ARC Energy Trust announces third quarter 2008 results

Oct 30, 2008

CALGARY, Oct. 30 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC"
or "the Trust") announces results for the third quarter and nine months ended
September 30, 2008.

<<
Three Months Ended Nine Months Ended
September 30 September 30
2008 2007 2008 2007
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FINANCIAL
($Cdn millions, except per unit
and per boe amounts)
Revenue before royalties 485.7 300.2 1,405.6 913.6
Per unit(1) 2.24 1.42 6.53 4.36
Per boe 82.06 53.41 78.84 53.73
Cash flow from operating
activities(2) 251.4 179.6 734.8 531.2
Per unit(1) 1.16 0.85 3.41 2.54
Per boe 42.48 31.95 41.22 31.23
Net income 311.7 120.8 450.3 389.0
Per unit(3) 1.46 0.58 2.12 1.88
Distributions 171.3 125.0 442.8 372.2
Per unit(1) 0.80 0.60 2.08 1.80
Per cent of cash flow from
operating activities(2) 68 70 60 70
Net debt outstanding(4) 773.2 699.8 773.2 699.8
OPERATING
Production
Crude oil (bbl/d) 28,509 28,437 28,372 28,682
Natural gas (mmcf/d) 192.0 173.3 197.0 177.6
Natural gas liquids (bbl/d) 3,822 3,795 3,862 4,013
Total (boe/d) 64,325 61,108 65,063 62,296
Average prices
Crude oil ($/bbl) 114.20 73.40 107.20 66.45
Natural gas ($/mcf) 8.68 5.52 8.94 6.90
Natural gas liquids ($/bbl) 82.87 55.64 77.92 52.07
Oil equivalent ($/boe) 81.42 53.28 78.44 53.61
Operating netback ($/boe)
Commodity and other revenue
(before hedging)(5) 82.06 53.41 78.84 53.73
Transportation costs (0.80) (0.65) (0.77) (0.73)
Royalties (15.00) (8.76) (14.18) (9.28)
Operating costs (10.19) (9.93) (10.14) (9.51)
Netback (before hedging) 56.07 34.07 53.75 34.21
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TRUST UNITS
(millions)
Units outstanding,
end of period(6) 217.4 208.8 217.4 208.8
Weighted average units(7) 216.6 210.9 215.2 209.4
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TRUST UNIT TRADING STATISTICS
($Cdn, except volumes) based
on intra-day trading
High 33.30 22.60 33.95 23.86
Low 22.33 19.00 20.00 19.00
Close 23.10 21.17 23.10 21.17
Average daily volume (thousands) 841 503 790 588
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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 third quarter of 2008 would be
$278.6 million ($1.29 per unit) and $763.5 million ($3.55 per unit)
year-to-date. Distributions as a percentage of Cash Flow would be
61 per cent for the third quarter of 2008 (58 per cent year-to-date).
Please refer to the non-GAAP measures section in the MD&A for further
details.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Net debt excludes current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(5) Includes other revenue.
(6) Includes 1.1 million exchangeable shares exchangeable into 2.43068
trust units each for an aggregate 2.7 million trust units.
(7) Includes trust units issuable for outstanding exchangeable shares at
period end.

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

- During the third quarter, the Trust paid record distributions of
$171.3 million ($0.80 per unit). The third quarter distribution
increased 33 per cent relative to 2007 and included a $0.20 per unit
top-up. The top-up distributions were declared and paid based on
strong commodity prices during the quarter.

- Cash flow from operating activities for the quarter was
$251.4 million ($1.16 per unit), a 40 per cent increase compared to
$179.6 million ($0.85 per unit) in 2007. The increase is primarily a
result of a 53 per cent increase in the Trust's total realized
commodity price for the quarter and a five per cent increase in
production volumes. Using the more traditional non-GAAP measure of
Cash Flow that excludes changes in non-cash working capital and site
restoration spending for the quarter, Cash Flow was $278.6 ($1.29 per
unit).

- Production for the quarter increased five per cent to 64,325 boe per
day compared with the third quarter of 2007 with the growth in
production at Dawson accounting for most of the increase in
production. Third quarter volumes were marginally decremented for
scheduled turnarounds and downtime. The Trust has maintained its full
year production guidance of between 64,000 and 65,000 boe per day.

- As WTI oil prices were strong throughout much of the third
quarter averaging US$118 per barrel, the Trust posted realized
cash risk management hedging losses of $26.8 million on its oil
volumes ($34.3 million on total contracts) negatively impacting cash
flows in the quarter; however, the Trust was also able to participate
in the market prices on approximately 70 per cent of its total third
quarter production.

- Total capital spending for the quarter, including undeveloped crown
land purchases of $18.6 million and net undeveloped land property
acquisitions of $13.1 million, was $149.5 million. This amount was
funded 79 per cent by the Trust's cash flow from operating activities
and proceeds from the distribution re-investment program ("DRIP").
The Trust has revised the 2008 capital spending guidance down to
$530 million from $550 million and intends to finance the fourth
quarter capital program with cash flow and available borrowing
capacity under existing credit facilities.

- During the third quarter, the Trust drilled 94 wells (83 net) with a
100 per cent success rate on operated properties. The majority of the
wells drilled were in the Southeast Alberta area where the Trust
drilled 47 gas wells as part of its shallow gas program. Year-to-
date, the Trust has drilled 59 gross oil wells and 87 gross gas wells
with a 100 per cent success rate.

- The Trust's board of directors has approved a $585 million capital
program in 2009, which will set the stage for considerable production
growth in 2010. This program will maintain base production in the
order of 64,000 boe per day while accelerating development of the
Montney resource play in northeastern British Columbia. The Trust
expects to drill 17 wells and construct an ARC operated 60 mmcf per
day gas plant in the Dawson area which we expect will increase
production to over 72,000 boe per day in 2010. The Trust will also
proceed with additional spending on its CO(2) pilot project at
Redwater with the goal of assessing commercial viability of large
scale CO(2) sequestration and injection. The Trust will pursue the
cost effective means of financing its 2009 capital program
including: a combination of cash flow, existing credit facilities,
potential DRIP proceeds and assets dispositions and new borrowings
or equity, if necessary. The Trust will pursue the most cost
effective means of financing its 2009 capital program through a
combination of cash flow, existing credit facilities, DRIP proceeds,
potential asset disposition proceeds and new borrowings or equity,
if necessary. Management will review the 2009 capital program on a
regular basis in the context of prevailing economic conditions and
make adjustments as deemed necessary to the program, subject to
quarterly review by the Trust's Board of Directors.

- The Trust has completed an assessment of the Alberta Government's
New Royalty Framework ("Framework") and has estimated that the
Trust's average corporate royalty rate will increase from
approximately 18 per cent in 2008 to between 20 and 28 percent in
2009 depending upon commodity prices. A table showing the expected
sensitivity to commodity prices is included in the MD&A. Currently,
65 per cent of the Trust's production is in Alberta. The 2009
capital budget proposes to invest 60 per cent of funds outside of
Alberta as the Trust can deliver greater levels of return to
unitholders in jurisdictions that are not subject to the new
Framework.

- The Trust reviewed distribution levels in light of the outlook
for commodity prices and the estimated increase in Alberta royalties
pursuant to the new Framework in 2009. Following the $0.24 per unit
October distribution to be paid November 17, 2008, the monthly
distribution will be $0.20 per unit per month. Distribution levels
are reviewed regularly and revisions are approved at the discretion
of the Board of Directors.

- The recent global economic downturn, decline in commodity prices and
resultant declines in global stock markets have had a significant
impact on all businesses and individuals and ARC is no exception. The
Trust has experienced a significant decline in its trust unit price
similar to other oil and gas entities. Additionally, the decline in
commodity prices during and subsequent to quarter end will have a
direct impact on the Trust's cash flows, payout ratios and levels of
debt funding of capital programs in the future. Likewise, the
financial and lending markets have been faced with reduced lending
capacity which in turn will result in reduced access to capital and
increased borrowing costs for businesses and individuals. The Trust
has diligently maintained a conservative capital structure and low
debt levels, attributes that are particularly important in light of
the current economic situation. At September 30, the Trust's net debt
to annualized cash flow and net debt to total capitalization were 0.8
times and 13 per cent, respectively. While the current economic
environment presents challenges, ARC's business remains strong, our
assets are top quality, our financial position is good and our future
internal development prospects are the best we have ever had.

- Montney Resource Play Development

At Dawson, ARC drilled and completed two delineation wells on the
outer edges of the field as well as drilling four deviated infill
wells from the 6-25-79-15W6 surface location in the third quarter.
With seven wells drilled into section 25, ARC expects to use new
completion techniques, microseismic fracture mapping and pressure
data acquisition in order to contribute to the understanding of the
infill drilling density required to optimally exploit this field.
Production from the field averaged approximately 40 mmcf per day, as
planned and unplanned maintenance limited the ability of the
processing facilities to run at the maximum contracted capacity.

At West Dawson, ARC drilled two horizontal delineation wells at
2-7-79-15W6 with one well targeting the lower Montney and the second
targeting the upper Montney horizons. This is the first horizontal
well to target the lower Montney within the main Dawson Pool.

Approval has been received from the National Energy Board to
construct a 10 mmcf per day gas line from the Dawson field to Fourth
Creek in Alberta. ARC expects to have the new line completed by late
fourth quarter 2008 with start-up dependent on installation of a new
compressor at the Spectra 5-22 location.

ARC has decided to accelerate the construction plans for additional
processing capacity for the Dawson field. Engineering and procurement
of long lead time items for a 60 mmcf per day gas plant has been
initiated. ARC now expects to have this gas plant on-line early in
2010.

ARC engaged GLJ Petroleum Consultants to update the Dawson Montney
property reserves evaluation utilizing production and drilling data
to the end of the third quarter. As of October 1, 2008 GLJ estimates
that there are 416 Bcf (71 mmboe) of Proved plus Probable reserves at
Dawson. This is an addition of 171 Bcf (29 mmboe) of Proved reserves
and 254 Bcf (43 mmboe) of Proved plus Probable reserves for the
Dawson property (based on 6:1 gas/oil boe conversion). Additional
information on the revised reserves evaluation for Dawson can be
found in the "ARC Energy Trust Announces Significant Increase in
Montney Reserves and Land Valuations" news release dated October 30,
2008 and filed on SEDAR at www.sedar.com.

The Trust continues to expand its Montney land base through purchases
of land at crown land sales and acquisitions from other companies.
The Trust also continues to convert undeveloped lands to developed
lands through the drilling of wells. As at the end of the third
quarter, the Trust held 148 gross undeveloped sections (123 net) of
lands in the Dawson and the Montney West Exploratory Lands. This is
up from 96 gross undeveloped sections (87 net) at December 31, 2007.

The Trust began the delineation process of the Sunrise discovery with
the drilling of two successful vertical delineation wells,
participation in a partner operated horizontal delineation well and
the drilling of two horizontal wells. The two horizontal wells were
drilled from the 9-13 discovery well into the upper Montney
formations. Testing of the ARC operated wells will take place in the
fourth quarter, but based on log analysis and the successful testing
of a partner operated horizontal well at Sunrise (50 per cent ARC
working interest), ARC has allocated funds from its 2009 budget for
development of this field.

Elsewhere, ARC had a successful start to the exploratory drilling
program on the new Montney lands with the drilling of the Saturn
13-11-81-20W6 vertical well and a subsequent follow-up horizontal
well. Drilling of a second vertical well at Saturn, the first wells
at Sunset and Monias and two wells at Sundown are expected to take
place in the fourth quarter.

- Enhanced Oil Recovery Initiatives

The Trust spent $10.1 million during the third quarter of 2008 on
enhanced oil recovery ("EOR") initiatives, including development
capital for the Weyburn and Midale CO(2) floods in Saskatchewan. The
highlight of the quarter was the successful start-up of the Redwater
EOR CO(2) pilot. Injection commenced on July 29 and has been
proceeding smoothly. The Trust expects that it will take 12 to
18 months before it will be known if the pilot has been successful in
increasing oil production and has shown potential for a commercial
scale EOR scheme.

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 October 29,
2008 and should be read in conjunction with the unaudited Consolidated
Financial Statements for the period ended September 30, 2008, the MD&A and the
unaudited Consolidated Financial Statements for the period ended June 30,
2008, the MD&A and the unaudited Consolidated Financial Statements for the
period ended March 31, 2008, and the audited Consolidated Financial Statements
and MD&A for the period ended December 31, 2007 as well as the Trust's 2007
Annual Information Form that is filed on SEDAR at www.sedar.com.
The MD&A contains forward-looking statements and readers are cautioned
that the MD&A should be read in conjunction with the Trust's disclosure under
"Forward-Looking Statements" included at the end of this MD&A.

Executive Overview

ARC Energy Trust ("ARC") is one of the top 20 producers of conventional
oil and gas in western Canada. As at September 30, 2008, ARC held interests in
excess of 18,000 wells with approximately 5,500 wells operated by ARC and the
remainder operated primarily by other major oil and gas companies. ARC's
production has averaged between 61,000 and 67,000 boe per day in each quarter
for the last three years. The total capitalization of ARC, which trades on the
Toronto Stock Exchange, as at September 30, 2008 was $5.8 billion as shown on
Table 21. Subsequent to quarter end, the market has experienced a high degree
of volatility and Trust has seen a decrease in total capitalization to
approximately $4.4 billion on October 29, 2008.

<<
ARC's objective as an energy company is to provide superior and
sustainable long-term returns to unitholders. Key attributes to the business
plan include:

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

- Pay a portion of cash flow to unitholders annually. The Trust will
distribute $0.24 per unit for the November 17, 2008 distribution;
thereafter the distribution is set at $0.20 per unit beginning with
the December 15, 2008 distribution. 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 September 30, 2008, the Trust has distributed $3.1
billion or $23.11 per unit.

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

Table 1 illustrates ARC's production and reserves per unit that have
been achieved while making distributions since January 1, 2006, of
$6.88 per unit or $1.5 billion.

Table 1
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Per Trust Unit Q3 2008 YTD 2008 2007 2006
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Normalized production
per unit(1) 0.30 0.31 0.30 0.31
Normalized reserves
per unit(1)(2) - - 1.35 1.40
Distributions per unit $0.80 $2.08 $2.40 $2.40
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(1) Normalized indicates that all years as presented have been
adjusted to reflect a net debt to capitalization of
15 per cent. It is assumed that additional trust units were
issued (or repurchased) at a period end price for the reserves
per unit calculation and at an annual average price for the
production per unit calculation in order to achieve a net debt
balance of 15 per cent of total capitalization each year. The
normalized amounts are presented to enable comparability of
annual per unit values.
(2) Reserves per unit are only calculated on an annual basis when the
Trust has a full independent reserve evaluation prepared.

- The periodic strategic acquisition of producing and undeveloped
properties to enhance current production or provide the potential for
future drilling locations and if successful, additional production
and reserves.

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

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

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

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

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

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

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

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

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

Table 2
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Total Returns(1) Trailing Trailing Trailing
($ per unit except for per cent) One Year Three Year Five Year
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Distributions per unit $ 2.68 $ 7.48 $ 11.27
Capital appreciation per unit $ 2.39 $ 0.74 $ 9.50
Total return per unit $ 5.07 $ 8.22 $ 20.77
Annualized total return per unit 21.2% 9.1% 23.3%
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(1) Calculated as at September 30, 2008.

2008 Guidance

Table 3 is a summary of the Trust's 2008 Revised Guidance and a review of
2008 actual results compared to guidance:

Table 3
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September 2008 Actual
Guidance 2008 YTD
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Production (boe/d) 64,000-65,000 65,063
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Expenses ($/boe):
Operating costs 10.20 10.14
Transportation 0.80 0.77
G&A expenses(1) 2.75 2.65
Interest 1.50 1.39
Capital expenditures ($ millions)(2) 530 379.1
Weighted average trust units and
units issuable (millions) 216 217
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(1) G&A guidance has been revised from the original estimate of $3.15 per
boe. The components of the $2.75 per boe G&A guidance for the full
year are as follows: cash G&A - $1.70 perboe; cash component of
LTIP -$0.90 per boe; non-cash LTIP component - $0.15 per boe
(2) 2008 Capital Expenditure Guidance has been revised downward to
$530 million from the original estimate of $550 million.
>>

The 2008 Guidance provides unitholders with information as to
management's expectations for results of operations for 2008. Readers are
cautioned that the 2008 Guidance may not be appropriate for other purposes.
The Trust reviewed distribution levels in light of the outlook for
commodity prices and the estimated increase in Alberta royalties pursuant to
the new Framework in 2009. Following the $0.24 per unit October distribution
to be paid November 17, 2008, the monthly distribution will be $0.20 per unit
per month. Distribution levels are reviewed regularly and revisions are
approved at the discretion of the Board of Directors.
Actual results for the first nine months of 2008 were in line with 2008
guidance with some minor exceptions as follows:

<<
- G&A expenses of $2.65 per boe were lower than initial guidance of
$3.15 per boe due to the decrease in the Trust's unit price at
quarter-end that resulted in a lower non-cash LTIP expense. Full year
G&A cash expenses are still expected to be in line with guidance
while total G&A may fluctuate due to the variability of the Trust's
unit price. The Trust has lowered the cash LTIP expense to $0.90 per
boe from $1.00 per boe and the non-cash LTIP expense to $0.15 per boe
from $0.44 per boe based on the reduction in the unit price.

- Capital expenditures guidance included amounts that the Trust
anticipated spending on crown land acquisitions throughout the year,
however, it was difficult to know the success rate that the Trust
would have in the silent bid process used for crown land sales. At
this time, the Trust is revising its guidance to $530 million down
from the original guidance of $550 million.
>>

Non-GAAP Measures

Historically, management used the non-GAAP measure Cash Flow or cash flow
from operations to analyze operating performance, leverage and liquidity. We
have now chosen to use the GAAP measure cash flow from operating activities
instead of Cash Flow or cash flow from operations. There are two differences
between the two measures and cash flow from operating activities: positive or
negative changes in non-cash working capital and the deduction of expenditures
on site restoration and reclamation as they appear on the Consolidated
Statements of Cash Flows. Although management feels that Cash Flow, or cash
flow from operations, is a valued measure of funds generated by the Trust
during the reported quarter, we have changed our disclosure to only discuss
the GAAP measure in the MD&A in order to avoid any potential confusion by
readers of our financial information and in our opinion, to more fully comply
with the intent of certain regulatory requirements.
Our historical measure of Cash Flow reflected revenues and costs for the
three months reported in the quarter. This amount, however, comprised accruals
for at least one month of revenue and approximately two months of costs. The
oil and gas industry is designed such that revenues are typically collected on
the 25th day of the month following the actual production month. Royalties are
typically paid two months following the actual production month and operating
costs are paid as the invoices are received. This can take several months;
however, most invoices for operated properties are paid within approximately
two months of the production month. In the event that commodity prices and or
volumes have changed significantly from the last month of the previous
reporting period over the last month of the current reporting period, a
difference could occur between cash flow from operating activities and our
historical non-GAAP measure of Cash Flow or cash flow from operations.
Additionally, periods where the Trust spends a significant amount on site
restoration and reclamation would result in a difference between cash flow
from operating activities and Cash Flow or cash flow from operations.
At the time of writing this MD&A, substantially all revenues have been
collected for the production period of September 2008. Management performs
analysis on the amounts collected to ensure that the amounts accrued for
September are accurate. Analysis is also performed regularly on royalties and
operating costs to ensure that amounts have been accurately accrued.
Management uses certain key performance indicators ("KPIs") and industry
benchmarks such as distributions as a per cent of cash flow from operating
activities, operating netbacks ("netbacks"), total capitalization, finding,
development and acquisition costs, recycle ratio, reserve life index, reserves
per unit and production per unit to analyze financial and operating
performance. Management feels that these KPIs and benchmarks are key measures
of profitability and overall sustainability for the Trust. These KPIs and
benchmarks as presented do not have any standardized meaning prescribed by
Canadian GAAP and therefore may not be comparable with the calculation of
similar measures for other entities.

<<
2008 Third Quarter Financial and Operational Results

Financial Highlights
Table 4
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
(Cdn $ millions,
except per unit % %
and volume data) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 251.4 179.6 40 734.8 531.2 38
Cash flow from operating
activities per unit(1) 1.16 0.85 36 3.41 2.54 34
Net income 311.7 120.8 158 450.3 389.0 16
Net income per unit(2) 1.46 0.58 152 2.12 1.88 13
Distributions per unit(3) 0.80 0.60 33 2.08 1.80 16
Distributions as a per cent
of cash flow from
operating activities 68 70 (3) 60 70 (14)
Average daily production
(boe/d)(4) 64,325 61,108 5 65,063 62,296 4
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(1) Per unit amounts are based on weighted average trust units
outstanding plus trust units issuable for exchangeable shares at
year-end.
(2) Based on net income after non-controlling interest divided by
weighted average trust units outstanding excluding trust units
issuable for exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf: 1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the well head. Use of the term boe in isolation may be
misleading.
>>

Net Income

Net income in the third quarter of 2008 was $311.7 million ($1.46 per
unit), an increase of $190.9 million from $120.8 million ($0.58 per unit) in
2007. While cash flow from operating activities increased $71.8 million in the
third quarter of 2008 compared to the same period in 2007 (see Table 6 for
details), there were several non-cash items that impacted the Trust's net
income in the current quarter as follows:

<<
- The Trust recorded a $187.5 million unrealized gain on risk
management contracts, a $185.4 million increase compared to an
unrealized gain of $2.1 million for the same period of 2007. The
unrealized gain was attributed to the decline in commodity prices
during the third quarter.
- The Trust recorded a $15.5 million non-cash foreign exchange loss on
its U.S. denominated debt as a result of the weakening of the
Canadian dollar relative to the U.S. dollar during the quarter
compared to a non-cash gain of $25.7 million in 2007.
- The Trust recorded a non-cash G&A recovery of $5.5 million in the
third quarter compared to a non-cash expense of $3.7 million in 2007
on the Trust's Long-term incentive plan due to the decrease in the
trust unit price in the quarter.
- The Trust recorded a $48.4 million future income tax expense for the
third quarter of 2008 compared to a $6.3 million recovery in 2007.
The future income tax expense was attributed to the unrealized gain
on risk management contracts in the quarter.
>>

A measure of sustainability is the comparison of net income to
distributions. Net income incorporates all costs including depletion expense
and other non-cash expenses whereas cash flow from operating activities
measures the cash generated in a given period before the cost of acquiring or
replacing the associated reserves produced. Therefore, net income may be more
representative of the profitability of the entity and thus a relevant measure
against which to measure distributions to illustrate sustainability. As net
income is sensitive to fluctuations in commodity prices and the impact of risk
management contracts, currency fluctuations and other non-cash items, it is
expected that there will be deviations between annual net income and
distributions. Table 5 illustrates the annual shortfall of distributions to
net income as a measure of long-term sustainability.

<<
Table 5
-------------------------------------------------------------------------
Net income and Distributions
($ millions except per cent) Q3 2008 YTD 2008 2007 2006
-------------------------------------------------------------------------
Net income 311.7 450.3 495.3 460.1
Distributions 171.3 442.8 498.0 484.2
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Excess (Shortfall) 140.4 7.5 (2.7) (24.1)
Excess (Shortfall) as per cent
of net income 45% 2% (1%) (5%)
Distributions as a per cent of
cash flow from operating
activities 68% 60% 71% 66%
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Cash Flow from Operating Activities

Cash flow from operating activities increased by 40 per cent in the third
quarter of 2008 to $251.4 million from $179.6 million in the third quarter of
2007. The increase in third quarter 2008 cash flow from operating activities
is detailed in Table 6.

Table 6
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($ per (%
($ millions) trust unit) variance)
-------------------------------------------------------------------------
Q3 2007 Cash flow from
Operating Activities 179.6 0.85 -
-------------------------------------------------------------------------
Volume variance 15.8 0.07 9
Price variance 169.6 0.80 94
Cash losses on risk management contracts (42.3) (0.19) (24)
Royalties (39.6) (0.19) (22)
Expenses:
Transportation (1.2) (0.01) (1)
Operating(1) (6.6) (0.03) (4)
Cash G&A (0.6) - -
Interest 0.8 - -
Realized foreign exchange gain / loss (0.8) - -
Weighted average trust units - (0.03) -
Non-cash and other items(2) (23.3) (0.11) (13)
-------------------------------------------------------------------------
Q3 2008 Cash flow from Operating
Activities 251.4 1.16 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Excludes non-cash portion of LTIP expense recorded in operating
costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.

Year-to-date cash flow from operating activities increased by 38 per cent
in 2008 to $734.8 million from $531.2 million in the first nine months of
2007. The increase in 2008 cash flow from operating activities is detailed in
Table 6a.

Table 6a
-------------------------------------------------------------------------
($ per (%
($ millions) trust unit) variance)
-------------------------------------------------------------------------
YTD 2007 Cash flow from
Operating Activities 531.2 2.54 -
-------------------------------------------------------------------------
Volume variance 44.1 0.21 8
Price variance 447.8 2.14 84
Cash losses on risk management contracts (123.8) (0.60) (23)
Royalties (95.0) (0.45) (18)
Expenses:
Transportation (1.4) (0.01) -
Operating(1) (18.8) (0.09) (4)
Cash G&A (8.1) (0.04) (2)
Interest 2.8 0.01 1
Realized foreign exchange gain / loss (0.9) - -
Weighted average trust units - (0.09) -
Non-cash and other items(2) (43.1) (0.21) (8)
-------------------------------------------------------------------------
YTD 2008 Cash flow from Operating
Activities 734.8 3.41 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Excludes non-cash portion of LTIP expense recorded in operating
costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.

2008 Cash Flow from Operating Activities Sensitivity

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

Table 7
-------------------------------------------------------------------------
Impact on Annual
Cash flow from operating activities(2)
-------------------------------------------------------------------------
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 107.10 $ 1.00 $ 0.04
Natural gas price (Cdn $AECO/mcf)(1) $ 8.40 $ 0.10 $ 0.03
Cdn$/US$ exchange rate $ 1.04 $ 0.01 $ 0.05
Interest rate on floating rate debt % 4.0 % 1.0 $ 0.03
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.05
Natural gas production volumes
(mmcf/d) 195.5 % 1.0 $ 0.02
Operating expenses per boe $ 10.20 % 1.0 $ 0.01
Cash G&A expenses per boe $ 2.60 % 10.0 $ 0.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Analysis does not include the effect of hedging contracts.
(2) Assumes constant working capital.

Production
Table 8
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
% %
Production 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Light & medium crude oil
(bbl/d) 27,211 27,207 - 27,073 27,353 (1)
Heavy oil (bbl/d) 1,298 1,230 6 1,299 1,329 (2)
Natural gas (mmcf/d) 192.0 173.3 11 197.0 177.6 11
NGL (bbl/d) 3,822 3,795 1 3,862 4,013 (4)
-------------------------------------------------------------------------
Total production
(boe/d)(1) 64,325 61,108 5 65,063 62,296 4
% Natural gas production 50 47 6 50 48 4
% Crude oil and liquids
production 50 53 (6) 50 52 (4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Reported production for a period may include minor adjustments from
previous production periods.
>>

Production volumes averaged 64,325 boe per day in the third quarter of
2008 up five per cent from the same period in 2007. The majority of the
increase in volumes was from the Dawson area due to the start-up of a third
party gas plant in the fourth quarter of 2007. The volumes were in line with
management's expectations and incorporated minor downtime for planned
turnarounds that were completed during the quarter. The Trust is maintaining
its full year production guidance at 64,000 to 65,000 boe per day.

<<
Table 9 summarizes the Trust's third quarter production by core area:

Table 9
-------------------------------------------------------------------------
Three Months Ended September 30, 2008
-------------------------------------------------------------------------
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,428 1,380 29.0 1,218
Northern AB & BC 21,705 5,112 90.2 1,553
Pembina & Redwater 13,972 9,866 19.1 921
S.E. AB & S.W. Sask. 9,629 977 51.9 8
S.E. Sask. & MB 11,591 11,175 1.8 122
-------------------------------------------------------------------------
Total 64,325 28,510 192.0 3,822
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Three Months Ended September 30, 2007
-------------------------------------------------------------------------
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,694 1,522 29.6 1,234
Northern AB & BC 19,106 5,776 71.2 1,475
Pembina & Redwater 13,497 9,411 18.7 971
S.E. AB & S.W. Sask. 9,679 1,008 52.0 10
S.E. Sask. & MB 11,132 10,720 1.8 105
-------------------------------------------------------------------------
Total 61,108 28,437 173.3 3,795
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is
southwest.

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

Table 9a
-------------------------------------------------------------------------
Nine Months Ended September 30, 2008
-------------------------------------------------------------------------
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,549 1,405 29.5 1,228
Northern AB & BC 22,550 5,473 93.1 1,553
Pembina & Redwater 13,599 9,405 19.7 911
S.E. AB & S.W. Sask. 9,826 991 52.9 12
S.E. Sask. & MB 11,539 11,098 1.8 158
-------------------------------------------------------------------------
Total 65,063 28,372 197.0 3,862
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Nine Months Ended September 30, 2007
-------------------------------------------------------------------------
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,984 1,644 30.2 1,313
Northern AB & BC 19,545 5,815 73.2 1,526
Pembina & Redwater 13,579 9,378 18.9 1,051
S.E. AB & S.W. Sask. 9,969 1,065 53.4 9
S.E. Sask. & MB 11,218 10,780 1.9 114
-------------------------------------------------------------------------
Total 62,296 28,682 177.6 4,013
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is
southwest.
>>

Revenue

Revenue increased to $485.7 million for the third quarter of 2008. The
increase in revenue was attributable to both higher realized oil prices and
increased production volumes. Prior to hedging activities, ARC's total
realized commodity price was $82.06 per boe in the third quarter of 2008, a
54 per cent increase from the $53.41 per boe received prior to hedging in
2007. For the nine months ended September 30, 2008, the Trust realized
$78.84 per boe, a 47 per cent increase over the realized price of $53.73 per
boe received in the comparable period in 2007. Both of these amounts are prior
to hedging losses.

<<
A breakdown of revenue is as follows in Table 10:

Table 10
-------------------------------------------------------------------------
Revenue Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
% %
($ millions) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Oil revenue 299.5 192.0 56 833.3 520.3 60
Natural gas revenue 153.3 88.1 74 482.6 334.3 44
NGL revenue 29.1 19.4 50 82.4 57.0 45
-------------------------------------------------------------------------
Total commodity revenue 481.9 299.5 61 1,398.3 911.6 53
Other revenue 3.8 0.7 443 7.3 2.0 265
-------------------------------------------------------------------------
Total revenue 485.7 300.2 62 1,405.6 913.6 54
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

The oil and natural gas prices realized by the Trust are based upon
quality and transportation differentials from major North American commodity
postings. The Trust's realized oil price was 94 per cent of the Edmonton
posted oil prices, slightly higher than the comparable quarter of 2007 where
ARC received 92 per cent. The Trust has not experienced any significant change
in the quality composition of its oil production hence the increase in price
relative to Edmonton posted prices is due to the strengthening of prices for
sour and medium sour blend postings relative to Edmonton posted prices.
Approximately 43 per cent of ARC's crude oil production is light sweet oil,
53 per cent is light and medium sour crude with the balance being heavy oil.
The Trust's natural gas price of $8.68 per mcf was lower than the AECO monthly
average in the quarter of $9.27 per mcf as a portion of the Trust's natural
gas production is sold at the AECO daily spot price which averaged $7.75 per
mcf during the third quarter.

<<
Table 11
-------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
% %
2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Average Benchmark Prices
AECO gas ($/mcf)(1) 9.27 5.61 65 8.58 6.81 26
WTI oil (US$/bbl)(2) 118.18 75.33 57 113.39 66.22 71
Cdn$/US$ foreign
exchange rate 1.04 1.04 - 1.02 1.10 (7)
Edmonton Posted oil
(Cdn$/bbl) 121.77 79.78 53 114.99 72.99 58
-------------------------------------------------------------------------
ARC Realized Prices
Prior to Hedging
Oil ($/bbl) 114.20 73.40 56 107.20 66.45 61
Natural gas ($/mcf) 8.68 5.52 57 8.94 6.90 30
NGL ($/bbl) 82.87 55.64 49 77.91 52.07 50
-------------------------------------------------------------------------
Total commodity revenue
before hedging ($/boe) 81.42 53.28 53 78.44 53.61 46
Other revenue ($/boe) 0.64 0.13 392 0.40 0.12 233
-------------------------------------------------------------------------
Total revenue before
hedging ($/boe) 82.06 53.41 54 78.84 53.73 47
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

Risk Management and Hedging Activities

ARC continues to maintain an ongoing risk management program to reduce
the volatility of revenues in order to increase the certainty of
distributions, protect acquisition economics, and fund capital expenditures.
The risk management program and Board approved parameters are discussed in the
Trust's 2007 Annual Report filed on SEDAR and available on the Trust's website
- www.arcenergytrust.com.
Strong commodity prices throughout the third quarter had a significant
positive impact on the Trust's revenue; however, these strong prices resulted
in realized cash losses of $34.3 million on the Trust's oil and natural gas
risk management contracts. Despite strong average commodity prices during the
third quarter, prices decreased late in the quarter and futures prices as of
September 30, 2008 were significantly lower than June 30, 2008. Consequently,
the Trust recorded a $187.5 million unrealized non-cash mark-to-market gain on
risk management contracts.
Table 12 is a summary of the total gain (loss) on risk management
contracts for the third quarter of 2008 as compared to the same period in
2007.

<<
Table 12
-------------------------------------------------------------------------
Risk Management
Contracts Crude Oil Natural Foreign
($ millions) & Liquids Gas Currency(3) Power
-------------------------------------------------------------------------
Realized cash (loss) gain
on contracts(1) (26.9) (7.5) (0.2) -
Unrealized (loss) gain on
contracts(2) 139.6 39.6 5.6 1.9
-------------------------------------------------------------------------
Total gain (loss) on risk
management contracts 112.7 32.1 5.4 1.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

--------------------------------------------------------------
Risk Management
Contracts Q3 2008 Q3 2007
($ millions) Interest Total Total
--------------------------------------------------------------
Realized cash (loss) gain
on contracts(1) 0.3 (34.3) 8.0
Unrealized (loss) gain on
contracts(2) 0.8 187.5 2.1
--------------------------------------------------------------
Total gain (loss) on risk
management contracts 1.1 153.2 10.1
--------------------------------------------------------------
--------------------------------------------------------------

(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
(3) Unrealized gain on foreign currency contracts includes a $6.2 million
dollar gain on contracts related to repayments of the Trust's U.S.
denominated long-term debt. See the Foreign Exchange Gains and Losses
section of this MD&A for further details on the debt related
contracts.

Table 12a
-------------------------------------------------------------------------
Risk Management
Contracts Crude Oil Natural Foreign
($ millions) & Liquids Gas Currency(3) Power
-------------------------------------------------------------------------
Realized cash (loss) gain
on contracts(1) (78.0) (17.8) 0.1 -
Unrealized (loss) gain
on contracts(2) 3.3 13.2 6.5 1.9
-------------------------------------------------------------------------
Total gain (loss) on risk
management contracts (74.7) (4.6) 6.6 1.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

--------------------------------------------------------------
Risk Management
Contracts YTD 2008 YTD 2007
($ millions) Interest Total Total
--------------------------------------------------------------
Realized cash (loss) gain
on contracts(1) (12.8) (108.5) 15.3
Unrealized (loss) gain
on contracts(2) 1.1 26.0 (8.0)
--------------------------------------------------------------
Total gain (loss) on risk
management contracts (11.7) (82.5) 7.3
--------------------------------------------------------------
--------------------------------------------------------------

(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
(3) Unrealized gain on foreign currency contracts includes a $6.9 million
dollar gain on contracts related to repayments of the Trust's U.S.
denominated long-term debt. See the Foreign Exchange Gains and Losses
section of this MD&A for further details on the debt related
contracts.
>>

The volatility of oil and natural gas prices can lead to significant
changes in the mark-to-market position of the Trust's oil and natural gas
contracts. Unrealized losses at September 30, 2008 were calculated using
forward strip prices as of that date to arrive at a closing mark-to-market
loss position excluding contracts designated as effective accounting hedges,
of $38.6 million compared to a loss position of $226 million at June 30, 2008
resulting from a weakening in commodity prices late in the third quarter.
Commodity prices continued to decline after the quarter end, resulting in an
increase in the value of the Trust's risk management contracts.
For the remainder of 2008 the Trust has unlimited price participation on
approximately 70 per cent of forecast production. The remaining 30 per cent of
production volumes have price caps at average prices of US$90 per barrel on
crude oil and Cdn$9.68 per GJ on natural gas along with downside price
protection at average prices of US$68.13 per barrel on crude oil and
Cdn$7.42 per GJ on natural gas. For 2009, the Trust has 5,000 barrels per day
of production capped at US$90 per barrel. Subsequent to the quarter end the
Trust has bought back a portion of this contract to regain the upside price
potential on this production. Table 13 is an indicative summary of the Trust's
positions for crude oil, natural gas and related foreign exchange for the next
twelve months as at September 30, 2008:

<<
Table 13
-------------------------------------------------------------------------
Hedge Positions Summary
As at September 30, 2008(1)(2)
-------------------------------------------------------------------------
Q4 2008 Q1 2009
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 90.00 10,000 90.00 5,000
Bought Put 68.13 10,000 55.00 5,000
Sold Put 51.07 7,000 40.00 5,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 9.68 48,570 10.51 42,202
Bought Put 7.42 48,570 7.81 42,202
Sold Put 5.26 10,480 - -
-------------------------------------------------------------------------
Foreign Exchange Cdn$/US$ $ million Cdn$/US$ $ million
-------------------------------------------------------------------------
Bought Put 1.0750 3.00 - -
Sold Put 1.0300 3.00 - -
Swap 1.0150 12.00 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Hedge Positions Summary
As at September 30, 2008(1)(2)
-------------------------------------------------------------------------
Q2 2009 Q3 2009
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 90.00 5,000 90.00 5,000
Bought Put 55.00 5,000 55.00 5,000
Sold Put 40.00 5,000 40.00 5,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call - - - -
Bought Put - - - -
Sold Put - - - -
-------------------------------------------------------------------------
Foreign Exchange Cdn$/US$ $ million Cdn$/US$ $ million
-------------------------------------------------------------------------
Bought Put - - - -
Sold Put - - - -
Swap - - - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) The prices and volumes noted above represent averages for several
contracts and the average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. Viewing the average price of a group of options is purely
for indicative purposes. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price. In addition to positions
shown here, ARC has entered into additional basis positions.
(2) Please refer to note 9 in the Notes to the Consolidated Financial
Statements for full details of the Trust's hedging positions as at
September 30, 2008.

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

- If the market price is below $51.07, ARC will receive $68.13 less the
difference between $51.07 and the market price on 7,000 barrels per
day. For example if the market price is $51.06, ARC will receive
$68.12 on 7,000 barrels per day.
- If the market price is between $51.07 and $68.13, ARC will receive
$68.13 on 10,000 barrels per day.
- If the market price is between $68.13 and $90.00, ARC will receive
the market price on 10,000 barrels per day.
- If the market price exceeds $90.00, ARC will receive $90.00 on
10,000 barrels per day.

Operating Netbacks

The Trust's operating netback, after realized commodity and related
foreign exchange hedging losses, increased 42 per cent to $50.28 per boe in
the third quarter of 2008 compared to $35.52 per boe in the same period of
2007. The increase in netbacks in 2008 is primarily due to a 53 per cent
increase in the Trust's weighted average sales price. The increase in revenue
was partially offset by an increase in royalties and operating costs.

The components of operating netbacks are shown in Tables 14 and 14a:

Table 14
-------------------------------------------------------------------------
Light and
Medium Heavy Natural Q3 2008 Q3 2007
Netbacks Crude Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 114.92 98.97 8.68 82.87 81.42 53.28
Other revenue - - - - 0.64 0.13
-------------------------------------------------------------------------
Total revenue 114.92 98.97 8.68 82.87 82.06 53.41
Royalties (17.57) (10.53) (1.99) (23.83) (15.00) (8.76)
Transportation (0.18) (1.10) (0.24) - (0.80) (0.65)
Operating costs(1) (13.80) (11.26) (1.19) (9.78) (10.19) (9.93)
-------------------------------------------------------------------------
Netback prior to
hedging 83.37 76.08 5.26 49.26 56.07 34.07
Realized gain (loss)
on risk management
contracts (10.81) - (0.43) - (5.79) 1.45
-------------------------------------------------------------------------
Netback after
hedging 72.56 76.08 4.83 49.26 50.28 35.52
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Table 14a
-------------------------------------------------------------------------
Light and
Medium Heavy Natural YTD 2008 YTD 2007
Netbacks Crude Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 108.09 88.49 8.94 77.92 78.44 53.61
Other revenue - - - - 0.40 0.12
-------------------------------------------------------------------------
Total revenue 108.09 88.49 8.94 77.92 78.84 53.73
Royalties (16.69) (9.49) (1.89) (22.15) (14.18) (9.28)
Transportation (0.13) (1.16) (0.23) - (0.77) (0.73)
Operating costs(1) (14.00) (10.94) (1.21) (7.18) (10.14) (9.51)
-------------------------------------------------------------------------
Netback prior to
hedging 77.27 66.90 5.61 48.59 53.75 34.21
Realized gain (loss)
on risk management
contracts(2) (10.49) - (0.33) - (6.08) 0.93
-------------------------------------------------------------------------
Netback after
hedging 66.78 66.90 5.28 48.59 47.67 35.14
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
(2) Realized loss on risk management contracts excludes the settlement
amount for the treasury interest rate lock contracts that were
unwound during the first quarter of 2008.
>>

Royalties as a percentage of pre-hedged commodity revenue net of
transportation costs were 18.5 per cent ($15.00 per boe) and 16.6 per cent
($8.76 per boe), respectively, for the third quarters of 2008 and 2007. The
increase in the royalty rate from 16.6 per cent to 18.5 per cent was partially
due to a higher proportion of gas revenue as natural gas royalty rates are
generally higher, on average than royalty rates on crude oil production. In
2007, the Trust's royalty rates were lower than normal levels due to Gas Cost
Allowance credits and royalty credits received on a portion of the Trust's BC
gas production. The higher rate is also attributed to changes to the Trust's
production profile as new production has come on to offset production declines
at existing properties.
Operating costs increased to $10.19 per boe in the third quarter of 2008
compared to $9.93 per boe in the third quarter of 2007. Costs for the third
quarter were in-line with expectations as turnarounds and maintenance
activities continued throughout the summer months. For 2008, the Trust has
maintained guidance at $10.20 per boe based on production of between 64,000
and 65,000 barrels per day. Total operating costs are projected to be
approximately $235 million for the full year of 2008.

Alberta Government New Royalty Framework

On April 10, 2008, the Alberta Government announced revisions to the New
Royalty Framework ("Framework" or "NRF") that will take effect on January 1,
2009 pending final legislation which is expected in November 2008.

<<
The revisions to the Framework include the following:

- Increased royalty rates on conventional and non-conventional oil and
natural gas production in Alberta whereby royalty rates may increase
to maximum rates 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;
>>

Approximately 65 per cent of the Trust's production is in Alberta;
consequently, the Framework will have a significant adverse 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 increase from approximately 18 per cent of revenue
in 2008 to between 20 and 28 per cent of revenue in 2009 depending upon
commodity prices as illustrated in Table 14b.

<<
Table 14b
-------------------------------------------------------------------------
Royalty Rates - New Royalty Framework
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Edmonton posted oil (Cdn$/bbl)(1) $60 $80 $100 $120
AECO natural gas (Cdn$/GJ)(1) $6 $8 $10 $12
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Current Alberta royalty rate(2) 17.5% 17.5% 17.5% 17.5%
-------------------------------------------------------------------------
NRF Alberta royalty rate(3) 20.0% 25.0% 29.0% 33.0%
-------------------------------------------------------------------------
% Increase - Alberta royalty rate 14% 43% 66% 89%
-------------------------------------------------------------------------
Current Corporate royalty rate(2) 18.0% 18.0% 18.0% 18.0%
-------------------------------------------------------------------------
NRF Corporate royalty rate(3) 20.0% 23.0% 26.0% 28.0%
-------------------------------------------------------------------------
% Increase - Corporate royalty rate 11% 28% 44% 56%
-------------------------------------------------------------------------
Incremental Annual Corporate
royalties ($ Millions) $15.0 $60.0 $125.0 $200.0
-------------------------------------------------------------------------
Decrease in annual cash flow per unit $0.07 $0.27 $0.58 $0.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Canadian dollar denominated prices before quality differentials.
(2) Current Alberta and Corporate royalty rates are consistent across all
price scenarios as price ceilings have been exceeded under the
current royalty regime whereby royalty rates change only marginally
across the price scenarios presented.
(3) Estimated royalty rates based on draft guidelines that are subject to
interpretation. Changes to draft royalty guidelines may result in
changes to the estimated royalty rates. Royalty rate includes Crown,
Freehold and Gross Override royalties for all jurisdictions in which
the Trust operates.

Table 14c illustrates provincial royalty rates following implementation of
the Framework whereby royalty rates in Alberta will be significantly higher
than royalty rates in the Trust's other operating jurisdictions. Production in
each province currently approximates 65 per cent in Alberta, 22 per cent in
Saskatchewan, 11 per cent in British Columbia and one per cent in Manitoba.
The Trust may redirect future capital spending from Alberta if rates of return
erode relative to other provinces following implementation of the Framework in
January 2009.

Table 14c
-------------------------------------------------------------------------
Provincial Royalty Rates - New Royalty Framework
-------------------------------------------------------------------------

(2) Royalty rate includes Crown, Freehold and Gross Override royalties
for all jurisdictions in which the Trust operates.
>>

As royalties under the new Framework are sensitive to both commodity
prices and production levels, the estimated NRF Alberta and corporate royalty
rates will fluctuate with commodity prices, well production rates, production
decline of existing wells, and performance and location of new wells drilled.
The estimated Alberta and corporate royalty rates are based on draft
guidelines that may change pending the outcome of final legislation.
The Trust will upgrade its production accounting system in the fourth
quarter to accommodate royalty calculations and reporting requirements under
the Framework effective January 1, 2009.

General and Administrative Expenses and Trust Unit Incentive Compensation

Cash G&A expenses net of overhead recoveries on operated properties,
excluding cash costs of the Whole Trust Unit Incentive Plan ("Whole Unit
Plan"), increased seven per cent to $9 million in the third quarter of 2008
from $8.4 million in the same period of 2007. Increases in G&A expenses for
2008 were due to increased staff levels and higher compensation costs.
The Trust recorded a non-cash G&A recovery of $5.5 million (a recovery of
$0.93 per boe) during the third quarter, representing a reduction in the value
of the Whole Unit Plan due to the decrease in the Trust's unit price from
$33.95 per unit at June 30, 2008 to $23.10 at September 30, 2008. There were
no cash payments under the plan in the third quarter. Subsequent to quarter
end, the Trust made a cash payment under the plan of $9.3 million of which
$7.0 million was recorded in G&A. The amount paid subsequent to quarter end
was fully accrued as non-cash expense in the third quarter and the cash
payment will be reflected as cash G&A and a decrement to cash flow from
operating activities in the fourth quarter.

Table 15 is a breakdown of G&A and trust unit incentive compensation
expense:

<<
Table 15
-------------------------------------------------------------------------
G&A and Trust Unit
Incentive Compensation Three Months Ended Nine Months Ended
Expense September 30 September 30
-------------------------------------------------------------------------
($ millions % %
except per boe) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
G&A expenses 13.3 12.0 11 40.3 38.1 6
Operating recoveries (4.3) (3.6) 19 (12.2) (12.0) 2
-------------------------------------------------------------------------
Cash G&A before
Whole Unit Plan 9.0 8.4 7 28.1 26.1 8
Whole Unit Plan - cash - - - 14.4 8.3 74
- accrued (5.5) 3.7 (249) 4.7 (0.3) 1667
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense 3.5 12.1 (71) 47.2 34.1 38
-------------------------------------------------------------------------
Total G&A and trust unit
incentive compensation
expense per boe 0.59 2.16 (73) 2.65 2.00 33
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

The components of the initial $3.15 per boe G&A guidance for the full
year were as follows: cash G&A - $1.71/boe; cash component of LTIP - $1.00 per
boe; non-cash LTIP component - $0.44 per boe. The $1.00 per boe cash and
$0.44 per boe non-cash Whole Unit Plan amounts have been revised downward to
$0.90 per boe cash and $0.15 per boe non-cash to account for the decline in
the trust unit price which impacts the fourth quarter cash payout and non-cash
expense amounts under the Whole Unit Plan. The cash G&A guidance remains
unchanged at $1.70 per boe for the remainder of 2008. The revised full year
guidance for G&A is now $2.75 per boe.

Whole Unit Plan

The Whole Unit Plan results in each employee, officer and director (the
"plan participants") receiving cash compensation in relation to the value of a
specified number of underlying trust units. The Whole Unit Plan consists of
Restricted Trust Units ("RTUs") for which the number of units is fixed and
will vest over a period of three years and Performance Trust Units ("PTUs")
for which the number of units is variable and will vest at the end of three
years.
Upon vesting, the plan participant is entitled to receive a cash payment
based on the fair value of the underlying trust units plus accrued
distributions. The cash compensation issued upon vesting of the PTUs is
dependent upon the performance of the Trust compared to its peers and
indicated by the performance multiplier. The performance multiplier is based
on the percentile rank of the Trust's total unitholder return compared to its
peers. Total return is calculated as the sum of the change in the market price
of the trust units in the period plus the amount of distributions in the
period. The performance multiplier ranges from zero, if ARC's performance
ranks in the bottom quartile, to two for top quartile performance.
Table 16 shows the changes to the Whole Unit Plan during the first nine
months of 2008 along with the estimated value of the plan at September 30,
2008:
<<
Table 16
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and Number of Number of Total
$ millions except per unit) RTUs PTUs RTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 746 903 1,649
Granted in the period 414 353 767
Vested in the period (193) (183) (376)
Forfeited in the period (41) (42) (83)
-------------------------------------------------------------------------
Balance, end of period(1) 926 1,031 1,957
-------------------------------------------------------------------------
Estimated distributions
to vesting date(2) 277 431 708
Estimated units upon vesting
after distributions 1,203 1,462 2,665
Performance multiplier(3) - 1.5 -
-------------------------------------------------------------------------
Estimated total units upon vesting 1,203 2,145 3,348
-------------------------------------------------------------------------
Trust unit price at
September 30, 2008 $23.10 $23.10 $23.10
Estimated total value upon
vesting ($ millions) 27.8 49.5 77.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(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 September 30, 2008 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.
>>

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 17 is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier and units
outstanding as at September 30, 2008:

<<
Table 17
-------------------------------------------------------------------------
Value of Whole Unit Plan
as at September 30, 2008 Performance multiplier
-------------------------------------------------------------------------
(units thousands and
$ millions except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated units to vest
RTUs 1,203 1,203 1,203
PTUs - 1,462 2,923
-------------------------------------------------------------------------
Total units(1) 1,203 2,665 4,126
-------------------------------------------------------------------------
Trust unit price(2) $23.10 $23.10 $23.10
Trust unit distributions
per month(2) $0.24 $0.24 $0.24
-------------------------------------------------------------------------
Value of Whole Unit Plan
upon vesting 27.8 61.6 95.3
-------------------------------------------------------------------------
Officers 2.9 18.8 34.8
Directors 1.9 1.9 1.9
Staff 23.0 40.9 58.6
-------------------------------------------------------------------------
Total payments under
Whole Unit Plan(3) 27.8 61.6 95.3
-------------------------------------------------------------------------
2008 4.3 6.5 8.6
2009 10.7 19.1 27.6
2010 8.3 19.8 31.2
2011 4.5 16.2 27.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Includes additional estimated units to be issued for accrued
distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumes
future trust unit price of $23.10 per trust unit and distributions
based on current levels at September 30.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in March
and April for the spring grants, and September and October for the
fall grants of each year and at that time is reflected as a reduction
of cash flow from operating activities.
>>

Due to the variability in the future payments under the plan, the Trust
estimates that between $27.8 million and $95.3 million will be paid out from
2008 through 2011 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.

Provision for Non-recoverable Accounts Receivable

On July 22, 2008, SemCanada Crude filed for protection under the
Companies' Creditors Arrangement Act ("CCAA"). At that time, the Trust had a
receivable of $30.6 million owing from the counterparty for crude oil
production that SemCanada marketed on behalf of the Trust. To date, the Trust
has recorded a provision for non-recoverable accounts receivable of
$18 million ($13.5 million net of tax) for the estimated non-recoverable
portion of the $30.6 million balance as Management believes that some portion
of the $30.6 million owed by SemCanada is recoverable. The Trust has no
additional exposure to SemCanada Crude as all production was allocated to
other marketing counterparties effective July 23, 2008.

Interest Expense

Interest expense decreased to $7.8 million in the third quarter of 2008
from $8.6 million in the third quarter of 2007 due to a decrease in short-term
interest rates. As at September 30, 2008, the Trust had $695.7 million of debt
outstanding, of which $231 million was fixed at a weighted average rate of
4.8 per cent and $464.7 million was floating at current market rates plus a
credit spread of 60 basis points. The Canadian market interest rates have
declined to approximately 4.2 per cent in the third quarter of 2008 as
compared to approximately 4.9 per cent in the same period of 2007. U.S. London
Inter-Bank Offer Rate ("LIBOR") interest rates have declined to approximately
3.1 per cent in the third quarter of 2008 as compared to approximately six per
cent in the same period of 2007. Although Canadian interest rates and US LIBOR
rates have decreased on average since the third quarter of 2007, they have
been volatile towards the end of the September and into the month of October
due to the credit crisis and the uncertainty surrounding some banks' sources
of funds. In light of this volatility, the Trust has maintained annual
guidance for interest expense at $1.50 per boe.

Foreign Exchange Gains and Losses

In the third quarter of 2008, the Trust recorded a loss of $16.3 million
on foreign exchange transactions compared to a gain of $25.7 million in the
same period of 2007. These amounts include both realized and unrealized
foreign exchange gains and losses.
Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements.
Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances into Canadian dollars based on period end
foreign exchange rates. The unrealized gain/loss impacts net income but does
not impact cash flow from operating activities as it is a non-cash amount.
During the third quarter, the Canadian dollar weakened to 1.06 CAD$/US$ from
1.01 CAD$/US$ at June 30, 2008, resulting in an unrealized loss of
$15.5 million on U.S. dollar denominated debt of US$374 million.
ARC entered into forward contracts to lock in exchange rates for
principal repayments on US$127.2 million of the US$218 million fixed term debt
outstanding. The forward contracts had a mark-to-market gain position at
September 30, 2008 of $9.5 million. The unrealized gain on these contracts has
been included in the unrealized risk management contracts on the Consolidated
Statement of Income and Deficit.

Taxes

In the third quarter of 2008 the Trust recorded a future income tax
expense of $48.4 million versus an income tax recovery of $6.3 million in the
third quarter of 2007. The third quarter expense of $48.4 million is primarily
due to the $187.5 million unrealized mark-to-market gain on risk management
contracts. The Trust has recorded a current future income tax asset of
$13.9 million as at September 30, 2008 relating to the current portion of
mark-to-market losses on risk management contracts. The net future tax
liability on the balance sheet reflects the estimated tax liability associated
with the Trust's income tax pools being less than the net book value of the
Trust's assets. Each quarter as the Trust makes distributions it effectively
passes the taxable income in the current period on to its unitholders.
On February 26, 2008, the Federal Government announced as part of the
Federal budget that the provincial component of the tax on the Trust is to be
calculated based on the general provincial rate in each province in which the
Trust has a permanent establishment. This is the same way a corporation would
calculate its provincial tax rate, and is different than the original
calculation of the tax on the Trust, which had a deemed provincial rate of
13 per cent rather than Alberta's provincial rate of 10 per cent. At the time
of writing this MD&A, the Federal budget had been substantively enacted;
however, the specific rules for determining the provincial rates for trusts
had not been substantively enacted as at September 30, 2008. As a result, a
reduction in the tax rate used for the Trust's future income tax calculation
has not been reflected in the third quarter of 2008.
On July 14, 2008, the Department of Finance released proposed amendments
(the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the
conversion of existing income trusts into corporations. In general, the
proposed amendments will permit a conversion to be tax deferred for both the
unitholders and the income trust. However, the Conversion Rules provide
alternative approaches to completing a tax deferred conversion. The Department
of Finance requested comments on the Conversion Rules by September 15, 2008
and it is anticipated that there will be further amendments to the Conversion
Rules. Management and the Board of Directors continue to review the impact of
the trust tax on our business strategy and while there has not been a decision
as to ARC's future direction, at this time we are of the opinion that the
conversion from a trust into a corporation may be the most logical and tax
efficient alternative for ARC unitholders. We expect future technical
interpretations and details will further clarify the legislation. At the
present time, ARC believes that if structural or other similar changes are not
made, the relative after-tax distribution amount in 2011 to taxable Canadian
investors will remain approximately the same at the same distribution levels,
however, will decline for both tax-deferred Canadian investors (RRSPs, RRIFs,
pension plans, etc.) and foreign investors.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate decreased
slightly to $15.79 per boe in the third quarter of 2008 from $16.11 per boe in
the third quarter of 2007. Total depletion of oil and gas assets increased by
$3.4 million due to an increase in the Trust's production volumes for the
quarter. The lower depletion rate in the third quarter and first nine months
of 2008 relative to 2007 is due to a slight increase in the Trust's proven
reserve base and a reduction in future development capital associated with the
Trust's proven reserve base in 2008.

<<
A breakdown of the DD&A rate is detailed in Table 18:

Table 18
-------------------------------------------------------------------------
DD&A Rate Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
($ millions except % %
per boe amounts) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Depletion of oil & gas
assets(1) 91.1 87.7 4 276.5 267.8 3
Accretion of asset
retirement obligation(2) 2.3 2.9 (21) 6.9 8.7 (21)
-------------------------------------------------------------------------
Total DD&A expense 93.4 90.6 3 283.4 276.5 2
DD&A rate per boe 15.79 16.11 (2) 15.90 16.26 (2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the Property Plant & Equipment
("PP&E") balance and is being depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
>>

Capital Expenditures and Net Acquisitions

During the third quarter of 2008, the Trust spent $136.4 million on
capital expenditures, including $18.6 million for purchases of undeveloped
land at land sales. In addition, $13.1 million was spent on net acquisitions
of both producing properties and undeveloped land. Year-to-date, the Trust has
spent $379.1 million on capital expenditures, including $105.3 million on
undeveloped land. As well, the Trust has spent $23.4 million on minor
producing property and undeveloped land property acquisitions in the first
nine months of 2008.
The following summarizes the Trust's year-to-date spending as it relates
to our strategic focus areas:

Resource Plays

The Trust's resource play spending consists of costs incurred for
projects in the Montney gas play, the Bakken oil play and the Trust's natural
gas from coal ("NGC") projects. Year-to-date, the Trust has spent
$200.6 million which includes land purchases of $107.5 million.
In the Montney, ARC has spent a total of $72.3 million ($159.8 million
including crown land purchases and property purchases from other companies)
during the period. At September 30, 2008, the Trust had drilled and completed
four horizontal and two vertical wells while an additional 15 wells (3
horizontal and 12 vertical) have been drilled and are scheduled to be
completed in the fourth quarter. The Trust is on schedule with the
construction of its 10 mmcf per day pipeline from Dawson to Fourth Creek with
project completion expected in the fourth quarter.
In the Bakken, the Trust purchased undeveloped land for $19.9 million and
spent $11.7 million on the drilling of five wells that are all on production
at the end of the third quarter at a combined rate of over 1,000 boe per day.
NGC project spending has totaled $9.2 million for the first nine months
of 2008.

Tertiary EOR Initiatives

Total spending of $34 million included $11.3 million spent on the
Redwater CO(2) injection pilot project during the first nine months of 2008.
During the third quarter the Trust received final approval from the Energy
Resources Conservation Board for the pilot project and began injecting CO(2)
on July 29th. In addition, $12.4 million has been spent at Weyburn where the
Trust participates in a CO(2) EOR flood operated by EnCana Corporation.
Finally, the Trust spent $10 million on projects at Midale where the Trust
participates in a CO(2) EOR flood operated by Apache Corporation.

Conventional Assets

ARC's conventional assets accounted for total spending of $167.7 million,
including land purchases. Some of the highlights of the conventional program
are as follows.
The Trust has drilled and completed 20 oil wells in the Pembina Cardium
area, all of which are on production at the end of the third quarter.
In Southwest Saskatchewan, the Trust has drilled a total of 49 shallow
gas wells. Of these wells, 26 are currently on production and the remaining 23
will be completed and tied-in during the fourth quarter. In addition, the
Trust completed 22 wells in the first quarter of 2008 that were drilled in the
fourth quarter of 2007. The Trust was planning to drill an additional 26
shallow gas wells in this area, however, environmental regulatory approvals
have caused delays which may cause the Trust to defer this project until 2009.
In Redwater, the Trust has drilled eight wells of which three are on
production with the remaining five expected to be completed in the fourth
quarter.

Acquisitions and Dispositions

The Trust completed minor net producing property acquisitions for
$0.2 million and undeveloped land purchases for $23.2 million year-to-date.
The acquisition of undeveloped property for $23.2 million is included in the
Montney resource play land purchases discussed above.
A breakdown of capital expenditures and net acquisitions is shown in
Table 19:

<<
Table 19
-------------------------------------------------------------------------
Capital Expenditures Three Months Ended Nine Months Ended
September 30 September 30
-------------------------------------------------------------------------
% %
-------------------------------------------------------------------------
($ millions) 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Geological and geophysical 1.3 2.9 (55) 23.3 11.9 96
Drilling and completions 91.4 73.4 25 188.3 154.4 22
Plant and facilities 24.2 21.1 15 59.9 54.1 11
Undeveloped land 18.6 33.0 (44) 105.3 34.9 202
Other capital 0.9 1.5 (40) 2.3 2.6 (12)
-------------------------------------------------------------------------
Total capital
expenditures 136.4 131.9 3 379.1 257.9 47
-------------------------------------------------------------------------
Producing property
acquisitions(1) - 27.3 (100) 0.3 42.0 (99)
Undeveloped land property
acquisitions 13.1 - 100 26.9 - 100
Producing property
dispositions(1) - - - (0.1) (4.6) (98)
Undeveloped land property
dispositions - - - (3.7) - 100
-------------------------------------------------------------------------
Total capital expenditures
and net acquisitions 149.5 159.2 (6) 402.5 295.3 36
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Value is net of post-closing adjustments.
>>

Approximately 57 per cent of the $136.4 million capital program in the
third quarter of 2008 was financed with cash flow from operating activities
compared to 38 per cent in the same period of 2007. Property acquisitions were
financed through debt. On a year-to-date basis, the Trust has funded 77 per
cent of the capital expenditures with cash flow from operating activities as
compared to 58 percent for the first nine months of 2007.

<<
Table 20
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30, 2008 September 30, 2007
-------------------------------------------------------------------------
Devel- Net Total Devel- Net Total
opment Acquis- Expend- opment Acquis- Expend-
Capital itions itures Capital itions itures
-------------------------------------------------------------------------
Expenditures 136.4 13.1 149.5 131.9 27.3 159.2
-------------------------------------------------------------------------

Cash flow from
operating activities 57% - 53% 38% - 31%
Proceeds from DRIP
and Rights Plan 29% - 26% 21% - 17%
Debt 14% 100% 21% 41% 100% 52%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Table 20a
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
YTD September 30, 2008 YTD September 30, 2007
-------------------------------------------------------------------------
Devel- Net Total Devel- Net Total
opment Acquis- Expend- opment Acquis- Expend-
Capital itions itures Capital itions itures
-------------------------------------------------------------------------
Expenditures 379.1 23.4 402.5 257.9 37.4 295.3
-------------------------------------------------------------------------

Cash flow from
operating activities 77% - 72% 58% - 50%
Proceeds from DRIP
and Rights Plan 23% 38% 24% 33% - 29%
Debt - 62% 4% 9% 100% 21%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

Asset Retirement Obligation and Reclamation Fund

The Asset Retirement Obligation ("ARO") increased by $3.1 million in the
first nine months of 2008 to $143.1 million ($140 million at December 31,
2007) for future abandonment and reclamation of the Trust's properties.
Included in the September 30, 2008 ARO balance is a $1.6 million increase
related to development activities in the first nine months of 2008 as well as
changes in estimates for the existing liability. The ARO liability was also
increased by $6.9 million for accretion expense in the period and was reduced
by $7.8 million for actual abandonment expenditures incurred in the first nine
months of 2008.
The Trust maintains two reclamation funds that together held
$26.9 million at September 30, 2008, one exclusively for the reclamation of
the Redwater property and the other for all of the Trust's other properties.
In total, ARC contributed $9 million cash to its reclamation funds in the
first nine months of 2008 and earned interest of $0.9 million on the fund
balances. The fund balances were reduced by $9 million for cash-funded
abandonment expenditures in the first nine months of 2008.

Capitalization, Financial Resources and Liquidity

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

<<
Table 21
-------------------------------------------------------------------------
Capital Structure and Liquidity September 30, December 31,
($ millions except per cent and ratio amounts) 2008 2007
-------------------------------------------------------------------------
Net debt obligations(1) 773.2 752.7
Market value of trust units and exchangeable
shares(2) 5,021.9 4,349.3
-------------------------------------------------------------------------
Total capitalization(3) 5,795.1 5,102.0
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 13.3% 14.8%
Net debt to annualized YTD cash flow from
operating activities 0.8 1.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Net debt is a non-GAAP measure and is calculated as long-term debt
plus current liabilities less the current assets as they appear on
the Consolidated Balance Sheets. Net debt excludes current unrealized
amounts pertaining to risk management contracts and the current
portion of future income taxes.
(2) Calculated using the total trust units outstanding at September 30,
2008 including the total number of trust units issuable for
exchangeable shares at September 30, 2008 multiplied by the closing
trust unit price of $23.10.
(3) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by the Trust.
>>

The Trust's current credit facilities comprise US$218 million in senior
secured notes currently outstanding, a Cdn$800 million syndicated bank credit
facility, of which $452.3 million was outstanding at September 30, 2008 and a
Cdn$25 million demand working capital facility, of which $12.4 million was
outstanding at September 30, 2008. On April 15, 2008 ARC extended the credit
facility to April 2011 under the same terms. The credit facility syndicate
includes 11 domestic and international banks. The Trust's debt agreements
contain a number of covenants all of which were met as at September 30, 2008;
these agreements are available at www.SEDAR.com. The major financial covenants
are described below:

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

As at September 30, 2008 ARC has approximately $270 million of unused
credit available, net of the working capital deficiency (before risk
management contracts and the current portion of future income tax), under its
bank credit facility and the ability to issue an additional US$100 million of
long-term notes under an agreement with one lender. This option, which will
expire in May 2009, would allow the Trust to issue long-term notes at a rate
equal to the related U.S. treasuries corresponding to the term of the notes
plus an appropriate credit risk adjustment at the time of issuance.
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 the remainder of its 2008 capital program and 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 if so, will execute the most cost
effective and efficient means of financing its ongoing operations.

Unitholders' Equity

At September 30, 2008, there were 217.4 million trust units issued and
issuable for exchangeable shares, an increase of 4.2 million trust units from
December 31, 2007. The increase in number of trust units outstanding is mainly
attributable to the 3.7 million trust units issued pursuant to the DRIP during
the nine months of 2008 at an average price of $25.16 per unit. 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.
The Trust had two thousand rights outstanding as of September 30, 2008
under an employee plan where further rights issuances were discontinued in
2004. The rights are fully vested and may be exercised to purchase trust units
at an average adjusted exercise price of $10.33 per unit as at September 30,
2008. The rights will expire on or before December 31, 2008. During the first
nine months of 2008, the Trust issued 0.2 million units at an average price of
$17.37 per unit.

Distributions

ARC declared distributions of $171.3 million ($0.80 per unit),
representing 68 per cent of 2008 third quarter cash flow from operating
activities compared to distributions of $125 million ($0.60 per unit), and
representing 70 per cent of cash flow from operating activities in the third
quarter of 2007. The increase in the distributions was a reflection of the
increase in commodity prices year over year. Distribution levels are reviewed
regularly and revisions are approved at the discretion of the Board of
Directors.
The following items, outlined in Table 22, may be deducted from cash flow
from operating activities to arrive at distributions to unitholders: the
portion of capital expenditures that are funded with cash flow from operating
activities, an annual contribution to the reclamation funds, debt principal
repayments from time to time and income taxes that are not passed on to
unitholders.
Cash flow from operating activities and distributions in total and per
unit are detailed in Table 22 and Table 22a:

<<
Table 22
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
September 30 September 30
Cash flow from operating ($ millions) ($ per unit)
activities and % %
distributions 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 251.4 179.6 40 1.16 0.85 36
Net reclamation fund
(contributions)
withdrawals(1) (1.7) 6.1 (128) (0.01) (0.02) 50
Capital expenditures
funded with cash flow
from operating activities (78.4) (60.7) (29) (0.36) (0.24) (50)
Other(2) - - - 0.01 0.01 -
-------------------------------------------------------------------------
Distributions 171.3 125.0 37 0.80 0.60 33
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Table 22A
-------------------------------------------------------------------------
YTD September 30 YTD September 30
Cash flow from operating ($ millions) ($ per unit)
activities and % %
distributions 2008 2007 Change 2008 2007 Change
-------------------------------------------------------------------------
Cash flow from operating
activities 734.8 531.2 38 3.41 2.54 34
Net reclamation fund
(contributions)
withdrawals(1) (0.9) 4.5 (120) - (0.05) 100
Capital expenditures
funded with cash flow
from operating
activities (291.1) (163.5) (78) (1.35) (0.71) (90)
Other(2) - - - 0.02 0.02 -
-------------------------------------------------------------------------
Distributions 442.8 372.2 19 2.08 1.80 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit cash flow from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operating activities are based on weighted average outstanding trust
units in the year plus trust units issuable for exchangeable shares
at period-end.
>>

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

Environmental Legislation Impacting the Trust

On July 8, 2008 the Alberta government announced two new funds totaling
$4 billion to reduce greenhouse gas emissions. The province will create a
$2 billion fund to advance carbon capture and storage projects while a second
$2 billion fund will propel energy-saving public transit in Alberta. The Trust
is actively working to gain an understanding of how the carbon capture funds
will be allocated as it may allow the Trust access to additional funding for
its ongoing carbon capture and storage projects at Redwater and may increase
the possibility of achieving commercial viability of the CO(2) injection
program if proper infrastructure is put in place to capture and deliver CO(2)
to the Redwater area.
On February 19, 2008 the British Columbia government introduced a
consumer-based carbon tax. Effective July 1, 2008, ARC is required to pay tax
on all fuel used in the course of operations in that province. During the
third quarter, the Trust paid $0.1 million of carbon tax to the B.C.
Government.

Contractual Obligations and Commitments

The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments, sales commitments, royalty obligations, regulatory
fees, and lease rental obligations and employee agreements. These obligations
are of a recurring and consistent nature and impact the Trust's cash flows in
an ongoing manner. The Trust also has contractual obligations and commitments
that are of a less routine nature as disclosed in the following table.
Following is a summary of the Trust's contractual obligations and
commitments as at September 30, 2008:

<<
Table 23
-------------------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------------------
2009- 2011- There-
($ millions) 2008 2010 2012 after Total
-------------------------------------------------------------------------
Debt repayments(1) 18.8 44.7 507.4 124.8 695.7
Interest payments(2) 2.9 21.4 16.5 14.5 55.3
Reclamation fund contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase commitments 4.4 19.0 7.2 6.4 37.0
Operating leases 3.0 8.6 12.4 88.1 112.1
Derivative contract premiums(4) 3.2 3.0 - - 6.2
-------------------------------------------------------------------------
Total contractual obligations 38.1 106.9 552.4 305.7 1,003.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
>>

The risk management contract premiums noted in Table 23 are part of the
Trust's commitments related to its risk management program. In addition to
these premiums, the Trust has additional commitments related to its risk
management program that fluctuate based on market conditions. As the premiums
are part of the underlying risk management contract, they have been recorded
at fair market value at September 30, 2008 on the balance sheet as part of
risk management contracts.
The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At a given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2008 capital budget has
been approved by the Board. This commitment has not been disclosed in the
commitment table (Table 23) as it is of a routine nature and is part of normal
course of operations for active oil and gas companies and trusts.
The operating leases noted in Table 23 include amounts for the Trust's
head office lease. The current lease expires in May 2010. In December 2007,
the Trust entered into a 13 year lease commitment beginning in 2010 for office
space in a new building that is under construction in downtown Calgary. The
new lease commitment is reflected in Table 23. In addition to the lease
commitments included in Table 23, the Trust will incur additional costs to
design and construct the office space. No material commitments have been
entered into at this time, however the Trust has currently committed to costs
of less than $1 million for consulting costs related to the build out of the
office space.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the commitment table does not include any
commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table as
it is of a routine nature and is part of normal course of operations.

Off Balance Sheet Arrangements

The Trust has certain lease agreements, all of which are reflected in the
Contractual Obligations and Commitments table (Table 23), which were entered
into in the normal course of operations. All leases have been treated as
operating leases whereby the lease payments are included in operating expenses
or G&A expenses depending on the nature of the lease. No asset or liability
value has been assigned to these leases in the balance sheet as of September
30, 2008.

Critical Accounting Estimates

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

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

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

<<
Internal Controls over Financial Reporting and Disclosure Controls and
Procedures
>>

ARC is required to comply with Multilateral Instrument 52-109
"Certification of Disclosure in Issuers' Annual and Interim Filings",
otherwise referred to as Canadian SOX ("C-Sox"). The 2008 certificate requires
that the Trust disclose in the interim MD&A any changes in the Trust's
internal control over financial reporting that occurred during the period that
has materially affected, or is reasonably likely to materially affect the
Trust's internal control over financial reporting. The Trust confirms that no
such changes were made to the internal controls over financial reporting
during the first nine months of 2008.

Financial Reporting Update

Current Year Accounting Changes

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

A. Capital Disclosures

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

<<
B. Financial Instruments - Disclosures, Financial Instruments -
Presentation
>>

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

Future Accounting Changes

A. Goodwill and Intangible Assets

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

B. International Financial Reporting Standards ("IFRS")

In April 2008, the CICA published the exposure draft "Adopting IFRSs in
Canada". The exposure draft proposes to incorporate IFRSs 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 IFRSs. The Trust is currently reviewing the
standards to determine the potential impact on its consolidated financial
statements. At this time, the Trust has appointed internal staff to lead the
conversion project along with sponsorship from the senior leadership team. In
addition, an external advisor has been retained to assist the Trust in scoping
its conversion project.

Forward-Looking Statements

This discussion and analysis contains forward-looking statements as to
the Trust's internal projections, expectations or beliefs relating to future
events or future performance within the meaning of the "safe harbour"
provisions of the United States Private Securities Litigation Reform Act of
1995 and the Securities Act (Ontario). In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions and, in
particular, includes the material under the heading "2008 Guidance". These
statements represent management's expectations or beliefs concerning, among
other things, future operating results and various components thereof or the
economic performance of ARC Energy Trust ("ARC" or "the Trust"). The
projections, estimates and beliefs contained in such forward-looking
statements are based on management's assumptions relating to the production
performance of ARC's oil and gas assets, the cost and competition for services
throughout the oil and gas industry in 2008, the continuation of ARC's
historical experience with expenses and production, changes in the capital
expenditure budgets relating to undeveloped land or reserve acquisitions. and
the continuation of the current regulatory and tax regime in Canada, and
necessarily involve known and unknown risks and uncertainties, including the
business risks discussed in this MD&A, and related to management's assumptions
set forth herein, which may cause actual performance and financial results in
future periods to differ materially from any projections of future performance
or results expressed or implied by such forward-looking statements.
Accordingly, readers are cautioned that events or circumstances could cause
actual results to differ materially from those predicted. Other than the 2008
Guidance which is updated and discussed quarterly, the Trust does not
undertake to update any forward looking information in this document whether
as to new information, future events or otherwise except as required by
securities laws and regulations.

Additional Information

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

<<
QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit amounts) 2008 2007
-------------------------------------------------------------------------
FINANCIAL Q3 Q2 Q1 Q4

Revenue before royalties 485.7 512.0 407.9 338.0
Per unit(1) 2.24 2.38 1.91 1.59
Cash flow from operating
activities(2) 251.4 273.4 209.9 173.7
Per unit - basic(1) 1.16 1.27 0.98 0.82
Per unit - diluted 1.16 1.27 0.98 0.82
Net income 311.7 57.3 81.3 106.3
Per unit - basic(3) 1.46 0.27 0.39 0.51
Per unit - diluted 1.46 0.27 0.38 0.51
Distributions 171.3 144.7 126.8 125.8
Per unit - basic(4) 0.80 0.68 0.60 0.60
Total assets 3,687.5 3,664.3 3,592.6 3,533.0
Total liabilities 1,530.8 1,689.6 1,560.4 1,491.3
Net debt outstanding(5) 773.2 756.1 770.1 752.7
Weighted average trust
units(6) 216.6 215.2 213.8 212.5
Trust units outstanding and
issuable(6) 217.4 215.8 214.7 213.2
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 1.3 16.4 5.5 3.0
Land 18.6 57.8 28.8 42.6
Drilling and completions 91.4 32.6 64.4 75.2
Plant and facilities 24.2 24.1 11.6 17.9
Other capital 0.9 0.4 1.0 0.6
Total capital expenditures 136.4 131.3 111.3 139.3
Property acquisitions
(dispositions) net 13.1 0.3 10.1 5.0
Corporate acquisitions(7) - - - -
Total capital expenditures
and net acquisitions 149.5 131.6 121.4 144.3
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,509 27,541 29,064 28,682
Natural gas (mmcf/d) 192.0 194.7 204.3 187.4
Natural gas liquids (bbl/d) 3,822 3,906 3,856 4,067
Total (boe per day 6:1) 64,325 63,896 66,976 63,989
Average prices
Crude oil ($/bbl) 114.20 118.32 89.72 77.53
Natural gas ($/mcf) 8.68 10.41 7.80 6.32
Natural gas liquids ($/bbl) 82.87 82.29 68.54 62.75
Oil equivalent ($/boe) 81.42 87.73 66.67 57.26
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
unit prices
High 33.30 33.95 27.06 21.55
Low 22.33 25.19 20.00 18.90
Close 23.10 33.95 26.38 20.40
Average daily volume
(thousands) 841 659 863 624
-------------------------------------------------------------------------
-------------------------------------------------------------------------

QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit amounts) 2007 2006
-------------------------------------------------------------------------

FINANCIAL Q3 Q2 Q1 Q4
Revenue before royalties 300.2 305.6 307.8 292.5
Per unit(1) 1.42 1.46 1.48 1.42
Cash flow from operating
activities(2) 179.6 179.4 172.3 159.4
Per unit - basic(1) 0.85 0.86 0.83 0.77
Per unit - diluted 0.85 0.86 0.83 0.77
Net income 120.8 184.9 83.3 56.6
Per unit - basic(3) 0.58 0.90 0.41 0.28
Per unit - diluted 0.58 0.89 0.41 0.28
Distributions 125.0 124.1 123.1 122.3
Per unit - basic(4) 0.60 0.60 0.60 0.60
Total assets 3,460.8 3,432.8 3,540.1 3,479.0
Total liabilities 1,421.4 1,415.3 1,526.6 1,550.6
Net debt outstanding(5) 699.8 653.9 729.7 739.1
Weighted average trust
units(6) 210.9 209.5 207.9 206.5
Trust units outstanding and
issuable(6) 211.7 210.2 208.7 207.2
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 2.9 4.1 4.9 3.7
Land 33.0 1.7 0.2 11.8
Drilling and completions 73.4 25.8 55.1 79.1
Plant and facilities 21.1 16.3 16.8 26.5
Other capital 1.5 0.6 0.5 0.8
Total capital expenditures 131.9 48.5 77.5 121.9
Property acquisitions
(dispositions) net 27.3 10.0 0.2 76.4
Corporate acquisitions(7) - - - 16.6
Total capital expenditures
and net acquisitions 159.2 58.5 77.7 214.9
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,437 28,099 29,520 29,605
Natural gas (mmcf/d) 173.3 176.7 183.0 179.5
Natural gas liquids (bbl/d) 3,795 4,088 4,161 4,144
Total (boe per day 6:1) 61,108 61,637 64,175 63,663
Average prices
Crude oil ($/bbl) 73.40 65.21 60.79 58.26
Natural gas ($/mcf) 5.52 7.38 7.75 6.99
Natural gas liquids ($/bbl) 55.64 52.76 48.04 46.51
Oil equivalent ($/boe) 53.28 54.37 53.18 49.82
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
unit prices
High 22.60 23.86 23.02 29.22
Low 19.00 20.78 20.05 19.20
Close 21.17 21.74 21.25 22.30
Average daily volume
(thousands) 503 599 658 1,125
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) This is a GAAP measure and a change from the non-GAAP measure
reported in prior reports. Refer to non-GAAP section.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.

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

(Cdn$ millions) 2008 2007
-------------------------------------------------------------------------
ASSETS
Current assets
Cash $ - $ 7.0
Accounts receivable (Note 3) 172.8 162.5
Prepaid expenses 18.2 15.0
Risk management contracts (Notes 3 and 9) 9.8 13.1
Future income taxes 13.9 4.0
-------------------------------------------------------------------------
214.7 201.6
Reclamation funds (Note 4) 26.9 26.1
Risk management contracts (Notes 3 and 9) 15.5 4.7
Property, plant and equipment 3,272.8 3,143.0
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,687.5 $ 3,533.0
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 5) $ 217.0 $ 180.6
Distributions payable 51.5 42.1
Risk management contracts (Notes 3 and 9) 46.1 57.6
-------------------------------------------------------------------------
314.6 280.3
Risk management contracts (Notes 3 and 9) 14.2 28.2
Long-term debt (Note 6) 695.7 714.5
Accrued long-term incentive compensation
(Note 15) 17.5 12.1
Asset retirement obligations (Note 7) 143.1 140.0
Future income taxes 345.7 316.2
-------------------------------------------------------------------------
Total liabilities 1,530.8 1,491.3
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 16)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 10) 42.7 43.1

UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 2,570.2 2,465.7
Contributed surplus (Note 14) - 1.7
Deficit (Note 12) (458.4) (465.9)
Accumulated other comprehensive income
(loss) (Note 12) 2.2 (2.9)
-------------------------------------------------------------------------
Total unitholders' equity 2,114.0 1,998.6
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,687.5 $ 3,533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

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

Three Months Ended Nine Months Ended
(Cdn$ millions, except per September 30 September 30
unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
REVENUES
Oil, natural gas and
natural gas liquids $ 485.7 $ 300.2 $ 1,405.6 $ 913.6
Royalties (88.8) (49.2) (252.8) (157.8)
-------------------------------------------------------------------------
396.9 251.0 1,152.8 755.8
(Loss) gain on risk
management contracts (Note 9)
Realized (34.3) 8.0 (108.5) 15.3
Unrealized 187.5 2.1 26.0 (8.0)
-------------------------------------------------------------------------
550.1 261.1 1,070.3 763.1
-------------------------------------------------------------------------

EXPENSES
Transportation 4.8 3.6 13.8 12.4
Operating 60.2 55.7 180.8 161.7
General and administrative 3.5 12.1 47.2 34.1
Provision for
non-recoverable
accounts receivable
(Note 3) - - 18.0 -
Interest on long-term
debt (Note 6) 7.8 8.6 24.9 27.7
Depletion, depreciation
and accretion 93.4 90.6 283.4 276.5
Loss (gain) on foreign
exchange 16.3 (25.7) 28.1 (66.2)
-------------------------------------------------------------------------
186.0 144.9 596.2 446.2
-------------------------------------------------------------------------

Gain on sale of investment - - - 13.3
Future income tax (expense)
recovery (48.4) 6.3 (17.8) 64.1
-------------------------------------------------------------------------
Net income before
non-controlling
interest 315.7 122.5 456.3 394.3
Non-controlling interest
(Note 10) (4.0) (1.7) (6.0) (5.3)
-------------------------------------------------------------------------
Net income $ 311.7 $ 120.8 $ 450.3 $ 389.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Deficit, beginning of
period $ (598.8) $ (442.2) $ (465.9) $ (463.2)
Distributions paid or
declared (Note 13) (171.3) (125.0) (442.8) (372.2)
-------------------------------------------------------------------------
Deficit, end of period
(Note 12) $ (458.4) $ (446.4) $ (458.4) $ (446.4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 11)
Basic $ 1.46 $ 0.58 $ 2.12 $ 1.88
Diluted $ 1.46 $ 0.58 $ 2.12 $ 1.88
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

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

Three Months Ended Nine Months Ended
(Cdn$ millions, except September 30 September 30
per unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------
Net income $ 311.7 $ 120.8 $ 450.3 $ 389.0

Other comprehensive income
(loss), net of tax
Loss on financial
instruments designated
as cash flow hedges(1) (0.8) (4.0) (2.8) (1.0)
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) (0.5) 0.8 (2.0) 0.2
Net unrealized (losses)
gains on available-
for-sale reclamation
funds' investments(4) (0.1) 0.2 (0.1) (0.2)
-------------------------------------------------------------------------
Other comprehensive (loss)
income (1.4) (3.0) 5.1 (1.0)
-------------------------------------------------------------------------
Comprehensive income $ 310.3 $ 117.8 $ 455.4 $ 388.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other
comprehensive income
(loss), beginning of
period 3.6 6.9 (2.9) -
Application of initial
adoption - - - 4.9
Other comprehensive (loss)
income (1.4) (3.0) 5.1 (1.0)
-------------------------------------------------------------------------
Accumulated other
comprehensive income, end
of period (Note 12) $ 2.2 $ 3.9 $ 2.2 $ 3.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Amounts are net of tax of $0.3 million for the three months ended
September 30, 2008 and net of tax of $1.0 million for the nine months
ended September 30, 2008 (net of tax of $1.3 million and
$0.4 million, respectively, for the three and nine months ended
September 30, 2007).
(2) Amount is net of tax of $3.6 million for the nine months ended
September 30, 2008.
(3) Amounts are net of tax of $0.2 million and $0.7 million,
respectively, for the three and nine months ended September 30, 2008
(net of tax of $0.4 and $0.1 million for the three and nine months
ended September 30, 2007).
(4) Nominal future income tax impact for the three and nine months ended
September 30, 2008 (nominal for the three and nine months ended
September 30, 2007).

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS(unaudited)
For the three and nine months ended September 30

Three Months Ended Nine Months Ended
September 30 September 30
(Cdn$ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 311.7 $ 120.8 $ 450.3 $ 389.0
Add items not involving
cash:
Non-controlling interest
(Note 10) 4.0 1.7 6.0 5.3
Future income tax
expense (recovery) 48.4 (6.3) 17.8 (64.1)
Depletion, depreciation
and accretion 93.4 90.6 283.4 276.5
Non-cash (gain) loss on
risk management
contracts (Note 9) (187.5) (2.1) (26.0) 8.0
Non-cash loss (gain) on
foreign exchange 15.5 (25.7) 26.9 (66.5)
Non-cash trust unit
incentive compensation
(Notes 14 and 15) (6.9) 4.5 5.1 (0.1)
Gain on sale of investment - - - (13.3)
Expenditures on site
restoration and reclamation
(Note 7) (1.8) (2.7) (7.8) (14.6)
Change in non-cash working
capital (25.4) (1.2) (20.9) 11.0
-------------------------------------------------------------------------
251.4 179.6 734.8 531.2
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING
ACTIVITIES

(Repayment) issuance of
long-term debt under
revolving credit
facilities, net (6.6) 5.1 (45.6) 5.1
Issue of trust units 0.5 0.6 4.3 2.9
Cash distributions paid
(Note 13) (132.5) (97.9) (341.2) (289.3)
Payment of retention bonuses - (1.0) - (1.0)
Change in non-cash working
capital 1.7 1.5 1.1 1.3
-------------------------------------------------------------------------
(136.9) (91.7) (381.4) (281.0)
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING
ACTIVITIES
Acquisition of petroleum
and natural gas properties (13.1) (27.3) (23.6) (38.6)
Proceeds on disposition of
petroleum and natural gas
properties - - 0.2 1.2
Capital expenditures (137.6) (132.5) (378.0) (257.6)
Long-term investment - - - 33.3
Net reclamation fund
(contributions)
withdrawals (Note 4) (1.7) 6.1 (0.9) 4.5
Change in non-cash working
capital 37.9 30.8 41.9 4.2
-------------------------------------------------------------------------
(114.5) (122.9) (360.4) (253.0)
-------------------------------------------------------------------------
(DECREASE) INCREASE IN
CASH - (35.0) (7.0) (2.8)
CASH, BEGINNING OF PERIOD - 35.0 7.0 2.8
-------------------------------------------------------------------------
CASH, END OF PERIOD $ - $ - $ - $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

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

1. SUMMARY OF ACCOUNTING POLICIES

The unaudited interim consolidated financial statements follow the
same accounting policies as the most recent annual audited financial
statements, except as highlighted in Note 2. The interim consolidated
financial statement note disclosures do not include all of those
required by Canadian generally accepted accounting principles
("GAAP") applicable for annual consolidated financial statements.
Accordingly, these interim consolidated financial statements should
be read in conjunction with the audited consolidated financial
statements included in the Trust's 2007 annual report.

2. NEW ACCOUNTING POLICIES

Current Year Accounting Changes

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

A. Capital Disclosures

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

B. Financial Instruments - Disclosures, Financial Instruments -
Presentation

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

These standards were adopted prospectively.

Future Accounting Changes

A. Goodwill and Intangible Assets

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

B. International Financial Reporting Standards ("IFRS")

3. FINANCIAL ASSETS AND CREDIT RISK

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

Receivables from oil and natural gas marketers are normally collected
on the 25th day of the month following production. The Trust
historically has not experienced any collection issues with its oil
and natural gas marketers. Joint venture receivables are typically
collected within one to three months of the joint interest billing
being issued to the partner. On July 22, 2008 a counterparty that
marketed a portion of the Trust's production filed for protection
under the Companies' Creditors Arrangement Act. The Trust's total
exposure to this counterparty is $30.6 million. Management believes
that some portion of the $30.6 million is collectible; however, the
final amount of the recovery is unknown. Management has recorded an
allowance for doubtful accounts of $18 million as at September 30,
2008. This amount will continue to be monitored at each reporting
date. The Trust's allowance for doubtful accounts was nil as at
December 31, 2007.

When determining whether amounts that are past due are collectable,
management assesses the creditworthiness and past payment history of
the partner/counterparty, as well as the nature of the past due
amount. ARC considers all amounts greater than 90 days to be past
due. As at September 30, 2008 $5 million of accounts receivable are
past due, other than as described above, all of which are considered
to be collectable.

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

In order to mitigate concentration of credit risk, the Trust reviews
counterparty exposure on a quarterly basis. The majority of the
credit exposure on accounts receivable at September 30, 2008 and
December 31, 2007 pertains to the revenue accrual for September 2008
and December 2007 production volumes, respectively. The Trust markets
its production to a variety of counterparties of which, at
September 30, 2008, no one counterparty accounts for more than 20 per
cent of the total exposure.

4. RECLAMATION FUNDS

---------------------------------------------------------------------
Balance,
beginning
of period $ 14.4 $ 11.7 $ 24.8 $ 6.1
Contributions 8.8 0.2 6.2 5.9
Reimbursed
expenditures(1) (8.0) (1.0) (17.5) (0.6)
Interest earned
on funds 0.6 0.3 1.1 0.3
Net unrealized
gains and
losses on
available-for-
sale sale
investments (0.1) - (0.2) -
---------------------------------------------------------------------
Balance, end of
period(2) $ 15.7 $ 11.2 $ 14.4 $ 11.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by the Trust due
to timing differences and discretionary reimbursements.
(2) As at September 30, 2008 the unrestricted reclamation fund held
$2.4 million in cash and cash equivalents ($1.5 million at
December 31, 2007), with the balance held in investment grade
assets.

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

5. FINANCIAL LIABILITIES AND LIQUIDITY RISK

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

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

---------------------------------------------------------------------
2 - 3 4 - 5 Beyond
($ millions) 1 year years years 5 years Total
---------------------------------------------------------------------
Accounts payable
and accrued
liabilities(1) 221.2 - - - 221.2
Distributions
payable 51.5 - - - 51.5
Risk management
contracts(2) 33.9 11.6 - - 45.5
Senior secured
notes and
interest 27.4 64.7 83.2 111.1 286.4
Revolving credit
facilities - 464.7 - - 464.7
Accrued long-term
incentive
compensation(1) - 50.2 - - 50.2
---------------------------------------------------------------------
Total financial
liabilities 334.0 591.2 83.2 111.1 1,119.5
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Liabilities under the Whole Trust Unit Incentive Plan represent
the total amount expected to be paid out on vesting.
(2) Amounts payable for the risk management contracts have been
included at their intrinsic value.

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

6. LONG-TERM DEBT

---------------------------------------------------------------------
September 30, December 31,
2008 2007
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility - Cdn$
denominated $ 286.9 $ 344.9
Syndicated credit facility - US$
denominated 165.4 154.1
Working capital facility(1) 12.4 -
Senior secured notes
5.42% US$ Note 79.5 74.1
4.94% US$ Note 19.1 17.8
4.62% US$ Note 66.2 61.8
5.10% US$ Note 66.2 61.8
---------------------------------------------------------------------
Total long-term debt outstanding $ 695.7 $ 714.5
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount borrowed under the working capital facility includes
$12.4 million of outstanding cheques in excess of bank balance.

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

The following are the significant financial covenants governing the
revolving credit facilities:

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

In the event that the Trust enters into a material acquisition
whereby the purchase price exceeds 10 per cent of the book value of
the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times, while the third covenant is increased
to 55 per cent for the subsequent six month period. As at
September 30, 2008, the Trust had $2.0 million in letters of credit
($4.8 million as at December 31, 2007), no subordinated debt, and was
in compliance with all covenants.

During the third quarter of 2008, the weighted-average effective
interest rate under the credit facility was 3.6 per cent (5.5 per
cent in 2007) and 4.0 per cent for the nine months ended
September 30, 2008 (5.5 per cent in 2007).

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

Amounts due under the working capital facility and the senior secured
notes in the next 12 months of $12.4 million and US$16.4 million,
respectively, have not been included in current liabilities as
management has the ability and intent to refinance this amount
through the syndicated credit facility. The fair value of senior
secured notes as at September 30, 2008 is $245.3 million
($226.1 million as at December 31, 2007), and is calculated as the
present value of principal and interest payments discounted at the
Trust's credit adjusted risk free rate.

The difference between interest paid and interest expense in 2008 and
2007 was nominal.

7. ASSET RETIREMENT OBLIGATIONS

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

---------------------------------------------------------------------
September 30, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of period $ 140.0 $ 177.3
Increase in liabilities relating to
development activities 1.6 3.8
Increase (decrease) in liabilities
relating to change in estimate 2.4 (34.4)
Settlement of liabilities during the period (7.8) (18.2)
Accretion expense 6.9 11.5
---------------------------------------------------------------------
Balance, end of period $ 143.1 $ 140.0
---------------------------------------------------------------------
---------------------------------------------------------------------

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

8. CAPITAL MANAGEMENT

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

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

The Trust manages the following capital:

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

When evaluating the Trust's capital structure, management's objective
is to limit net debt to less than 2.0 times annualized cash flow from
operating activities and 20 per cent of total capitalization. As at
September 30, 2008 the Trust's net debt to annualized cash flow from
operating activities ratio is 0.8 and its net debt to total
capitalization ratio is 13.3 per cent.

---------------------------------------------------------------------
($ millions except per unit and September 30, December 31,
per cent amounts) 2008 2007
---------------------------------------------------------------------
Long-term debt 695.7 714.5
Accounts payable and accrued liabilities 217.0 180.6
Distributions payable 51.5 42.1
Cash, accounts receivable and prepaid
expenses (191.0) (184.5)
---------------------------------------------------------------------
Net debt obligations(1) 773.2 752.7
---------------------------------------------------------------------

Trust units outstanding and issuable for
exchangeable shares (millions) 217.4 213.2
Trust unit price 23.10 20.40
---------------------------------------------------------------------
Market capitalization(1) 5,021.9 4,349.3
Net debt obligations(1) 773.2 752.7
---------------------------------------------------------------------
Total capitalization(1) 5,795.1 5,102.0
---------------------------------------------------------------------

Net debt as a percentage of total
capitalization 13.3% 14.8%
Net debt obligations to annualized cash flow
from operating activities 0.8 1.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Market capitalization, net debt obligations and total
capitalization as presented do not have any standardized meaning
prescribed by Canadian GAAP and therefore may not be comparable
with the calculation of similar measures for other entities.

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

Monthly distributions were decreased during the quarter from
$0.28/unit to $0.24/unit. The $0.04/unit decrease during the quarter
is a result of ongoing review in the context of commodity prices and
other factors. No current taxes have been paid by the Trust in the
nine months ended September 30, 2008.

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

9. MARKET RISK MANAGEMENT

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

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

Commodity price risk

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

ARC manages the risks associated with changes in commodity prices by
entering into a variety of risk management contracts (see risk
management contracts below). The following table illustrates the
effects of movement in commodity prices on net income due to changes
in the fair value of risk management contracts in place at
September 30, 2008. The sensitivity is based on a $20 increase and
$40 decrease in WTI and $2 increase and $2 decrease in AECO. The
commodity price assumptions are based on management's assessment of
reasonably possible changes in oil and natural gas prices that could
occur between September 30, 2008 and the Trust's next reporting date
(December 31, 2008).

---------------------------------------------------------------------
Increase in Decrease in
Commodity Price Commodity Price
---------------------------------------------------------------------
($ millions) Crude oil Natural gas Crude oil Natural gas
---------------------------------------------------------------------
Net income
(decrease)
increase (53.2) 1.8 45.0 1.3
---------------------------------------------------------------------
---------------------------------------------------------------------

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

Interest Rate Risk

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

If interest rates applicable to floating rate debt and interest rate
swaps were to have increased by 100 bps (1 per cent) it is estimated
that the Trust's net income for the nine months ended September 30,
2008 would decrease by $5.2 million, of which $2.6 million is the
result of increased interest expense and $2.6 million is due to the
change in fair value of risk management contracts in place at
September 30, 2008. An opposite change in interest rates will result
in an opposite impact on net income.

Foreign Exchange Risk

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

ARC has entered into certain risk management contracts to mitigate
these risks (see risk management contracts below). The following
table demonstrates the effect of exchange rate movement on net income
due to changes in the fair value of risk management contracts in
place at September 30, 2008 as well as the unrealized gain or loss on
revaluation of outstanding US$ denominated debt. The sensitivity is
based on a $0.25 Cdn$/US$ increase and $0.05 Cdn$/US$ decrease in the
foreign exchange rate.

---------------------------------------------------------------------
Cdn$/US$ Exchange Rate
---------------------------------------------------------------------
Increase in Decrease in
($ millions) Cdn$/US$ rate Cdn$/US$ rate
---------------------------------------------------------------------
Increase gain/decrease loss (increase
loss/decrease gain) on risk management
contracts 12.2 (3.8)
Increase gain/decrease loss (increase
loss/decrease gain) on foreign exchange (69.8) 14.0
---------------------------------------------------------------------
Net income (decrease) increase (57.6) 10.2
---------------------------------------------------------------------
---------------------------------------------------------------------

As with the other noted risk variables, the sensitivity is based on
management's assessment of reasonably possible changes in the foreign
exchange rate that could occur between September 30, 2008 and the
Trust's next reporting date (December 31, 2008). The results of the
sensitivity should not be considered to be predictive of future
changes in rates or performance.

Risk Management Contracts

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

Following is a summary of all risk management contracts in place as
at September 30, 2008 that do not qualify for hedge accounting:

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

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

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

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

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

---------------------------------------------------------------------
Foreign Exchange Contracts
---------------------------------------------------------------------
Notional Bought Sold
Volume Swap Put Put
Term Contract MM US$ Cdn$/US$ Cdn$/US$ Cdn$/US$
---------------------------------------------------------------------
Oct 08 - Dec 08 Swap 12.00 1.0150 - -
USD Option Contracts
Oct 08 - Dec 08 Put Spread 3.00 - 1.0750 1.0300
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
Financial Interest Rate Contracts (1)(2)

---------------------------------------------------------------------
Fixed
Principal Annual Spread on
Term Contract MM US$ Rate % 3 Mo. LIBOR
---------------------------------------------------------------------
Oct 08 - Apr 14 Swap 30.5 4.62 38 bps
Oct 08 - Apr 14 Swap 32.0 4.62 (25.5 bps)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Starting in 2009, the notional amount of the contracts decreases
annually until 2014. The Trust pays the floating interest rate
based on a three month LIBOR plus a spread and receives the fixed
interest rate.
(2) Starting in 2009, a mutual put exists where both parties have the
right to call on the other party to pay the then current mark-to-
market value of the contract.

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

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

---------------------------------------------------------------------
Financial Electricity Contracts(3)(4)
---------------------------------------------------------------------
Volume Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
Oct 08 - Dec 08 Swap 15.0 60.17
Jan 09 - Dec 09 Swap 15.0 59.33
Jan 10 - Dec 10 Swap 5.0 63.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) Contracted volume is based on a 24/7 term.
(4) Includes margin provision on 5MWh per year if contract value
exceeds $30 million. If exercised, a letter of credit would be
issued for values in excess of $30 million.

At September 30, 2008, the fair value of the contracts that were not
designated as accounting hedges was a loss of $38.6 million. The
Trust recorded a loss on risk management contracts of $82.5 million
in the statement of income for the nine months ended September 30,
2008 ($7.3 million gain in 2007). 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:

---------------------------------------------------------------------
September 30, September 30,
2008 2007
---------------------------------------------------------------------
Fair value, beginning of period $ (64.6) $ (8.7)
Fair value, end of period(1) (38.6) (16.7)
---------------------------------------------------------------------
Change in fair value of contracts in
the period 26.0 (8.0)
Realized (losses) gains in the period (108.5) 15.3
---------------------------------------------------------------------
(Losses)gains on risk management
contracts $ (82.5) $ 7.3
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $24.7 million at
September 30, 2008 ($15.3 million loss at September 30, 2007).

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

The Trust's electricity contracts are intended to manage price risk
on electricity consumption. A portion of the Trust's financial
electricity contracts were designated as effective accounting hedges
on their respective contract dates. A realized gain of $0.7 million
and $2.8 million for the three and nine months ended September 30,
2008 (gain of $1.2 million and $0.5 million respectively in 2007) has
been included in operating costs on these electricity contracts. The
unrealized fair value gain on these contracts of $3.6 million has
been recorded on the consolidated balance sheet at September 30, 2008
with the movement in fair value recorded in OCI, net of tax. The fair
value movement for the nine months ended September 30, 2008 amounts
to an unrealized loss of $0.4 million. Over the next 12 months
$2.3 million of the unrealized fair value gain is expected to be
recognized in income.

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:

---------------------------------------------------------------------
September 30, September 30,
2008 2007
---------------------------------------------------------------------
Fair value, beginning of period(1) $ (3.4) $ 7.0
Change in fair value of financial
electricity contracts (0.4) (1.2)
Change in fair value of treasury rate
lock contracts prior to de-designation (6.2) -
Reclassification of loss on treasury rate
lock contracts to net income 13.6 -
---------------------------------------------------------------------
Fair value, end of period(2) $ 3.6 $ 5.8
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes $7.4 million unrealized loss on treasury rate lock
contracts and $4 million unrealized gain on electricity
contracts.
(2) Intrinsic value of risk management contracts designated as
effective accounting hedges equals a gain of $3.6 million at
September 30, 2008 ($7.5 million gain at September 30, 2007).

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

10. EXCHANGEABLE SHARES
---------------------------------------------------------------------
September 30, December 31,
ARL EXCHANGEABLE SHARES (thousands) 2008 2007
---------------------------------------------------------------------
Balance, beginning of period 1,310 1,433
Exchanged for trust units(1) (188) (123)
---------------------------------------------------------------------
Balance, end of period 1,122 1,310
Exchange ratio, end of period 2.43068 2.24976
Trust units issuable upon conversion,
end of period 2,727 2,947
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first nine months of 2008, 187,767 ARL exchangeable
shares were converted to trust units at a weighted average
exchange ratio of 2.31764.

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

---------------------------------------------------------------------
September 30, December 31,
2008 2007
---------------------------------------------------------------------
Non-controlling interest, beginning of
period $ 43.1 $ 40.0
Reduction of book value for conversion to
trust units (6.4) (3.7)
Current period net income attributable to
non-controlling interest 6.0 6.8
---------------------------------------------------------------------
Non-controlling interest, end of period 42.7 43.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated earnings attributable to non-
controlling interest $ 40.1 $ 34.1
---------------------------------------------------------------------
---------------------------------------------------------------------

11. UNITHOLDERS' CAPITAL

---------------------------------------------------------------------
September 30, 2008 December 31, 2007
---------------------------------------------------------------------
Number of Number of
trust units trust units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning
of period 210,232 2,465.7 204,289 2,349.2
Issued on conversion of
ARL exchangeable
shares (Note 10) 440 6.4 261 3.7
Issued on exercise of
employee rights
(Note 14) 236 4.1 131 2.1
Distribution
reinvestment program 3,736 94.0 5,551 110.7
---------------------------------------------------------------------
Balance, end of period 214,644 2,570.2 210,232 2,465.7
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
---------------------------------------------------------------------
2008 2007 2008 2007
---------------------------------------------------------------------
Weighted average trust
units(1) 213.9 208.0 212.5 206.5
Trust units issuable on
conversion of exchangeable
shares(2) 2.7 2.9 2.7 2.9
Dilutive impact of rights(3) - 0.1 0.1 0.2
---------------------------------------------------------------------
Diluted trust units and
exchangeable shares 216.6 211.0 215.3 209.6
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Weighted average trust units exclude trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding
exchangeable shares at the period end exchange ratio.
(3) All outstanding rights were dilutive and therefore have been
included in the diluted unit calculation for both 2008 and 2007.

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

12. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE INCOME

The deficit balance is composed of the following items:

---------------------------------------------------------------------
September 30, December 31,
2008 2007
---------------------------------------------------------------------
Accumulated earnings $ 2,641.4 $ 2,191.1
Accumulated distributions (3,099.8) (2,657.0)
---------------------------------------------------------------------
Deficit $ (458.4) $ (465.9)
Accumulated other comprehensive income
(loss) 2.2 (2.9)
---------------------------------------------------------------------
Deficit and accumulated other
comprehensive income (loss) $ (456.2) $ (468.8)
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
September 30, December 31,
2008 2007
---------------------------------------------------------------------
Unrealized gains and losses on financial
instruments designated as cash flow
hedges $ 2.4 $ (2.8)
Net unrealized gains and losses on
available-for-sale reclamation funds'
investments (0.2) (0.1)
---------------------------------------------------------------------
Accumulated other comprehensive income
(loss), end of period $ 2.2 $ (2.9)
---------------------------------------------------------------------
---------------------------------------------------------------------

13. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
DISTRIBUTIONS

Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operating activities is
reduced by reclamation fund contributions including interest earned
on the funds, a portion of capital expenditures and, when applicable,
debt repayments. The portion of cash flow from operating activities
withheld to fund capital expenditures and to make debt repayments is
at the discretion of the Board of Directors.

---------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30 September 30
2008 2007 2008 2007
---------------------------------------------------------------------
Cash flow from operating
activities $ 251.4 $ 179.6 $ 734.8 $ 531.2
Deduct:
Cash withheld to fund
current period capital
expenditures (78.4) (60.7) (291.1) (163.5)
Net reclamation fund
(contributions)
withdrawals (1.7) 6.1 (0.9) 4.5
---------------------------------------------------------------------
Distributions(1) 171.3 125.0 442.8 372.2
Accumulated distributions,
beginning of period 2,928.5 2,406.2 2,657.0 2,159.0
---------------------------------------------------------------------
Accumulated distributions,
end of period $3,099.8 $2,531.2 $3,099.8 $2,531.2
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per unit(2) $ 0.80 $ 0.60 $ 2.08 $ 1.80
Accumulated distributions
per unit, beginning of
period $ 22.31 $ 19.83 $ 21.03 $ 18.63
Accumulated distributions
per unit, end of
period(3) $ 23.11 $ 20.43 $ 23.11 $ 20.43
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include accrued and non-cash amounts of $39 million
and $102 million for the three and nine months ended
September 30, 2008, respectively ($27 million and $83 million for
the same periods in 2007).
(2) Distributions per trust unit reflect the sum of the per trust
unit amounts declared monthly to unitholders.
(3) Accumulated distributions per unit reflect the sum of the per
trust unit amounts declared monthly to unitholders since the
inception of the Trust in July 1996.

14. TRUST UNIT INCENTIVE RIGHTS PLAN

A summary of the changes in rights outstanding under the plan for the
period ending September 30, 2008 is as follows:

---------------------------------------------------------------------
Weighted
Number of Average
Rights Exercise
(thousands) Price ($)
---------------------------------------------------------------------
Balance, beginning of period 238 8.50
Exercised 236 10.41
---------------------------------------------------------------------
Balance before reduction of exercise price 2 11.29
Reduction of exercise price(1) - (0.96)
---------------------------------------------------------------------
Balance, end of period 2 10.33
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The holder of the right has the option to exercise rights held at
the original grant price or a reduced exercise price.

Of the 3,013,569 rights issued on or after January 1, 2003 that were
subject to recording compensation expense, 357,999 rights have been
cancelled and 2,653,270 rights have been exercised to September 30,
2008.

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

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

15. WHOLE TRUST UNIT INCENTIVE PLAN

The following table summarizes the Restricted Trust Unit ("RTU") and
Performance Trust Unit ("PTU") movement for the nine months ended
September 30, 2008:
---------------------------------------------------------------------
Number of Number of
RTUs PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of period 746 903
Vested (193) (183)
Granted 414 353
Forfeited (41) (42)
---------------------------------------------------------------------
Balance, end of period 926 1,031
---------------------------------------------------------------------
---------------------------------------------------------------------

Non-cash compensation expense was based on the September 30, 2008
unit price of $23.10 ($21.17 at September 30, 2007), accrued
distributions, an average performance multiplier of 1.5 (1.6 at
September 30, 2007), and the estimated number of units to be issued
on maturity.

The change in the net accrued long-term incentive compensation
liability relating to the Whole Trust Unit Incentive Plan can be
reconciled as follows:
---------------------------------------------------------------------
September 30, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of period $ 30.3 $ 26.1
Change in net liabilities in the period
General and administrative expense 4.6 3.2
Operating expense 0.5 0.3
Property, plant and equipment 1.1 0.7
---------------------------------------------------------------------
Balance, end of period(1) $ 36.5 $ 30.3
---------------------------------------------------------------------
Current portion of liability 20.3 18.2
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 17.5 $ 12.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Includes $1.3 million of recoverable amounts recorded in accounts
receivable as at September 30, 2008 (nil for 2007).

16. COMMITMENTS AND CONTINGENCIES

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

---------------------------------------------------------------------
Payments Due by Period
---------------------------------------------------------------------
($ millions) 2008 2009-2010 2011-2012 Thereafter Total
---------------------------------------------------------------------
Debt repayments(1) 18.8 44.7 507.4 124.8 695.7
Interest
payments(2) 2.9 21.4 16.5 14.5 55.3
Reclamation fund
contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase
commitments 4.4 19.0 7.2 6.4 37.0
Operating leases 3.0 8.6 12.4 88.1 112.1
Derivative contract
premiums(4) 3.2 3.0 - - 6.2
---------------------------------------------------------------------
Total contractual
obligations 38.1 106.9 552.4 305.7 1,003.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.

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

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

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with a current enterprise value of approximately $4.4 billion.
The Trust expects full year 2008 oil and gas production to average
approximately 64,000 to 65,000 barrels of oil equivalent per day from six core
areas in western Canada. ARC Energy Trust trades on the TSX under the symbol
AET.UN and its exchangeable shares trade under the symbol ARX.

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

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

<<
ARC RESOURCES LTD.

John P. Dielwart,
President and Chief Executive Officer
>>

%SEDAR: 00001245E %CIK: 0001029509

For further information: Investor Relations, E-mail: ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free 1-888-272-4900, ARC Resources Ltd., 2100, 440 - 2nd Avenue S.W., Calgary, AB T2P 5E9, www.arcenergytrust.com