow levels in 2009, the Trust decreased
monthly distributions to $0.10 per unit or 72 per cent of cash flow
from operating activities. This provided sufficient cash flow to
fund 55 per cent of the second quarter capital program (90 per cent
when including the quarterly proceeds from the distributions re-
investment program) with only 10 per cent being funded through debt.

- The Trust executed a $48.9 million capital expenditure program in the
second quarter of 2009 that included: drilling one oil well in
southeast Saskatchewan, drilling eight natural gas wells in the
Dawson area, and spending $10.4 million on the new gas plant at
Dawson. Of the wells drilled in the second quarter, two natural gas
wells were completed as well as 26 additional wells that were drilled
in previous quarters.

- The Trust has maintained its capital expenditure guidance at $350
million for full year 2009. Included in this number is
approximately $30 million of new projects that have been added to
take advantage of drilling incentives provided by the Alberta
Government and to follow-up on the success of our horizontal
drilling program.

- On April 14, 2009, the Trust announced the closing of a private
placement of long-term debt in the form of senior secured notes
totaling US$125 million at a blended average interest rate of 7.47
per cent. The notes were offered in three tranches with repayment
dates between 2012 and 2021 allowing the Trust to convert a portion
of its credit facility debt to long term notes that mature over a
number of years as opposed to being re-financed all in one year.
Proceeds from the notes were used to reduce the debt outstanding on
the Trust's $800 million credit facility. At June 30, 2009 the Trust
had approximately $650 million of unused credit available and a net
debt to annualized year-to-date cash flow from operating activities
of 1.6 times.

- The Trust's reserves and production profile is managed to mitigate
the impact of commodity price volatility. The Trust's first half 2009
production is weighted 49 per cent to crude oil and natural gas
liquids and 51 per cent to natural gas. Although natural gas prices
have decreased throughout the second quarter of 2009, the recovery of
crude oil prices during the second quarter has tempered the impact of
lower realized natural gas prices.

- The Trust's current plans are to convert to a dividend paying
Corporation effective December 31, 2010. At this time, Management
believes that this will be the most logical and tax efficient
alternative for ARC unitholders. The potential conversion, that will
be subject to regulatory and unitholder approval, is in the planning
stages and ARC is working with legal and tax advisors to map out the
required steps for the conversion process.

- Montney Resource Play Development

Production from the Dawson area was above budget at an average rate
of 56 mmcf per day throughout the second quarter as a planned
turnaround of a third party gas plant was delayed to the third
quarter.

During the second quarter of 2009, the Trust spent $29.1 million on
development activities in the Dawson area including drilling seven
horizontal wells, one of which was completed during the quarter. One
vertical well was also drilled and completed during the quarter. The
Dawson B-10-8-79-14W6 horizontal well tested 9.5 mmcf per day of
natural gas at a flowing pressure of 2,000 pounds per square inch.
One vertical acid gas disposal well required for the new gas plant
was also drilled and completed during the quarter. The Trust plans
to drill two additional horizontal wells at Dawson during the second
half of 2009.

At this time, the Trust has 22 wells drilled in the Dawson gas field
that are in various stages of completion. In the completed and
waiting on tie-in category are 14 wells (six horizontal and eight
vertical), while the remaining eight wells (six horizontal and two
vertical) are yet to be completed. In addition to these Dawson
wells, the Trust has drilled five vertical wells and two horizontal
wells in the Sunrise-Sunset area, none of which are tied-in. The
Trust has also participated in one partner operated horizontal well
at Sunrise.

The Trust drilled a successful exploration well on its Montney West
lands during the quarter. The Sunset 13-24-79-19W6 well encountered
over 150 meters of gas bearing porosity within the Montney formation.
Results from this well are similar to those encountered in ARC's
Sunrise discovery wells. ARC plans to participate in a small
development project on partner operated lands at Sunrise. Current
plans call for the drilling of four horizontal wells, construction of
pipelines and a gathering system and the expansion of a third party
operated gas plant. Assuming that the drilling and construction go as
planned, production from this area should be approximately 10 mmcf
per day net to ARC's 50 per cent working interest by the beginning of
2010.

The Trust continues to work towards a first quarter 2010 completion
date for a new 60 mmcf per day gas plant at Dawson. $18.8 million has
been spent year-to-date on the project with design work complete, all
major equipment ordered and the public notification process
completed. Applications have been submitted to the appropriate
regulatory agencies and are currently under review with approvals for
construction expected by the end of August. As long as construction
starts by early September, ARC expects that the gas plant will be
operational by the end of the first quarter of 2010.

- Enhanced Oil Recovery Initiatives

During the second quarter, the Trust spent $4 million on enhanced oil
recovery ("EOR") initiatives. The Redwater CO(2) pilot project
continues with both the CO(2) injection and oil production facilities
continuing operations. Highlights for the quarter included the
addition of a second production well and CO(2) injection volumes
continuing to ramp up as scheduled. Results continue to be
encouraging but the Trust anticipates that it will take until at
least the first quarter of 2010 before it will know to what extent
the pilot has been successful in mobilizing incremental volumes of
oil. While the pilot project may indicate enhanced recovery, the
current outlook for crude oil prices and the cost and availability of
CO(2) may impact the Trust's ability to achieve commercial viability
for a full scale EOR scheme at Redwater.

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 August 5,
2009 and should be read in conjunction with the unaudited Consolidated
Financial Statements for the period ended June 30, 2009, the MD&A and the
unaudited Consolidated Financial Statements ended March 31, 2009 and the
audited Consolidated Financial Statements and MD&A as at and for the year
ended December 31, 2008 as well as the Trust's Annual Information Form that is
filed on SEDAR at www.sedar.com.
The MD&A contains Non-GAAP measures and forward-looking statements and
readers are cautioned that the MD&A should be read in conjunction with the
Trust's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements"
included at the end of this MD&A.

ARC's Business

ARC Energy Trust ("ARC") or ("the Trust") is an actively managed oil and
natural gas entity formed to provide investors with indirect ownership in cash
generating energy assets, that currently consist of oil and gas assets. The
cash flow from operating activities is based on the production and sale of
crude oil, natural gas liquids and natural gas.
ARC is one of the top 20 producers of conventional oil and gas in western
Canada. As at June 30, 2009, ARC held interests in excess of 18,600 wells with
approximately 5,600 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, which trades on the Toronto Stock Exchange, as at
June 30, 2009 was $5 billion as shown on Table 23.

ARC's Objective

ARC's goal is to be one of the top performing oil and gas companies in
Canada as measured by quality of assets, management expertise and investor
returns. The focus is on risk managed value creation. Table 1 shows the
Trust's ability to maintain stable production and reserves per unit while
distributing a portion of the cash flows back to unitholders. The decrease in
2009 production per unit reflects the impact of issuing 15.5 million trust
units in the first quarter that raised $240 million to be used to partially
fund capital expenditures in the Dawson area. ARC is constructing a gas plant
with a 60 mmcf per day capacity with an expectation that production per unit
will increase in 2010 upon startup of this plant.

<<
Table 1
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Full year Full year
Per Trust Unit Q2 2009 YTD 2009 2008 2007
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Normalized production per
unit(1)(2) 0.27 0.28 0.29 0.30
Normalized reserves per
unit(1)(3) N/A N/A 1.42 1.35
Distributions per unit $0.32 $0.68 $2.67 $2.40
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(1) Normalized indicates that all periods 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 per unit values.
(2) Production per unit represents daily average production (boe) per
thousand trust units and is calculated based on daily average
production divided by the normalized weighted average trust units
outstanding including trust units issuable for exchangeable shares.
(3) Reserves per unit are calculated based on proved plus probable
reserves (boe) divided by period end trust units outstanding
including trust units issuable for exchangeable shares.
>>

Currently the Trust distributes $0.10 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, 2009, the Trust has distributed $3.4 billion or $24.38 per unit.
ARC's business plan has resulted in significant operational success as
seen in Table 2 where the Trust's trailing five year annualized return per
unit was 14.6 per cent. However, commodity prices and the current economic
downturn are significant factors impacting the profitability of ARC and
capital appreciation of our trust units in the market place. The impact of
these external factors has led to a negative return for the trailing one and
three years despite the successful execution of ARC's business plan and
operational successes.

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Table 2
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Total Returns(1) Trailing Trailing Trailing
($ per unit except for per cent) One Year Three Year Five Year
-------------------------------------------------------------------------
Distributions per unit $ 2.07 $ 6.95 $ 11.04
Capital appreciation per unit $ (16.14) $ (10.19) $ 2.46
Total return per unit $ (14.07) $ (3.24) $ 13.50
Annualized total return per unit (31.6)% (4.5)% 14.6%
S&P/TSX Capped Energy Trust Index (35.5)% (9.2)% 10.2%
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(1) Calculated as at June 30, 2009.

2009 Second Quarter Financial and Operational Results

Following is a discussion of ARC's 2009 guidance and second quarter
financial and operating results.

2009 Guidance and Financial Highlights

Table 3 is a summary of the Trust's 2009 Guidance and a review of 2009
actual results compared to guidance:

Table 3
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2009 2009
Guidance Actual YTD % Change
-------------------------------------------------------------------------
Production (boe/d)(1) 63,000-64,000 64,418 -
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 10.70 10.57 (1)
Transportation 1.00 0.90 (10)
G&A expenses (cash & non-cash)(2) 2.10 1.94 (8)
Interest 1.30 1.15 (12)
Capital expenditures ($ millions) 350 146 -
Annual weighted average trust units
and trust units issuable (millions) 238 233 -
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(1) The Trust has narrowed the 2009 full year production guidance range
to between 63,000 and 64,000 based on favorable year-to-date 2009
production results and forecast production levels for the balance of
the year.
(2) G&A guidance amount of $2.10 per boe includes $1.75 per boe for cash
G&A costs, $0.55 per boe for cash whole unit plan costs and a
recovery of $0.20 per boe for non-cash portion of the whole unit
plan.
>>

The 2009 Guidance provides unitholders with information on Management's
expectations for results of operations, excluding any acquisitions or
dispositions, for 2009. Readers are cautioned that the 2009 Guidance may not
be appropriate for other purposes.
Table 4 is a review of the financial highlights and operating results for
the second quarter and the first six months of 2009.

<<
Table 4
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Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
(Cdn $ millions, except
per unit and volume % %
data) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 104.3 273.4 (62) 228.6 483.4 (53)
Cash flow from operating
activities per unit(1) 0.44 1.27 (65) 0.98 2.25 (56)
Net income 66.1 57.3 15 88.4 138.6 (36)
Net income per unit(2) 0.28 0.27 4 0.38 0.65 (42)
Distributions per unit(3) 0.32 0.68 (53) 0.68 1.28 (47)
Distributions as a per
cent of cash flow from
operating activities 72 53 36 69 56 23
Average daily production
(boe/d)(4) 63,969 63,896 - 64,418 65,436 (2)
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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 boe in isolation may be
misleading.
>>

Net Income

Net income in the second quarter of 2009 was $66.1 million ($0.28 per
unit), an increase of $8.8 million from $57.3 million ($0.27 per unit) in the
second quarter of 2008. While the Trust posted higher net income during the
second quarter of 2009, there were several non-cash items that negatively
impacted the 2008 results, masking the impact of the significant decrease in
commodity prices in 2009.
In the second quarter of 2008, the Trust recorded a $142.8 million
unrealized non-cash loss on risk management contracts ($106.4 million, net of
future income taxes). As well, the Trust recorded an $18 million provision for
non-recoverable accounts receivable relating a crude oil revenue receivable
from a counterparty that filed for protection under the Companies' Creditors
Arrangement Act in July 2008 ($13.4 million net of future income taxes).
Lastly, the Trust recorded a $3.6 million non-cash foreign exchange gain on
its U.S. denominated debt as a result of the movement in the Canadian dollar
relative to the U.S. dollar ($3.1 million, net of future income taxes).
In the second quarter of 2009, the Trust recorded a $39.7 million
non-cash foreign exchange gain on U.S. denominated debt ($34.7 million, net of
future income taxes) and a $0.6 million unrealized non-cash loss on risk
management contracts ($0.5 million, net of future income taxes).
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. Distributions have been
reduced from $0.28 per unit per month in July 2008 to the current rate of
$0.10 per unit per month.

<<
Table 5
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Net income and
Distributions
($ millions except Second quarter YTD Full year Full year
per cent) 2009 2009 2008 2007
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Net income 66.1 88.4 533.0 495.3
Distributions 75.0 157.0 570.0 498.0
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Excess (Shortfall) (8.9) (68.6) (37.0) (2.7)
Excess (Shortfall) as per
cent of net income (13%) (77%) (7%) (1%)
-------------------------------------------------------------------------
Cash flow from operating
activities 104.3 228.6 944.4 704.9
Distributions as a per
cent of cash flow from
operating activities 72% 69% 60% 71%
Average distribution per
unit per month $0.11 $0.11 $0.22 $0.20
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>>

Cash Flow from Operating Activities

Cash flow from operating activities decreased by 62 per cent in the
second quarter of 2009 to $104.3 million from $273.4 million in the second
quarter of 2008. Decreases in crown royalties and cash losses on risk
management contracts were more than offset by the 54 per cent ($47.41 per boe)
decrease in commodity prices relative to the second quarter of 2008. The
decrease in second quarter 2009 cash flow from operating activities compared
with the second quarter of 2008 is detailed in Table 6.

<<
Table 6
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($ per
($ millions) trust unit) (% Change)
-------------------------------------------------------------------------
Q2 2008 Cash flow from Operating
Activities 273.4 1.27 -
-------------------------------------------------------------------------
Volume variance 0.6 - 0.2
Price variance (277.2) (1.29) (101.3)
Cash (losses) and gains on risk
management contracts 42.8 0.20 15.7
Royalties 64.3 0.30 23.5
Expenses:
Transportation (0.3) - (0.1)
Operating(1) (0.7) - (0.3)
Cash G&A 14.1 0.07 5.2
Interest 0.7 - 0.3
Realized foreign exchange loss 0.8 - 0.3
Weighted average trust units - (0.04) -
Non-cash and other items(2) (14.2) (0.07) -
-------------------------------------------------------------------------
Q2 2009 Cash flow from Operating
Activities 104.3 0.44 -
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-------------------------------------------------------------------------
(1) Excludes non-cash portion of Whole Unit Plan 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 decreased by 53 per cent
in 2009 to $228.6 million from $483.4 million in the first half of 2008. The
49 per cent ($37.59 per boe) decrease in year-to-date commodity prices
relative to the same period of 2008 more than offset decreases in crown
royalties and cash losses on risk management contracts. The decrease in
year-to-date 2009 cash flow from operating activities compared with the first
half of 2008 is detailed in Table 6a.

<<
Table 6a
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($ per
($ millions) trust unit) (% Change)
-------------------------------------------------------------------------
YTD 2008 Cash flow from
Operating Activities 483.4 2.25 -
-------------------------------------------------------------------------
Volume variance (19.3) (0.09) (4.0)
Price variance (440.2) (2.04) (91.1)
Cash (losses) and gains on risk
management contracts 88.6 0.41 18.3
Royalties 99.6 0.46 20.6
Expenses:
Transportation (1.5) (0.01) (0.3)
Operating(1) (4.6) (0.02) (1.0)
Cash G&A 7.3 0.03 1.5
Interest 3.7 0.02 0.8
Realized foreign exchange loss 0.6 - 0.1
Weighted average trust units - (0.08) -
Non-cash and other items(2) 11.0 0.05 -
-------------------------------------------------------------------------
YTD 2009 Cash flow from Operating
Activities 228.6 0.98 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes non-cash portion of Whole Unit Plan expense recorded in
operating costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.

2009 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 and the
resulting impact on cash flows from operating activities in total and per
trust unit:

Table 7
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Impact on Annual Cash
flow from operating
activities(2)
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 60.00 $ 1.00 $ 0.04
Natural gas price (Cdn$AECO/mcf)(1) $ 4.35 $ 0.10 $ 0.02
Cdn$/US$ exchange rate(3) 1.15 $ 0.01 $ 0.03
Interest rate on debt % 3.90 % 1.0 $ 0.02
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.02
Gas production volumes (mmcf/d) 189.0 % 1.0 $ 0.01
Operating expenses per boe $ 10.70 % 1.0 $ 0.01
Cash G&A and LTIP expenses per boe $ 2.30 % 10.0 $ 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Analysis does not include the effect of hedging contracts.
(2) Assumes constant working capital.
(3) Includes impact of foreign exchange on crude oil prices which are
presented in U.S. dollars. This amount does not include a foreign
exchange impact relating to natural gas prices as they are presented
in Canadian dollars in this sensitivity.
>>

Production

Production volumes averaged 63,969 boe per day in the second quarter of
2009 compared to 63,896 boe per day in the same period of 2008 as detailed in
Table 8. In the second quarter of 2009, the Trust posted higher than
anticipated volumes in the Dawson area, due to the delay of a planned gas
plant turnaround, and, at Ante Creek and Goodlands due to strong production
volumes from horizontal wells drilled during this past winter, allowing total
production to exceed budget through the first part of the turnaround season.

<<
Table 8
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
% %
Production 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Light & medium crude
oil (bbl/d) 25,901 26,288 (1) 26,805 27,003 (1)
Heavy oil (bbl/d) 1,016 1,253 (19) 1,051 1,299 (19)
Natural gas (mmcf/d) 200.2 194.7 3 197.0 199.5 (1)
NGL (bbl/d) 3,679 3,906 (6) 3,721 3,882 (4)
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Total production
(boe/d)(1) 63,969 63,896 - 64,418 65,436 (2)
% Natural gas production 52 51 51 51
% Crude oil and liquids
production 48 49 49 49
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>

Light and medium crude oil production decreased marginally to 25,901 boe
per day compared to 26,288 boe per day in 2008, while heavy oil production
declined by 237 boe per day. When compared to the first quarter of 2009, the
total crude oil production in the second quarter of 2009 decreased by seven
per cent. This is a result of scheduled facility turnarounds completed in the
quarter. Natural gas production was 200.2 mmcf per day in the second quarter
of 2009, an increase of three per cent from the 194.7 mmcf per day produced in
the second quarter of 2008, due primarily to the increased production from the
Dawson area.
The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During the second quarter of 2009, the Trust
drilled nine gross wells (nine net wells) on operated properties; one gross
oil well, and eight gross natural gas wells with a 100 per cent success rate.
Of the wells drilled during the second quarter, two gas wells were completed.
A total of nine operated wells were brought on production during the second
quarter, all of which were drilled earlier in the year.
The Trust expects that 2009 full year production will average
approximately 63,000 to 64,000 boe per day and that 122 gross wells (101 net
wells) will be drilled by ARC on operated properties with participation in an
additional 54 gross wells to be drilled on the Trust's non-operated
properties. The Trust estimates that the revised 2009 drilling program will
add sufficient production from new wells to offset the majority of production
declines on existing properties, however, overall production is expected to
decrease by 1,000 to 2,000 boe per day relative to 2008 production levels. The
planned capital expenditures are being continuously monitored in the context
of the current economic environment and will be revised as required.
Table 9 summarizes the Trust's production by core area:

<<
Table 9
-------------------------------------------------------------------------
Three Months Ended June 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 6,918 1,084 28.4 1,101
N.E. BC & N.W. AB 14,477 708 78.3 718
Northern AB 8,981 3,976 25.2 801
Pembina & Redwater 13,214 9,181 18.7 919
S.E. AB & S.W. Sask. 9,026 1,001 48.1 12
S.E. Sask. & MB 11,353 10,967 1.5 128
-------------------------------------------------------------------------
Total 63,969 26,917 200.2 3,679
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Three Months Ended June 30, 2008
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,450 1,376 29.2 1,203
N.E. BC & N.W. AB 12,395 832 65.7 622
Northern AB 10,086 4,574 27.2 985
Pembina & Redwater 12,822 8,883 18.4 873
S.E. AB & S.W. Sask. 9,811 1,011 52.7 11
S.E. Sask. & MB 11,332 10,865 1.5 212
-------------------------------------------------------------------------
Total 63,896 27,541 194.7 3,906
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is
northwest, S.E. is southeast and S.W. is southwest.

Table 9a summarizes the Trust's production by core area for the first half
of 2009:

Table 9a
-------------------------------------------------------------------------
Six Months Ended June 30, 2009
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,023 1,236 28.1 1,108
N.E. BC & N.W. AB 14,050 731 75.8 674
Northern AB 9,235 4,163 25.3 853
Pembina & Redwater 13,504 9,413 18.9 946
S.E. AB & S.W. Sask. 8,909 998 47.4 13
S.E. Sask. & MB 11,697 11,315 1.5 127
-------------------------------------------------------------------------
Total 64,418 27,856 197.0 3,721
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Six Months Ended June 30, 2008
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,610 1,418 29.8 1,234
N.E. BC & N.W. AB 12,619 842 66.8 624
Northern AB 10,359 4,814 27.7 930
Pembina & Redwater 13,410 9,172 20.0 906
S.E. AB & S.W. Sask. 9,926 998 53.5 13
S.E. Sask. & MB 11,512 11,058 1.7 175
-------------------------------------------------------------------------
Total 65,436 28,302 199.5 3,882
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Revenue

Revenue decreased to $235.2 million in the second quarter of 2009, $276.8
million lower than 2008 revenues of $512 million. While oil volumes were
relatively unchanged year-over-year, the decrease in realized oil prices
accounted for a $142.8 million decrease in revenues with only $7.1 million of
the decrease attributable to lower volumes. Natural gas revenue decreased by
$116.4 million, comprising a $118.3 million decrease due to lower prices
realized in 2009 and a $1.9 million increase due to higher volumes produced in
2009.
A breakdown of revenue is outlined in Table 10:

<<
Table 10
-------------------------------------------------------------------------
Revenue Three Months Ended Six Months Ended
June 30 June 30
% %
($ millions) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Oil revenue 153.7 296.5 (48) 274.1 533.9 (49)
Natural gas revenue 68.0 184.4 (63) 158.6 329.3 (52)
NGL revenue 13.0 29.3 (56) 26.2 53.3 (51)
-------------------------------------------------------------------------
Total commodity revenue 234.7 510.2 (54) 458.9 916.5 (50)
Other revenue 0.5 1.8 (72) 1.5 3.4 (56)
Total revenue 235.2 512.0 (54) 460.4 919.9 (50)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Commodity Prices Prior to Hedging

Table 11
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
% %
2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Average Benchmark Prices
AECO gas ($/mcf)(1) 3.66 9.35 (61) 4.64 8.24 (44)
WTI oil (US$/bbl)(2) 59.62 124.00 (52) 51.46 110.98 (54)
Cdn$/US$ foreign exchange
rate 1.16 1.01 (15) 1.20 1.01 (19)
WTI oil (Cdn$/bbl) 69.25 125.78 (45) 61.59 111.56 (45)
-------------------------------------------------------------------------
ARC Realized Prices Prior
to Hedging
Oil ($/bbl) 62.74 118.32 (47) 54.36 103.63 (48)
Natural gas ($/mcf) 3.73 10.41 (64) 4.45 9.07 (51)
NGL ($/bbl) 38.89 82.29 (53) 38.88 75.46 (48)
-------------------------------------------------------------------------
Total commodity revenue
before hedging ($/boe) 40.32 87.73 (54) 39.36 76.95 (49)
Other revenue ($/boe) 0.09 0.31 (71) 0.13 0.29 (55)
Total revenue before
hedging ($/boe) 40.41 88.04 (54) 39.49 77.24 (49)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

Oil prices began to recover in the second quarter of 2009 with US$WTI
prices averaging $59.62 as compared to $43.21 in the first quarter of 2009.
Despite this recovery, prices in the second quarter of 2009 were down 52 per
cent over the comparable period in 2008. This dramatic decrease was partially
offset by the weakening of the Canadian dollar compared to the U.S. dollar;
however, widening of the price differentials further eroded the Trust's
realized oil price. The Trust's oil production consists predominantly of light
and medium crude oil while heavy oil accounts for less than five per cent of
the Trust's crude oil production. The realized price for the Trust's oil,
before hedging, was $62.74 per boe, a 47 per cent reduction over the second
quarter 2008 realized price of $118.32 per boe.
Natural gas prices declined considerably in the second quarter of 2009.
Alberta AECO Hub natural gas prices, which are commonly used as an industry
reference, averaged $3.66 per mcf in the second quarter of 2009 compared to
$9.35 per mcf in the same period of 2008. ARC's realized gas price, before
hedging, decreased by 64 per cent to $3.73 per mcf compared to $10.41 per mcf
in the second quarter of 2008. ARC's realized gas price is based on prices
received at the various markets in which the Trust sells its natural gas.
ARC's natural gas sales portfolio consists of gas sales priced at the AECO
monthly index, the AECO daily spot market, eastern and mid-west United States
markets and a portion to aggregators. Natural gas prices have continued to
soften in the third quarter of 2009 with posted prices in the month of July
registering under $3 per mcf. Management does not expect natural gas prices to
improve in the near term as a result of continuing record storage volumes and
concern over the state of the North American economy. Unitholders should
expect further deterioration in natural gas revenue in the third quarter with
possible recovery beginning in the fourth quarter.
Prior to hedging activities, ARC's total realized commodity price was
$40.32 per boe in the second quarter of 2009, a 54 per cent decrease from the
$87.73 per boe received prior to hedging in the second quarter of 2008.

Risk Management and Hedging Activities

ARC maintains 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.
Gain or loss on risk management contracts comprise realized and
unrealized gains or losses on risk management contracts that do not meet the
accounting definition requirements of an effective hedge, even though the
Trust considers all risk management contracts to be effective economic hedges.
Accordingly, gains and losses on such contracts are shown as a separate
category in the statement of income.
In the second quarter of 2008, the Trust recorded significant realized
and unrealized losses on risk management contracts as commodity prices, and in
particular oil prices, rose to record highs generating a total unrealized loss
of $142.8 million and a cash realized loss of $44.7 million. With the decrease
in commodity prices that occurred in the later part of 2008 and the first half
of 2009, the unrealized losses recorded at this time last year have not
materialized.
Lower natural gas prices in the second quarter of 2009 resulted in
realized cash gains of $2.7 million on natural gas risk management contracts
as the Trust's contracted prices were higher than market prices during the
quarter. Realized cash losses of $5 million were recorded on the Trust's crude
oil risk management contracts as a result of premiums paid during the second
quarter of 2009 and small losses recorded on the Trust's fixed price swap
contract during the month of June where the market oil price rose above the
contracted price.
ARC's second quarter 2009 results include an unrealized total
mark-to-market loss of $0.6 million with a net unrealized mark-to-market loss
position of $3.8 million as at June 30, 2009. The net loss position is mostly
attributed to losses on the Trust's power and crude oil contracts and offset
by gains on the Trust's natural gas contracts. The mark-to-market values
represent the market price to buy-out the Trust's contracts as of June 30,
2009 and may differ from what will eventually be realized.
Table 12 summarizes the total gain (loss) on risk management contracts
for the second quarter of 2009 as compared to the same period in 2008:

<<
Table 12
-------------------------------------------------------------------------
Risk Management Crude Foreign Q2 Q2
Contracts Oil & Natural Curr- Inter- 2009 2008
($ millions) Liquids Gas ency Power(3) est Total Total
-------------------------------------------------------------------------
Realized cash
(loss) gain on
contracts(1) (5.0) 2.7 0.8 (0.4) 0.0 (1.9) (44.7)
Unrealized
(loss) gain on
contracts(2) (4.4) 3.1 0.0 0.7 0.0 (0.6) (142.8)
-------------------------------------------------------------------------
Total (loss) gain
on risk management
contracts (9.4) 5.8 0.8 0.3 0.0 (2.5) (187.5)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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) Amounts presented in Table 12 exclude a $0.9 million realized loss
and an unrealized loss of $0.2 million for the Trust's power
contracts that have been designated as effective hedges for
accounting purposes. Realized gains and losses on these contracts are
recorded in operating costs and unrealized gains and losses are
recorded in the Consolidated Statement of Comprehensive Income and
Accumulated Other Comprehensive Income.

Table 12a summarizes the total gain (loss) on risk management contracts
for the first half of 2009 as compared to the same period in 2008:

Table 12a
-------------------------------------------------------------------------
Risk Management Crude Foreign YTD YTD
Contracts Oil & Natural Curr- Inter- 2009 2008
($ millions) Liquids Gas ency Power(3) est Total Total
-------------------------------------------------------------------------
Realized cash
(loss) gain on
contracts(1) (6.9) 16.2 0.8 (0.5) 4.8 14.4 (74.2)
Unrealized
(loss) gain on
contracts(2) (4.8) 6.5 0.0 (3.5) (5.4) (7.2) (161.5)
-------------------------------------------------------------------------
Total (loss) gain
on risk management
contracts (11.7) 22.7 0.8 (4.0) (0.6) 7.2 (235.7)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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) Amounts presented in Table 12a exclude a $0.8 million realized loss
and an unrealized loss of $3.2 million for the Trust's power
contracts that have been designated as effective hedges for
accounting purposes. Realized gains and losses on these contracts are
recorded in operating costs and unrealized gains and losses are
recorded in the Consolidated Statement of Comprehensive Income and
Accumulated Other Comprehensive Income.

The Trust currently limits the amount of forecast production that can be
hedged to a maximum 50 per cent with the remaining 50 per cent of production
being sold at market prices. The following table is an indicative summary of
the Trust's positions for crude oil and natural gas as at June 30, 2009.

Table 13
-------------------------------------------------------------------------
Hedge Positions
As at June 30, 2009(1)(2)
Q3 2009 Q4 2009
-------------------------------------------------------------------------
Crude Oil Cdn$/bbl bbl/day Cdn$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 75.00 3,000 80.75 4,000
Bought Put 64.52 5,500 66.99 6,500
Sold Put 46.50 2,500 46.50 2,500
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 5.48 80,000 5.83 60,109
Bought Put 4.73 80,000 5.05 60,109
Sold Put 4.50 20,000 4.50 20,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Hedge Positions
As at June 30, 2009(1)(2)
Q1 2010(3) Q2-Q4 2010(3)
-------------------------------------------------------------------------
Crude Oil Cdn$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 93.00 1,000
Bought Put 75.56 1,000 No contracts in place
Sold Put N/A -
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 6.80 5,000 6.80 5,000
Bought Put 6.80 5,000 6.80 5,000
Sold Put N/A - N/A -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The prices and volumes noted above represents 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.
(2) In addition to positions shown here, ARC has entered into additional
basis positions until October 2012, an energy equivalent swap until
December 31, 2009, as well as a fixed price swap for crude oil for
the month of April 2009. Please refer to note 9 in the Notes to the
Consolidated Financial Statements for full details of the Trust's
risk management positions as of June 30, 2009.
(3) The natural gas contract listed for 2010 is a fixed price swap
starting in 2010 and ending in December 2013. During the quarter, the
Trust took advantage of favorable forward curve pricing for natural
gas and entered into a long-term contract for a small portion of
future forecast production.

Table 13 should be interpreted as follows using the third quarter 2009
natural gas 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 $4.73, ARC will receive $4.73 less the
difference between $4.50 and the market price on 20,000 GJ per day.
For example if the market price is $4.45, the Trust will receive
$4.68 on 20,000 GJ per day.
- If the market price is between $4.50 and $4.73, ARC will receive
$4.73 on 80,000 GJ per day.
- If the market price is between $4.73 and $5.48, ARC will receive the
market price on 80,000 GJ per day.
- If the market price exceeds $5.48, ARC will receive $5.48 on
80,000 GJ per day.
>>

Operating Netbacks

The Trust's operating netback, before realized hedging gains and losses,
decreased 61 per cent to $23.82 per boe in the second quarter of 2009 compared
to $60.75 per boe in the same period of 2008. The decrease in netbacks is due
most significantly to the reduced commodity prices in the period as well as
higher operating costs and transportation costs and was partially offset by
lower royalties corresponding to the lower commodity prices.
The Trust's second quarter 2009 netback, after realized hedging gains and
losses, was $23.36 per boe, a 56 per cent decrease from the same period in
2008. The 2009 netback includes net losses recorded on the Trust's crude oil
and natural gas contracts during the quarter of $0.46 per boe compared to a
net loss of $7.67 per boe recorded for the same period in 2008.
The components of operating netbacks are summarized in Table 14 and 14a:

<<
Table 14
-------------------------------------------------------------------------
Crude Heavy Q2 2009 Q2 2008
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average sales
price 62.92 57.96 3.73 38.89 40.32 87.73
Other revenue - - - - 0.09 0.31
-------------------------------------------------------------------------
Total revenue 62.92 57.96 3.73 38.89 40.41 88.04
Royalties (8.65) (3.59) (0.17) (10.86) (4.72) (15.79)
Transportation (0.14) (1.29) (0.25) - (0.85) (0.79)
Operating costs(1) (13.20) (12.65) (1.52) (7.75) (11.02) (10.71)
-------------------------------------------------------------------------
Netback prior to hedging 40.93 40.43 1.79 20.28 23.82 60.75
Realized gain (loss) on
risk management contracts (2.11) - 0.15 - (0.46) (7.67)
-------------------------------------------------------------------------
Netback after hedging 38.82 40.43 1.94 20.28 23.36 53.08
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Table 14a
-------------------------------------------------------------------------
YTD YTD
Crude Heavy 2009 2008
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average sales
price 54.61 47.76 4.45 38.88 39.36 76.95
Other revenue - - - - 0.13 0.29
-------------------------------------------------------------------------
Total revenue 54.61 47.76 4.45 38.88 39.49 77.24
Royalties (7.78) (3.15) (0.50) (12.17) (5.53) (13.77)
Transportation (0.16) (1.40) (0.27) - (0.90) (0.76)
Operating costs(1) (12.96) (14.31) (1.41) (7.83) (10.57) (10.11)
-------------------------------------------------------------------------
Netback prior to hedging 33.71 28.90 2.27 18.88 22.49 52.60
Realized gain (loss)
on risk management
contracts(2) (1.42) - 0.46 - 0.76 (6.23)
-------------------------------------------------------------------------
Netback after hedging 32.29 28.90 2.73 18.88 23.25 46.37
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 decreased to 11.9 per cent ($4.72 per boe) in the second
quarter of 2009 compared to 18.1 per cent ($15.79 per boe) in 2008. Royalties
for the first half of 2009 decreased to 14.3 per cent ($5.53 per boe) as
compared to 18 per cent ($13.77) for the same period of 2008. During the
second quarter of 2009, the Trust recorded a credit of $2.6 million related to
natural gas royalties in British Columbia. The adjustment relates to prior
periods for additional operating cost deductions that are applied in the
determination of royalties in the province. The Alberta Government's New
Royalty Framework ("Framework" or "NRF") took effect January 1, 2009 and
provides for lower royalty payments during times of low commodity prices and
significantly higher royalty payments when commodity prices are high. The 2009
royalty rate is in line with Management's expectations due to the low
commodity price environment. The Trust continues to evaluate the amendments to
the new royalty framework in order to determine the optimal elections that
should be made by the Trust. See Alberta Government New Royalty Framework for
additional discussion.
Operating costs increased to $11.02 per boe compared to $10.71 per boe in
the second quarter of 2008. Total operating costs increased $1.9 million, or
three per cent in the second quarter of 2009 in part due to the large number
of maintenance turnarounds on operated properties throughout the second
quarter of 2009. The Trust completed 37 turnarounds with minimal production
downtime. There is a high fixed operating cost component for the Trust's
properties resulting in a trend of increased operating costs on a per boe
basis as production declines over time. The Trust estimates that full year
2009 operating costs will be approximately $245 million or approximately
$10.70 per boe based on annual production of between 63,000 and 64,000 boe per
day. This includes a six per cent increase for costs associated with the
increase in total operated wells in 2009 as compared to 2008.

Alberta Government New Royalty Framework

The Alberta Crown Royalty Framework was legislated in November 2008 and
took effect on January 1, 2009 with the following elements:

<<
- Increased royalty rates on conventional and non-conventional oil and
natural gas production in Alberta whereby royalty rates may increase
to a maximum rate of 50 per cent;

- Sliding scale royalty calculations based on a broader range of
commodity prices whereby conventional oil and natural gas royalty
rates may increase up to maximum prices of approximately Cdn$120 per
barrel and Cdn$16 per GJ, respectively;

- The elimination of royalty incentive and royalty holiday programs
with the exception of specific programs relating to deep oil and
natural gas drilling programs, innovative technology and enhanced
recovery programs.
>>

Subsequent to legislation of the NRF, the Alberta Government introduced
the Transitional Royalty Plan ("TRP") which offers reduced royalty rates for
new wells drilled on or after November 19, 2008 through December 31, 2013 that
meet certain depth criteria. The TRP is in place for a maximum period of five
years to December 31, 2013; all wells will convert to the NRF on January 1,
2014. The TRP is an "elective plan" whereby an election must be filed on an
individual well basis to qualify for the TRP.
On March 3, 2009, the Alberta Government announced the Energy Incentive
Program ("EIP") in response to the decrease in energy related development
activity in the province. The EIP was further revised on June 25, 2009. The
incentive program will work in tandem with the NRF and the TRP and includes
the following key elements:

<<
- Drilling Royalty Credit - producers will receive a drilling credit
for new wells drilled between April 1, 2009 and March 31, 2011. The
drilling credit is based on a $200 per meter credit on total meters
drilled, however the maximum drilling credit is limited to 10 per
cent of total Alberta Crown Royalties paid for companies producing
greater than 25,000 boe per day in Alberta. The drilling credit will
be recorded as a reduction of capital expenditures rather than a
reduction of royalty expense.

- New Well Incentive Program - new production brought on-stream between
April 1, 2009 and March 31, 2011 will qualify for a five per cent
Alberta Crown Royalty rate for a period of 12 months subject to
volume caps of 50,000 barrels of crown oil production and 150 Mmcf of
crown natural gas production.
>>

Approximately 65 per cent of the Trust's production is in Alberta;
consequently, the Framework including the TRP and EIP will have a significant
impact on the Trust's Alberta and corporate royalty rates. The Trust has
completed an assessment of the Framework and has estimated that the Trust's
average corporate royalty rate will change from approximately 18 per cent of
revenue in 2008 to between 15 and 25 per cent of revenue in 2009 depending
upon commodity prices as illustrated in Table 15 and the value of incentives
realized in 2009. As at June 30, 2009, no amounts have been recorded in the
Trust's second quarter financial statements for the EIP as the final rules had
not been finalized by the Alberta Government.

<<
Table 15
-------------------------------------------------------------------------
2009 Estimated Royalty Rates - New Royalty Framework
-------------------------------------------------------------------------
Edmonton posted oil
(Cdn$/bbl)(1) $40 $60 $80 $100
AECO natural gas (Cdn$/GJ)(1) $4 $6 $8 $10
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Alberta royalty rate prior
to NRF(2) 17.5% 17.5% 17.5% 17.5%
NRF Alberta royalty rate
before incentives(3) 11.8% 18.0% 23.8% 29.0%
NRF Alberta royalty after
estimated incentives(3)(4) 11.6% 17.7% 23.4% 28.4%
-------------------------------------------------------------------------
Per cent increase
(decrease) - Alberta
royalty rate (34)% 1% 34% 62%
-------------------------------------------------------------------------
Corporate royalty rate
prior to NRF(2) 18.0% 18.0% 18.0% 18.0%
NRF corporate royalty rate
before incentives(3) 15.0% 18.9% 22.6% 25.8%
NRF corporate royalty rate
after estimated
incentives(3)(4) 14.9% 18.7% 22.3% 25.5%
-------------------------------------------------------------------------
Per cent increase
(decrease) - Corporate
royalty rate (17)% 4% 24% 42%
-------------------------------------------------------------------------
Increase (decrease) in
annual Corporate
royalties ($millions) $(23.0) $7.9 $63.2 $137.4
-------------------------------------------------------------------------
Increase (decrease) annual
cash flow per unit $0.10 $(0.03) $(0.27) $(0.58)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Canadian dollar denominated prices before quality differentials.
(2) Under the previous Alberta Crown Royalty regime, Alberta and
Corporate royalty rates were consistent across all price scenarios as
price ceilings were exceeded whereby royalty rates changed only
marginally across the price scenarios presented.
(3) Estimated royalty rates include Crown, Freehold and Gross Overriding
royalties for all jurisdictions in which the Trust operates.
(4) Assuming all wells drilled on Alberta Crown lands on or after
April 1, 2009 will qualify for the five per cent new well incentive
rate and the drilling royalty credit program. The drilling credit
amount has not been reflected as a reduction of royalty expense as
this amount will be reflected as a reduction of capital expenditures.

General and Administrative ("G&A") Expenses and Trust Unit Incentive
Compensation
>>

G&A net of overhead recoveries on operated properties increased four per
cent to $10.2 million in the second quarter of 2009 from $9.8 million in 2008.
The modest increase in G&A expenses was due to a decrease in operating
recoveries of $0.4 million.
The Trust did not make any payments under the Whole Trust Unit Incentive
Plan ("Whole Unit Plan") in the second quarter of 2009 due to a change in the
plan whereby the first half 2009 cash payment of $7.6 million was recorded in
the first quarter of 2009. In 2008, $18.3 million in cash payments were made
under the Whole Unit Plan in the second quarter. For the first six month
period in 2009, cash G&A expenses including the Whole Unit Plan payments
decreased by 22 per cent from $33.5 million in 2008 to $26.2 million in 2009.
The next cash payment under the Whole Unit Plan is scheduled to occur in
September 2009.
Table 16 is a breakdown of G&A and trust unit incentive compensation
expense under the Whole Unit Plan:

<<
Table 16
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
G&A and Trust Unit
Incentive Compensation
Expense % %
($ millions except per boe) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
G&A expenses 13.8 13.8 - 28.6 27.0 6
Operating recoveries (3.6) (4.0) (10) (8.0) (7.9) 1
-------------------------------------------------------------------------
Cash G&A expenses before
Whole Unit Plan 10.2 9.8 4 20.6 19.1 8
Cash Expense - Whole
Unit Plan - 14.4 (100) 5.6 14.4 (61)
-------------------------------------------------------------------------
Cash G&A expenses including
Whole Unit Plan 10.2 24.2 (58) 26.2 33.5 (22)
Accrued compensation -
Whole Unit Plan 7.3 (1.7) 529 (3.6) 10.2 (135)
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense 17.5 22.5 (23) 22.6 43.7 (48)
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense per boe 2.99 3.88 (23) 1.94 3.67 (47)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $7.3 million ($1.24 per boe) was recorded in the
second quarter of 2009 compared to a recovery of $1.7 million ($0.29 per boe)
in 2008. The expense in 2009 relates to the estimated costs of the plan to
June 30, 2009 and an increase in the liability for the units outstanding at
June 30, 2009 due to the increase in the trust unit price relative to the
closing price of the trust units at March 31, 2009. The 2008 non-cash amount
relates to a reversal of the accrual for the cash payment made in the second
quarter.

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 17 shows the changes to the Whole Unit Plan during the first six
months of 2009 along with the estimated value upon vesting of the plan at June
30, 2009:

<<
Table 17
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and $ millions Number of Number of Total RTUs
except per unit) RTUs PTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 756 959 1,715
Granted in the period 412 379 791
Vested in the period (180) (154) (334)
Forfeited in the period (34) (17) (51)
-------------------------------------------------------------------------
Balance, end of period(1) 954 1,167 2,121
Estimated distributions to vesting date(2) 195 325 520
-------------------------------------------------------------------------
Estimated units upon vesting after
distributions 1,149 1,492 2,641
Performance multiplier(3) - 1.5 -
-------------------------------------------------------------------------
Estimated total units upon vesting 1,149 2,169 3,318
-------------------------------------------------------------------------
Trust unit price at June 30, 2009 17.81 17.81 17.81
Estimated total value upon vesting
($ millions) 20.5 38.6 59.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 1.5 at June 30, 2009 based on an 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
except during the first year of each grant where a performance
multiplier of 1.0 is used.
>>

The value associated with the RTUs and PTUs is expensed in the statement
of income over the vesting period with the expense amount being determined by
the trust unit price, the number of PTUs to be issued on vesting, and
distributions. In periods where substantial trust unit price fluctuation
occurs, the Trust's G&A expense is subject to significant volatility.
Table 18 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, 2009:

<<
Table 18
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
June 30, 2009 Performance multiplier
(units thousands and $ millions --------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 1,149 1,149 1,149
PTUs - 1,492 2,984
-------------------------------------------------------------------------
Total units(1) 1,149 2,641 4,133
-------------------------------------------------------------------------
Trust unit price(2) 17.81 17.81 17.81
Trust unit distributions per month(2) 0.10 0.10 0.10
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting(3) 20.5 47.0 73.6
-------------------------------------------------------------------------
2009 3.7 6.3 8.9
2010 8.2 16.1 24.0
2011 5.6 13.4 21.2
2012 3.0 11.2 19.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 a
future trust unit price of $17.81 and $0.10 per trust unit
distributions based on the unit price and distribution levels in
place at June 30, 2009.
(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 September 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 $20.5 million and $73.6 million will be paid out from
2009 through 2012 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.

Interest and financing charges

Interest and financing charges decreased to $7.6 million in the second
quarter of 2009 from $8.3 million in 2008 due to a decrease in short-term
interest rates. As at June 30, 2009, the Trust had $707.3 million of long-term
debt outstanding, of which $382.5 million was fixed at a weighted average rate
of six per cent and $324.8 million, including the working capital facility,
was floating at current market rates plus a credit spread of 60 basis points.
Sixty-three per cent (US $385.1 million) of the Trust's debt is denominated in
U.S. dollars.

Foreign Exchange Gains and Losses

The Trust recorded a gain of $40 million in the second quarter of 2009 on
foreign exchange transactions compared to a gain of $3.1 million in 2008.
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. The 2009 realized foreign exchange loss of $0.3 million relates
to interest payments and hedging settlements in the quarter.
Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The volatility of the Canadian dollar during
the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain or loss impacts net income
but does not impact cash flow from operating activities as it is a non-cash
amount. From March 31, 2009 to June 30, 2009, the Cdn$/US$ exchange rate
decreased from 1.26 to 1.16 resulting in an unrealized gain of $39.7 million
on U.S. dollar denominated debt.

Taxes

In the second quarter of 2009, a future income tax recovery of $13
million was included in income compared to a recovery of $31.1 million in the
second quarter of 2008. The large recovery in 2008 was attributable to the
future tax recovery recorded on the unrealized risk management contract losses
recorded during the same period.
The corporate income tax rate applicable to 2009 is 29 per cent; however
the Trust and its subsidiaries did not pay any material cash income taxes for
the second quarter of 2009. Due to the Trust's structure, currently, both
income tax and future tax liabilities are passed on to the unitholders by
means of royalty payments made between ARC Resources and the Trust.
Management and the Board of Directors continue to review the impact of
the SIFT rules on our business strategy. At this time Management is of the
opinion that the conversion from a trust to a corporation is the most logical
and tax efficient alternative for ARC unitholders. With this in mind,
Management has begun the process of detailing the steps required to convert to
a corporation and is working with tax advisors to further define the process.
A conversion to a corporation will require approval of ARC's unitholders,
as well as customary court and regulatory approvals. The Trust currently
anticipates that the closing of a conversion would occur on or before December
31, 2010. This would require a unitholder meeting to be scheduled for early to
mid-December 2010. To be implemented, a conversion must be approved by not
less than two-thirds of the votes cast by unitholders voting at the meeting.
The intention would be for a conversion to be tax deferred for Canadian and
U.S. income tax purposes.
For Canadian GAAP, Management anticipates that the conversion would be
accounted for on a continuity of interests basis. Under the continuity of
interests method of accounting, the corporation would be recognized as the
successor entity to the Trust and the Consolidated Financial Statements would
reflect financial position, results of operations and cash flows as if the
corporation had always carried on the business formerly carried on by the
Trust. Certain terms such as shareholder, unitholder, dividend, and
distribution would be used interchangeably throughout the Consolidated
Financial Statements.
The corporation would expect to allocate its cash flow among funding a
portion of capital expenditures, periodic debt repayments, site reclamation
expenditures, and dividends, or distributions. Current taxes payable by ARC
after converting to a corporation will be subject to normal corporate tax
rates. Taxable income as a corporation will vary depending on total income and
expenses and vary with changes to commodity prices, costs, claims for both
accumulated tax pools and tax pools associated with current year expenditures.
As ARC has accumulated $2.2 billion of income tax pools, taxable income will
be reduced or potentially eliminated for the initial period post conversion.
The $2.2 billion of income tax pools (detailed in Table 19) are deductible at
various rates and annual deductions associated with the initial tax pools will
decline over time.

<<
Table 19
-------------------------------------------------------------------------
Cdn $ millions at
Tax Pool type June 30, 2009 Annual deductibility
-------------------------------------------------------------------------
Canadian Oil and Gas Property
Expense 989.2 10% declining balance
Canadian Development Expense 376.2 30% declining balance
Canadian Exploration Expense 93.2 100%
Un-depreciated Capital Cost 396.6 Primarily 25% declining
balance
Non-Capital Losses 132.5 100%
Research and Experimental Credits 0.8 100%
Other 17.5 Various rates, 7%
declining balance to 20%
-------------------------------------------------------------------------
Total Federal Tax Pools 2,006.0
-------------------------------------------------------------------------
Additional Alberta Tax Pools 155.5 Various rates, 25%
declining balance to 100%
-------------------------------------------------------------------------
Total Federal and Provincial Pools 2,161.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Returns to shareholders post conversion will be impacted by the reduction
of cash flow required to pay current income taxes, if any. Over the longer
term, we would expect Canadian investors who hold their trust units in a
taxable account will be relatively indifferent on an after tax basis as to
whether ARC is structured as a corporation or as a trust in 2011. However,
Canadian tax deferred investors (those holding their trust units in a tax
deferred vehicle such as an RRSP, RRIF or pension plan) and foreign investors
will realize a lower after tax return on distributions in 2011 due to the
introduction of the SIFT Tax should ARC stay as a trust, and their inability
to claim the dividend tax credit if ARC converts to a corporation.
If a conversion from the trust structure to a corporation is approved by
the unitholders, the income tax payable by unitholders will vary and each
unitholder should consult their own tax advisor for details on the direct
impact to themselves.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate increased to
$16.89 per boe in the second quarter of 2009 from $15.98 per boe in the second
quarter of 2008. The Trust posted a large increase in proved reserves at
year-end 2008; however, these reserves were offset by a significant increase
in the future development costs required to convert proven undeveloped
reserves to proven producing reserves.
A breakdown of the DD&A rate is summarized in Table 20:

<<
Table 20
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
DD&A Rate
($ millions except per % %
boe amounts) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Depletion of oil and gas
assets(1) 94.9 90.7 5 190.0 185.4 2
Accretion of asset
retirement obligation(2) 2.3 2.3 - 4.6 4.6 -
-------------------------------------------------------------------------
Total DD&A 97.2 93.0 5 194.6 190.0 2
DD&A rate per boe 16.89 15.98 6 16.69 15.95 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the property, plant and equipment
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

Capital expenditures, excluding acquisitions and dispositions, totaled
$48.9 million in the second quarter of 2009 compared to $131.3 million in the
same period of 2008. This amount was incurred on drilling and completions,
geological, geophysical and facilities expenditures.
Of the total amount spent in the second quarter, $29.1 million was spent
on the Montney resource play while the remaining $19.8 million was spent on
the remainder of the Trust's conventional portfolio which has produced strong
production results despite the reduced capital re-investment in 2009.
In addition to capital expenditures on development activities, the Trust
completed small net property acquisitions of $2.2 million in the second
quarter of 2009 most of which related to the acquisition of undeveloped land
in the Dawson area.
For the remainder of 2009, the Trust expects to drill 32 gross wells on
operated properties, complete all wells in inventory and start constructing
the Dawson gas plant that is now expected to be operational by the end of the
first quarter of 2010. Total capital expenditures are forecast to be $350
million in 2009.
Subsequent to quarter end, the Trust completed a small property
disposition of non-core assets in southeast Saskatchewan for proceeds of $33.5
million. This disposition will have no material impact on the forecast
production volumes for the year.
A breakdown of capital expenditures and net acquisitions is shown in
Table 21:

<<
Table 21
-------------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
-------------------------------------------------------------------------
Capital Expenditures % %
($ millions) 2009 2008 Change 2009 2008 Change
-------------------------------------------------------------------------
Geological and geophysical 5.0 16.4 (70) 7.8 21.9 (64)
Drilling and completions 18.6 32.6 (43) 87.1 97.0 (10)
Plant and facilities 23.6 24.1 (2) 48.7 35.7 36
Undeveloped land purchased
at crown land sales 0.2 57.8 (99) 0.4 86.6 (99)
Other capital 1.5 0.4 275 2.1 1.4 50
-------------------------------------------------------------------------
Total capital expenditures
before net acquisitions 48.9 131.3 (63) 146.1 242.6 (40)
-------------------------------------------------------------------------
Producing property
acquisitions(1) 0.1 0.4 (75) 0.2 0.3 (33)
Undeveloped land property
acquisitions 2.2 - 100 8.3 13.9 (40)
Producing property
dispositions(1) - (0.1) (100) - (0.1) (100)
Undeveloped land property
dispositions - - - - (3.7) (100)
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 51.2 131.6 (61) 154.6 253.0 (39)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
>>

Approximately 90 per cent of the $48.9 million capital program in the
second quarter of 2009 was financed with cash flow from operating activities
and proceeds from the distribution re-investment plan ("DRIP") compared to 100
per cent for the same period of 2008. Property acquisitions were financed
through debt and working capital. On a year-to-date basis, the Trust has
funded 73 per cent of the capital expenditures with cash flow from operating
activities and proceeds from the DRIP as compared to 100 per cent for the
first six months of 2008.

<<
Table 22
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30, 2009 June 30, 2008
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions itures itures itions itures
-------------------------------------------------------------------------

Expenditures 48.9 2.3 51.2 131.3 0.3 131.6
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating activities 55% - 53% 96% - 95%
Proceeds from
Distribution
re-investment plan
("DRIP") 35% - 33% 4% 100% 5%
Debt(1) 10% 100% 14% - - -
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The Trust's debt balance was reduced by $240 million with the net
proceeds of the equity offering completed in the first quarter. These
proceeds are intended to fund a portion of ARC's expenditures in the
Montney resource play.

Table 22a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Six Months Ended Six Months Ended
June 30, 2009 June 30, 2008
-------------------------------------------------------------------------
Capital Net Total Capital Net Total
Expend- Acquis- Expend- Expend- Acquis- Expend-
itures itions itures itures itions itures
-------------------------------------------------------------------------
Expenditures 146.1 8.5 154.6 242.6 10.4 253.0
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating activities 49% - 46% 85% - 81%
Proceeds from
Distribution
re-investment plan
("DRIP") 24% - 23% 15% 100% 19%
Debt(1) 27% 100% 31% - - -
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The Trust's debt balance was reduced by $240 million with the net
proceeds of the equity offering completed in the first quarter. These
proceeds are intended to fund a portion of ARC's expenditures in the
Montney resource play.
>>

Asset Retirement Obligation and Reclamation Fund

At June 30, 2009, the Trust recorded an Asset Retirement Obligation
("ARO") of $144.1 million ($141.5 million at December 31, 2008) for future
abandonment and reclamation of the Trust's properties.
Included in the June 30, 2009 ARO balance was a $0.9 million increase
related to development activities and changes in estimates in the first half
of 2009, $4.6 million for accretion expense in the period and a reduction of
$2.9 million for actual abandonment expenditures incurred in the first half of
2009.
ARC's reclamations funds held $28.9 million as at June 30, 2009. Under
the terms of the Trust's investment policy, reclamation fund investments and
excess cash can only be invested in Canadian or U.S. Government securities,
investment grade corporate bonds, or investment grade short-term money market
securities.

Capitalization, Financial Resources and Liquidity

A breakdown of the Trust's capital structure is outlined in Table 23, as
at June 30, 2009 and December 31, 2008:

<<
Table 23
-------------------------------------------------------------------------
Capital Structure and Liquidity June 30, December 31,
($ millions except per cent and ratio amounts) 2009 2008
-------------------------------------------------------------------------
Net debt obligations(1) 737.6 961.9
Market value of trust units and exchangeable
shares(2) 4,222.8 4,405.9
-------------------------------------------------------------------------
Total capitalization(3) 4,960.4 5,367.8
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 14.9% 17.9%
Net debt to annualized YTD cash flow from
operating activities 1.6 1.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Net debt is a non-GAAP measure and therefore it may not be comparable
with the calculation of similar measures for other entities. It 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 trust units outstanding at June 30 and
December 31 including the total number of trust units issuable for
exchangeable shares at June 30 and December 31 multiplied by the
closing trust unit price of $17.81 and $20.10 at June 30, 2009 and
December 31, 2008, respectively.
(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.
>>

On April 14, 2009, the Trust announced the closing of a private placement
of long-term debt in the form of senior secured notes totaling US$125 million
at a blended average interest rate of 7.47 per cent. The notes were offered in
three tranches, one tranche of US$67.5 million senior notes with a five year
average life repayable in years 2012 through 2016 issued at an interest rate
of 7.19 per cent. The second tranche of US$35 million senior notes with a 10
year average life repayable in years 2017 through 2021, issued at an interest
rate of 8.21 per cent. The third tranche of Cdn$29 million senior notes was
issued with a five year average life repayable in years 2012 through 2016,
issued at an interest rate of 6.5 per cent.
At June 30, 2009, the Trust's current credit facilities comprised
Cdn$382.5 million in senior secured notes currently outstanding, a Cdn$800
million syndicated bank credit facility, of which Cdn$324.1 million was
outstanding and a Cdn$25 million demand working capital facility, of which
$0.7 million was outstanding. 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, 2009; these agreements are
available at www.SEDAR.com.
In April 2009, ARC extended its uncommitted master shelf agreement from
May 2009 to April 2012. The extended agreement allows for an aggregate draw of
up to US$225 million (Cdn$261.6 million) in 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.
As at June 30, 2009, the Trust has approximately $648.4 million of unused
credit available: $475.9 million under its credit facility, and $172.5 million
available to draw long-term notes under the master shelf agreement.
As a result of the weakened global economic situation, the Trust along
with all other oil and gas entities will have restricted access to capital and
increased borrowing costs. Although the Trust's business and asset base have
not changed, the lending capacity of all financial institutions has been
diminished and risk premiums have increased. These issues will impact the
Trust as it reviews financing alternatives for the 2009 capital program,
assesses potential future acquisition opportunities and manages future cash
flow decremented by lower commodity prices and higher borrowing costs. The
Trust intends to finance its 2009 capital program with cash flow, existing
credit facilities, proceeds from the DRIP, potential asset dispositions and
new borrowings or equity if necessary. Beyond that, the Trust may need to
access additional capital and/or curtail capital expenditure plans and will
look to do so in the most cost effective manner possible.

Unitholders' Equity

At June 30, 2009, there were 237.1 million trust units issued and
issuable for exchangeable shares, an increase of 17.9 million trust units from
December 31, 2008 due mostly to the issuance of 15.5 million trust units as
part of an equity offering in February 2009.
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 2009, the Trust raised proceeds of
$35.6 million and issued 2.4 million trust units pursuant to the DRIP at an
average price of $15.52 per unit.

Distributions

ARC declared distributions of $75 million ($0.32 per unit), representing
72 per cent of 2009 second quarter cash flow from operating activities
compared to distributions of $144.7 million ($0.68 per unit) representing 53
per cent of cash flow from operating activities in the second quarter of 2008.

<<
The following items 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. In the first half of 2009, the Trust
withheld approximately 31 per cent of cash flow from operating
activities to fund 49 per cent of the capital program excluding
acquisitions. The remaining portion of capital expenditures was
financed by proceeds from the DRIP program and debt.

- An annual contribution to the reclamation funds, with $12 million
scheduled to be contributed in 2009. The reclamation funds are
segregated bank accounts or subsidiary trusts and the balances will be
drawn on in future periods as the Trust incurs abandonment and
reclamation costs over the life of its properties.

- Debt principal repayments from time to time as determined by the board
of directors. The Trust's current debt level is well within the
covenants specified in the debt agreements and, accordingly, there are
no current mandatory requirements for repayment.

- Income taxes that are not passed on to unitholders. The Trust has a
liability for future income taxes due to the excess of book value over
the tax basis of the assets of the Trust and its corporate
subsidiaries. The Trust currently, and up until January 1, 2011, may
minimize or eliminate cash income taxes in corporate subsidiaries by
maximizing deductions, however in future periods there may be cash
income taxes if deductions are not sufficient to eliminate taxable
income. Taxability of the Trust is currently passed on to unitholders
in the form of taxable distributions whereby corporate income taxes
are eliminated at the Trust level. The Trust taxation legislation,
which will take effect in 2011, will result in taxes payable at the
Trust level and therefore distributions to unitholders will decrease.

- Working capital requirements as determined by the board of directors.
Certain working capital amounts may be deducted from cash flow from
operating activities, however such amounts would be minimal and the
Trust does not anticipate any such deductions in the foreseeable
future.

- The Trust has certain obligations for future payments relative to
employee long-term incentive compensation. Presently, the Trust
estimates that $20.5 million to $73.6 million will be paid out
pursuant to such commitments in 2009 through 2012 subject to vesting
provisions and future performance of the Trust. These amounts will
reduce cash flow from operating activities and may in turn reduce
distributions in future periods.

Cash flow from operating activities and distributions in total and per
unit are summarized in Table 24 and Table 24a:

Table 24
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
June 30 June 30
Cash flow from
operating 2009 2008 % Change 2009 2008 % Change
activities and
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 104.3 273.4 (62) 0.44 1.27 (65)

Net reclamation fund
withdrawals
(contributions)(1) (2.3) (3.3) (30) (0.01) (0.02) (50)

Capital expenditures
funded with cash
flow from operating
activities (27.0) (125.4) (78) (0.11) (0.58) (81)

Other(2) - - - - 0.01 (100)
-------------------------------------------------------------------------
Distributions 75.0 144.7 (48) 0.32 0.68 (53)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Table 24a
-------------------------------------------------------------------------
Six Months Ended Six Months Ended
June 30 June 30
Cash flow from
operating 2009 2008 % Change 2009 2008 % Change
activities and
distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 228.6 483.4 (53) 0.98 2.25 (56)

Net reclamation fund
withdrawals
(contributions)(1) (0.8) (6.6) (88) - (0.03) (100)

Capital expenditures
funded with cash
flow from operating
activities (70.8) (205.3) (66) (0.30) (0.96) (69)

Other(2) - - - - 0.02 (100)
-------------------------------------------------------------------------
Distributions 157.0 271.5 (42) 0.68 1.28 (47)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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
operated activities are based on weighted average outstanding trust
units in the period.

The Trust continually assesses distribution levels, in light of commodity
prices, capital expenditure programs and production volumes, to ensure that
distributions are in line with the long-term strategy and objectives of the
Trust as per the following guidelines:

- To maintain a level of distributions that, in normal times, in the
opinion of Management and the Board of Directors, is sustainable for a
minimum period of six months after factoring in the impact of current
commodity prices on cash flows. The Trust's objective is to normalize
the effect of volatility of commodity prices rather than to pass on
that volatility to unitholders in the form of fluctuating monthly
distributions.

- To ensure that the Trust's financial flexibility is maintained by a
review of the Trust's debt to equity and debt to cash flow from
operating activities levels. The use of cash flow from operating
activities and proceeds from equity offerings to fund capital
development activities reduces the requirements of the Trust to use
debt to finance these expenditures. In the first half of 2009 the
Trust funded 49 per cent of capital development activities with a
portion of cash flow from operating activities. Distributions and the
actual amount of cash flows withheld to fund the Trust's capital
expenditure program is dependent on the commodity price environment
and is subject to the approval and discretion of the Board of
Directors.
>>

The actual amount of future monthly distributions is proposed by
Management and is subject to the approval and discretion of the Board of
Directors. The Board reviews future distributions in conjunction with their
review of quarterly financial and operating results.
Please refer to the Trust's website at www.arcenergytrust.com for details
of the monthly distribution amounts and distribution dates for 2009.

Environmental Initiatives Impacting the Trust

On July 1, 2009, the British Columbia government increased the rates
applicable to the consumer-based carbon tax as expected. This increase in
rates will increase the tax amount that the Trust is required to pay on all
fuel used in the course of operations in that province, however, the total
impact to the Trust is still expected to be 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, 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 Table 25.

<<
Table 25
-------------------------------------------------------------------------
Payments due by period
-------------------------------------------------------------------------
1 year 2-3 4-5 Beyond Total
years years 5 years
-------------------------------------------------------------------------
Debt repayments(1) 19.1 413.8 118.1 156.3 707.3
Interest payments(2) 22.6 41.6 29.9 28.2 122.3
Reclamation fund
contributions(3) 5.3 9.5 8.3 67.9 91.0
Purchase commitments 15.7 12.5 4.8 3.5 36.5
Transportation commitments(4) 2.2 19.2 27.2 9.2 57.8
Operating leases 6.3 9.5 14.7 78.2 108.7
Risk management contract
premiums(5) 8.8 - - - 8.8
-------------------------------------------------------------------------
Total contractual obligations 80.0 506.1 203.0 343.3 1,132.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 payments for transporting production from the Dawson gas plant,
expected to be operational in early 2010.
(5) Fixed premiums to be paid in future periods on certain commodity risk
management contracts.
>>

The above noted risk management contract premiums are part of the Trust's
commitments related to its risk management program and have been recorded at
fair market value at June 30, 2009 on the balance sheet as part of risk
management contracts. In addition to the premiums, the Trust has commitments
related to its risk management program.
The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At any given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2009 capital budget has
been approved by the Board at $350 million. This commitment has not been
disclosed in the commitment table (Table 25) as it is of a routine nature and
is part of normal course of operations for active oil and gas companies and
trusts.
The 2009 capital budget of $350 million includes $11 million for
leasehold development costs related to the Trust's new office space in
downtown Calgary. These costs will be incurred throughout 2009 with additional
costs to be incurred in 2010. The operating lease commitments for the new
space begin in the first quarter of 2010 and are included in Table 25.
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 (Table 25) 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
(Table 25) 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 25), 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,
2009.

Critical Accounting Estimates

The Trust has continuously evolved and documented its management and
internal reporting systems to provide assurance that accurate, timely internal
and external information is gathered and disseminated.

<<
The Trust's financial and operating results incorporate certain estimates
including:

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

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

Internal Control over Financial Reporting

ARC is required to comply with National Instrument 52-109 "Certification
of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to
as Canadian SOX ("C-Sox"). The certification of interim filings for the
interim period ended June 30, 2009 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
2009.

<<
Financial Reporting Update

Current Year Accounting Changes

Effective January 1, 2009, the Trust prospectively adopted Section 3064,
Goodwill and Intangible Assets issued by the Canadian Institute of Chartered
Accountants ("CICA"). Section 3064 establishes standards for the recognition,
measurement, presentation and disclosure of goodwill and intangible assets
subsequent to its initial recognition. This new section has no current impact
on the Trust or its Consolidated Financial Statements.

Future Accounting Changes
International Financial Reporting Standards ("IFRS")
In April 2008, the CICA published the exposure draft "Adopting IFRS in
Canada". The exposure draft proposes to incorporate IFRS into the CICA
Accounting Handbook effective for interim and annual financial statements
relating to fiscal years beginning on or after January 1, 2011. At this date,
publicly accountable enterprises will be required to prepare financial
statements in accordance with IFRS.
The Trust has commenced the process to transition from current Canadian
GAAP to IFRS. Internal staff has been appointed to lead the conversion project
along with sponsorship from the leadership team. Regular progress reporting to
the audit committee of the Board of Directors on the status of the IFRS
conversion has been implemented.

ARC's project consists of three key phases:

- Scoping and diagnostic phase - this phase involves performing a high
level impact analysis to identify areas that may be affected by the
transition to IFRS. The results of this analysis are priority ranked
according to complexity and the amount of time required to assess the
impact changes in transitioning to IFRS.

- Impact analysis and evaluation phase - during this phase, items
identified in the diagnostic are addressed according to the priority
levels assigned to them. This phase involves analysis of policy
choices allowed under IFRS and their impact to the financial
statements. In addition, certain potential differences are further
investigated to assess whether there may be a broader impact to the
Trust's debt agreements, compensation arrangements or management
reporting systems. The conclusion of the impact analysis and
evaluation phase will require the audit committee of the Board of
Directors to review and approve all accounting policy choices as
proposed by Management.

- Implementation phase - involves implementation of all changes approved
in the impact analysis phase and will include changes to information
systems, business processes, modification of agreements and training
of all staff who are impacted by the conversion.
>>

The Trust has completed the scoping and diagnostic phase and expects to
complete the impact analysis and evaluation phase during the fall of 2009.
In July 2009, the international accounting standards board issued
amendments to IFRS 1, "First-Time Adoption of International Financial
Reporting Standards" ("IFRS 1"). IFRS 1 provides entities adopting IFRS for
the first time with a number of optional exemptions and mandatory exceptions,
in certain areas to the general requirement for full retrospective application
of IFRS. The amendment issued in July provides the option to value the
property plant and equipment ("PP&E") assets at their deemed cost being the
net book value assigned to these assets as at the date of transition, January
1, 2010. This amendment is permissible for entities, such as the Trust, who
currently follow the full cost accounting guideline under Canadian GAAP that
accumulates all oil and gas assets into one cost centre. Under IFRS, the
Trust's PP&E assets must be divided into smaller cost centers. The net book
value of the assets on the date of transition will be allocated to the new
cost centers of the basis of the Trust's reserve values at that point in time.
As this is one of the Trust's largest differences from Canadian GAAP to IFRS,
the Trust can now assess that this area will not create material changes to
the Trust's financial results upon transition.

Business Combinations
The CICA issued Handbook section 1582 "Business Combinations" which
replaces the previous business combinations standard. Under this guidance, the
purchase price used in a business combination is based on the fair value of
shares exchanged at the market price at acquisition date. Under the current
standard, the purchase price used is based on the market price of shares for a
reasonable period before and after the date the acquisition is agreed upon and
announced. In addition, the guidance generally requires all acquisition costs
to be expensed. Current standards allow for the capitalization of these costs
as part of the purchase price. This new Section also addresses contingent
liabilities, which will be required to be recognized at fair value on
acquisition, and subsequently re-measured at each reporting period until
settled. Currently, standards require only contingent liabilities that are
payable to be recognized. The new guidance requires negative goodwill to be
recognized in earnings rather than the current standard of deducting from
non-currents assets in the purchase price allocation. This standard will be
effective for the Trust on January 1, 2011, with prospective application.

Consolidated Financial Statements and Non-controlling Interest
The CICA issued Handbook Sections 1601 "Consolidated Financial
Statements", and 1602 "Non-controlling Interests", which replaces existing
guidance under Section 1600 "Consolidated Financial Statements". Section 1601
establishes standards for the preparation of Consolidated Financial
Statements. Section 1602 provides guidance on accounting for a non-controlling
interest in a subsidiary in Consolidated Financial Statements subsequent to a
business combination. These standards will be effective for the Trust for
business combinations occurring on or after January 1, 2011.

Financial Instruments - Disclosures
The CICA issued amendments to Handbook Section 3862, Financial
Instruments - Disclosures. The amendments include enhanced disclosures related
to the fair value of financial instruments and the liquidity risk associated
with financial instruments. The amendments will be effective for annual
financial statements for fiscal years ending after September 30, 2009. The
amendments are consistent with recent amendments to financial instrument
disclosure standards in International Financial Reporting Standards "IFRS".
The Trust will include these additional disclosures in its annual Consolidated
Financial Statements for the year ending December 31, 2009.

Non-GAAP Measures

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, net asset value and total returns 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.

Forward-looking Information and Statements

This news release contains certain forward-looking information and
statements within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "objective",
"ongoing", "may", "will", "project", "should", "believe", "plans", "intends",
"strategy" and similar expressions are intended to identify forward-looking
information or statements. In particular, but without limiting the foregoing,
this news release contains forward-looking information and statements
pertaining to the following: the volumes and estimated value of ARC's oil and
gas reserves; the life of ARC's reserves; the volume and product mix of ARC's
oil and gas production; future oil and natural gas prices and ARC's commodity
risk management programs; the amount of future asset retirement obligations;
future liquidity and financial capacity; future results from operations and
operating metrics; future costs, expenses and royalty rates; future interest
costs; future development, exploration, acquisition and development activities
(including drilling plans) and related capital expenditures, future tax
treatment of income trusts and future taxes payable by ARC; and ARC's tax
pools.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
ARC including, without limitation: that ARC will continue to conduct its
operations in a manner consistent with past operations; the general
continuance of current industry conditions; the continuance of existing (and
in certain circumstances, the implementation of proposed) tax, royalty and
regulatory regimes; the accuracy of the estimates of ARC's reserves and
resource volumes; certain commodity price and other cost assumptions; and the
continued availability of adequate debt and equity financing and cash flow to
fund its planned expenditures; ARC believes the material factors, expectations
and assumptions reflected in the forward-looking information and statements
are reasonable but no assurance can be given that these factors, expectations
and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
changes in the demand for or supply of ARC's products; unanticipated operating
results or production declines; changes in tax or environmental laws, royalty
rates or other regulatory matters; changes in development plans of ARC or by
third party operators of ARC's properties, increased debt levels or debt
service requirements; inaccurate estimation of ARC's oil and gas reserve and
resource volumes; limited, unfavorable or a lack of access to capital markets;
increased costs; a lack of adequate insurance coverage; the impact of
competitors; and certain other risks detailed from time to time in ARC's
public disclosure documents (including, without limitation, those risks
identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news
release speak only as of the date of this news release, and none of ARC or its
subsidiaries assumes any obligation to publicly update or revise them to
reflect new events or circumstances, except as may be required pursuant to
applicable laws.

<<
Additional Information

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

QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except per unit
amounts) 2009 2008
-------------------------------------------------------------------------
FINANCIAL Q2 Q1 Q4 Q3
Revenue before royalties 235.2 225.2 300.8 485.7
Per unit(1) 0.99 0.98 1.38 2.24
Cash flow from operating activities 104.3 124.3 209.4 251.4
Per unit - basic(1) 0.44 0.54 0.96 1.16
Per unit - diluted 0.44 0.54 0.96 1.16
Net income 66.1 22.3 82.7 311.7
Per unit - basic(2) 0.28 0.10 0.38 1.46
Per unit - diluted 0.28 0.10 0.38 1.46
Distributions 75.0 82.0 127.2 171.3
Per unit - basic(3) 0.32 0.36 0.59 0.80
Total assets 3,672.5 3,733.1 3,766.7 3,687.5
Total liabilities 1,323.1 1,392.1 1,624.6 1,530.8
Net debt outstanding(4) 737.6 781.5 961.9 773.2
Weighted average trust units(5) 236.6 228.9 218.3 216.6
Trust units outstanding and
issuable(5) 237.1 236.0 219.2 217.4
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 5.0 2.8 3.7 1.3
Land 0.2 0.2 17.1 18.6
Drilling and completions 18.6 68.5 117.1 91.4
Plant and facilities 23.6 25.1 30.5 24.2
Other capital 1.5 0.6 1.0 0.9
Total capital expenditures 48.9 97.2 169.4 136.4
Property acquisitions (dispositions)
net 2.3 6.2 27.6 13.1
Total capital expenditures and net
acquisitions 51.2 103.4 197.0 149.5
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 26,917 28,806 28,935 28,509
Natural gas (mmcf/d) 200.2 193.8 195.1 192.0
Natural gas liquids (bbl/d) 3,679 3,764 3,858 3,822
Total (boe per day 6:1) 63,969 64,872 65,313 64,325
Average prices
Crude oil ($/bbl) 62.74 46.44 56.26 114.20
Natural gas ($/mcf) 3.73 5.20 7.48 8.68
Natural gas liquids ($/bbl) 38.89 38.86 45.22 82.87
Oil equivalent ($/boe) 40.32 38.40 49.93 81.42
-------------------------------------------------------------------------
TRUST UNIT TRADING PRICES
(based on intra-day trading)
High 19.25 20.90 22.55 33.30
Low 14.12 11.73 15.01 22.33
Close 17.81 14.15 20.10 23.10
Average daily volume (thousands) 988 1,240 1,523 841
-------------------------------------------------------------------------

-------------------------------------------------------------------------
(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 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(2) 0.27 0.39 0.51 0.58
Per unit - diluted 0.27 0.39 0.51 0.58
Distributions 144.7 126.8 125.8 125.0
Per unit - basic(3) 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(4) 756.1 770.1 752.7 699.8
Weighted average trust units(5) 215.2 213.8 212.5 210.9
Trust units outstanding and
issuable(5) 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
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 PRICES
(based on intra-day trading)
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
-------------------------------------------------------------------------
(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) 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).
(3) Based on number of trust units outstanding at each distribution date.
(4) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(5) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.

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

(Cdn$ millions) 2009 2008
-------------------------------------------------------------------------

ASSETS
Current assets
Cash and cash equivalents (Note 3) $ - $ 40.0
Accounts receivable (Note 4) 110.8 110.0
Prepaid expenses 18.4 16.8
Risk management contracts (Note 9) 7.7 24.4
Future income taxes 5.4 3.9
-------------------------------------------------------------------------
142.3 195.1
Reclamation funds 28.9 28.2
Risk management contracts (Note 9) 1.7 9.2
Property, plant and equipment 3,342.0 3,376.6
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,672.5 $ 3,766.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued
liabilities (Note 5) $ 136.0 $ 194.4
Distributions payable 23.5 32.5
Risk management contracts (Note 9) 12.7 23.5
-------------------------------------------------------------------------
172.2 250.4
Risk management contracts (Note 9) 0.4 3.4
Long-term debt (Note 6) 707.3 901.8
Accrued long-term incentive compensation
(Note 14) 12.3 14.2
Asset retirement obligations (Note 7) 144.1 141.5
Future income taxes 286.8 313.3
-------------------------------------------------------------------------
Total liabilities 1,323.1 1,624.6
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 15)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 10) 37.1 42.4

UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 2,884.4 2,600.7
Deficit (Note 12) (571.5) (502.9)
Accumulated other comprehensive (loss)
income (Note 12) (0.6) 1.9
-------------------------------------------------------------------------
Total unitholders' equity 2,312.3 2,099.7
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,672.5 $ 3,766.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
June 30 June 30
(Cdn$ millions, except per
unit amounts) 2009 2008 2009 2008
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and natural gas
liquids $ 235.2 $ 512.0 $ 460.4 $ 919.9
Royalties (27.5) (91.8) (64.5) (164.0)
-------------------------------------------------------------------------
207.7 420.2 395.9 755.9
(Loss) gain on risk management
contracts (Note 9)
Realized (1.9) (44.7) 14.4 (74.2)
Unrealized (0.6) (142.8) (7.2) (161.5)
-------------------------------------------------------------------------
205.2 232.7 403.1 520.2
-------------------------------------------------------------------------
EXPENSES
Transportation 4.9 4.6 10.5 9.0
Operating 64.2 62.3 123.3 120.5
General and administrative 17.5 22.5 22.6 43.7
Provision for non-recoverable
accounts receivable (Note 4) - 18.0 - 18.0
Interest and financing charges
(Note 6) 7.6 8.3 13.4 17.1
Depletion, depreciation and
accretion 97.2 93.0 194.6 190.0
(Gain) loss on foreign exchange (40.0) (3.1) (25.4) 11.9
-------------------------------------------------------------------------
151.4 205.6 339.0 410.2
-------------------------------------------------------------------------

Future income tax recovery 13.0 31.1 25.2 30.6
-------------------------------------------------------------------------
Net income before non-controlling
interest 66.8 58.2 89.3 140.6
Non-controlling interest (Note 10) (0.7) (0.9) (0.9) (2.0)
-------------------------------------------------------------------------
Net income $ 66.1 $ 57.3 $ 88.4 $ 138.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Deficit, beginning of period $(562.6) $(511.4) $(502.9) $(465.9)
Distributions paid or declared
(Note 13) (75.0) (144.7) (157.0) (271.5)
-------------------------------------------------------------------------
Deficit, end of period (Note 12) $(571.5) $(598.8) $(571.5) $(598.8)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 11)
Basic $ 0.28 $ 0.27 $ 0.38 $ 0.65
Diluted $ 0.28 $ 0.27 $ 0.38 $ 0.65
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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
June 30 June 30
(Cdn$ millions) 2009 2008 2009 2008
-------------------------------------------------------------------------

Net income $ 66.1 $ 57.3 $ 88.4 $ 138.6

Other comprehensive (loss) income,
net of tax
Losses on financial instruments
designated as cash flow hedges(1) (0.8) 0.9 (2.9) (2.0)
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) 0.7 (1.1) 0.6 (1.5)
Net unrealized (losses) gains on
available-for-sale reclamation
funds' investments(4) (0.1) (0.2) (0.2) -
-------------------------------------------------------------------------
Other comprehensive (loss) income (0.2) (0.4) (2.5) 6.5
Comprehensive income $ 65.9 $ 56.9 $ 85.9 $ 145.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other comprehensive
income (loss), beginning of period (0.4) 4.0 1.9 (2.9)
Other comprehensive (loss) income (0.2) (0.4) (2.5) 6.5
-------------------------------------------------------------------------
Accumulated other comprehensive (loss)
income, end of period (Note 12) $ (0.6) $ 3.6 $ (0.6) $ 3.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amounts are net of tax of $0.3 million and $1 million, respectively,
for the three months and six months ended June 30, 2009 (net of tax
of $0.3 million and $0.7 million, respectively, for the three and six
months ended June 30, 2008).
(2) Amount is net of tax of $3.6 million for the six months ended June
30, 2008.
(3) Amounts are net of tax of $0.2 million for the three and six months
ended June 30, 2009 (net of tax of $0.4 million and $0.5 million,
respectively, for the three and six months ended June 30, 2008).
(4) Nominal future income tax impact for the three and six months ended
June 30, 2009 (net of tax of $0.1 million for the three months ended
June 30, 2008).

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) 2009 2008 2009 2008
-------------------------------------------------------------------------

CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 66.1 $ 57.3 $ 88.4 $ 138.6
Add items not involving cash:
Non-controlling interest (Note 10) 0.7 0.9 0.9 2.0
Future income tax recovery (13.0) (31.1) (25.2) (30.6)
Depletion, depreciation and
accretion 97.2 93.0 194.6 190.0
Non-cash loss on risk management
contracts (Note 9) 0.6 142.8 7.2 161.5
Non-cash (gain) loss on foreign
exchange (39.7) (3.6) (25.3) 11.4
Non-cash trust unit incentive
compensation expense (recovery)
(Note 14) 8.6 (1.8) (3.5) 12.0
Expenditures on site restoration and
reclamation (Note 7) (1.2) (2.3) (2.9) (6.0)
Change in non-cash working capital (15.0) 18.2 (5.6) 4.5
-------------------------------------------------------------------------
104.3 273.4 228.6 483.4
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of long-term debt under
revolving credit facilities, net (97.2) (29.7) (309.6) (39.0)
Issue of Senior Secured Notes 152.9 - 152.9 -
Repayment of Senior Secured Notes (12.6) - (12.6) -
Issue of trust units 0.5 1.0 254.0 3.8
Trust unit issue costs (0.2) - (13.1) -
Cash distributions paid (Note 13) (63.1) (107.4) (131.3) (208.7)
Change in non-cash working capital 0.1 (1.5) 2.0 (0.6)
-------------------------------------------------------------------------
(19.6) (137.6) (57.7) (244.5)
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural
gas properties (2.3) (0.4) (8.5) (10.5)
Proceeds on disposition of petroleum
and natural gas properties - 0.1 - 0.2
Capital expenditures (47.1) (131.0) (146.4) (240.4)
Net reclamation fund (contributions)
withdrawals (2.3) 0.6 (0.8) 0.8
Change in non-cash working capital (33.0) (7.5) (55.2) 4.0
-------------------------------------------------------------------------
(84.7) (138.2) (210.9) (245.9)
-------------------------------------------------------------------------
DECREASE IN CASH AND CASH EQUIVALENTS - (2.4) (40.0) (7.0)
CASH AND CASH EQUIVALENTS, BEGINNING
OF PERIOD - 2.4 40.0 7.0
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF
PERIOD $ - $ - $ - $ -
-------------------------------------------------------------------------
See accompanying notes to the Consolidated Financial Statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
June 30, 2009 and 2008
(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 2008 annual report.

2. NEW ACCOUNTING POLICIES

Current Year Accounting Changes

Effective January 1, 2009, the Trust adopted Section 3064, Goodwill
and Intangible Assets issued by the Canadian Institute of Chartered
Accountants ("CICA"). Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. This new
section has no current impact on the Trust or its Consolidated
Financial Statements.

This standard was adopted prospectively.

Future Accounting Changes

A. Business Combinations

The CICA issued Handbook section 1582 "Business Combinations" that
replaces the previous business combinations standard. Under this
guidance, the purchase price used in a business combination is based
on the fair value of shares exchanged at the market price at
acquisition date. Under the current standard, the purchase price used
is based on the market price of shares for a reasonable period before
and after the date the acquisition is agreed upon and announced. In
addition, the guidance generally requires all acquisition costs to be
expensed. Current standards allow for the capitalization of these
costs as part of the purchase price. This new Section also addresses
contingent liabilities, which will be required to be recognized at
fair value on acquisition, and subsequently remeasured at each
reporting period until settled. Currently, standards require only
contingent liabilities that are payable to be recognized. The new
guidance requires negative goodwill to be recognized in earnings
rather than the current standard of deducting from non-currents
assets in the purchase price allocation. This standard will be
effective for the Trust on January 1, 2011, with prospective
application.

B. Consolidated Financial Statements and Non-controlling Interest

The CICA issued Handbook Sections 1601 "Consolidated Financial
Statements", and 1602 "Non-controlling Interests", which replaces
existing guidance under Section 1600 "Consolidated Financial
Statements". Section 1601 establishes standards for the preparation
of consolidated financial statements. Section 1602 provides guidance
on accounting for a non-controlling interest in a subsidiary in
consolidated financial statements subsequent to a business
combination. These standards will be effective for the Trust for
business combinations occurring on or after January 1, 2011.

C. Financial Instruments - Disclosures

The CICA issued amendments to Handbook Section 3862, Financial
Instruments - Disclosures. The amendments include enhanced
disclosures related to the fair value of financial instruments and
the liquidity risk associated with financial instruments. The
amendments will be effective for annual financial statements for
fiscal years ending after September 30, 2009. The amendments are
consistent with recent amendments to financial instrument disclosure
standards in International Financial Reporting Standards "IFRS". The
Trust will include these additional disclosures in its annual
Consolidated Financial Statements for the year ending December 31,
2009.

D. International Financial Reporting Standards ("IFRS")

In April 2008, the CICA published the exposure draft "Adopting IFRS
in Canada". The exposure draft proposes to incorporate IFRS into the
CICA Accounting Handbook effective for interim and annual financial
statements relating to fiscal years beginning on or after January 1,
2011. At this date, publicly accountable enterprises will be required
to prepare financial statements in accordance with IFRS.

3. CASH AND CASH EQUIVALENTS

Cash equivalents are nil as at June 30, 2009 ($40 million in Canadian
Treasury Bills as at December 31, 2008).

4. FINANCIAL ASSETS AND CREDIT RISK

The majority of the credit exposure on accounts receivable at
June 30, 2009 pertains to accrued revenue for June 2009 production
volumes. The Trust transacts with a number of oil and natural gas
marketing companies and commodity end users ("commodity purchasers").
Commodity purchasers and marketing companies typically remit amounts
to the Trust by the 25th day of the month following production.
Joint interest receivables are typically collected within one to
three months following production. At June 30, 2009, no one
counterparty accounted for more than 25 per cent of the total
accounts receivable balance and the largest commodity purchaser
receivable balance is 100 per cent secured with Letters of Credit.

During the first six months of 2009 the Trust did not record any
provision for non-collectible accounts receivable. The Trust's
allowance for doubtful accounts was $32 million as at June 30, 2009
and December 31, 2008 ($18 million as at June 30, 2008).

When determining whether amounts that are past due are collectable,
management assesses the credit worthiness and past payment history of
the 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, 2009, $2.4 million of accounts receivable are past due,
excluding amounts described above, all of which are considered to be
collectable.

Maximum credit risk is calculated as the total recorded value of cash
equivalents, accounts receivable, reclamation funds, and risk
management contracts at the balance sheet date.

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.
Management believes that future cash flows generated from these
sources will be adequate to settle the Trust's financial liabilities.

The following table details the Trust's financial liabilities as at
June 30, 2009:

---------------------------------------------------------------------
2 - 3 4 - 5 Beyond
($ millions) 1 year years years 5 years Total
---------------------------------------------------------------------
Accounts payable
and accrued
liabilities(1) 141.2 - - - 141.2
Distributions
payable(2) 18.2 - - - 18.2
Risk management
contracts(3) 16.6 0.1 0.2 - 16.9
Senior secured
notes and
interest 41.7 130.6 148.0 184.5 504.8
Revolving credit
facilities - 324.8 - - 324.8
Accrued long-term
incentive
compensation(1) - 37.7 - - 37.7
---------------------------------------------------------------------
Total financial
liabilities 217.7 493.2 148.2 184.5 1,043.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Liabilities under the Whole Unit Plan represent the total amount
expected to be paid out on vesting.
(2) Amounts payable for the distribution represents the net cash
payable after distribution reinvestment.
(3) Amounts payable for the risk management contracts have been
included at their intrinsic value.

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. 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,
2009 2008
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility -
Cdn$ denominated $ 229.9 $ 399.5
Syndicated credit facility -
US$ denominated 94.2 240.6
Working capital facility 0.7 2.1
Senior secured notes
5.42% US$ Note 87.2 91.9
4.94% US$ Note 13.9 14.7
4.62% US$ Note 60.5 76.5
5.10% US$ Note 72.7 76.5
7.19% US$ Note 78.5 -
8.21% US$ Note 40.7 -
6.50% Cdn$ Note 29.0 -
---------------------------------------------------------------------
Total long-term debt outstanding $ 707.3 $ 901.8
---------------------------------------------------------------------

Revolving Credit Facilities

The Trust has an $800 million secured, annually extendible, financial
covenant-based syndicated credit facility. The Trust also has in
place a $25 million demand working capital facility. The working
capital facility is secured and is subject to the same covenants as
the syndicated credit facility.

Borrowings under the syndicated credit facility bear interest at bank
prime (2.25 per cent at June 30, 2009, four per cent at December 31,
2008) or, at the Trust's option, Canadian dollar bankers' acceptances
or U.S. dollar LIBOR loans, plus a stamping fee. At the option of the
Trust, the lenders will review the syndicated credit facility each
year and determine whether they will extend the revolving period for
another year. In the event that the credit facility is not extended
at any time before the maturity date, the loan balance will become
repayable on the maturity date. The maturity date of the current
syndicated credit facility is April 15, 2011. All drawings under the
facility are subject to stamping fees depending on the ratio of
consolidated long-term debt and letters of credit to annualized net
income before non-cash items and interest expense. These stamping
fees vary between a minimum of 60 basis points ("bps") to a maximum
of 110 bps.

As at June 30, 2009, the Trust had $1.9 million in letters of credit
($2 million in 2008), no subordinated debt, and was in compliance
with all covenants.

The payment of principal and interest are allowable deductions in the
calculation of cash available for distribution to unitholders and
rank ahead of cash distributions payable to unitholders. Should the
properties securing this debt generate insufficient revenue to repay
the outstanding balances; the unitholders have no direct liability.

Senior Secured Notes

During the second quarter, the Trust closed a private placement of
long-term debt in the form of senior secured notes totaling
US$125 million at a blended average interest rate of 7.47 per cent.
The notes were offered in three tranches, one tranche of
US$67.5 million senior notes with a five year average life repayable
in years 2012 through 2016 issued at an interest rate of 7.19 per
cent. The second tranche of US$35 million senior notes with a 10 year
average life repayable in years 2017 through 2021, issued at an
interest rate of 8.21 per cent. The third tranche of Cdn$29 million
senior notes was issued with a five year average life repayable in
years 2012 through 2016 and at an interest rate of 6.5 per cent.

In the second quarter of 2009 ARC extended its uncommitted master
shelf agreement from May 2009 to April 2012. The extended agreement
allows for an aggregate draw of up to US$225 million (Cdn$261.6
million) in 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. As at June 30, 2009,
the Trust has drawn US$87 million (Cdn$ 101.1 million) under this
agreement. These amounts are reflected in the above table.

The fair value of senior secured notes as at June 30, 2009, is
$368.5 million ($289.9 million as at December 31, 2008), and is
calculated as the present value of principal and interest payments
discounted at the Trust's credit adjusted risk free rate.

Supplemental disclosures

Amounts of US$16.4 million due under the senior notes and
$0.7 million due under the Trust's working capital facility in the
next 12 months have not been included in current liabilities as
Management has the ability and intent to refinance this amount
through the syndicated credit facility.

Interest paid during the second quarter of 2009 was equal to interest
expense ($1.3 million more than interest expense in the second
quarter of 2008).

During the second quarter of 2009, the weighted-average effective
interest rate under the credit facility was 1.1 per cent (3.9 per
cent in 2008) and 1.4 per cent for the six months ended June 30, 2009
(4.2 per cent in 2008).

At June 30, 2009, the Trust had approximately $648 million of total
unused credit available.

The Trust's total long-term debt is secured in the form of a floating
charge on all lands and assignments and a negative pledge on
petroleum and natural gas properties.

7. ASSET RETIREMENT OBLIGATIONS

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

---------------------------------------------------------------------
Six
Months Ended Year Ended
June 30, December 31,
2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 141.5 $ 140.0
Increase in liabilities relating
to development activities 0.4 2.0
Increase in liabilities relating
to change in estimate 0.5 2.6
Settlement of reclamation
liabilities during the period (2.9) (12.4)
Accretion expense 4.6 9.3
---------------------------------------------------------------------
Balance, end of period $ 144.1 $ 141.5
---------------------------------------------------------------------
---------------------------------------------------------------------

The Trust's weighted average credit adjusted risk free rate as at
June 30, 2009 was 6.5 per cent (6.6 per cent as at December 31,
2008).

8. CAPITAL MANAGEMENT

The Trust's objective when managing its capital is to maintain a
conservative capital structure that 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 normal times, 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 commodity price volatility to unitholders; and
- Maintain a level of distributions which will transfer tax
liabilities 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 and future income
taxes).

When evaluating the Trust's capital structure, management's objective
is to limit net debt to less than 2.0 times annualized cash flow from
operating activities and 20 per cent of total capitalization. As at
June 30, 2009 the Trust's net debt to annualized cash flow from
operating activities ratio is 1.6 and its net debt to total
capitalization ratio is 14.9 per cent.

---------------------------------------------------------------------
June 30, December 31,
2009 2008
---------------------------------------------------------------------
Long-term debt 707.3 901.8
Accounts payable and accrued liabilities 136.0 194.4
Distributions payable 23.5 32.5
Cash and cash equivalents, accounts
receivable and prepaid expenses (129.2) (166.8)
---------------------------------------------------------------------
Net debt obligations(1) 737.6 961.9
---------------------------------------------------------------------
Trust units outstanding and issuable for
exchangeable shares (millions) 237.1 219.2
Trust unit price(2) 17.81 20.10
---------------------------------------------------------------------
Market capitalization(1) 4,222.8 4,405.9
Net debt obligations(1) 737.6 961.9
---------------------------------------------------------------------
Total capitalization(1) 4,960.4 5,367.8
---------------------------------------------------------------------

Net debt as a percentage of total
capitalization 14.9% 17.9%
Net debt obligations to annualized
cash flow from operating activities 1.6 1.0
---------------------------------------------------------------------
---------------------------------------------------------------------
(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.
(2) TSX close price as at June 30, 2009 and December 31, 2008
respectively.

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 change
its capital structure by issuing new trust units, exchangeable
shares, new debt or changing its distribution policy.

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, 2009
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 support the Trust's business plan
by mitigating adverse changes in commodity prices, interest rates and
foreign exchange rates.

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") crude oil price.

Commodity price risk

The Trust's operational results and financial condition, and
therefore the amount of distributions paid to unitholders, are
largely dependent on the commodity prices received for oil and
natural gas production. Commodity prices have fluctuated widely
during recent years due to global and regional factors including
supply and demand fundamentals, inventory levels, weather, economic,
and geopolitical factors. Movement in commodity prices could have a
significant positive or negative impact on 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,
2009. The sensitivity is based on a $15 increase and $15 decrease in
the price of US$ WTI crude oil and $2 increase and $2 decrease in the
price of Cdn$ AECO natural gas. 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, 2009 and
the Trust's next reporting date.

---------------------------------------------------------------------
Increase in Commodity Price Decrease in Commodity Price
---------------------------------------------------------------------
($ millions) Crude oil Natural gas Crude oil Natural gas
---------------------------------------------------------------------
Net income
(decrease)
increase (6.5) (15.1) 5.7 16.6
---------------------------------------------------------------------
---------------------------------------------------------------------

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 fixed rate 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 were to have
increased by 50 bps (0.5 per cent) it is estimated that the Trust's
net income for the period ended June 30, 2009 would decrease by
$1.2 million. Management does not expect interest rates to decrease.

Foreign Exchange Risk

North American oil and natural gas prices 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 US$
denominated debt of which future cash repayments are directly
impacted by the exchange rate in effect on the repayment date.
Variations in the Canadian/U.S. dollar exchange rate could also have
a significant positive or negative impact on distributions to
unitholders.

As at June 30, 2009 no risk management contracts pertaining to
foreign exchange were outstanding.

If foreign exchange rates applicable to U.S. denominated debt were to
have increased or decreased by $0.10Cdn$/US$ it is estimated that the
Trust's net income for the period ended June 30, 2009 would decrease
or increase by $30 million, respectively. Increases and decreases in
foreign exchange rates applicable to US$ payables and receivables
would have a nominal impact on the Trust's net income for the period
ended June 30, 2009.

Risk Management Contracts

The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices, foreign exchange rates,
interest rates and power prices. 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, 2009 that do not qualify for hedge accounting:

---------------------------------------------------------------------
Financial WTI Crude Oil Contracts In Conjunction with 2005 Redwater
and North Pembina Cardium Unit Acquisition(1)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Jul-09 Dec-09 Put Spread 2,500 $55.00 $40.00 -
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial WTI Crude Oil Option Contracts(1)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Oct-09 Mar-10 Collar 1,000 $65.00 - $80.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Monthly average

---------------------------------------------------------------------
Financial Cdn$ WTI Crude Oil Option Contracts(2)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract bbl/d Cdn$/bbl Cdn$/bbl Cdn$/bbl
---------------------------------------------------------------------
1-Jul-09 30-Sep-09 Collar 3,000 $65.00 - $75.00
1-Oct-09 31-Dec-09 Collar 2,000 $65.00 - $75.00
1-Oct-09 31-Dec-09 Collar 1,000 $70.00 - $80.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) Monthly average

---------------------------------------------------------------------
Financial AECO Natural Gas Option Contracts(3)
---------------------------------------------------------------------
Bought Sold Sold
Volume Put Put Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
Jul-09 Oct-09 Collar 20,000 $4.00 - $4.75
Jul-09 Oct-09 Collar 20,000 $4.25 - $5.00
Jul-09 Dec-09 3-way collar 20,000 $6.50 $4.50 $8.00
Nov-09 Dec-09 Collar 10,000 $5.25 - $6.25
---------------------------------------------------------------------
---------------------------------------------------------------------

---------------------------------------------------------------------
Financial AECO Natural Gas Swap Contracts(3)
---------------------------------------------------------------------
Bought
Volume Swap Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
Jul-09 Jul-09 Swap 20,000 $4.155 -
Aug-09 Oct-09 Swap 10,000 $4.06 -
Aug-09 Oct-09 Swap 10,000 $4.25 $6.00
Nov-09 Dec-09 Swap 20,000 $4.155 -
Jan-10 Dec-13 Swap 5,000 $6.80 -
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) AECO 7a monthly index

---------------------------------------------------------------------
Energy Equivalent Swap
---------------------------------------------------------------------
Term Contract Volume Swap
---------------------------------------------------------------------
Financial AECO Natural
Gas Sales Contract(4)
Jul-09 Dec-09 Swap 10,000 GJ/d Cdn$ 4.67/GJ
Financial Cdn$ WTI
Crude Oil Purchase
Contract(5)
Jul-09 Dec-09 Swap 650 bbl/d Cdn$ 71.95/bbl
---------------------------------------------------------------------
---------------------------------------------------------------------
(4) AECO 5a monthly index
(5) Monthly average

---------------------------------------------------------------------
Financial Basis Swap Contract(6)
---------------------------------------------------------------------
Volume Basis Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
Jul-09 Oct-10 Basis Swap-L3d 50,000 ($1.0430)
Nov-10 Oct-11 Basis Swap-Ld 15,000 ($0.4850)
Nov-11 Oct-12 Basis Swap-Ld 15,000 ($0.4067)
---------------------------------------------------------------------
---------------------------------------------------------------------
(6) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO 7a
monthly index

---------------------------------------------------------------------
Financial Electricity Heat Rate Contracts(7)
---------------------------------------------------------------------
Heat
Volume AESO Power AECO 5(a) multiplied Rate
Term Contract MWh $/MWh $/GJ by GJ/MWh
---------------------------------------------------------------------
Jan-10 - Heat Rate Receive Pay AECO
Dec-13 Swap 5 AESO 5(a) x 90
---------------------------------------------------------------------
---------------------------------------------------------------------
(7) Alberta Power Pool (monthly average 24x7), AECO 5a monthly index

---------------------------------------------------------------------
Financial Electricity Contracts(8)
---------------------------------------------------------------------
Volume Basis Swap
Term Contract MWh US$/mmbtu
---------------------------------------------------------------------
Jul-09 Dec-12 Swap 5 $ 72.495
---------------------------------------------------------------------
---------------------------------------------------------------------
(8) Alberta Power Pool (monthly average 24x7)

Following is a summary of all risk management contracts in place as
at June 30, 2009 that qualify for hedge accounting:

---------------------------------------------------------------------
Financial Electricity Contracts(9)
---------------------------------------------------------------------
Volume Basis Swap
Term Contract MWh US$/mmbtu
---------------------------------------------------------------------
Jul-09 Dec-09 Swap 15 $59.33
Jan-10 Dec-10 Swap 5 $63.00
---------------------------------------------------------------------
(9) Alberta Power Pool (monthly average 24x7)

At June 30, 2009, the fair value of the contracts that were not
designated as accounting hedges was a loss of $3.8 million. The
Trust recorded a gain on risk management contracts of $7.2 million in
the statement of income for the six months ended June 30, 2009
($235.7 million loss in 2008). This amount includes the realized and
unrealized gains and losses on risk management contracts that do not
qualify as effective accounting hedges.

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:

---------------------------------------------------------------------
Six Six
Months Months
Ended Ended
June 30, June 30,
2009 2008
---------------------------------------------------------------------
Fair value, beginning of period $ 3.4 $ (64.6)
Fair value, end of period (1) (3.8) (226.1)
---------------------------------------------------------------------
Change in fair value of contracts in the period (7.2) (161.5)
Realized gain (loss) in the period 14.4 (74.2)
---------------------------------------------------------------------
Gain (loss) on risk management contracts $ 7.2 $(235.7)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $1.2 million at
June 30, 2009 ($222.1 million loss at June 30, 2008).

During 2007 the Trust entered into treasury rate lock contracts in
order to manage the Trust's interest rate exposure on future debt
issuances. During 2008 it was determined that the previously
anticipated debt issuance was no longer expected to occur and the
associated treasury rate lock contracts were unwound at a loss of
$13.6 million. The loss was reclassified from Other Comprehensive
Income ("OCI"), net of tax of $10 million and recognized in net
income.

The Trust's electricity contracts are intended to manage price risk
on electricity consumption. Portions of the Trust's financial
electricity contracts were designated as effective accounting hedges
on their respective contract dates. A realized loss of $0.9 million
and $0.8 million for the three and six months ended June 30, 2009
(gain of $1.5 million and $2 million respectively in 2008) has been
included in operating costs on these electricity contracts. The
accumulated unrealized fair value gain of $0.1 million on these
contracts has been recorded on the Consolidated Balance Sheet at June
30, 2009 with the movement in fair value recorded in OCI, net of tax.
The fair value movement for the six months ended June 30, 2009 is an
unrealized loss of $3.2 million. As at June 30, 2009 $0.1 million of
the unrealized fair value gain is attributed to contracts that will
settle over the next twelve months. The following table reconciles
the movement in the fair value of the Trust's financial risk
management contracts that have been designated as effective
accounting hedges:

---------------------------------------------------------------------
Six Six
Months Months
Ended Ended
June 30, June 30,
2009 2008
---------------------------------------------------------------------
Fair value, beginning of period $ 3.3 $ (3.4)
Change in fair value of financial electricity
contracts (3.2) 1.4
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(1) $ 0.1 $ 5.4
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts designated as
effective accounting hedges equals a gain of $0.1 million at
June 30, 2009 ($5.3 million gain at June 30, 2008).

All of the Trust's risk management contracts are transacted in liquid
markets fair values are determined using a valuation model based on
published, third party, and market based price and rate information.

10. EXCHANGEABLE SHARES

---------------------------------------------------------------------
Six
Months Ended Year Ended
June 30, December 31,
(units thousands) 2009 2008
---------------------------------------------------------------------
Balance, beginning of period 1,092 1,310
Exchanged for trust units(1) (159) (218)
---------------------------------------------------------------------
Balance, end of period 933 1,092
Exchange ratio, end of period 2.63365 2.51668
Trust units issuable upon conversion, end
of period 2,457 2,748
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first six months of 2009, 159,171 ARL exchangeable
shares were converted to trust units at an average exchange ratio
of 2.55444, compared to 218,455 exchangeable shares at an average
exchange ratio of 2.36901 during the year ended 2008.

Following is a summary of the non-controlling interest for 2009 and
2008:

---------------------------------------------------------------------
Six
Months Ended Year Ended
June 30, December 31,
(units thousands) 2009 2008
---------------------------------------------------------------------
Non-controlling interest, beginning of period $ 42.4 $ 43.1
Reduction of book value for conversion to
trust units (6.2) (7.6)
Current period net income attributable to
non-controlling interest 0.9 6.9
---------------------------------------------------------------------
Non-controlling interest, end of period 37.1 42.4
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 41.9 $ 41.0
---------------------------------------------------------------------
---------------------------------------------------------------------

11. UNITHOLDERS' CAPITAL

---------------------------------------------------------------------
Six Months Ended Year Ended
June 30, 2009 December 31, 2008
---------------------------------------------------------------------
Number Number
of trust of trust
(units thousands) units $ units $
---------------------------------------------------------------------
Balance, beginning of
period 216,435 2,600.7 210,232 2,465.7
Issued for cash 15,474 253.0 - -
Issued on conversion of ARL
exchangeable shares (Note 10) 407 6.2 517 7.6
Issued on exercise of employee
rights - - 238 4.2
Distribution reinvestment program 2,351 35.6 5,448 123.2
Trust unit issue costs, net of
tax (1) - (11.1) - -
---------------------------------------------------------------------
Balance, end of period 234,667 2,884.4 216,435 2,600.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount is net of tax of $2 million for the period ended June
30, 2009.

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

---------------------------------------------------------------------
Three Months Ended Six Months Ended
June 30 June 30
(units thousands) 2009 2008 2009 2008
---------------------------------------------------------------------
Weighted average trust units(1) 234,173 212,539 230,346 211,783
Trust units issuable on
conversion of exchangeable
shares(2) 2,457 2,693 2,457 2,693
Dilutive impact of rights(3) - 11 - 96
---------------------------------------------------------------------
Diluted trust units and
exchangeable shares 236,630 215,243 232,803 214,572
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 year-end exchange ratio.
(3) There are no rights outstanding as of June 30, 2009 and
therefore, no dilutive impact. Previously outstanding rights
were dilutive and therefore were included in the diluted unit
calculation for 2008.

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 (LOSS) INCOME

---------------------------------------------------------------------
June 30, December 31,
2009 2008
---------------------------------------------------------------------
Accumulated earnings $ 2,812.5 $ 2,724.1
Accumulated distributions (3,384.0) (3,227.0)
---------------------------------------------------------------------
Deficit $ (571.5) $ (502.9)
Accumulated other comprehensive (loss)
income (0.6) 1.9
---------------------------------------------------------------------
Deficit and accumulated other
comprehensive (loss) income $ (572.1) $ (501.0)
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
June 30, December 31,
2009 2008
---------------------------------------------------------------------
Unrealized gains and losses on financial
instruments designated as cash flow
hedges $ (0.2) $ 2.0
Net unrealized gains and losses on
available-for-sale reclamation funds'
investments (0.4) (0.1)
---------------------------------------------------------------------
Accumulated other comprehensive (loss)
income, end of period $ (0.6) $ 1.9
---------------------------------------------------------------------
---------------------------------------------------------------------

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
2009 2008 2009 2008
---------------------------------------------------------------------
Cash flow from
operating activities $ 104.3 $ 273.4 $ 228.6 $ 483.4
Deduct:
Cash withheld to fund
current period
capital expenditures (27.0) (125.4) (70.8) (205.3)
Net reclamation fund
(contributions)
withdrawals (2.3) (3.3) (0.8) (6.6)
---------------------------------------------------------------------
Distributions(1) 75.0 144.7 157.0 271.5
Accumulated
distributions,
beginning of period 3,309.0 2,783.8 3,227.0 2,657.0
---------------------------------------------------------------------
Accumulated
distributions,
end of period $ 3,384.0 $ 2,928.5 $ 3,384.0 $ 2,928.5
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per
unit(2) $ 0.32 $ 0.68 $ 0.68 $ 1.28
Accumulated dist-
ributions per unit,
beginning of period $ 24.06 $ 21.63 $ 23.70 $ 21.03
Accumulated dist-
ributions per unit,
end of period(3) $ 24.38 $ 22.31 $ 24.38 $ 22.31
---------------------------------------------------------------------
(1) Distributions include accrued and non-cash amounts of
$11.9 million and $25.7 million for the three and six months
ended June 30, 2009 ($38 million and $63 million for the same
periods in 2008).
(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. WHOLE TRUST UNIT INCENTIVE PLAN

Compensation expense associated with the Whole Trust Unit Incentive
Plan ("the Whole Unit Plan") is granted in the form of Restricted
Trust Units ("RTUs") and Performance Trust Units ("PTUs") and is
determined based on the intrinsic value of the Whole Trust Units at
each period end.

The Trust recorded non-cash compensation (recovery) expense of
$(3.6) million and $0.1 million to general and administrative and
operating expenses, respectively, and capitalized $(0.4) million to
property, plant and equipment in the six months ended June 30, 2009
for the estimated change in the Plan liability ($10.2 million,
$1.8 million, and $2.2 million as expense for the six months ended
June 30, 2008). The non-cash compensation (recovery) expense was
based on the June 30, 2009 unit price of $17.81 ($33.95 at June 30,
2008), accrued distributions, a performance multiplier, and the
estimated number of units to be issued on maturity.

The following table summarizes the RTU and PTU movement for the six
months ended June 30, 2009:

---------------------------------------------------------------------
Number of Number of
RTUs PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of period 756 959
Granted 412 379
Vested (180) (154)
Forfeited (34) (17)
---------------------------------------------------------------------
Balance, end of period 954 1,167
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
June 30, December 31,
2009 2008
---------------------------------------------------------------------
Balance, beginning of period $ 31.9 $ 30.3
Change in net liabilities in the period
General and administrative expense (3.6) 1.1
Operating expense 0.1 (0.1)
Property, plant and equipment (0.4) 0.6
---------------------------------------------------------------------
Balance, end of period(1) $ 28.0 $ 31.9
---------------------------------------------------------------------
Current portion of liability 16.3 18.8
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 12.3 $ 14.2
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes $0.6 million of recoverable amounts recorded in accounts
receivable as at June 30, 2009 ($0.9 million for 2008).

During the first six months of 2009 cash payments of $7.8 million
were made to employees relating to the Whole Unit Plan compared to
$18.5 million in 2008. In October 2008, vesting periods were revised
from April and October to March and September of each year commencing
in 2009.

15. COMMITMENTS AND CONTINGENCIES

Following is a summary of the Trust's contractual obligations and
commitments as at June 30, 2009:

---------------------------------------------------------------------
Payments due by period
---------------------------------------------------------------------
2-3 4-5 Beyond
1 year years years 5 years Total
---------------------------------------------------------------------
Debt repayments(1) 19.1 413.8 118.1 156.3 707.3
Interest payments(2) 22.6 41.6 29.9 28.2 122.3
Reclamation fund
contributions(3) 5.3 9.5 8.3 67.9 91.0
Purchase commitments 15.7 12.5 4.8 3.5 36.5
Transportation
commitments(4) 2.2 19.2 27.2 9.2 57.8
Operating leases 6.3 9.5 14.7 78.2 108.7
Risk management contract
premiums(5) 8.8 - - - 8.8
---------------------------------------------------------------------
Total contractual
obligations 80.0 506.1 203.0 343.3 1,132.4
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 payments for transporting production from the Dawson gas
plant, expected to be operational in early 2010.
(5) Fixed premiums to be paid in future periods on certain commodity
risk management contracts.

In addition to the above Risk management contract premiums, the Trust
has commitments related to its risk management program (see Note 9).

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 expenditures in a future
period. The Trust's 2009 capital budget has been set at $350 million.
This commitment has not been disclosed in the commitment table as it
is of a routine nature and is part of normal course of operations for
active oil and gas companies and trusts.

The 2009 capital budget of $350 million includes approximately
$11 million for leasehold development costs related to the Trust's
new office space in downtown Calgary. These costs will be incurred
throughout 2009 with additional amounts to be incurred in 2010. The
operating lease commitments for the new space are included in the
table above.

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 above
table does not include any commitments for outstanding litigation and
claims.

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.
>>

FORWARD-LOOKING INFORMATION AND STATEMENTS

This news release contains certain forward-looking information and
statements within the meaning of applicable securities laws. The use of any of
the words "expect", "anticipate", "continue", "estimate", "objective",
"ongoing", "may", "will", "project", "should", "believe", "plans", "intends",
"strategy" and similar expressions are intended to identify forward-looking
information or statements. In particular, but without limiting the foregoing,
this news release contains forward-looking information and statements
pertaining to the following: the volumes and estimated value of ARC's oil and
gas reserves; the life of ARC's reserves; the volume and product mix of ARC's
oil and gas production; future oil and natural gas prices and ARC's commodity
risk management programs; the amount of future asset retirement obligations;
future liquidity and financial capacity; future results from operations and
operating metrics; future costs, expenses and royalty rates; future interest
costs; future development, exploration, acquisition and development activities
(including drilling plans) and related capital expenditures, future tax
treatment of income trusts and future taxes payable by ARC; and ARC's tax
pools.
The forward-looking information and statements contained in this news
release reflect several material factors and expectations and assumptions of
ARC including, without limitation: that ARC will continue to conduct its
operations in a manner consistent with past operations; the general
continuance of current industry conditions; the continuance of existing (and
in certain circumstances, the implementation of proposed) tax, royalty and
regulatory regimes; the accuracy of the estimates of ARC's reserve and
resource volumes; certain commodity price and other cost assumptions; and the
continued availability of adequate debt and equity financing and cash flow to
fund its planned expenditures; ARC believes the material factors, expectations
and assumptions reflected in the forward-looking information and statements
are reasonable but no assurance can be given that these factors, expectations
and assumptions will prove to be correct.
The forward-looking information and statements included in this news
release are not guarantees of future performance and should not be unduly
relied upon. Such information and statements involve known and unknown risks,
uncertainties and other factors that may cause actual results or events to
differ materially from those anticipated in such forward-looking information
or statements including, without limitation: changes in commodity prices;
changes in the demand for or supply of ARC's products; unanticipated operating
results or production declines; changes in tax or environmental laws, royalty
rates or other regulatory matters; changes in development plans of ARC or by
third party operators of ARC's properties, increased debt levels or debt
service requirements; inaccurate estimation of ARC's oil and gas reserve and
resource volumes; limited, unfavorable or a lack of access to capital markets;
increased costs; a lack of adequate insurance coverage; the impact of
competitors; and certain other risks detailed from time to time in ARC's
public disclosure documents (including, without limitation, those risks
identified in this news release and in ARC's Annual Information Form).
The forward-looking information and statements contained in this news
release speak only as of the date of this news release, and none of ARC or its
subsidiaries assumes any obligation to publicly update or revise them to
reflect new events or circumstances, except as may be required pursuant to
applicable laws.

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with a current enterprise value of approximately $4.7 billion.
The Trust expects 2009 oil and gas production to average 63,000 to 64,000 of
barrels of oil equivalent per day from six core areas in western Canada. ARC
Energy Trust units trade on the TSX under the symbol AET.UN and ARC Resources
exchangeable shares trade under the symbol ARX. ARC Energy Trust trades on the
TSX under the symbol AET.UN and its exchangeable shares trade under the symbol
ARX.

<<
ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer
>>