ARC Energy Trust announces fourth quarter and year-end 2008 results

CALGARY, Feb. 11 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC"
or "the Trust") announces the results for the fourth quarter and the year
ended December 31, 2008.

<<
Three Months Ended Twelve Months Ended
December 31 December 31
2008 2007 2008 2007
-------------------------------------------------------------------------
FINANCIAL
(Cdn$ millions, except per
unit and per boe amounts)
Revenue before royalties 300.8 338.0 1,706.4 1,251.6
Per unit(1) 1.38 1.59 7.90 5.95
Per boe 50.06 57.42 71.59 54.67
Cash flow from operating
activities(2) 209.4 173.7 944.4 704.9
Per unit(1) 0.96 0.82 4.37 3.35
Per boe 34.85 29.51 39.62 30.79
Net income 82.7 106.3 533.0 495.3
Per unit(3) 0.38 0.51 2.50 2.39
Distributions 127.2 125.8 570.0 498.0
Per unit(1) 0.59 0.60 2.67 2.40
Per cent of cash flow from
operating activities(2) 61 72 60 71
Net debt outstanding(4) 961.9 752.7 961.9 752.7
OPERATING
Production
Crude oil (bbl/d) 28,935 28,682 28,513 28,682
Natural gas (mmcf/d) 195.1 187.4 196.5 180.1
Natural gas liquids (bbl/d) 3,858 4,067 3,861 4,027
Total (boe/d) 65,313 63,989 65,126 62,723
Average prices
Crude oil ($/bbl) 56.26 77.53 94.20 69.24
Natural gas ($/mcf) 7.48 6.32 8.58 6.75
Natural gas liquids ($/bbl) 45.22 62.75 69.71 54.79
Oil equivalent ($/boe) 49.93 57.26 71.25 54.54
Operating netback ($/boe)
Commodity and other revenue
(before hedging)(5) 50.06 57.42 71.59 54.67
Transportation costs (0.86) (0.69) (0.80) (0.72)
Royalties (9.14) (10.46) (12.91) (9.59)
Operating costs (10.09) (9.64) (10.13) (9.54)
Netback (before hedging) 29.97 36.63 47.75 34.82
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TRUST UNITS
(millions)
Units outstanding, end
of period(6) 219.2 213.2 219.2 213.2
Weighted average units(7) 218.3 212.5 216.0 210.2
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TRUST UNIT TRADING STATISTICS
(Cdn$, except volumes) based
on intra-day trading
High 22.55 21.55 33.95 23.86
Low 15.01 18.90 15.01 18.90
Close 20.10 20.40 20.10 20.40
Average daily volume (thousands) 1,523 624 975 597
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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 fourth quarter of 2008 would be
$172.9 million ($0.79 per unit) and $936.5 million ($4.34 per unit)
year-to-date. Distributions as a percentage of Cash Flow would be
74 per cent for the fourth quarter of 2008 (61 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) For 2008, includes 1.1 million (1.3 million in 2007) exchangeable
shares exchangeable into 2.517 trust units (2.250 in 2007) each for
an aggregate 2.7 million (2.9 million in 2007) trust units.
(7) Includes trust units issuable for outstanding exchangeable shares at
period end.

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

- The Trust had record cash flow from operating activities of
$944.4 million ($4.37 per unit) for the full year of 2008 as compared
to $704.9 million ($3.35 per unit) in 2007. Record high oil prices
through the majority of the year and record annual production
contributed to the significant increase in cash flows during 2008.
While oil prices declined dramatically in the last quarter of 2008,
the annual average realized oil price was $94.20 per boe as compared
to $69.24 per boe in 2007. An increase in the Trust's natural gas
price also contributed to the increase in cash flows, along with an
increase in natural gas production for the year.

- Record production volumes for 2008 averaged 65,126 boe per day, a
four per cent increase over 2007 volumes, as a result of the Trust's
active drilling program and growth in gas production in the Dawson
area. Average daily production per unit has remained constant at
0.30 boe per one thousand units compared to 2007.

- During 2008, the Trust distributed $570 million ($2.67 per unit), a
record for the Trust. Monthly distribution amounts were revised
throughout 2008 in response to the unprecedented volatility in the
commodity price environment observed throughout the year where US$
West Texas Intermediate Crude Oil prices rose as high as
US$147.27 per barrel in July and declined as low as US$32.41 per
barrel in December. The Trust's fourth quarter distributions were
$127.2 million or $0.59 per unit. Subsequent to year-end, the Trust
further decreased monthly distributions to $0.12 per unit in light of
ongoing weak commodity prices and in order to provide the Trust with
a more appropriate balance between cash retained to fund ongoing
capital expenditures for the future benefit of unitholders and the
cash paid out monthly to unitholders.

- The Trust executed a $548.6 million capital expenditure program in
2008 that included the purchase of undeveloped land for
$122.4 million and $426.2 million of development activities. The
Trust drilled 178 net wells on operated properties with a 99 per cent
success rate. The 2008 capital expenditures were 91 per cent funded
by cash flow from operating activities and proceeds from the DRIP
program and the remaining portion was funded through debt.

- The Trust replaced 248 per cent of annual production with the
addition of 59.2 million barrels of oil equivalent ("mmboe") of
proved plus probable reserves in 2008. Total proved reserves
increased eight per cent to 243 mmboe and total proved plus probable
reserves increased 12 per cent to 322 mmboe relative to 2007. The
Trust's all-in annual Finding, Development and Acquisition ("FD&A")
costs were $10.13 per boe before consideration of future development
capital ("FDC") for the proved plus probable reserves category. This
is a 47 per cent reduction from the $19 per boe FD&A cost realized in
2007. Including FDC, 2008 FD&A cost decreased 15 per cent to $17 per
boe compared to $20.03 per boe in 2007. This success has been
achieved through internal development of the Trust's existing asset
base. Additional information on the reserves evaluation can be found
in the "ARC Energy Trust Releases 2008 Year-end Reserves Information"
news release dated February 11, 2009 and filed on SEDAR at
www.sedar.com.

- With the recent global economic downturn and weak commodity price
environment, the Trust has been challenged with ensuring that
sufficient funds are available to fund the Trust's capital
expenditure program. The Trust has been disciplined and kept a strong
balance sheet with conservative debt levels when compared to cash
flow and total capitalization. In January 2009, the Trust completed
an equity offering of 15.5 million trust units for net proceeds of
$240 million that was used to reduce current indebtedness, freeing up
credit capacity to fund the 2009 capital budget which is currently
set at $450 million. The proceeds of the equity offering were
received on February 6, 2009 reducing debt levels to approximately
$645 million. The Trust is confident that it is well positioned to
capitalize on existing opportunities and proceed with growth and
expansion opportunities in 2009 and 2010.

- Montney Resource Play Development

During the fourth quarter at Dawson, the Trust spent $51.5 million on
exploration and development activities and a further $43 million on
the acquisition of crown land and lands from other industry
participants for a total of $94.5 million. Collectively, the land
acquisitions added 8.75 sections of highly prospective land in and
around our core Montney development areas, bringing our total land
holdings to 186 net sections of Montney rights in the Dawson area of
British Columbia. For the full year 2008, the Trust spent
$123.8 million on exploration and development activities,
$80.3 million on crown land purchases and $51 million on property
acquisitions from third parties consisting of predominantly
undeveloped land.

At the main Dawson field, ARC drilled two wells and completed nine
wells. With the completion of an NEB regulated sales gas pipeline in
mid November that transports ARC's production from Dawson to Alberta,
ARC was able to increase production during the fourth quarter to
46.5 mmcf per day, with peak rates above 50 mmcf per day. Further
production growth through the new NEB line is contingent upon the
completion of a third party compressor installation scheduled for the
first quarter of 2009. At year-end, the Trust had 12 vertical wells
and 3 horizontal wells waiting on tie-in.

ARC drilled a total of six wells on the West Montney exploratory
acreage during the fourth quarter, with two wells at Sunrise, two
wells at Saturn and one each at Monias and Sundown. To the end of
2008, the Trust has drilled three horizontal wells and seven
vertical wells on the West Montney lands and completed two
horizontal and three vertical wells, including one well that was
drilled in 2007. The Trust plans on testing the remaining six wells
during 2009. The trust is evaluating the processing facility and
pipeline options required to bring this gas to market.

The Trust continues to work towards a first quarter 2010 completion
date for a new 60 mmcf per day gas plant for Dawson. Design work is
nearing completion, long-lead time items have been ordered and
public notification letters have been distributed. After the public
notification process is complete, the applications will be submitted
to the appropriate regulatory agencies.

- Enhanced Oil Recovery Initiatives

During the fourth quarter, the Trust spent $14.8 million on enhanced
oil recovery ("EOR") initiatives. The Redwater CO(2) pilot project is
well underway and on schedule. The Trust expects that it will take
until at least the first quarter of 2010 before it will know if the
pilot has been successful in increasing oil production. While the
pilot project may indicate enhanced recovery, the current outlook for
crude oil prices and the cost and availability of CO(2) may impact
the Trust's ability to achieve commercial viability for a full scale
EOR scheme.

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 February 10,
2009 and should be read in conjunction with the audited Consolidated Financial
Statements as at and for the year ended December 31, 2008, the audited
Consolidated Financial Statements and MD&A as at and for the year ended
December 31, 2007, the MD&A and the unaudited Consolidated Financial
Statements as at and for the periods ended March 31, 2008, June 30, 2008 and
September 30, 2008 as well as the Trust's Annual Information Form that is
filed on SEDAR at www.sedar.com.
The MD&A contains Non-GAAP measures and forward-looking statements and
readers are cautioned that the MD&A should be read in conjunction with the
Trust's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements"
included at the end of this MD&A.

Executive Overview

ARC Energy Trust ("ARC") is one of the top 20 producers of conventional
oil and gas in western Canada. ARC as at December 31, 2008 held interests in
excess of 18,600 wells with approximately 5,600 wells operated by ARC and the
remainder operated primarily by other major oil and gas companies. ARC's
production has averaged between 61,000 and 67,000 boe per day in each quarter
for the last three years. The total capitalization of ARC, which trades on the
Toronto Stock Exchange, as at December 31, 2008 was $5.4 billion as shown on
Table 23. Subsequent to year-end, the Trust completed an equity offering of
15.5 million units for net proceeds of $240 million bringing the total
capitalization to approximately $4 billion as at February 10, 2009.
ARC's objective as an energy company is to provide superior and
sustainable long-term returns to unitholders. Key attributes of the business
plan include:

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

- Pay a portion of cash flow to unitholders annually. Currently the
Trust distributes $0.12 per unit per month. The remainder of the cash
flow is used to fund reclamation costs, and a portion of capital
expenditures and land acquisitions. Since the Trust's inception in
July 1996 to December 31, 2008, the Trust has distributed
$3.3 billion or $23.70 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. Calculated on a boe basis, ARC's
normalized reserves per unit have increased from 1.40 to 1.42;
production per unit has decreased slightly from 0.31 to 0.29 while
the Trust has made distributions of $7.47 per unit or $1.6 billion
from January 1, 2006 through to December 31, 2008. Details of the
calculations for normalized production and reserves per unit are
provided in Table 1.

- The periodic acquisition of strategic 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.

- Reviewing our structure in order to optimize returns to investors
with the commencement of the trust taxation on January 1, 2011. ARC's
most likely course of action will be to convert to a corporation,
subject to unitholder approval.

- 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.

Table 1
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Per Trust Unit 2008 2007 2006
-------------------------------------------------------------------------
Normalized production per unit(1)(2) 0.29 0.30 0.31
Normalized reserves per unit(1)(3) 1.42 1.35 1.40
Distributions per unit $2.67 $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) Production per unit represents daily average production (boe) per
thousand trust units. Calculated based on daily average production
divided by the normalized weighted average trust units outstanding
including trust units issuable for exchangeable shares.
(3) Reserves per unit are calculated based on proved plus probable
reserves (boe) divided by period end trust units outstanding
including trust units issuable for exchangeable shares.
>>

The effectiveness of ARC's business plan can best be measured by
historical results as shown in Table 2. Commodity prices and the ongoing
economic crisis are significant factors in determining profitability and
market returns of the units. The successful execution of ARC's business plan
and operational successes, contributed to our 9.7 per cent annual return for
2008 despite the negative impact of external factors.

<<
Table 2
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Total Returns (1) Trailing Trailing Trailing
($ per unit except for per cent) One Year Three Year Five Year
-------------------------------------------------------------------------
Distributions per unit $ 2.67 $ 7.47 $ 11.26
Capital appreciation per unit $ (0.30) $ (6.39) $ 5.36
Total return per unit $ 2.37 $ 1.08 $ 16.62
Annualized total return per unit 9.7% 1.1% 17.9%
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(1) Calculated as at December 31, 2008.

2008 Review and 2009 Guidance

Table 3 is a summary of the Trust's 2009 Revised Guidance and a review of
2008 actual results compared to guidance:

Table 3
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2008 %
2008 Guidance Actual Change 2009 Guidance
-------------------------------------------------------------------------
Production (boe/d) 64,000-65,000 65,126 - 64,000-65,000
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 10.20 10.13 (1) 10.70
Transportation 0.80 0.80 - 1.15
G&A expenses(1) 2.75 2.57 (7) 2.80
Interest 1.50 1.38 (8) 1.85
Capital expenditures
($ millions) 530 548.6 4 450
Weighted average trust
units and units
issuable (millions)(2) 216 216 - 235
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(1) The components of the $2.80 per boe G&A guidance for the full year
are as follows: cash G&A - $1.80 per boe; cash component of LTIP -
$0.85 per boe; non-cash LTIP component - $0.15 per boe
(2) 2009 guidance for weighted average trust units has been revised to
include the 15.5 million trust units issued on February 6, 2009 under
the Trust's equity offering.

The 2009 Guidance provides unitholders with information of management's
expectations for results of operations for 2009. Readers are cautioned that
the 2009 Guidance may not be appropriate for other purposes.
Actual results for 2008 were in line with 2008 guidance with some minor
exceptions as follows:

- G&A expenses of $2.57 per boe were lower than guidance of $2.75 per
boe due primarily to the decrease in the trust unit price at year-end
which resulted in a lower non-cash LTIP expense of $0.05 per boe as
compared to the guidance amount of $0.15 per boe.

- Interest expense for 2008 was $1.38 as compared to guidance of
$1.50 due to lower short-term interest rates on the Trust's floating
rates debt. In addition, with record cash flow levels posted, the
Trust was able to cash fund a higher portion of capital expenditures
in the year.

- Capital expenditures exceeded guidance by $18.6 million due to
additional expenditures and crown land purchases incurred in the
Northern area during the fourth quarter of 2008.

2008 Annual Financial and Operational Results

Following is a discussion of ARC's 2008 annual financial and operating
results.

Financial Highlights

Table 4
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(Cdn $ millions, except
per unit and volume data) 2008 2007 % Change
-------------------------------------------------------------------------
Cash flow from operating activities 944.4 704.9 34
Cash flow from operating activities
per unit(1) 4.37 3.35 30
Net income 533.0 495.3 8
Net income per unit(2) 2.50 2.39 5
Distributions per unit(3) 2.67 2.40 11
Distributions as a per cent of cash
flow from operating activities 60 71 (15)
Average daily production (boe/d)(4) 65,126 62,723 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 boe in isolation may be
misleading.

Net Income

Net income in 2008 was $533 million ($2.50 per unit), an increase of $37.7
million from $495.3 million ($2.39 per unit) in 2007. While cash flow from
operating activities increased $239.5 million in 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 year as follows:

- The Trust recorded a $68 million unrealized gain on risk management
contracts, a $123.9 million increase compared to an unrealized loss
of $55.9 million for the same period of 2007. The unrealized gain was
attributed to the sharp decline in commodity prices at year-end.

- The Trust recorded an $88.5 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 2008 compared to a
non-cash gain of $69.6 million in 2007.

- The Trust recorded a non-cash provision for non-recoverable accounts
receivable of $32 million in 2008 ($nil in 2007) due primarily to a
provision of $30.6 million recorded for an account receivable from
one counterparty that marketed a portion of the Trust's production.
See section titled Provision for Non-recoverable Accounts Receivable
for details.

- The Trust recorded a $4.5 million future income tax recovery for 2008
compared to a $121.3 million recovery in 2007. The 2007 future income
tax recovery was attributed to a significant change in the
Trust's future tax rate that came into effect during the year as
compared to a small rate change in 2008.
>>

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

<<
Table 5
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Net income and Distributions
($ millions except per cent) 2008 2007 2006
-------------------------------------------------------------------------
Net income 533.0 495.3 460.1
Distributions 570.0 498.0 484.2
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Excess (Shortfall) (37.0) (2.7) (24.1)
Excess (Shortfall) as per cent
of net income (7%) (1%) (5%)
-------------------------------------------------------------------------
Cash flow from operating activities 944.4 704.9 734.0
Distributions as a per cent of cash
flow from operating activities 60% 71% 66%
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Cash Flow from Operating Activities

Cash flow from operating activities increased by 34 per cent in 2008 to
$944.4 million from $704.9 million in 2007. The increase in 2008 cash flow
from operating activities is detailed in Table 6.

Table 6
-------------------------------------------------------------------------
($ per
trust (%
($ millions) unit) variance)
-------------------------------------------------------------------------
2007 Cash flow from Operating Activities 704.9 3.35 -
-------------------------------------------------------------------------
Volume variance 51.5 0.25 7
Price variance 403.3 1.91 57
Cash losses on risk management contracts (89.8) (0.43) (13)
Royalties (88.3) (0.42) (13)
Expenses:
Transportation (2.6) (0.01) -
Operating(1) (23.5) (0.11) (3)
Cash G&A (14.2) (0.07) (2)
Interest 4.0 0.02 1
Realized foreign exchange loss (0.7) - -
Weighted average trust units - (0.12) -
Non-cash and other items(2) (0.2) - -
-------------------------------------------------------------------------
2008 Cash flow from Operating Activities 944.4 4.37 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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.

2009 Cash Flow from Operating Activities Sensitivity

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

Table 7
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Impact on Annual
Cash flow from operating activities(2)
-------------------------------------------------------------------------
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 48.55 $ 1.00 $ 0.04
Natural gas price (Cdn $AECO/mcf)(1) $ 5.95 $ 0.10 $ 0.02
Cdn$/US$ exchange rate 1.27 $ 0.01 $ 0.02
Interest rate on debt % 5.75 % 1.0 $ 0.02
Operational
Liquids production volume (bbl/d) 31,500 % 1.0 $ 0.03
Gas production volumes (mmcf/d) 195.0 % 1.0 $ 0.02
Operating expenses per boe $ 10.70 % 1.0 $ 0.01
Cash G&A and LTIP expenses per boe $ 2.65 % 10.0 $ 0.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Analysis does not include the effect of hedging contracts.
(2) Assumes constant working capital.

Production

Production volumes averaged 65,126 boe per day in 2008 compared to 62,723
boe per day in 2007 as detailed in Table 8. Late in the fourth quarter of
2007, the Trust brought on new production in both the Dawson and Pouce Coupe
areas, achieving exit production of 65,000 boe per day in December 2007 and
maintained that production level throughout the full year of 2008.

Table 8
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Production 2008 2007 % Change
-------------------------------------------------------------------------
Light & medium crude oil (bbl/d) 27,239 27,366 -
Heavy oil (bbl/d) 1,274 1,316 (3)
Natural gas (mmcf/d) 196.5 180.1 9
NGL (bbl/d) 3,861 4,027 (4)
-------------------------------------------------------------------------
Total production (boe/d)(1) 65,126 62,723 4
% Natural gas production 50 48 4
% Crude oil and liquids production 50 52 (4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>

Oil production decreased slightly to 27,239 boe per day from 27,366 boe
per day in 2007. Natural gas production was 196.5 mmcf per day in 2008, an
increase of nine per cent from the 180.1 mmcf per day produced in 2007. The
increased gas production was a result of the Trust's active drilling program
in the Dawson area and the completion of a third party operated gas plant.
The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During 2008, the Trust drilled 232 gross wells
(178 net wells) on operated properties; 138 gross oil wells, and 93 gross
natural gas wells with a 99 per cent success rate.
The Trust expects that 2009 full year production will be approximately
64,000 to 65,000 boe per day and that 191 gross wells (171 net wells) will be
drilled by ARC on operated properties with participation in an additional 112
gross wells to be drilled on the Trust's non-operated properties. The Trust
estimates that the 2009 drilling program will add sufficient production from
new wells to offset production declines on existing properties. The planned
capital expenditures will be continuously monitored in the context of the
current economic environment and will be revised as required.
Table 9 summarizes the Trust's production by core area:

<<
Table 9
-------------------------------------------------------------------------
2008
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,495 1,406 29.2 1,218
Northern AB & BC 22,469 5,318 93.7 1,534
Pembina & Redwater 13,707 9,495 19.7 936
S.E. AB & S.W. Sask. 9,701 985 52.2 11
S.E. Sask. & MB 11,754 11,309 1.7 162
-------------------------------------------------------------------------
Total 65,126 28,513 196.5 3,861
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
2007
Production Total Oil Gas NGL
Core Area(1) (boe/d) (bbl/d) (mmcf/d) (bbl/d)
-------------------------------------------------------------------------
Central AB 7,967 1,596 30.3 1,319
Northern AB & BC 19,797 5,773 74.8 1,552
Pembina & Redwater 13,703 9,474 19.2 1,034
S.E. AB & S.W. Sask. 10,040 1,044 53.9 10
S.E. Sask. & MB 11,216 10,795 1.9 112
-------------------------------------------------------------------------
Total 62,723 28,682 180.1 4,027
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 an historical high of $1.7 billion in 2008, $454.8
million higher than 2007 revenues of $1.3 billion. While oil volumes were
relatively unchanged year over year, the increase in realized oil prices
generated additional oil revenue of $258.3 million. Natural gas revenue
increased by $173.4 million, comprising a $120.6 million increase due to
higher prices realized in 2008 and a $52.8 million increase due to higher
volumes produced in 2008.
A breakdown of revenue is outlined in Table 10:

<<
Table 10
-------------------------------------------------------------------------
Revenue
($ millions) 2008 2007 % Change
-------------------------------------------------------------------------
Oil revenue 983.1 724.8 36
Natural gas revenue 616.8 443.4 39
NGL revenue 98.5 80.5 22
-------------------------------------------------------------------------
Total commodity revenue 1,698.4 1,248.7 36
Other revenue 8.0 2.9 176
Total revenue 1,706.4 1,251.6 36
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Commodity Prices Prior to Hedging

Table 11
-------------------------------------------------------------------------
2008 2007 % Change
-------------------------------------------------------------------------
Average Benchmark Prices
AECO gas ($/mcf)(1) 8.13 6.61 23
WTI oil (US$/bbl)(2) 99.66 72.37 38
Cdn$/US$ foreign exchange rate 1.05 1.06 (1)
WTI oil (Cdn$/bbl) 104.30 77.35 35
-------------------------------------------------------------------------
ARC Realized Prices Prior to Hedging
Oil ($/bbl) 94.20 69.24 36
Natural gas ($/mcf) 8.58 6.75 27
NGL ($/bbl) 69.71 54.79 27
-------------------------------------------------------------------------
Total commodity revenue before
hedging ($/boe) 71.25 54.54 31
Other revenue ($/boe) 0.34 0.13 162
Total revenue before hedging ($/boe) 71.59 54.67 31
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

Although oil prices achieved record highs throughout 2008, peaking in
July at US$147.27 per barrel for WTI and averaging US$99.66 per barrel for the
full year, the sharp decline in oil prices during the fourth quarter of 2008
has resulted in exit 2008 oil prices at their lowest level since 2002. The
full impact of the price decline will not be realized until the first quarter
of 2009. The average Cdn$/US$ foreign exchange rate was 1.05 for the full year
of 2008; however, a sharp decline in the fourth quarter resulted in the
Canadian dollar closing at 1.22 per U.S. dollar on December 31, 2008. The
negative correlation between the Canadian dollar and U.S. dollar denominated
West Texas Intermediate oil prices should lessen the impact on the Trust of
any future declines in the price of oil, however, crude oil prices have
remained depressed in the early part of 2009 and investors should expect that
revenues in 2009 will be significantly lower than those recorded in 2008.
The Trust's oil production consists predominantly of light and medium
crude oil while heavy oil accounts for less than five per cent of the Trust's
crude oil production. The realized price for the Trust's oil, before hedging,
increased 36 per cent to $94.20 from $69.24 for the full year of 2007.
Alberta AECO Hub natural gas prices, which are commonly used as an
industry reference, averaged $8.13 per mcf in 2008 compared to $6.61 per mcf
in 2007. ARC's realized gas price, before hedging, increased by 27 per cent to
$8.58 per mcf compared to $6.75 per mcf in 2007. ARC's realized gas price is
based on prices received at the various markets in which the Trust sells its
natural gas. ARC's natural gas sales portfolio consists of gas sales priced at
the AECO monthly index, the AECO daily spot market, eastern and mid-west
United States markets and a portion to aggregators.
Prior to hedging activities, ARC's total realized commodity price was
$71.59 per boe in 2008, a 31 per cent increase from the $54.67 per boe
received prior to hedging in 2007.

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 was revised in 2005 to maintain a significant
portion of upside price participation on production volumes.
Gain or loss on risk management contracts comprise realized and
unrealized gains or losses on risk management contracts that do not meet the
accounting definition requirements of an effective hedge, even though the
Trust considers all risk management contracts to be effective economic hedges.
Accordingly, gains and losses on such contracts are shown as a separate
category in the statement of income.
Strong commodity prices throughout most of 2008 had a significant impact
on the Trust's revenue; however, these strong prices resulted in realized cash
losses of $67.8 million and $11.4 million for the Trust's oil and natural gas
risk management contracts, respectively.
During 2008, the Trust recorded a $16.2 million realized cash gain due
primarily to the unwinding of foreign exchange risk management contracts,
which had locked in the foreign exchange rates on future principal debt
repayments of US$127.2 million at an average rate of (1.02 Cdn$/US$).
Conversely, the Trust recorded a net cash loss of $12.7 million on its
interest rate risk management contracts. Included in this balance is a loss of
$13.6 million related to treasury lock contracts that were unwound in the
first quarter of 2008.
ARC's 2008 results include an unrealized total mark-to-market gain of $68
million with a net unrealized mark-to-market gain position of $6.7 million as
at December 31, 2008. The mark-to-market values represent the market price to
buy-out the Trust's contracts as of December 31, 2008 and may be different
from what will eventually be realized.
Table 12 summarizes the total gain (loss) on risk management contracts
for the year-over-year change as of the 2008 year-end:

<<
Table 12
-------------------------------------------------------------------------
Risk Management Contracts Crude Oil Natural Foreign
($ millions) & Liquids Gas Currency Power
-------------------------------------------------------------------------
Realized cash gain (loss)
on contracts(1) (67.8) (11.4) 16.2 -
Unrealized gain (loss)
on contracts(2) 50.7 12.4 (2.6) 3.0
-------------------------------------------------------------------------
Total gain (loss) on risk
management contracts (17.1) 1.0 13.6 3.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

--------------------------------------------------------------
Risk Management Contracts 2008 2007
($ millions) Interest Total Total
--------------------------------------------------------------
Realized cash gain (loss)
on contracts(1) (12.7) (75.7) 14.1
Unrealized gain (loss)
on contracts(2) 4.5 68.0 (55.9)
--------------------------------------------------------------
Total gain (loss) on risk
management contracts (8.2) (7.7) (41.8)
--------------------------------------------------------------
--------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.

The Trust currently limits the amount of forecast production that can be
hedged to a maximum 50 per cent with the remaining 50 per cent of production
being sold at market prices. The following table is an indicative summary of
the Trust's positions for crude oil, natural gas and related foreign exchange
for the next twelve months as at December 31, 2008.

Table 13
-------------------------------------------------------------------------
Hedge Positions
As at December 31, 2008(1)(2)
Q1 2009 Q2 2009
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call - - - -
Bought Put 55.00 2,500 55.00 2,500
Sold Put 40.00 2,500 40.00 2,500
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 10.76 62,202 8.00 20,000
Bought Put 8.17 62,202 6.50 20,000
Sold Put 4.50 20,000 4.50 20,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Hedge Positions
As at December 31, 2008(1)(2)
Q3 2009 Q4 2009
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call - - - -
Bought Put 55.00 2,500 55.00 2,500
Sold Put 40.00 2,500 40.00 2,500
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 8.00 20,000 8.00 20,000
Bought Put 6.50 20,000 6.50 20,000
Sold Put 4.50 20,000 4.50 20,000
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) The prices and volumes noted above represents averages for several
contracts and the average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. Viewing the average price of a group of options is purely
for indicative purposes. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price. In addition to positions
shown here, ARC has entered into additional basis positions.
(2) Please refer to note 13 in the Notes to the Consolidated Financial
Statements for full details of the Trust's hedging positions as of
December 31, 2008.

Table 13 should be interpreted as follows using the first quarter 2009
natural gas hedges as an example. To accurately analyze the Trust's hedge
position, contracts need to be modeled separately as using average prices and
volumes may be misleading.
- If the market price is below $4.50, ARC will receive $8.17 less the
difference between $4.50 and the market price on 20,000 GJ per day.
For example if the market price is $4.45, the Trust will receive
$8.12 on 20,000 GJ per day.
- If the market price is between $4.50 and $8.17, ARC will receive
$8.17 on 62,202 GJ per day.
- If the market price is between $8.17 and $10.76, ARC will receive the
market price on 62,202 GJ per day.
- If the market price exceeds $10.76, ARC will receive $10.76 on 62,202
GJ per day.
>>

Operating Netbacks

The Trust's operating netback, before realized hedging gains and losses,
increased 37 per cent to $47.75 per boe in 2008 compared to $34.82 per boe in
2007. The increase in netbacks in 2008 is as a result of the significant
increase in revenue per boe that was partially offset by increased costs for
royalties, operating costs and transportation costs.
The Trust's 2008 netback, after realized hedging gains and losses,
decreased to $44.58 per boe as a result of losses recorded on the Trust's
crude oil and natural gas contracts during the year of $3.17 per boe compared
to a small gain of $0.62 per boe recorded in 2007 that increased the 2007
netback to $35.44 per boe.
The components of operating netbacks are summarized in Table 14:

<<
Table 14
-------------------------------------------------------------------------
Heavy 2008 2007
Netbacks Crude Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 94.97 77.85 8.58 69.71 71.25 54.54
Other revenue - - - - 0.34 0.13
-------------------------------------------------------------------------
Total revenue 94.97 77.85 8.58 69.71 71.59 54.67
Royalties (14.58) (8.41) (1.82) (19.58) (12.91) (9.59)
Transportation (0.14) (1.17) (0.24) - (0.80) (0.72)
Operating costs(1) (13.91) (11.63) (1.19) (8.22) (10.13) (9.54)
-------------------------------------------------------------------------
Netback prior to
hedging 66.34 56.64 5.33 41.91 47.75 34.82
Realized gain (loss)
on risk management
contracts (7.03) - (0.16) - (3.17) 0.62
-------------------------------------------------------------------------
Netback after
hedging 59.31 56.64 5.17 41.91 44.58 35.44
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
>>

Royalties as a percentage of pre-hedged commodity revenue net of
transportation were relatively unchanged at 18.2 per cent ($12.91 per boe) in
2008 compared to 17.8 per cent ($9.59 per boe) in 2007. The Trust's typical
royalty rate has been approximately 18 per cent on a consolidated basis. Going
forward into 2009, the Trust expects to see more volatility in the royalty
rates as a result of the Alberta Government's New Royalty Framework. See
Alberta Government New Royalty Framework.
Operating costs increased to $10.13 per boe compared to $9.54 per boe in
2007. Total operating costs increased $23.1 million, or 11 per cent in 2008.
The increased costs were in line with guidance and reflect the additional
costs associated with the approximately 300 new wells brought on stream during
2008. There is a high fixed operating cost component for the Trust's
properties resulting in a trend of increased operating costs on a per boe
basis as the properties' production declines over time. The Trust estimates
that full year 2009 operating costs will be approximately $250 million or
approximately $10.70 per boe based on annual production of approximately
64,000 to 65,000 boe per day. This includes a six per cent increase for costs
associated with new drills in 2009.

Alberta Government New Royalty Framework

On April 10, 2008, the Alberta Government announced revisions to the New
Royalty Framework ("Framework" or "NRF"). The Framework was legislated in
November 2008 and took effect on January 1, 2009.
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;
>>

Subsequent to legislation of the NRF, the Alberta Government introduced
the Transitional Royalty Plan ("TRP") in response to the anticipated decrease
in Alberta development activity resulting from the economic downturn and
declining commodity prices. The TRP offers reduced royalty rates for new wells
drilled on or after November 19, 2008 that meet certain depth criteria. The
TRP is in place for a maximum period of five years to December 31, 2013; all
wells will convert to the NRF on January 1, 2014. The TRP is an "elective
plan" whereby an election must be filed on an individual well basis to qualify
for the TRP. The Trust does not anticipate a significant benefit from the TRP
in 2009 as the majority of the Trust's wells converted to the NRF on January
1, 2009.
Approximately 65 per cent of the Trust's production is in Alberta;
consequently, the Framework will have a significant impact on the Trust's
Alberta and corporate royalty rates. The Trust has completed an assessment of
the Framework and has estimated that the Trust's average corporate royalty
rate will change from approximately 18 per cent of revenue in 2008 to between
17 and 26 per cent of revenue in 2009 depending upon commodity prices as
illustrated in Table 15.

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

-------------------------------------------------------------------------
Current Alberta royalty rate(2) 17.5% 17.5% 17.5% 17.5%
NRF Alberta royalty rate(3) 15.5% 20.0% 25.0% 29.0%
% increase (decrease) -
Alberta royalty rate (10)% 14% 43% 66%
-------------------------------------------------------------------------
Current Corporate royalty rate(2) 18.0% 18.0% 18.0% 18.0%
NRF Corporate royalty rate(3) 17.0% 20.0% 23.0% 26.0%
-------------------------------------------------------------------------
% increase (decrease) -
Corporate royalty rate (6)% 11% 28% 44%
-------------------------------------------------------------------------
Increase (decrease) in annual
Corporate royalties ($Millions) $(10.0) $15.0 $60.0 $125.0
-------------------------------------------------------------------------
Decrease (increase) annual
cash flow per unit $(0.05) $0.07 $0.27 $0.58
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 guidelines that are subject to
interpretation. Royalty rate includes Crown, Freehold and Gross
Override royalties for all jurisdictions in which the Trust operates.
>>

Table 16 illustrates provincial royalty rates following implementation of
the Framework in Alberta. At low prices, royalty rates will be lower in
Alberta, while at moderate to high prices royalty rates will be higher in
Alberta than in the Trust's other operating jurisdictions. Approximately 65
per cent of production comes from Alberta, 22 per cent from Saskatchewan and
11 per cent from British Columbia and one per cent from Manitoba. The Trust
will continue to evaluate projects on the basis of each province's fiscal
regime as well as technical merits and direct its future investment spending
to the most economically favorable projects.

<<
Table 16
-------------------------------------------------------------------------
Provincial Royalty Rates - New Royalty Framework
-------------------------------------------------------------------------
Edmonton posted oil (Cdn/$/bbl)(1) $40 $60 $80 $100
AECO natural gas (Cdn$/GJ)(1) $6 $6 $8 $10
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Current Alberta royalty rate(2) 17.5% 17.5% 17.5% 17.5%
-------------------------------------------------------------------------
NRF Alberta royalty rate(3) 15.5% 20.0% 25.0% 29.0%
-------------------------------------------------------------------------
Saskatchewan royalty rate(2) 20.7% 20.7% 20.7% 20.7%
-------------------------------------------------------------------------
British Columbia royalty rate(2) 23.5% 23.5% 23.5% 23.5%
-------------------------------------------------------------------------
Manitoba royalty rate(2) 17.4% 17.4% 17.4% 17.4%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Canadian dollar denominated prices before quality differentials.
(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 Trust completed an upgrade to its production accounting system in the
fourth quarter of 2008 to accommodate royalty calculations and reporting
requirements under the Framework effective January 1, 2009.

General and Administrative Expenses and Trust Unit Incentive Compensation

G&A net of overhead recoveries on operated properties increased seven per
cent to $38.8 million in 2008 from $36.3 million in 2007. Increases in G&A
expenses for 2008 were a result of increased staff costs based on a six per
cent increase in the staff levels on average in 2008 due to higher levels of
activity.
The Trust paid out $28.2 million under the Whole Trust Unit Incentive
Plan ("Whole Unit Plan") in 2008 compared to $12.7 million in 2007 ($21.3
million and $9.6 million of the payouts were allocated to G&A in 2008 and
2007, respectively, and the remainder to operating costs and property, plant
and equipment). The increase in payments during 2008 was a result of having
two different performance unit grants vest during the year as compared to only
one grant that vested in 2007. The next cash payments under the Whole Unit
Plan are scheduled to occur in March and September 2009.
Table 17 is a breakdown of G&A and trust unit incentive compensation
expense:

<<
Table 17
-------------------------------------------------------------------------
G&A and Trust Unit Incentive
Compensation Expense
($ millions except per boe) 2008 2007 % Change
-------------------------------------------------------------------------
G&A expenses 55.6 52.7 6
Operating recoveries (16.8) (16.4) 2
-------------------------------------------------------------------------
Cash G&A expenses before Whole Unit Plan 38.8 36.3 7
Cash Expense - Whole Unit Plan 21.3 9.6 122
-------------------------------------------------------------------------
Cash G&A expenses including Whole Unit Plan 60.1 45.9 31
-------------------------------------------------------------------------
Accrued compensation - Whole Unit Plan 1.1 3.2 (66)
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense 61.2 49.1 25
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense per boe 2.57 2.15 20
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $1.1 million ($0.05 per boe) was recorded in 2008
compared to $3.2 million ($0.14 per boe) in 2007. This non-cash amount relates
to estimated costs of the Whole Unit Plan to December 31, 2008.

Whole Unit Plan

In March 2004, the Board of Directors approved a new Whole Unit Plan to
replace the Rights Plan for new awards granted subsequent to the first quarter
of 2004. The new Whole Unit Plan results in employees, officers and directors
(the "plan participants") receiving cash compensation in relation to the value
of a specified number of underlying 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 18 shows the changes during the year of RTUs and PTUs outstanding:

<<
Table 18
-------------------------------------------------------------------------
Whole Unit Plan Total
(units in thousands and Number of Number of RTUs and
$ millions except per unit) RTUs PTUs PTUs
-------------------------------------------------------------------------
Balance, beginning of year 746 903 1,649
Granted in the year 403 352 755
Vested in the year (347) (252) (599)
Forfeited in the year (46) (44) (90)
-------------------------------------------------------------------------
Balance, end of year(1) 756 959 1,715
-------------------------------------------------------------------------
Estimated distributions to vesting date(2) 197 328 525
Estimated units upon vesting after
distributions 953 1,287 2,240
Performance multiplier(3) - 1.6 -
-------------------------------------------------------------------------
Estimated total units upon vesting 953 2,110 3,063
-------------------------------------------------------------------------
Trust unit price at December 31, 2008 $20.10 $20.10 $20.10
Estimated total value upon vesting 19.2 42.4 61.6
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on underlying units before performance multiplier and accrued
distributions.
(2) Represents estimated additional units to be issued equivalent to
estimated distributions accruing to vesting date.
(3) The performance multiplier only applies to PTUs and was estimated to
be 1.6 at December 31, 2008 based on an average for 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. Therefore, the expense recorded in the statement of income
fluctuates over time.
Table 19 is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier:

<<
Table 19
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
December 31, 2008 Performance multiplier
------------------------------
(units thousands and $ millions
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 953 953 953
PTUs - 1,287 2,575
-------------------------------------------------------------------------
Total units(1) 953 2,240 3,528
-------------------------------------------------------------------------
Trust unit price(2) $20.10 $20.10 $20.10
Trust unit distributions per month(2) $0.15 $0.15 $0.15
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting $19.2 $45.0 $70.9
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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 a
future trust unit price of $20.10 and $0.15 per trust unit
distributions based on the unit price and distribution levels in
place at December 31, 2008. Subsequent to year-end, the distribution
level decreased to $0.12 per trust unit.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in March
and September of each year and at that time is reflected as a
reduction of cash flow from operating activities.
>>

Due to the variability in the future payments under the plan, the Trust
estimates that between $19.2 million and $70.9 million will be paid out from
2009 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

The Trust recorded a provision for non-recoverable accounts receivable of
$32 million ($23.9 million net of tax) in 2008 (nil in 2007). In July 2008,
SemCanada Crude ("SemCanada"), a counterparty that marketed a portion of the
Trust's production filed for protection under the Companies' Creditors
Arrangement Act ("CCAA"). SemCanada's parent company had continuously rated as
investment grade credit by an external rating agency up until 10 days prior to
filing for credit protection in the United States. The Trust's total exposure
to SemCanada was $30.6 million. Due to uncertainty surrounding the ultimate
recoverable amount and expected timing of recovery, the Trust recorded a
provision for the full SemCanada receivable of $30.6 million in 2008. In
addition, the Trust recorded a provision of $1.4 million for six additional
counterparties that also filed for CCAA protection during 2008 or were
experiencing financial distress. The Trust's allowance for doubtful accounts
was $32 million as at December 31, 2008 (nil as at December 31, 2007).

Interest Expense

Interest expense decreased to $32.9 million in 2008 from $36.9 million in
2007 due to a decrease in short-term interest rates. As at December 31, 2008,
the Trust had $901.6 million of debt outstanding, of which $259.6 million was
fixed at a weighted average rate of 5.1 per cent and $642.2 million, including
the working capital facility, was floating at current market rates plus a
credit spread of 60 basis points. Fifty-five per cent (US $408.5 million) of
the Trust's debt is denominated in U.S. dollars.

Foreign Exchange Gains and Losses

The Trust recorded a loss of $89.4 million ($3.76 per boe) in 2008 on
foreign exchange transactions compared to a gain of $69.4 million ($3.03 per
boe) in 2007. These amounts include both realized and unrealized foreign
exchange gains and losses.
Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The volatility of the Canadian dollar during
the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain/loss impacts net income but
does not impact cash flow from operating activities as it is a non-cash
amount. From December 31, 2007 to December 31, 2008, the Cdn$/US$ exchange
rate has increased from 1.01 to 1.22 creating an unrealized loss of $90.8
million on U.S. dollar denominated debt.
Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements. Included in the 2008 realized foreign exchange gain was a gain of
$2.3 million relating, in part, to a repayment of US$6 million of debt in
October 2008. The debt was issued in 2002 when the Cdn$/US$ foreign exchange
rate was approximately 1.56 and strengthened considerably to 1.04 on repayment
in 2008.

Taxes

In 2008, a future income tax recovery of $4.5 million was included in
income compared to $121.3 million in 2007. The future income tax recovery in
2007 included the impact of a legislated reduction in the future corporate
income tax rates in the fourth quarter of 2007 whereby the Trust's expected
future corporate income tax rate decreased from 29.4 per cent to 25.8 per cent
after the rate reduction. In 2008, the Trust's expected future corporate
income tax rate decreased marginally, creating a recovery of $4.5 million for
the year.
At December 31, 2008, the Trust and the Trust's subsidiaries had tax
pools of approximately $2.1 billion. The tax pools consist of $1.8 billion of
tangible and intangible capital assets, $86.9 million of non-capital loss
carry-forwards that expire at various periods to 2026, and $213.1 million of
other tax pools. Included in the above tax basis are the Trust's tax pools of
approximately $590.2 million.
On June 22, 2007, the federal legislation (Bill C-52) implementing the
tax on publicly traded income trusts and limited partnerships (the "SIFT
Rules") received Royal Assent. The SIFT Rules are not expected to effect the
Trust until 2011 provided the Trust does not exceed the normal growth
guidelines announced by the Department of Finance. Subsequent to the Trust's
equity issuance that closed on February 6, 2009, the Trust may now increase
its equity by approximately $5.1 billion between now and 2011 without
exceeding the normal growth guidelines. The Trust does not anticipate that the
normal growth guidelines will impair the Trust's ability to annually replace
or grow reserves in the next two years as the guidelines allow sufficient
growth targets.
On February 26, 2008 the Minister of Finance 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, however it is different than the Provincial
tax component included in the SIFT Rules, which currently provide for a deemed
rate of 13 per cent. At December 31, 2008 the Trust has used the deemed 13 per
cent provincial rate to calculate its future income taxes as the proposed
legislation had not been issued for calculating the provincial rate. On
February 1, 2009 the Minister of Finance tabled a Notice of Ways and Means
that includes the proposed legislation for calculating the provincial tax
rate.
On November 28, 2008 the Minister of Finance introduced legislation to
facilitate the conversion of existing income trusts into corporations. In
general, the proposed legislation will permit a conversion to be tax deferred
for both the unitholders and the income trust. Due to Parliament being
prorogued on December 4, 2008 this proposed legislation essentially expired.
On February 1, 2009 the Minister of Finance tabled a Notice of Ways and Means
that includes the proposed legislation to facilitate the conversion of
existing income trusts into corporations.
Management and the Board of Directors continue to review the impact of
the SIFT Rules 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 to a corporation may be the most logical and tax
efficient alternative for ARC unitholders. ARC expects future technical
interpretations and details will further clarify the legislation. It is
expected that total income taxes payable on distributions in 2011, including
both corporate and personal income taxes, will remain approximately the same
as current levels and thus result in approximately the same after tax
distribution amount to Canadian investors. However, Canadian tax-deferred
investors (those holding their trust units in a tax-deferred vehicle such as
an RRSP, RRIF or pension plan) will realize a lower distribution amount in
2011 due to the introduction of corporate income taxes.
The corporate income tax rate applicable to 2008 is 29.5 per cent,
however the Trust and its subsidiaries did not pay any material cash income
taxes for fiscal 2008. Due to the Trust's structure, currently, both income
tax and future tax liabilities are passed on to the unitholders by means of
royalty payments made between ARC Resources and the Trust.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate decreased to
$15.88 per boe in 2008 from $16.23 per boe in 2007. The lower DD&A rate was
driven by an increase in the Trust's proved reserves.
A breakdown of the DD&A rate is summarized in Table 20:

<<
Table 20
-------------------------------------------------------------------------
DD&A Rate
($ millions except per boe amounts) 2008 2007 % Change
-------------------------------------------------------------------------
Depletion of oil & gas assets(1) 370.3 360.0 3
Accretion of asset retirement obligation(2) 9.3 11.5 (19)
-------------------------------------------------------------------------
Total DD&A 379.6 371.5 2
DD&A rate per boe 15.88 16.23 (2)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the PP&E balance and is being
depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
>>

Goodwill

The goodwill balance of $157.6 million arose as a result of the
acquisition of Star Oil and Gas in 2003. The goodwill balance was determined
based on the excess of total consideration paid plus the future income tax
liability less the fair value of the assets, for accounting purposes, acquired
in the transaction.
Accounting standards require that the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate that the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. The Trust has determined that there was no goodwill impairment as of
December 31, 2008.

Capital Expenditures and Net Acquisitions

Total capital expenditures, excluding acquisitions and dispositions,
totaled $548.6 million in 2008 compared to $397.2 million in 2007. This amount
was incurred on drilling and completions, geological, geophysical and
facilities expenditures, and undeveloped land. The $122.4 million purchase of
undeveloped land in 2008 increased the Trust's land holdings to 534,416 net
acres that will provide drilling opportunities and, if successful, incremental
future production and reserves.
In addition to capital expenditures on development activities, the Trust
completed net property acquisitions of $51 million in 2008 of which $48.6
million related to the acquisition of undeveloped land and is included in the
net acres quoted above.
Proved plus probable oil and gas reserves increased 12 per cent to 321.7
million boe at year-end 2008 as a result of the Trust's 2008 capital
expenditure program.
A breakdown of capital expenditures and net acquisitions is shown in
Table 21:

<<
Table 21
-------------------------------------------------------------------------
Capital Expenditures
($ millions) 2008 2007 % Change
-------------------------------------------------------------------------
Geological and geophysical 27.1 14.9 82
Drilling and completions 305.4 229.5 33
Plant and facilities 90.4 72.1 25
Undeveloped land purchased at
crown land sales 122.4 77.5 58
Other capital 3.3 3.2 3
-------------------------------------------------------------------------
Total capital expenditures before
net acquisitions 548.6 397.2 38
-------------------------------------------------------------------------
Producing property acquisitions(1) 1.4 47.1 (97)
Undeveloped land property acquisitions 53.5 - 100
Producing property dispositions(1) (0.2) (4.6) (96)
Undeveloped land property dispositions (3.7) - 100
-------------------------------------------------------------------------
Total capital expenditures and
net acquisitions 599.6 439.7 36
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.

Approximately 68 per cent of the $548.6 million capital program was
financed with cash flow from operating activities in 2008 compared to 49 per
cent in 2007. Property acquisitions were financed through debt and working
capital.

Table 22
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
Devel- Net Total Devel- Net Total
opment Acquis- Expend- opment Acquis- Expend-
Capital itions itures Capital itions itures
-------------------------------------------------------------------------
Expenditures 548.6 51.0 599.6 397.2 42.5 439.7
-------------------------------------------------------------------------
Per cent funded by:
Cash flow from
operating activities 68% - 62% 49% - 44%
Proceeds from DRIP
and Rights Plan 23% - 21% 28% - 25%
Debt 9% 100% 17% 23% 100% 31%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>

ARC announced a $450 million capital expenditure budget for 2009 funding
a combination of annual production replacement and future growth development
including the development of a 60 mmcf per day gas plant in the Dawson area to
be operational in early 2010. The Trust will continually monitor the capital
expenditure program in the context of the current economic conditions and make
any necessary modifications to the planned expenditures as required.

Long-Term Investment

During the second quarter of 2007, the Trust sold its investment in the
shares of a private company that was involved in the acquisition of oil sands
leases. The transaction closed on June 25, 2007. The Trust recorded a cash
gain of $13.3 million with total proceeds of $33.3 million recorded as part of
cash flow from investing activities. The investment in the shares of the
private company was considered to be a related party transaction due to common
directorships of the Trust, the private company and the manager of a private
equity fund that held shares in the private company. In addition, certain
directors and officers of the Trust had minor direct and indirect
shareholdings in the private company.

Asset Retirement Obligation and Reclamation Fund

At December 31, 2008, the Trust recorded an Asset Retirement Obligation
("ARO") of $141.5 million ($140 million at December 31, 2007) for future
abandonment and reclamation of the Trust's properties. The estimated ARO
includes assumptions in respect of actual costs to abandon wells or reclaim
the property as well as annual inflation factors in order to calculate the
undiscounted total future liability. The undiscounted total future liability
was unchanged at $1.3 billion at December 31, 2008 and 2007. A significant
portion of the costs are projected to be incurred in years 2049 to 2059.
Included in the December 31, 2008 ARO balance was a $4.6 million increase
related to development activities in 2008 as well as minor changes in
management's estimate of the existing liabilities. The ARO liability was also
increased by $9.3 million for accretion expense in 2008 ($11.5 million in
2007) and was reduced by $12.4 million ($18.2 million in 2007) for actual
abandonment expenditures incurred in 2008.
As a result of the Redwater acquisition in December 2005, the Trust set
up a second reclamation fund (the "Redwater Fund") in 2006 to fund future
abandonment obligations attributed solely to the Redwater properties. The
Trust makes annual contributions to the Redwater fund and may utilize the
funds only for abandonment activities for the Redwater property. With the
addition of the Redwater Fund, the Trust now maintains two reclamation funds
that together held $28.2 million at December 31, 2008. Future contributions
for the two funds will vary over time in order to provide for the total
estimated future abandonment and reclamation costs that are to be incurred
upon abandonment of the Trust's properties. Minimum contributions to the
Redwater fund over the next 47 years will be approximately $91 million while
the main fund has no minimum contribution requirements.
In total, ARC contributed $11.7 million cash to its reclamation funds in
2008 ($12.1 million in 2007) and earned interest of $1.2 million ($1.4 million
in 2007) on the fund balances. The fund balances were reduced by $10.7 million
for cash-funded abandonment expenditures in 2008 ($18.1 million in 2007).
Under the terms of the Trust's investment policy, reclamation fund investments
and excess cash can only be invested in Canadian or U.S. Government
securities, investment grade corporate bonds, or investment grade short-term
money market securities.

Capitalization, Financial Resources and Liquidity

A breakdown of the Trust's capital structure is outlined in Table 23, as
at December 31, 2008 and 2007:

<<
Table 23
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per cent December 31, December 31,
and ratio amounts) 2008 2007
-------------------------------------------------------------------------
Net debt obligations(1) 961.9 752.7
Market value of trust units and exchangeable
shares(2) 4,405.9 4,349.3
-------------------------------------------------------------------------
Total capitalization(3) 5,367.8 5,102.0
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 17.9% 14.8%
Net debt to annualized YTD cash flow from
operating activities 1.0 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 December 31
including the total number of trust units issuable for exchangeable
shares at December 31 multiplied by the closing trust unit price of
$20.10 and $20.40 for 2008 and 2007, respectively.
(3) Total capitalization as presented does not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be
comparable with the calculation of similar measures for other
entities. Total capitalization is not intended to represent the total
funds from equity and debt received by the Trust.
>>

The Trust's current credit facilities comprise US$212 million in senior
secured notes currently outstanding, a Cdn$800 million syndicated bank credit
facility, of which $640.1 million was outstanding at December 31, 2008 and a
Cdn$25 million demand working capital facility, of which $2.1 million was
outstanding at December 31, 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 December 31, 2008;
these agreements are available at www.SEDAR.com. The major financial covenants
are described below:

<<
- Long-term debt and letters of credit not to exceed three times
annualized net income before non-cash items and interest expense;

- Long-term debt, letters of credit, and subordinated debt not to
exceed four times annualized net income before non-cash items and
interest expense; and

- Long-term debt and letters of credit not to exceed 50 per cent of the
book value of unitholders' equity and long-term debt, letters of
credit, and subordinated debt.
>>

As at December 31, 2008 ARC has approximately $300 million of unused
credit available: $160 million under its credit facility and the ability to
issue an additional US$113 million (Cdn$140 million) of long-term notes under
an agreement with one lender. This option, which will expire in May 2009,
unless renewed, 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.
The $240 million of net proceeds from the equity offering that closed on
February 6, 2009, were used to reduce outstanding indebtedness under the
Trust's credit facility (see Unitholders' Equity). This increased the Trust's
unused credit available to approximately $540 million including the option of
issuing US$113 million (Cdn$140 million) of U.S. dollar long-term notes.
As a result of the weakened global economic situation, the Trust along
with all other oil and gas entities will have restricted access to capital and
increased borrowing costs. Although the Trust's business and asset base have
not changed, the lending capacity of all financial institutions has been
diminished and risk premiums have increased. These issues will impact the
Trust as it reviews financing alternatives for the 2009 capital program,
assesses potential future acquisition opportunities and manages future cash
flow decremented by lower commodity prices and higher borrowing costs. The
Trust intends to finance its 2009 capital program with cash flow, existing
credit facilities, proceeds from the DRIP, potential asset dispositions and
new borrowings or equity if necessary. Beyond that, the Trust may need to
access additional capital and/or curtail capital expenditure plans and if so,
will execute the most cost effective and efficient means of financing its
ongoing operations.

Unitholders' Equity

At December 31, 2008, there were 219.2 million trust units issued and
issuable for exchangeable shares, an increase of six million trust units from
December 31, 2007. The increase in number of trust units outstanding is mainly
attributable to the 5.4 million trust units issued pursuant to the DRIP during
2008 at an average price of $22.61 per unit.
During 2008, the Trust issued 0.2 million trust units under the Trust
Unit Incentive Rights Plan ("the Rights Plan" for total proceeds of $4.2
million. At December 31, 2008 there were no rights outstanding as all rights
issued under the plan have been exercised or cancelled.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so at a
five per cent discount to the prevailing market price with no additional fees
or commissions. During 2008, the Trust raised proceeds of $123.2 million and
issued 5.4 million trust units pursuant to the DRIP.
On January 21, 2009 the Trust announced that it entered into an
agreement, on a bought deal basis, with a syndicate of underwriters for an
offering of 13.5 million trust units at $16.35 per trust unit, for gross
proceeds of $220 million as well as an over-allotment option to purchase, on
the same terms and conditions, up to an additional two million trust units.
This option was exercised, in whole prior to closing of the offering on
February 6, 2009. The gross proceeds raised under this offering were $253
million and proceeds net of underwriter and transaction fees were
approximately $240 million. The proceeds were used to reduce outstanding
indebtedness under the Trust's credit facility.

Distributions

ARC declared distributions of $570 million ($2.67 per unit), representing
60 per cent of 2008 cash flow from operating activities compared to
distributions of $498 million ($2.40 per unit) representing 71 per cent of
cash flow from operating activities in 2007.
As a result of the volatility of oil prices throughout 2008, the Trust
made several changes to the monthly distribution levels declared and paid to
unitholders. During the first seven months of 2008, oil prices soared to
record high amounts causing the Trust to increase monthly distributions to
$0.28 per unit in order to meet the Trust's objective of transferring tax
liabilities to unitholders and minimizing taxes paid by the Trust. In the
third quarter of 2008, oil prices decreased significantly causing the Trust to
reduce distributions to $0.15 per unit. Subsequent to year-end, the Trust
further decreased distributions to $0.12 per unit in light of the continued
weak commodity price environment.
The following items may be deducted from cash flow from operating
activities to arrive at distributions to unitholders:

<<
- The portion of capital expenditures that are funded with cash flow
from operating activities. In 2008, the Trust withheld 40 per cent of
2008 cash flow from operating activities to fund 68 per cent of the
capital program excluding acquisitions and to make contributions to
the reclamation funds. The remaining portion of capital expenditures
was financed by proceeds from the DRIP program and debt.

- An annual contribution to the reclamation funds, with $12.9 million
being contributed in 2008 including interest earned on the fund
balances. The reclamation funds are segregated bank accounts or
subsidiary trusts and the balances will be drawn on in future periods
as the Trust incurs abandonment and reclamation costs over the life
of its properties.

- Debt principal repayments from time to time as determined by the
board of directors. The Trust's current debt level is well within the
covenants specified in the debt agreements and, accordingly, there
are no current mandatory requirements for repayment. Refer to the
"Capital Structure and Liquidity" section of this MD&A for a detailed
review of the debt covenants.

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

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

- The Trust has certain obligations for future payments relative to
employee long-term incentive compensation. Presently, the Trust
estimates that $19.2 million to $61.6 million will be paid out
pursuant to such commitments in 2008 through 2010 subject to vesting
provisions and future performance of the Trust. These amounts will
reduce cash flow from operating activities and may in turn reduce
distributions in future periods.

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

Table 24
-------------------------------------------------------------------------
Cash flow from % %
operating activities 2008 2007 Change 2008 2007 Change
and distributions ($ millions) ($ per unit)
-------------------------------------------------------------------------
Cash flow from
operating
activities 944.4 704.9 34 4.37 3.35 30
Net reclamation fund
(contributions)
withdrawals(1) (2.2) 4.7 (147) (0.01) 0.02 (150)
Capital expenditures
funded with cash
flow from operating
activities (372.2) (211.6) 76 (1.72) (1.01) 70
Other(2) - - - 0.03 0.04 (25)
-------------------------------------------------------------------------
Distributions 570.0 498.0 14 2.67 2.40 12
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit cash flow from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operated activities are based on weighted average outstanding trust
units in the year plus trust units issuable for exchangeable shares
at year-end.

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

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

- To ensure that the Trust's financial flexibility is maintained by a
review of the Trust's debt to equity and debt to cash flow from
operating activities levels. The use of cash flow from operating
activities and proceeds from equity offerings to fund capital
development activities reduces the requirements of the Trust to use
debt to finance these expenditures. In 2008 the Trust funded
68 per cent of capital development activities with a portion of cash
flow from operating activities. Distributions and the actual amount
of cash flows withheld to fund the Trust's capital expenditure
program is dependent on the commodity price environment and is
subject to the approval and discretion of the Board of Directors.
>>

The actual amount of future monthly distributions is proposed by
management and is subject to the approval and discretion of the Board of
Directors. The Board reviews future distributions in conjunction with their
review of quarterly financial and operating results.
Monthly distributions for the first quarter of 2009 have been set at
$0.12 per unit subject to monthly review based on commodity price
fluctuations. Revisions, if any, to the monthly distribution are normally
announced on a quarterly basis in the context of prevailing and anticipated
commodity prices at that time.

Historical Distributions by Calendar Year

Table 25 presents distributions paid and payable for each calendar
period.

<<
Table 25
-------------------------------------------------------------------------
Calendar Year Distributions Taxable Portion Return of Capital
-------------------------------------------------------------------------
2009 YTD(2) 0.12 0.12 -
2008 2.67 2.62 0.05
2007 2.40 2.32 0.08
2006(1) 2.60 2.55 0.05
2005 1.94 1.90 0.04
2004 1.80 1.69 0.11
2003 1.78 1.51 0.27
2002 1.58 1.07 0.51
2001 2.41 1.64 0.77
2000 1.86 0.84 1.02
1999 1.25 0.26 0.99
1998 1.20 0.12 1.08
1997 1.40 0.31 1.09
1996 0.81 - 0.81
-------------------------------------------------------------------------
Cumulative $23.82 $16.95 $6.87
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Based on distributions paid and payable in 2006.
(2) Based on distributions declared at January 31, 2008 and estimated
taxable portion of 2008 distributions of 98 per cent.
>>

Please refer to the Trust's website at www.arcenergytrust.com for details
on 2008 monthly distributions and distribution dates for 2009.

Taxation of Distributions

Distributions comprise a return of capital portion (tax deferred) and a
return on capital portion (taxable). The return of capital component reduces
the cost basis of the trust units held. For 2008, distributions declared in
the calendar year will be 98 per cent return on capital or $2.62 per unit for
the year (taxable) and two per cent return of capital or $0.05 per unit for
the year (tax deferred). For a more detailed breakdown, please visit our
website at www.arcenergytrust.com.

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. Since July 1,
2008, the Trust paid approximately $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, and lease
rental obligations and employee agreements. These obligations are of a
recurring and consistent nature and impact the Trust's cash flows in an
ongoing manner. The Trust also has contractual obligations and commitments
that are of a less routine nature as disclosed in Table 26.

<<
Table 26
-------------------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------------------
2010- 2012-
($ millions) 2009 2011 2013 Thereafter Total
-------------------------------------------------------------------------
Debt repayments(1) 22.2 696.0 79.1 104.5 901.8
Interest payments(2) 12.8 22.2 15.4 10.0 60.4
Reclamation fund
contributions(3) 5.2 9.5 8.3 67.9 90.9
Purchase commitments 13.0 15.4 5.0 4.9 38.3
Transportation
commitments(4) - 14.9 21.9 21.0 57.8
Operating leases 7.0 9.8 14.3 81.8 112.9
Risk management
contract premiums(5) 19.3 - - - 19.3
-------------------------------------------------------------------------
Total contractual
obligations 79.5 767.8 144.0 290.1 1,281.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) Fixed payments for transporting production from the Dawson gas plant,
expected to be operational in early 2010.
(5) Fixed premiums to be paid in future periods on certain commodity risk
management contracts.
>>

The above noted risk management contract premiums are part of the Trust's
commitments related to its risk management program. In addition to the above
premiums, the Trust has commitments related to its risk management program. As
the premiums are part of the underlying risk management contract, they have
been recorded at fair market value at December 31, 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 2009 capital budget has
been approved by the Board at $450 million. This commitment has not been
disclosed in the commitment table (Table 26) as it is of a routine nature and
is part of normal course of operations for active oil and gas companies and
trusts.
The 2009 capital budget of $450 million includes $11 million for
leasehold development costs related to the Trust's new office space in
downtown Calgary. These costs will be incurred throughout 2009 with additional
costs to be incurred in 2010. The operating lease commitments for the new
space begin in the first quarter of 2010 and are included in Table 26.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the commitment table (Table 26) does not
include any commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table
(Table 26) 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 26), 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 December
31, 2008.

Fourth Quarter Financial and Operational Results

Strong operational results in the fourth quarter resulted in $209.5
million of cash flow from operating activities despite volatile commodity
prices and the global economic slow down during the fourth quarter. The Trust
successfully executed a $169.4 million capital development program that
contributed to quarterly average production of 65,313 boe per day. The Trust's
distributions were 61 per cent of cash flow from operating activities. The
remaining 39 per cent was used to fund $110.1 million of the fourth quarter
capital development program and make contributions to the reclamation funds.
The fourth quarter was an active one for the Trust with the drilling of 86
gross wells on operated properties. In total 52 natural gas wells and 33 oil
wells were drilled with a 99 per cent success rate.

<<
- As a result of the sharp decline in commodity prices during the
quarter, the Trust decreased monthly distributions to $0.15 in an
effort to preserve the Trust's cash available to fund future capital
programs. Total revenue decreased by $184.9 million in the fourth
quarter of 2008 as compared to the third quarter of 2008 despite
recording slightly higher production in the fourth quarter. The weak
commodity price environment has continued into 2009 and as a result,
the Trust decreased monthly distributions further to $0.12 per unit
in order to provide flexibility for financing the Trust's growth
development in the Montney in 2009.

- The Trust's fourth quarter production was 65,313 boe per day, an
increase of 1,324 boe per day from the fourth quarter of 2007 where
production was 63,989. The increased production is attributable, in
large part, to the development in the Dawson area in northeastern
British Columbia.

- The Trust spent $197 million on capital expenditures and net
acquisitions in the fourth quarter compared to $144.3 million in
2007. The Trust had a very active fourth quarter with the drilling of
86 gross wells (52 net wells) on operated properties with a 99 per
cent success rate. The Trust expanded its inventory of undeveloped
land acreage with the purchase of $38.8 million of land in the fourth
quarter. The land acquired was in core areas where the Trust has
identified strategic development opportunities.

- The fourth quarter netback before hedging decreased 18 per cent to
$29.97 per boe as compared to $36.63 for the same period of 2007. The
lower netback is largely attributed to the Trust's realized oil price
that decreased by 27 per cent in the fourth quarter of 2008 when
compared to the same period in 2007.

- Cash G&A expenses in the fourth quarter increased to $2.93 per boe as
compared to $1.96 for the same period in 2007. The majority of the
increase is attributable to a larger whole unit plan payment made in
October of 2008 that included PTUs granted in 2005. The 2007 October
payment was only RTUs as no PTUs were issued in October of 2004.

Table 27
-------------------------------------------------------------------------
Fourth Quarter Financial and Operational Highlights
(Cdn$ millions except per
unit and per cent) Q4 2008 Q4 2007 % Change
-------------------------------------------------------------------------
Production (boe/d) 65,313 63,989 2
Cash flow from operating
activities 209.4 173.7 21
Per unit $ 0.96 $ 0.82 17
Distributions 127.2 125.8 1
Per unit $ 0.58 $ 0.60 (3)
Per cent of cash flow from
operating activities 61 72 (15)
Net income 82.7 106.3 (22)
Per unit $ 0.38 $ 0.51 (25)
-------------------------------------------------------------------------
Prices
WTI (US$/bbl) 58.75 90.63 (35)
Cdn$/US$ exchange rate 1.21 1.02 19
Realized oil price (Cdn $/bbl) 56.26 77.53 (27)
AECO gas monthly index (Cdn $/mcf) 6.79 6.00 13
Realized gas price (Cdn $/mcf) 7.48 6.32 18
-------------------------------------------------------------------------
Operating netback ($/boe)
Revenue, before hedging 50.06 57.42 (13)
Royalties (9.14) (10.46) (13)
Transportation (0.86) (0.69) 25
Operating costs (10.09) (9.64) 5
Netback (before hedging) 29.97 36.63 (18)
Cash hedging gain (loss) 2.38 (0.20) 1,290
Netback (after hedging) $ 32.35 $ 36.43 (11)
-------------------------------------------------------------------------
Capital expenditures 169.4 139.3 22
Capital funded with cash flow from
operating activities (per cent) 65 32 103
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Critical Accounting Estimates

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

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

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

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

Disclosure Controls and Procedures

As of December 31, 2008, an internal evaluation was carried out of the
effectiveness of the Trust's disclosure controls and procedures as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in
Canada by National Instrument 52-109, Certification of Disclosure in Issuers'
Annual and Interim Filings. Based on that evaluation, the President and Chief
Executive Officer and the Senior Vice President Finance and Chief Financial
Officer concluded that the disclosure controls and procedures are effective to
ensure that the information required to be disclosed in the reports that the
Trust files or submits under the Exchange Act or under Canadian Securities
legislation is recorded, processed, summarized and reported, within the time
periods specified in the rules and forms therein. Disclosure controls and
procedures include, without limitation, controls and procedures designed to
ensure that the information required to be disclosed by the Trust in the
reports that it files or submits under the Exchange Act or under Canadian
Securities Legislation is accumulated and communicated to the Trust's
management, including the senior executive and financial officers, as
appropriate to allow timely decisions regarding the required disclosure.

Internal Control over Financial Reporting

Internal control over financial reporting is a process designed to
provide reasonable assurance that all assets are safeguarded, transactions are
appropriately authorized and to facilitate the preparation of relevant,
reliable and timely information. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements.
Management has assessed the effectiveness of the Trust's internal control over
financial reporting as defined in Rule 13a-15 under the US Securities Exchange
Act of 1934 and as defined in Canada by National Instrument 52-109,
Certification of Disclosure in Issuers' Annual and Interim Filings. The
assessment was based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Management concluded that the Trust's internal control over
financial reporting was effective as of December 31, 2008. The effectiveness
of the Trust's internal control over financial reporting as of December 31,
2008 has been audited by Deloitte & Touche LLP, as reflected in their report
for 2008. No changes were made to the Trust's internal control over financial
reporting during the year ending December 31, 2008, that have materially
affected, or are reasonably likely to materially affect, the internal controls
over financial reporting.

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 along with
sponsorship from the senior leadership team to review the impact of converting
to IFRS on the accounting policies, information and computer systems, internal
and disclosure controls, financial reporting in addition to the changes in the
Trust's financial statements. In addition, an external advisor has been
retained to assist the Trust in the conversion project.

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 utilize the GAAP measure cash flow from operating
activities instead of Cash Flow. 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 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.
At the time of writing this MD&A, substantially all revenues have been
collected for the production period of December 2008. Management performs
analysis on the amounts collected to ensure that the amounts accrued for
December 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, net asset value and total returns to analyze
financial and operating performance. Management feels that these KPIs and
benchmarks are key measures of profitability and overall sustainability for
the Trust. These KPIs and benchmarks as presented do not have any standardized
meaning prescribed by Canadian GAAP and therefore may not be comparable with
the calculation of similar measures for other entities.

Forward-looking Information and Statements

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

Additional Information

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

<<
ANNUAL HISTORICAL REVIEW
-------------------------------------------------------------------------
For the year ended December 31
(Cdn $ millions, except
per unit amounts) 2008 2007 2006 2005 2004
-------------------------------------------------------------------------
FINANCIAL
Revenue before royalties 1,706.4 1,251.6 1,230.5 1,165.2 901.8
Per unit(1) 7.90 5.95 6.02 6.10 4.85
Cash flow from operating
activities(2) 944.4 704.9 734.0 616.7 446.4
Per unit - basic(1) 4.37 3.35 3.59 3.23 2.40
Per unit - diluted 4.37 3.35 3.58 3.20 2.38
Net income 533.0 495.3 460.1 356.9 241.7
Per unit - basic(3) 2.50 2.39 2.28 1.90 1.32
Per unit - diluted 2.50 2.39 2.27 1.88 1.31
Distributions 570.0 498.0 484.2 376.6 330.0
Per unit(4) 2.67 2.40 2.40 1.99 1.80
Total assets 3,766.7 3,533.0 3,479.0 3,251.2 2,305.0
Total liabilities 1,624.6 1,491.3 1,550.6 1,415.5 755.7
Net debt outstanding(5) 961.9 752.7 739.1 578.1 264.8
Weighted average trust
units (millions)(6) 216.0 210.2 204.4 191.2 186.1
Trust units outstanding
and issuable at period
end (millions)(6) 219.2 213.2 207.2 202.0 188.8
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 27.1 14.9 11.4 9.2 5.4
Land 122.4 77.5 32.4 9.1 4.1
Drilling and completions 305.4 229.5 240.5 191.8 140.4
Plant and facilities 90.4 72.1 77.6 55.0 41.1
Other capital 3.3 3.2 2.6 3.7 2.8
Total capital expenditures 548.6 397.2 364.5 268.8 193.8
Property acquisitions
(dispositions), net 51.0 42.5 115.2 91.3 (58.2)
Corporate acquisitions(7) - - 16.6 505.0 72.0
Total capital expenditures
and net acquisitions 599.6 439.7 496.3 865.1 207.6
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,513 28,682 29,042 23,282 22,961
Natural gas (mmcf/d) 196.5 180.1 179.1 173.8 178.3
Natural gas liquids
(bbl/d) 3,861 4,027 4,170 4,005 4,191
Total (boe per day 6:1) 65,126 62,723 63,056 56,254 56,870
Average prices
Crude oil ($/bbl) 94.20 69.24 65.26 61.11 47.03
Natural gas ($/mcf) 8.58 6.75 6.97 8.96 6.78
Natural gas liquids
($/bbl) 69.71 54.79 52.63 49.92 39.04
Oil equivalent ($/boe) 71.25 54.54 53.33 56.54 43.13
-------------------------------------------------------------------------
RESERVES
(company interest)(8)
Proved plus probable
reserves
Crude oil and NGL
(mbbl) 153,020 158,341 162,193 163,385 123,226
Natural gas (bcf) 1,012.2 768.2 743.6 741.7 724.5
Total (mboe) 321,723 286,370 286,125 286,997 243,974
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day trading)
Unit prices
High 33.95 23.86 30.74 27.58 17.98
Low 15.01 18.90 19.20 16.55 13.50
Close 20.10 20.40 22.30 26.49 17.90
Average daily volume
(thousands) 975 597 706 656 420
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(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 quarters. 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.
(8) Company interest reserves are the gross interest reserves plus the
royalty interest prior to the deduction of royalty burdens.

QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except
per unit amounts) 2008
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 300.8 485.7 512.0 407.9
Per unit(1) 1.38 2.24 2.38 1.91
Cash flow from operating
activities(2) 209.4 251.4 273.4 209.9
Per unit - basic(1) 0.96 1.16 1.27 0.98
Per unit - diluted 0.96 1.16 1.27 0.98
Net income 82.7 311.7 57.3 81.3
Per unit - basic(3) 0.38 1.46 0.27 0.39
Per unit - diluted 0.38 1.46 0.27 0.38
Distributions 127.2 171.3 144.7 126.8
Per unit(4) 0.59 0.80 0.68 0.60
Total assets 3,766.7 3,687.5 3,664.3 3,592.6
Total liabilities 1,624.6 1,530.8 1,689.6 1,560.4
Net debt outstanding(5) 961.9 773.2 756.1 770.1
Weighted average trust units(6) 218.3 216.6 215.2 213.8
Trust units outstanding and
issuable(6) 219.2 217.4 215.8 214.7
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.7 1.3 16.4 5.5
Land 17.1 18.6 57.8 28.8
Drilling and completions 117.1 91.4 32.6 64.4
Plant and facilities 30.5 24.2 24.1 11.6
Other capital 1.0 0.9 0.4 1.0
Total capital expenditures 169.4 136.4 131.3 111.3
Property acquisitions
(dispositions) net 27.6 13.1 0.3 10.1
Total capital expenditures and
net acquisitions 197.0 149.5 131.6 121.4
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,935 28,509 27,541 29,064
Natural gas (mmcf/d) 195.1 192.0 194.7 204.3
Natural gas liquids (bbl/d) 3,858 3,822 3,906 3,856
Total (boe per day 6:1) 65,313 64,325 63,896 66,976
Average prices
Crude oil ($/bbl) 56.26 114.20 118.32 89.72
Natural gas ($/mcf) 7.48 8.68 10.41 7.80
Natural gas liquids ($/bbl) 45.22 82.87 82.29 68.54
Oil equivalent ($/boe) 49.93 81.42 87.73 66.67
-------------------------------------------------------------------------
TRUST UNIT TRADING (based on
intra-day trading)
Unit prices
High 22.55 33.30 33.95 27.06
Low 15.01 22.33 25.19 20.00
Close 20.10 23.10 33.95 26.38
Average daily volume (thousands) 1,523 841 659 863
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
(Cdn $ millions, except
per unit amounts) 2007
-------------------------------------------------------------------------
FINANCIAL Q4 Q3 Q2 Q1
Revenue before royalties 338.0 300.2 305.6 307.8
Per unit(1) 1.59 1.42 1.46 1.48
Cash flow from operating
activities(2) 173.7 179.6 179.4 172.3
Per unit - basic(1) 0.82 0.85 0.86 0.83
Per unit - diluted 0.82 0.85 0.86 0.83
Net income 106.3 120.8 184.9 83.3
Per unit - basic(3) 0.51 0.58 0.90 0.41
Per unit - diluted 0.51 0.58 0.89 0.41
Distributions 125.8 125.0 124.1 123.1
Per unit(4) 0.60 0.60 0.60 0.60
Total assets 3,533.0 3,460.8 3,432.8 3,540.1
Total liabilities 1,491.3 1,421.4 1,415.3 1,526.6
Net debt outstanding(5) 752.7 699.8 653.9 729.7
Weighted average trust units(6) 212.5 210.9 209.5 207.9
Trust units outstanding and
issuable(6) 213.2 211.7 210.2 208.7
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and geophysical 3.0 2.9 4.1 4.9
Land 42.6 33.0 1.7 0.2
Drilling and completions 75.2 73.4 25.8 55.1
Plant and facilities 17.9 21.1 16.3 16.8
Other capital 0.6 1.5 0.6 0.5
Total capital expenditures 139.3 131.9 48.5 77.5
Property acquisitions
(dispositions) net 5.0 27.3 10.0 0.2
Total capital expenditures and
net acquisitions 144.3 159.2 58.5 77.7
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 28,682 28,437 28,099 29,520
Natural gas (mmcf/d) 187.4 173.3 176.7 183.0
Natural gas liquids (bbl/d) 4,067 3,795 4,088 4,161
Total (boe per day 6:1) 63,989 61,108 61,637 64,175
Average prices
Crude oil ($/bbl) 77.53 73.40 65.21 60.79
Natural gas ($/mcf) 6.32 5.52 7.38 7.75
Natural gas liquids ($/bbl) 62.75 55.64 52.76 48.04
Oil equivalent ($/boe) 57.26 53.28 54.37 53.18
-------------------------------------------------------------------------
TRUST UNIT TRADING (based on
intra-day trading)
Unit prices
High 21.55 22.60 23.86 23.02
Low 18.90 19.00 20.78 20.05
Close 20.40 21.17 21.74 21.25
Average daily volume (thousands) 624 503 599 658
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(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.

CONSOLIDATED BALANCE SHEETS(unaudited)
As at December 31

(Cdn$ millions) 2008 2007
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents (Note 4) $ 40.0 $ 7.0
Accounts receivable (Note 5) 110.0 162.5
Prepaid expenses 16.8 15.0
Risk management contracts (Notes 5 and 13) 24.4 13.1
Future income taxes (Note 15) 3.9 4.0
-------------------------------------------------------------------------
195.1 201.6
Reclamation funds (Note 6) 28.2 26.1
Risk management contracts (Notes 5 and 13) 9.2 4.7
Property, plant and equipment (Note 7) 3,376.6 3,143.0
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,766.7 $ 3,533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 9) $ 194.4 $ 180.6
Distributions payable 32.5 42.1
Risk management contracts (Notes 5 and 13) 23.5 57.6
-------------------------------------------------------------------------
250.4 280.3
Risk management contracts (Notes 5 and 13) 3.4 28.2
Long-term debt (Note 10) 901.8 714.5
Accrued long-term incentive compensation (Note 21) 14.2 12.1
Asset retirement obligations (Note 11) 141.5 140.0
Future income taxes (Note 15) 313.3 316.2
-------------------------------------------------------------------------
Total liabilities 1,624.6 1,491.3
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 22)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 16) 42.4 43.1

UNITHOLDERS' EQUITY
Unitholders' capital (Note 17) 2,600.7 2,465.7
Contributed surplus (Note 20) - 1.7
Deficit (Note 18) (502.9) (465.9)
Accumulated other comprehensive income (loss)
(Note 18) 1.9 (2.9)
-------------------------------------------------------------------------
Total unitholders' equity 2,099.7 1,998.6
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,766.7 $ 3,533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
For the three and twelve months ended December 31

Three Months Ended Twelve Months Ended
(Cdn$ millions, except per December 31 December 31
unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------

REVENUES
Oil, natural gas and natural
gas liquids $ 300.8 $ 338.0 $ 1,706.4 $ 1,251.6
Royalties (54.9) (61.6) (307.7) (219.4)
-------------------------------------------------------------------------
245.9 276.4 1,398.7 1,032.2
Gain (loss) on risk management
contracts (Note 13)
Realized 32.8 (1.2) (75.7) 14.1
Unrealized 42.0 (47.9) 68.0 (55.9)
-------------------------------------------------------------------------
320.7 227.3 1,391.0 990.4
-------------------------------------------------------------------------

EXPENSES
Transportation 5.2 4.0 19.0 16.4
Operating 60.7 56.7 241.5 218.4
General and administrative 14.0 15.0 61.2 49.1
Provision for non-recoverable
accounts receivable (Note 5) 14.0 - 32.0 -
Interest on long-term debt
(Note 10) 8.1 9.2 32.9 36.9
Depletion, depreciation and
accretion (Notes 7 and 11) 96.2 95.0 379.6 371.5
Loss (gain) on foreign
exchange (Note 14) 61.2 (3.2) 89.4 (69.4)
-------------------------------------------------------------------------
259.4 176.7 855.6 622.9
-------------------------------------------------------------------------

Gain on sale of investment
(Note 8) - - - 13.3
Future income tax recovery
(Note 15) 22.3 57.2 4.5 121.3
-------------------------------------------------------------------------
Net income before
non-controlling interest 83.6 107.8 539.9 502.1
Non-controlling interest
(Note 16) (0.9) (1.5) (6.9) (6.8)
-------------------------------------------------------------------------
Net income $ 82.7 $ 106.3 $ 533.0 $ 495.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Deficit, beginning of period $ (458.4) $ (446.4) $ (465.9) $ (463.2)
Distributions paid or declared
(Note 19) (127.2) (125.8) (570.0) (498.0)
-------------------------------------------------------------------------
Deficit, end of period
(Note 18) $ (502.9) $ (465.9) $ (502.9) $ (465.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 17)
Basic $ 0.38 $ 0.51 $ 2.50 $ 2.39
Diluted $ 0.38 $ 0.51 $ 2.50 $ 2.39
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE INCOME (unaudited)
For the three and twelve months ended December 31

Three Months Ended Twelve Months Ended
(Cdn$ millions, except December 31 December 31
per unit amounts) 2008 2007 2008 2007
-------------------------------------------------------------------------

Net income $ 82.7 $ 106.3 $ 533.0 $ 495.3

Other comprehensive income
(loss), net of tax
Gains (losses) on financial
instruments designated as
cash flow hedges(1) 0.6 (6.4) (2.2) (7.4)
De-designation of cash flow
hedge(2) (Note 13) - - 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 13) (0.9) (0.5) (2.9) (0.3)
Net unrealized gains (losses)
on available-for-sale
reclamation funds'
investments(4) - 0.1 (0.1) (0.1)
-------------------------------------------------------------------------
Other comprehensive (loss)
income (0.3) (6.8) 4.8 (7.8)
-------------------------------------------------------------------------
Comprehensive income $ 82.4 $ 99.5 $ 537.8 $ 487.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other
comprehensive income (loss),
beginning of period 2.2 3.9 (2.9) -
Application of initial
adoption - - - 4.9
Other comprehensive (loss)
income (0.3) (6.8) 4.8 (7.8)
-------------------------------------------------------------------------
Accumulated other
comprehensive income (loss),
end of period (Note 18) $ 1.9 $ (2.9) $ 1.9 $ (2.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

(1) Amounts are net of tax of $0.2 million for the three months ended
December, 2008 and net of tax of $0.8 million for the twelve months
ended December 31, 2008 (net of tax of $2.4 million and $2.7 million,
respectively, for the three and twelve months ended December 31,
2007).
(2) Amount is net of tax of $3.6 million for the twelve months ended
December 31, 2008.
(3) Amounts are net of tax of $0.3 million and $1 million,
respectively, for the three and twelve months ended December 31, 2008
(net of tax of $0.2 and $0.1 million, respectively, for the three and
twelve months ended December 31, 2007).
(4) Nominal future income tax impact for the three and twelve months
ended December 31, 2008 (nominal for the three and twelve months
ended December 31, 2007).

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS(unaudited)
For the three and twelve months ended December 31

Three Months Ended Twelve Months Ended
December 31 December 31
(Cdn$ millions) 2008 2007 2008 2007
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING
ACTIVITIES
Net income $ 82.7 $ 106.3 $ 533.0 $ 495.3
Add items not involving cash:
Non-controlling interest
(Note 16) 0.9 1.5 6.9 6.8
Future income tax recovery
(Note 15) (22.3) (57.2) (4.5) (121.3)
Depletion, depreciation and
accretion (Notes 7 and 11) 96.2 95.0 379.6 371.5
Non-cash (gain) loss on
risk management contracts
(Note 13) (42.0) 47.9 (68.0) 55.9
Non-cash loss (gain) on
foreign exchange (Note 14) 61.6 (3.1) 88.5 (69.6)
Non-cash trust unit
incentive compensation
(recovery) expense (Note 21) (4.2) 3.6 1.0 3.5
Gain on sale of investment
(Note 8) - - - (13.3)
Expenditures on site
restoration and reclamation
(Note 11) (4.7) (3.6) (12.4) (18.2)
Change in non-cash working
capital 41.2 (16.7) 20.3 (5.7)
-------------------------------------------------------------------------
209.4 173.7 944.4 704.9
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING
ACTIVITIES
Issuance of long-term debt
under revolving credit
facilities, net 164.0 99.1 105.9 104.2
Repayment of senior secured
notes (7.1) (5.8) (7.1) (5.8)
Issue of trust units 0.5 0.8 4.9 3.7
Cash distributions paid
(Note 19) (117.6) (99.1) (458.8) (388.4)
Payment of retention bonuses - - - (1.0)
Change in non-cash working
capital (1.5) (0.9) (0.4) 0.4
-------------------------------------------------------------------------
38.3 (5.9) (355.5) (286.9)
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING
ACTIVITIES
Acquisition of petroleum and
natural gas properties (27.6) (5.1) (51.2) (43.7)
Proceeds on disposition of
petroleum and natural gas
properties - - 0.2 1.2
Capital expenditures (169.9) (138.9) (548.1) (396.5)
Long-term investment (Note 8) - - - 33.3
Net reclamation fund
(contributions) withdrawals
(Note 6) (1.3) 0.2 (2.2) 4.7
Change in non-cash working
capital 3.5 (17.0) 45.4 (12.8)
-------------------------------------------------------------------------
(195.3) (160.8) (555.9) (413.8)
-------------------------------------------------------------------------
INCREASE IN CASH AND CASH
EQUIVALENTS 52.4 7.0 33.0 4.2
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD (12.4) - 7.0 2.8
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $ 40.0 $ 7.0 $ 40.0 $ 7.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
December 31, 2008 and 2007
(all tabular amounts in Cdn$ millions, except per unit amounts)

1. STRUCTURE OF THE TRUST

ARC Energy Trust (the "Trust") was formed on May 7, 1996 pursuant to
a Trust indenture (the "Trust Indenture") that has been amended from
time to time, most recently on May 15, 2006. Computershare Trust
Company of Canada was appointed as Trustee under the Trust Indenture.
The beneficiaries of the Trust are the holders of the Trust units.

The Trust was created for the purposes of issuing trust units to the
public and investing the funds so raised to purchase a royalty in the
properties of ARC Resources Ltd. ("ARC Resources") and ARC Oil & Gas
Fund ("ARC Oil & Gas"). As part of an internal reorganization on
January 1, 2008 the properties of ARC Oil & Gas Fund were transferred
to ARC Resources and the royalty in the properties of ARC Oil & Gas
Fund was assigned to ARC Resources. The Trust Indenture was amended
on June 7, 1999 to convert the Trust from a closed-end to an open-
ended investment Trust. The current business of the Trust includes
the investment in all types of energy business-related assets
including, but not limited to, petroleum and natural gas-related
assets, gathering, processing and transportation assets. The
operations of the Trust consist of the acquisition, development,
exploitation and disposition of these assets and the distribution of
the net cash proceeds from these activities to the unitholders.

2. SUMMARY OF ACCOUNTING POLICIES

The Consolidated Financial Statements have been prepared by
management following Canadian generally accepted accounting
principles ("GAAP"). The preparation of financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingencies
at the date of the financial statements, and revenues and expenses
during the reporting year. Actual results could differ from those
estimated.

The amounts recorded for depreciation and depletion of petroleum and
natural gas property and equipment and for asset retirement
obligations are based on estimates of petroleum and natural gas
reserves and future costs. Estimates of reserves also provide the
basis for determining whether the carrying value of property, plant
and equipment is impaired. Accounts receivable are recorded at the
estimated net recoverable amount which involves estimates of
uncollectable accounts. Goodwill impairment tests involve estimates
of the Trust's fair value. By their nature, these estimates are
subject to measurement uncertainty, and the impact on the financial
statements of future periods could be material.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the
Trust and its subsidiaries. Any reference to "the Trust" throughout
these Consolidated Financial Statements refers to the Trust and its
subsidiaries. All inter-entity transactions have been eliminated.

Revenue Recognition

Revenue associated with the sale of crude oil, natural gas, and
natural gas liquids ("NGLs") owned by the Trust are recognized when
title passes from the Trust to its customers.

Transportation

Costs paid by the Trust for the transportation of natural gas, crude
oil and NGLs from the wellhead to the point of title transfer are
recognized when the transportation is provided.

Joint Interests

The Trust conducts many of its oil and gas production activities
through jointly controlled operations and the financial statements
reflect only the Trust's proportionate interest in such activities.

Depletion and Depreciation

Depletion of petroleum and natural gas properties and depreciation of
production equipment are calculated on the unit-of-production basis
based on:

(a) total estimated proved reserves calculated in accordance with
National Instrument 51-101, Standards of Disclosure for Oil and
Gas Activities;

(b) total capitalized costs, excluding undeveloped lands, plus
estimated future development costs of proved undeveloped
reserves, including future estimated asset retirement costs; and

(c) relative volumes of petroleum and natural gas reserves and
production, before royalties, converted at the energy equivalent
conversion ratio of six thousand cubic feet of natural gas to one
barrel of oil.

Unit Based Compensation

The Trust established a Trust Unit Incentive Rights Plan (the "Rights
Plan") for employees, independent directors and long-term consultants
who otherwise meet the definition of an employee of the Trust. The
exercise price of the rights granted under the Plan may be reduced in
future periods in accordance with the terms of the Plan. The Trust
accounts for the rights using the fair value method, whereby the fair
value of rights is determined on the date on which fair value can
initially be determined. The fair value is then recorded as
compensation expense over the period that the rights vest, with a
corresponding increase to contributed surplus. When rights are
exercised, the proceeds, together with the amount recorded in
contributed surplus, are recorded to unitholders' capital.

Whole Trust Unit Incentive Plan Compensation

The Trust has established a Whole Trust Unit Incentive Plan (the
"Whole Unit Plan") for employees, independent directors and long-term
consultants who otherwise meet the definition of an employee of the
Trust. Compensation expense associated with the Whole Unit Plan is
granted in the form of Restricted Trust Units ("RTUs") and
Performance Trust Units ("PTUs") and is determined based on the
intrinsic value of the Whole Trust Units at each period end. The
intrinsic valuation method is used as participants of the Whole Unit
Plan receive a cash payment on a fixed vesting date. This valuation
incorporates the year end Trust unit price, the number of RTUs and
PTUs outstanding at each period end, and certain management
estimates. As a result, large fluctuations, even recoveries, in
compensation expense may occur due to changes in the underlying trust
unit price. In addition, compensation expense is amortized and
recognized in earnings over the vesting period of the Whole Unit Plan
with a corresponding increase or decrease in liabilities.
Classification between accrued liabilities and accrued long-term
incentive compensation is dependent on the expected payout date.

The Trust charges amounts relating to head office employees to
general and administrative expense, amounts relating to field
employees to operating expense and amounts relating to geologists and
geophysicists to property, plant and equipment.

The Trust has not incorporated an estimated forfeiture rate for RTUs
and PTUs that will not vest. Rather, the Trust accounts for actual
forfeitures as they occur.

Cash Equivalents

Cash equivalents include short-term investments, such as money market
deposits or similar type instruments, with an original maturity of
three months or less when purchased.

Reclamation Funds

Reclamation funds hold investment grade assets and cash and cash
equivalents. Investments are categorized as either held-to-maturity
or available-for-sale assets, which are initially measured at fair
value. Held-to-maturity investments are subsequently measured at
amortized cost using the effective interest method. Available-for-
sale investments are subsequently measured at fair value with changes
in fair value recognized in other comprehensive income, net of tax.

Investments carried at amortized cost are subject to impairment
losses in the event of a non-temporary decline in market value.

Property, Plant and Equipment ("PP&E")

The Trust follows the full cost method of accounting. All costs of
exploring, developing and acquiring petroleum and natural gas
properties, including asset retirement costs, are capitalized and
accumulated in one cost centre as all operations are in Canada.
Maintenance and repairs are charged against earnings, and renewals
and enhancements that extend the economic life of the PP&E are
capitalized. Gains and losses are not recognized upon disposition of
petroleum and natural gas properties unless such a disposition would
alter the rate of depletion by 20 per cent or more.

Impairment

The Trust places a limit on the aggregate carrying value of PP&E,
which may be amortized against revenues of future periods.

Impairment is recognized if the carrying amount of the PP&E exceeds
the sum of the undiscounted cash flows expected to result from the
Trust's proved reserves. Cash flows are calculated based on third
party quoted forward prices, adjusted for the Trust's contract prices
and quality differentials.

Upon recognition of impairment, the Trust would then measure the
amount of impairment by comparing the carrying amounts of the PP&E to
an amount equal to the estimated net present value of future cash
flows from proved plus risked probable reserves. The Trust's risk-
free interest rate is used to arrive at the net present value of the
future cash flows. Any excess carrying value above the net present
value of the Trust's future cash flows would be recorded as a
permanent impairment and charged against net income.

The cost of unproved properties is excluded from the impairment test
described above and subject to a separate impairment test. In the
case of impairment, the book value of the impaired properties is
moved to the petroleum and natural gas depletable base.

Goodwill

The Trust must record goodwill relating to a corporate acquisition
when the total purchase price exceeds the fair value for accounting
purposes of the net identifiable assets and liabilities of the
acquired company. The goodwill balance is assessed for impairment
annually at year-end or as events occur that could result in an
indication of impairment. Impairment is recognized based on the fair
value of the reporting entity (consolidated Trust) compared to the
book value of the reporting entity. If the fair value of the
consolidated Trust is less than the book value, impairment is
measured by allocating the fair value of the consolidated Trust to
the identifiable assets and liabilities as if the Trust had been
acquired in a business combination for a purchase price equal to its
fair value. The excess of the fair value of the consolidated Trust
over the amounts assigned to the identifiable assets and liabilities
is the fair value of the goodwill. Any excess of the book value of
goodwill over this implied fair value of goodwill is the impairment
amount. Impairment is charged to earnings in the period in which it
occurs.

Goodwill is stated at cost less impairment and is not amortized.

Asset Retirement Obligations

The Trust recognizes an Asset Retirement Obligation ("ARO") in the
period in which it is incurred when a reasonable estimate of the fair
value can be made. On a periodic basis, management will review these
estimates and changes, if any, will be applied prospectively. The
fair value of the estimated ARO is recorded as a long-term liability,
with a corresponding increase in the carrying amount of the related
asset. The capitalized amount is depleted on a unit-of-production
basis over the life of the reserves. The liability amount is
increased each reporting period due to the passage of time and the
amount of accretion is charged to earnings in the period. Revisions
to the estimated timing of cash flows or to the original estimated
undiscounted cost would also result in an increase or decrease to the
ARO. Actual costs incurred upon settlement of the obligation are
charged against the ARO to the extent of the liability recorded.

Income Taxes

The Trust follows the liability method of accounting for income
taxes. Under this method, income tax liabilities and assets are
recognized for the estimated tax consequences attributable to
differences between the amounts reported in the financial statements
of the Trust and the Trust's corporate subsidiaries and their
respective tax base, using substantively enacted future income tax
rates. The effect of a change in income tax rates on future tax
liabilities and assets is recognized in income in the period in which
the change occurs, provided that the income tax rates are
substantively enacted. Temporary differences arising on acquisitions
result in future income tax assets and liabilities.

Basic and Diluted per Trust Unit Calculations

Basic net income per unit is computed by dividing the net income by
the weighted average number of trust units outstanding during the
period. Diluted net income per unit amounts are calculated based on
net income before non-controlling interest divided by dilutive trust
units. Dilutive trust units are arrived at by adding weighted average
trust units to trust units issuable on conversion of exchangeable
shares, and to the potential dilution that would occur if rights were
exercised at the beginning of the period. The treasury stock method
assumes that proceeds received from the exercise of in-the-money
rights and the unrecognized trust unit incentive compensation are
used to repurchase units at the average market price.

Financial Instruments

Financial assets, financial liabilities and non-financial derivatives
are measured at fair value on initial recognition. Measurement in
subsequent periods depends on whether the financial instrument has
been classified as held-for-trading, available-for-sale, held-to-
maturity, loans and receivables, or other financial liabilities.

a. Held-for-trading

Financial assets and liabilities designated as held-for-trading
are subsequently measured at fair value with changes in those fair
values charged immediately to earnings. With the exception of risk
management contracts that qualify for hedge accounting, the Trust
classifies all risk management contracts as held-for-trading. Cash
and cash equivalents are also classified as held-for-trading.

b. Available-for-sale assets

Available-for-sale financial assets are subsequently measured at
fair value with changes in fair value recognized in Other
Comprehensive Income ("OCI"), net of tax. Amounts recognized in
OCI for available-for-sale financial assets are charged to
earnings when the asset is derecognized or when there is an other
than temporary asset impairment.

c. Held-to-maturity investments, loans and receivables and other
financial liabilities

Held-to-maturity investments, loans and receivables, and other
financial liabilities are subsequently measured at amortized cost
using the effective interest method. The Trust classifies accounts
receivable to loans and receivables, and accounts payable,
distributions payable and long-term debt to other financial
liabilities.

Transaction costs are expensed as incurred for all financial
instruments.

The Trust has elected January 1, 2003 as the effective date to
identify and measure embedded derivatives in financial and non-
financial contracts that are not closely related to the host
contracts.

The Trust is exposed to market risks resulting from fluctuations in
commodity prices, foreign exchange rates and interest rates in the
normal course of operations. A variety of derivative instruments are
used by the Trust to reduce its exposure to fluctuations in commodity
prices, foreign exchange rates, and interest rates. The fair values
of these derivative instruments are based on an estimate of the
amounts that would have been received or paid to settle these
instruments prior to maturity. The Trust considers all of these
transactions to be effective economic hedges; however, most of the
Trust's contracts do not qualify or have not been designated as
effective hedges for accounting purposes.

For transactions that do not qualify for hedge accounting, the Trust
applies the fair value method of accounting by recording an asset or
liability on the Consolidated Balance Sheet and recognizing changes
in the fair value of the instruments in earnings during the current
period.

For derivative instruments that do qualify as effective accounting
hedges, policies and procedures are in place to ensure that the
required documentation and approvals are in place. This documentation
specifically ties the derivative financial instruments to their use,
and in the case of commodities, to the mitigation of market price
risk associated with cash flows expected to be generated. When
applicable, the Trust also identifies all relationships between
hedging instruments and hedged items, as well as its risk management
objective and the strategy for undertaking hedge transactions. This
would include linking the particular derivative to specific assets
and liabilities on the Consolidated Balance Sheet or to specific firm
commitments or forecasted transactions.

Where specific hedges are executed, the Trust assesses, both at the
inception of the hedge and on an ongoing basis, whether the
derivative used in the particular hedging transaction is effective in
offsetting changes in fair value or cash flows of the hedged item.
Hedge accounting is discontinued prospectively when the derivative no
longer qualifies as an effective hedge, or the derivative is
terminated or sold, or upon the sale or early termination of the
hedged item. The Trust has currently designated a portion of its
financial electricity contracts as effective cash flow hedges.

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

When hedge accounting is applied to a derivative used to hedge an
anticipated transaction and it is determined that the anticipated
transaction will not occur within the originally specified time
period, hedge accounting is discontinued and the unrealized gains and
losses are reclassified from AOCI to earnings.

Foreign Currency Translation

Monetary assets and liabilities denominated in a foreign currency are
translated at the rate of exchange in effect at the Consolidated
Balance Sheet date. Revenues and expenses are translated at the
period average rates of exchange. Translation gains and losses are
included in earnings in the period in which they arise.

Non-Controlling Interest

The Trust must record non-controlling interest when exchangeable
shares issued by a subsidiary of the Trust are transferable to third
parties. Non-controlling interest on the Consolidated Balance Sheet
is recognized based on the fair value of the exchangeable shares upon
issuance plus the accumulated earnings attributable to the non-
controlling interest. Net income is reduced for the portion of
earnings attributable to the non-controlling interest. As the
exchangeable shares are converted to Trust units, the non-controlling
interest on the Consolidated Balance Sheet is reduced by the
cumulative book value of the exchangeable shares and Unitholders'
capital is increased by the corresponding amount.

3. 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"): 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. 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. The Trust has performed a diagnostic analysis
that identifies differences between the Trust's current accounting
policies and IFRSs. At this time, the Trust is evaluating the impact
of these differences and assessing the need for amendments to
existing accounting policies in order to comply with IFRS.

4. CASH AND CASH EQUIVALENTS

Cash equivalents comprise $40 million in Canadian Treasury Bills as
at December 31, 2008 ($7 million in cash as at December 31, 2007).

5. FINANCIAL ASSETS AND CREDIT RISK

Credit risk is the risk of financial loss to the Trust if a partner
or counterparty to a product sales contract or financial instrument
fails to meet its contractual obligations. The Trust is exposed to
credit risk with respect to its cash equivalents, accounts
receivable, reclamation funds, and risk management contracts. Most of
the Trust's accounts receivable relate to oil and natural gas sales
and are subject to typical industry credit risks. The Trust manages
this credit risk as follows:

- By entering into sales contracts with only established credit
worthy counterparties as verified by a third party rating agency,
through internal evaluation or by requiring security such as
letters of credit;

- By limiting exposure to any one counterparty in accordance with
the Trust's Credit Policy;

- By restricting cash equivalent investments, reclamation fund
investments, and risk management transactions to counterparties
that, at the time of transaction are not less than investment
grade;

The majority of the credit exposure on accounts receivable at
December 31, 2008 pertains to accrued revenue for December 2008
production volumes. The Trust transacts with a number of oil and
natural gas marketing companies ("marketers") to sell the Trust's
production on its behalf. Marketers typically remit amounts to the
Trust by the 25th day of the month following production. Joint
interest receivables are typically collected within one to three
months following production. At December 31, 2008, no one
counterparty accounted for more than 20 per cent of the total
accounts receivable balance.

The Trust recorded a provision for non-collectible accounts
receivable of $32 million in 2008 (nil in 2007). In July 2008,
SemCanada Crude ("SemCanada"), a counterparty that marketed a portion
of the Trust's production filed for protection under the Companies'
Creditors Arrangement Act ("CCAA"). The Trust's total exposure to
SemCanada was $30.6 million. Due to uncertainty surrounding the
ultimate recoverable amount and expected timing of recovery, the
Trust recorded a provision for the full SemCanada receivable of
$30.6 million in 2008. In addition, the Trust recorded a provision of
$1.4 million for six additional counterparties that also filed for
CCAA protection during 2008 or were experiencing financial distress.
The Trust's allowance for doubtful accounts was $32 million as at
December 31, 2008 (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 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
December 31, 2008 $5.5 million of accounts receivable are past due,
excluding amounts described above, all of which are considered to be
collectable.

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

6. RECLAMATION FUNDS

---------------------------------------------------------------------
December 31, 2008 December 31, 2007
---------------------------------------------------------------------
Unrestricted Restricted Unrestricted Restricted
---------------------------------------------------------------------

---------------------------------------------------------------------
Balance,
beginning
of year $ 14.4 $ 11.7 $ 24.8 $ 6.1
Contributions 5.8 5.9 6.2 5.9
Reimbursed
expenditures(1) (9.7) (1.0) (17.5) (0.6)
Interest earned
on funds 0.8 0.4 1.1 0.3
Net unrealized
gains and losses
on available-for-
sale investments (0.1) - (0.2) -
---------------------------------------------------------------------
Balance, end
of year(2) $ 11.2 $ 17.0 $ 14.4 $ 11.7
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Amount differs from actual expenditures incurred by the Trust due
to timing differences and discretionary reimbursements.
(2) As at December 31, 2008 the unrestricted reclamation fund held
nil in cash and cash equivalents ($1.5 million at December 31,
2007), with the balance held in investment grade assets.

An unrestricted reclamation fund was established to fund future asset
retirement obligation costs. In addition, the Trust has created a
restricted reclamation fund associated with the Redwater property
acquired in 2005. Contributions to the restricted and unrestricted
reclamation funds and interest earned on the balances have been
deducted from the cash distributions to the unitholders. The Board of
Directors of ARC Resources has approved voluntary contributions to
the unrestricted reclamation fund over a 20-year period that
currently results in minimum annual contributions of $6 million
($6 million in 2007) based upon properties owned as at December 31,
2008. Required contributions to the restricted reclamation fund will
vary over time and have been disclosed in Note 22. Contributions for
both funds are continually reassessed to ensure that the funds are
sufficient to finance the majority of future abandonment obligations.
Interest earned on the funds is retained within the funds.

For the years ended December 31, 2008 and December 31, 2007,
respectively, nominal amounts relating to available-for-sale
reclamation fund assets were classified from accumulated other
comprehensive income into earnings. At December 31, 2007 the fair
value of reclamation fund assets designated as held to maturity
approximated carrying value. During the fourth quarter of 2008,
assets previously classified as held-to-maturity were reclassified to
available-for-sale, as it was determined that the Trust no longer has
the intention to hold these assets to maturity. As at December 31,
2008 all reclamation fund assets are reflected at fair value. The
fair values are obtained from third parties, determined directly by
reference to quoted market prices.

7. PROPERTY, PLANT AND EQUIPMENT

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Property, plant and equipment, at cost $ 5,668.9 $ 5,065.0
Accumulated depletion and depreciation (2,292.3) (1,922.0)
---------------------------------------------------------------------
Property, plant and equipment, net $ 3,376.6 $ 3,143.0
---------------------------------------------------------------------
---------------------------------------------------------------------

The calculation of 2008 depletion and depreciation included an
estimated $872 million ($549 million in 2007) for future development
costs associated with proved undeveloped reserves and excluded
$287.5 million ($173.7 million in 2007) for the book value of
unproved properties.

The Trust performed a ceiling test calculation at December 31, 2008
to assess the recoverable value of property plant and equipment
("PP&E"). Based on the calculation, the value of future net revenues
from the Trust's reserves exceeded the carrying value of the Trust's
PP&E at December 31, 2008. The benchmark prices used in the
calculation were as follows:

WTI Oil AECO Gas Cdn$/US$
Year (US$/bbl) (Cdn$/mmbtu) Exchange Rates
---------------------------------------------------------------------
2009 57.50 7.58 1.21
2010 68.00 7.94 1.18
2011 74.00 8.34 1.14
2012 85.00 8.70 1.08
2013 92.01 8.95 1.05
2014 93.85 9.14 1.05
2015 95.73 9.34 1.05
2016 97.64 9.54 1.05
2017 99.59 9.75 1.05
2018 101.59 9.95 1.05
2019 103.62 10.15 1.05
---------------------------------------------------------------------
Remainder(1) 2.0% 2.0% 1.05
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Percentage change represents the change in each year after 2019
to the end of the reserve life.

8. LONG-TERM INVESTMENT

In 2007 the Trust sold its equity investment in a private oil sands
company for proceeds of $33.3 million, resulting in a gain on sale of
investment of $13.3 million. The original investment was purchased in
2006 for $20 million. The investment in the shares of the private
company was considered to be a related party transaction due to
common directorships of the Trust, the private company and the
manager of a private equity fund that held shares in the private
company. In addition, certain directors and officers of the Trust had
minor direct and indirect shareholdings in the private company.

9. FINANCIAL LIABILITIES AND LIQUIDITY RISK

Liquidity risk is the risk that the Trust will not be able to meet
its financial obligations as they become due. The Trust actively
manages its liquidity through cash, distribution policy, and debt and
equity management strategies. Such strategies include continuously
monitoring forecasted and actual cash flows from operating, financing
and investing activities, available credit under existing banking
arrangements and opportunities to issue additional Trust units.
Management believes that future cash flows generated from these
sources will be adequate to settle the Trust's financial liabilities.

The following table details the Trust's financial liabilities as at
December 31, 2008:

---------------------------------------------------------------------
1 year 2 - 3 4 - 5 Beyond
($ millions) years years 5 years Total
---------------------------------------------------------------------
Accounts payable
and accrued
liabilities(1) 198.1 - - - 198.1
Distributions
payable(2) 25.6 - - - 25.6
Risk management
contracts(3) 24.3 6.4 0.3 - 31.0
Senior secured notes
and interest 33.0 78.0 187.6 21.6 320.2
Revolving credit
facilities - 642.2 - - 642.2
Accrued long-term
incentive
compensation(1) - 37.1 - - 37.1
---------------------------------------------------------------------
Total financial
liabilities 281.0 763.7 187.9 21.6 1,254.2
---------------------------------------------------------------------
---------------------------------------------------------------------

(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 distribution represents the net cash
payable after distribution reinvestment.
(3) Amounts payable for the risk management contracts have been
included at their intrinsic value.

The Trust actively maintains credit and working capital facilities to
ensure that it has sufficient available funds to meet its financial
requirements at a reasonable cost. Refer to Note 10 for further
details on available amounts under existing banking arrangements and
Note 12 for further details on capital management.

10. LONG-TERM DEBT

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility - Cdn$
denominated $ 399.5 $ 344.9
Syndicated credit facility - US$
denominated 240.6 154.1
Working capital facility(1) 2.1 -
Senior secured notes
5.42% US$ Note 91.9 74.1
4.94% US$ Note 14.7 17.8
4.62% US$ Note 76.5 61.8
5.10% US$ Note 76.5 61.8
---------------------------------------------------------------------
Total long-term debt outstanding $ 901.8 $ 714.5
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Amount borrowed under the working capital facility comprises
$2.1 million of outstanding cheques in excess of bank balance.

Revolving Credit Facilities

During 2008, the Trust renewed its $800 million secured, annually
extendible, financial covenant-based syndicated credit facility. The
revolving credit facility's security is in the form of a floating
charge on all lands and assignments and a negative pledge on
petroleum and natural gas properties. The Trust also has in place a
$25 million demand working capital facility.

Borrowings under the credit facility bear interest at bank prime
(four per cent at December 31, 2008 and six percent at December 31,
2007) or, at the Trust's option, Canadian dollar bankers' acceptances
or U.S. dollar LIBOR loans, plus a stamping fee. At the option of the
Trust, the lenders will review the credit facility each year and
determine whether they will extend the revolving period for another
year. In the event that the credit facility is not extended at
anytime before the maturity date, the loan balance will become
repayable on the maturity date. The maturity date of the current
credit facility is April 15, 2011. All drawings under the facility
are subject to stamping fees depending on the ratio of consolidated
long-term debt and letters of credit to annualized net income before
non-cash items and interest expense. These stamping fees vary between
a minimum of 60 basis points ("bps") at a ratio of less than one to a
maximum of 110 bps at a ratio exceeding 2.5.

The working capital facility allows for maximum borrowings of
$25 million and is due and payable immediately upon demand by the
bank. The facility is secured and is subject to the same covenants as
the syndicated credit facility.

5.42 Per Cent and 4.94 Per Cent Senior Secured US$ Notes

These senior secured notes were issued in two separate issues
pursuant to an Uncommitted Master Shelf Agreement. The US$12 million
senior secured notes were issued in 2002, bear interest at 4.94 per
cent, have a remaining final term of 1.8 years (remaining average
term of 1.3 years) and require equal principal repayments of
US$6 million in 2009 and 2010. The US$75 million senior secured notes
were issued in 2005, bear interest at 5.42 per cent, have a remaining
final term of nine years (remaining weighted average term of 5.5
years) and require equal principal repayments of US$9.4 million over
an eight year period commencing in 2010.

4.62 Per Cent and 5.10 Per Cent Senior Secured US$ Notes

These notes were issued on April 27, 2004 via a private placement in
two tranches of US$62.5 million each. The first tranche of
US$62.5 million bears interest at 4.62 per cent and has a remaining
final term of 5.3 years (remaining weighted average term of 2.9
years) and requires equal principal repayments of US$10.4 million
over a six year period commencing in 2009. Immediately following the
issuance, the Trust entered into interest rate swap contracts which
effectively changed the interest rate from fixed to floating (see
Note 13). The second tranche of US$62.5 million bears interest at
5.10 per cent and has a remaining final term of 7.3 years (remaining
weighted average term of 5.4 years). Repayment of the notes will
occur in equal principal repayments of US$12.5 million over a five
year period commencing in 2012.

Debt Covenants

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

- Long-term debt and letters of credit not to exceed three times
annualized net income before non-cash items and interest expense;

- Long-term debt, letters of credit, and subordinated debt not to
exceed four times annualized net income before non-cash items and
interest expense; and

- Long-term debt and letters of credit not to exceed 50 per cent of
the book value of unitholders' equity and long-term debt, letters
of credit, and subordinated debt.

In the event that the Trust enters into a material acquisition
whereby the purchase price exceeds 10 per cent of the book value of
the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times respectively, while the third covenant
is increased to 55% for the subsequent six month period. As at
December 31, 2008, the Trust had $1.9 million in letters of credit
($4.8 million in 2007), no subordinated debt, and was in compliance
with all covenants.

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

During 2008, the weighted-average effective interest rate under the
credit facility was 3.8 per cent (5.5 per cent in 2007).

Amounts of US$16.4 million due under the senior secured notes in the
next 12 months have not been included in current liabilities as
management has the ability and intent to refinance this amount
through the syndicated credit facility. The fair value of senior
secured notes as at December 31, 2008 is $289.9 million
($226.1 million as at December 31, 2007), and is calculated as the
present value of principal and interest payments discounted at the
Trust's credit adjusted risk free rate.

Interest paid during 2008 was $1.6 million more than interest
expense, $1.8 million less in 2007.

11. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligations were estimated by
management based on the Trust's net ownership interest in all wells
and facilities, estimated costs to reclaim and abandon the wells and
facilities and the estimated timing of the costs to be incurred in
future periods. The Trust has estimated the net present value of its
total asset retirement obligations to be $141.5 million as at
December 31, 2008 ($140 million in 2007) based on a total future
undiscounted liability of $1.32 billion ($1.29 billion in 2007). At
December 31, 2008 management estimates that these payments are
expected to be made over the next 51 years with the majority of
payments being made in years 2049 to 2059. The Trust's weighted
average credit adjusted risk free rate of 6.6 per cent (6.6 per cent
in 2007) and an inflation rate of 2.0 per cent (2.0 per cent in 2007)
were used to calculate the present value of the asset retirement
obligations. During the year, no gains or losses were recognized on
settlements of asset retirement obligations.

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

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of year $ 140.0 $ 177.3
Increase in liabilities relating to
development activities 2.0 3.8
Increase (decrease) in liabilities relating
to change in estimate 2.6 (34.4)
Settlement of liabilities during the year (12.4) (18.2)
Accretion expense 9.3 11.5
---------------------------------------------------------------------

---------------------------------------------------------------------
Balance, end of year $ 141.5 $ 140.0
---------------------------------------------------------------------
---------------------------------------------------------------------

12. 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 normal times, in the
opinion of Management and the Board of Directors, is sustainable
for a minimum period of six months in order to normalize the
effect of commodity price volatility to unitholders; and

- Maintain a level of distributions which will transfer tax
liabilities to unitholders and minimize taxes paid by the Trust.

The Trust manages the following capital:

- Trust units and exchangeable shares;

- Long-term debt; and

- Working capital (defined as current assets less current
liabilities excluding risk management contracts and future income
taxes).

When evaluating the Trust's capital structure, management's objective
is to limit net debt to less than 2.0 times annualized cash flow from
operating activities and 20 per cent of total capitalization. As at
December 31, 2008 the Trust's net debt to annualized cash flow from
operating activities ratio is 1.0 and its net debt to total
capitalization ratio is 17.9 per cent.

---------------------------------------------------------------------
($ millions except per unit and December 31, December 31,
per cent amounts) 2008 2007
---------------------------------------------------------------------
Long-term debt 901.8 714.5
Accounts payable and accrued liabilities 194.4 180.6
Distributions payable 32.5 42.1
Cash and cash equivalents, accounts receivable
and prepaid expenses (166.8) (184.5)
---------------------------------------------------------------------
Net debt obligations(1) 961.9 752.7
---------------------------------------------------------------------

Trust units outstanding and issuable for
exchangeable shares (millions) 219.2 213.2
Trust unit price 20.10 20.40
---------------------------------------------------------------------
Market capitalization(1) 4,405.9 4,349.3
Net debt obligations(1) 961.9 752.7
---------------------------------------------------------------------
Total capitalization(1) 5,367.8 5,102.0
---------------------------------------------------------------------

Net debt as a percentage of total
capitalization 17.9% 14.8%
Net debt obligations to annualized cash
flow from operating activities 1.0 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 change
its capital structure by issuing new trust units, exchangeable
shares, new debt or changing its distribution policy.

As a result of the volatility of oil prices throughout 2008, the
Trust made several changes to the monthly distribution amounts
declared and paid to unitholders. During the first seven months of
2008, oil prices soared to record high amounts causing the Trust to
increase monthly distributions to $0.28 per unit in order to meet the
Trust's objective of transferring tax liabilities to unitholders and
minimizing taxes paid by the Trust. In the third quarter of 2008, oil
prices decreased significantly causing the Trust to reduce
distributions to $0.15 per unit. Subsequent to year end, the Trust
further decreased distributions to $0.12 per unit in light of the
continued weak commodity price environment.

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 December 31,
2008 the Trust is in compliance with all covenants. Refer to Note 10
for further details.

13. 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. Financial instruments of the Trust
carried on the Consolidated Balance Sheet are carried at amortized
cost with the exception of cash and cash equivalents, reclamation
fund assets classified as available-for-sale and risk management
contracts, which are carried at fair value. With the exception of the
Trust's senior secured notes, there were no significant differences
between the carrying value of financial instruments and their
estimated fair values as at December 31, 2008. The fair value of the
Trust's senior secured notes is disclosed in Note 10.

ARC's risk management program is overseen by its Risk Committee based
on guidelines approved by the Board of Directors. The objective of
the risk management program is to support the Trust's business plan
by mitigating adverse changes in commodity prices, interest rates and
foreign exchange rates.

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

Commodity price risk

The Trust's operational results and financial condition, and
therefore the amount of distributions paid to unitholders, are
largely dependent on the commodity prices received for oil and
natural gas production. Commodity prices have fluctuated widely
during recent years due to global and regional factors including
supply and demand fundamentals, inventory levels, weather, economic,
and geopolitical factors. Movement in commodity prices could have a
significant positive or negative impact on distributions to
unitholders.

ARC manages the risks associated with changes in commodity prices by
entering into a variety of risk management contracts (see Risk
Management Contracts below). The following table illustrates the
effects of movement in commodity prices on net income due to changes
in the fair value of risk management contracts in place at December
31, 2008. The sensitivity is based on a $15 increase and $15 decrease
in the price of US$ WTI crude oil and $2 increase and $2 decrease in
the price of Cdn$ AECO natural gas. The commodity price assumptions
are based on management's assessment of reasonably possible changes
in oil and natural gas prices that could occur between December 31,
2008 and the Trust's next reporting date (March 31, 2009).

---------------------------------------------------------------------
Increase in Commodity Price Decrease in Commodity Price
---------------------------------------------------------------------
($ millions) Crude oil Natural gas Crude oil Natural gas
---------------------------------------------------------------------
Net income
(decrease)
increase (2.2) (1.0) 3.3 1.6
---------------------------------------------------------------------
---------------------------------------------------------------------

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

Interest Rate Risk

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

If interest rates applicable to floating rate debt 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 year ended December 31, 2008
would decrease by $6.4 million, of which $4.8 million is the result
of increased interest expense and $1.6 million is due to the change
in fair value of risk management contracts in place at December 31,
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.

As at December 31, 2008 no risk management contracts pertaining to
foreign exchange were outstanding.

If foreign exchange rates applicable to U.S. denominated debt were to
have increased or decreased by $0.10Cdn$/US$ it is estimated that the
Trust's net income for the year ended December 31, 2008 would
decrease by $29 million or increase by $32 million, respectively.
Increases and decreases in foreign exchange rates applicable to US$
payables and receivables would have a nominal impact on the Trust's
net income for the year ended December 31, 2008.

Risk Management Contracts

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

Following is a summary of all risk management contracts in place as
at December 31, 2008 that do not qualify for hedge accounting:

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

---------------------------------------------------------------------
Financial AECO Natural Gas Option Contracts(2)
---------------------------------------------------------------------
Bought
Volume Put Sold Put Sold Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ Cdn$/GJ
---------------------------------------------------------------------
Jan 09 -
Dec 09 3 - Way Collar 20,000 6.50 4.50 8.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) AECO 7a monthly index

---------------------------------------------------------------------
Financial NYMEX Natural Gas Contracts(3)
---------------------------------------------------------------------
Bought
Volume Put Sold Put Sold Call
Term Contract mmbtu/d US$/mmbtu US$/mmbtu US$/mmbtu
---------------------------------------------------------------------
Jan 09 - Mar 09 Collar 20,000 8.50 - 11.00
Jan 09 - Mar 09 Collar 10,000 9.00 - 12.00
Jan 09 - Mar 09 Collar 10,000 9.25 - 12.00
---------------------------------------------------------------------
---------------------------------------------------------------------
(3) Last 3 Day

---------------------------------------------------------------------
Financial Basis Swap Contract(4)
---------------------------------------------------------------------
Basis
Volume Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
Jan 09 -
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)
---------------------------------------------------------------------
---------------------------------------------------------------------
(4) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO
Monthly 7a

---------------------------------------------------------------------
Financial Interest Rate Contracts(5)(6)
---------------------------------------------------------------------
Fixed Spread
Principal Annual on 3 Mo.
Term Contract MM US$ Rate % LIBOR
---------------------------------------------------------------------
Jan 09 - Apr 14 Swap 30.5 4.62 38 bps
Jan 09 - Apr 14 Swap 32.0 4.62 (25.5 bps)
---------------------------------------------------------------------
---------------------------------------------------------------------
(5) 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.
(6) 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(7)
---------------------------------------------------------------------
AESO AECO multi- Heat
Volume Power 5(a) plied Rate
Term Contract MWh $/MWh $/GJ by GJ/MWh
---------------------------------------------------------------------
Jan 10 - Receive Pay
Dec 13 Heat Rate Swap 5.0 AESO AECO 9.0
---------------------------------------------------------------------
---------------------------------------------------------------------
(7) Alberta Power Pool (monthly average 24x7), AECO Monthly (5a)

---------------------------------------------------------------------
Financial Electricity Contracts(8)
---------------------------------------------------------------------
Volume Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
Jan 09 - Dec 12 Swap 5.0 72.50
---------------------------------------------------------------------

Following is a summary of all risk management contracts in place
as at December 31, 2008 that qualify for hedge accounting:

---------------------------------------------------------------------
Financial Electricity Contracts(8)
---------------------------------------------------------------------
Volume Swap
Term Contract MWh Cdn$/MWh
---------------------------------------------------------------------
Jan 09 - Dec 09 Swap 15.0 59.33
Jan 10 - Dec 10 Swap 5.0 63.00
---------------------------------------------------------------------
(8) Contracted volume is based on a 24/7 term.

At December 31, 2008, the fair value of the contracts that were not
designated as accounting hedges was a gain of $3.4 million. The Trust
recorded a loss on risk management contracts of $7.7 million in the
statement of income for the year ended December 31, 2008
($41.8 million loss in 2007). This amount includes the realized and
unrealized gains and losses on risk management contracts that do not
qualify as effective accounting hedges.

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:

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Fair value, beginning of year $ (64.6) $ (8.7)
Fair value, end of year(1) 3.4 (64.6)
---------------------------------------------------------------------
Change in fair value of contracts in the year 68.0 (55.9)
Realized (loss) gain in the year (75.7) 14.1
---------------------------------------------------------------------
Loss on risk management contracts $ (7.7) $ (41.8)
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $0.9 million at
December 31, 2008 ($47.6 million loss at December 31, 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. During 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. During 2008, the $13.6 million loss was
reclassified from OCI, net of tax and recognized in net income.

The Trust's electricity contracts are intended to manage price risk
on electricity consumption. Portions of the Trust's financial
electricity contracts were designated as effective accounting hedges
on their respective contract dates. A realized gain of $1.2 million
and $3.9 million for the three and twelve months ended December 31,
2008 (loss of $0.1 million and gain of $0.4 million respectively in
2007) has been included in operating costs on these electricity
contracts. The unrealized fair value gain of $3.3 million on these
contracts has been recorded on the Consolidated Balance Sheet at
December 31, 2008 with the movement in fair value recorded in OCI,
net of tax. The fair value movement for the year ended December 31,
2008 is an unrealized loss of $0.7 million. As at December 31, 2008
$2.5 million of the unrealized fair value gain is attributed to
contracts that will settle in 2009.

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:

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Fair value, beginning of year(1) $ (3.4) $ 7.0
Change in fair value of financial
electricity contracts (0.7) (10.4)
Change in fair value of treasury rate lock
contracts prior to de-designation (6.2) -
Reclassification of loss on treasury rate
lock contracts to net income 13.6 -
---------------------------------------------------------------------
Fair value, end of year(2) $ 3.3 $ (3.4)
---------------------------------------------------------------------
---------------------------------------------------------------------

(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 $3.4 million at
December 31, 2008 ($3.5 million loss at December 31, 2007).

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

14. (LOSS) GAIN ON FOREIGN EXCHANGE

The following is a summary of the total (loss) gain on US$
denominated transactions:

---------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------------------------
2008 2007 2008 2007
---------------------------------------------------------------------
Unrealized (loss)
gain on US$
denominated debt (63.9) (0.6) $ (90.8) $ 64.6
Realized gain on
US$ denominated
debt repayments 2.3 3.7 2.3 5.0
---------------------------------------------------------------------
Total non-cash
(loss) gain on
US$ denominated
transactions (61.6) 3.1 (88.5) 69.6
Realized cash
gain (loss) on
US$ denominated
transactions 0.4 0.1 (0.9) (0.2)
---------------------------------------------------------------------
Total foreign
exchange (loss)
gain (61.2) 3.2 $ (89.4) $ 69.4
---------------------------------------------------------------------
---------------------------------------------------------------------

15. INCOME TAXES

In 2007, Income Trust tax legislation was passed resulting in a two-
tiered tax structure subjecting distributions to the federal
corporate income tax rate plus a deemed 13 per cent provincial income
tax at the Trust level commencing in 2011. 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 that a
corporation would calculate its provincial tax rate. On February 1,
2009 the Minister of Finance tabled a Notice of Ways and Means which
includes the proposed legislation for calculating the provincial tax
rate. As the proposed rules were not substantively enacted as of
December 31, 2008, the Trust has not reflected a reduced tax rate in
the calculation of future income taxes in 2008.

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

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Income before future income tax recovery and
non-controlling interest $ 535.4 $ 380.8
---------------------------------------------------------------------
Canadian statutory rate(1) 32.4% 34.3%
---------------------------------------------------------------------
Expected income tax expense at statutory rates 173.4 130.6
Effect on income tax of:
Net income of the Trust (181.2) (163.6)
Effect of change in corporate tax rate (8.9) (41.3)
Initial recognition of Trust tax pools - (24.7)
Unrealized loss (gain) on foreign exchange 13.4 (10.4)
Change in estimated pool balances (1.0) (7.0)
Non-taxable portion of gains/losses - (2.1)
Other non-deductible items (0.2) (2.8)
---------------------------------------------------------------------
Future income tax recovery $ (4.5) $ (121.3)
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) The statutory rate consists of the combined Trust and Trust's
subsidiaries statutory tax rate

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

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Future tax liabilities:
Capital assets in excess of tax value $ 381.4 $ 371.6
Risk management contracts 1.7 -
Other comprehensive income (loss) 0.8 (0.7)
Long-term debt 0.2 11.9
Future tax assets:
Asset retirement obligations (35.8) (36.1)
Non-capital losses (24.4) (3.8)
Risk management contracts - (16.7)
Trust unit incentive compensation expense (8.3) (7.8)
Attributed Canadian royalty income (4.6) (4.6)
CEC, SR&ED pools and deductible share issue
costs (1.6) (1.6)
---------------------------------------------------------------------
Net future income tax liability $ 309.4 $ 312.2
---------------------------------------------------------------------
Future income tax (asset) $ (3.9) $ (4.0)
Future income tax liability $ 313.3 $ 316.2
---------------------------------------------------------------------
---------------------------------------------------------------------

The petroleum and natural gas properties and facilities owned by the
Trust have an approximate tax basis of $2.07 billion ($1.84 billion
in 2007) available for future use as deductions from taxable income.
Included in this tax basis are estimated non-capital loss carry
forwards of $86.9 million ($13.8 million in 2007) that expire in the
years 2010 through 2027. The following is a summary of the estimated
Trust's tax pools:

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Canadian oil and gas property expenses $ 1,001.3 $ 816.5
Canadian development expenses 360.7 326.1
Canadian exploration expenses 41.5 52.5
Undepreciated capital costs 414.5 460.2
Non-capital losses 86.9 13.8
SR&ED tax pools 0.3 -
Provincial tax pools 155.9 161.1
Other 7.0 10.3
---------------------------------------------------------------------
Estimated tax basis $ 2,068.1 $ 1,840.5
---------------------------------------------------------------------
---------------------------------------------------------------------

No current income taxes were paid or payable in both 2008 and 2007.

16. EXCHANGEABLE SHARES

The Trust is authorized to issue an unlimited number of ARL
Exchangeable Shares that can be converted (at the option of the
holder) into trust units at any time. The number of Trust units
issuable upon conversion is based upon the exchange ratio in effect
at the conversion date. The exchange ratio is calculated monthly
based on the cash distribution paid divided by the ten day weighted
average unit price preceding the record date and multiplied by the
opening exchange ratio. The exchangeable shares are not eligible for
distributions and, in the event that they are not converted, any
outstanding shares are redeemable by the Trust for Trust units on
August 28, 2012. The ARL Exchangeable Shares are publicly traded.

---------------------------------------------------------------------
December 31, December 31,
ARL Exchangeable Shares (thousands) 2008 2007
---------------------------------------------------------------------
Balance, beginning of year 1,310 1,433
Exchanged for trust units(1) (218) (123)
---------------------------------------------------------------------
Balance, end of year 1,092 1,310
Exchange ratio, end of year 2.51668 2.24976
Trust units issuable upon conversion, end
of year 2,748 2,947
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) During 2008, 218,455 ARL exchangeable shares were converted to
trust units at an average exchange ratio of 2.36901, compared to
123,263 exchangeable shares at an average exchange ratio of
2.12125 during 2007.

The non-controlling interest on the Consolidated Balance Sheet
consists of the fair value of the exchangeable shares upon issuance
plus the accumulated earnings attributable to the non-controlling
interest. The net income attributable to the non-controlling interest
on the Consolidated Statement of Income represents the cumulative
share of net income attributable to the non-controlling interest
based on the Trust units issuable for exchangeable shares in
proportion to total Trust units issued and issuable at each period
end.

Following is a summary of the non-controlling interest for 2008
and 2007:

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Non-controlling interest, beginning of year $ 43.1 $ 40.0
Reduction of book value for conversion to
trust units (7.6) (3.7)
Current year net income attributable to
non-controlling interest 6.9 6.8
---------------------------------------------------------------------
Non-controlling interest, end of year 42.4 43.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 41.0 $ 34.1
---------------------------------------------------------------------
---------------------------------------------------------------------

17. UNITHOLDERS' CAPITAL

The Trust is authorized to issue 650 million Trust units of which
216.4 million units were issued and outstanding as at December 31,
2008 (210.2 million as at December 31, 2007).

The Trust has in place a Distribution Reinvestment and Optional Cash
Payment Program ("DRIP") in conjunction with the Trusts' transfer
agent to provide the option for unitholders to reinvest cash
distributions into additional trust units issued from treasury at a
five per cent discount to the prevailing market price with no
additional fees or commissions.

The Trust is an open ended mutual fund under which unitholders have
the right to request redemption directly from the Trust. Trust units
tendered by holders are subject to redemption under certain terms and
conditions including the determination of the redemption price at the
lower of the closing market price on the date units are tendered or
90 per cent of the weighted average trading price for the 10 day
trading period commencing on the tender date. Cash payments for trust
units tendered for redemption are limited to $100,000 per month with
redemption requests in excess of this amount eligible to receive a
note from ARC Resources Ltd. accruing interest at 4.5 per cent and
repayable within 20 years.

---------------------------------------------------------------------

December 31, 2008 December 31, 2007
---------------------------------------------------------------------
Number of Number of
trust units trust units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance,
beginning
of year 210,232 2,465.7 204,289 2,349.2
Issued on
conversion of ARL
exchangeable
shares (Note 16) 517 7.6 261 3.7
Issued on exercise
of employee
rights (Note 20) 238 4.2 131 2.1
Distribution
reinvestment
program 5,448 123.2 5,551 110.7
---------------------------------------------------------------------
Balance, end
of year 216,435 2,600.7 210,232 2,465.7
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
Three Months Ended Twelve Months Ended
December 31 December 31
---------------------------------------------------------------------
2008 2007 2008 2007
---------------------------------------------------------------------
Weighted average
trust units(1) 215.6 209.6 213.3 207.3
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 218.3 212.6 216.1 210.4
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Weighted average trust units excludes trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding
exchangeable shares at the year-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.

18. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE INCOME

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Accumulated earnings $ 2,724.1. $ 2,191.1
Accumulated distributions (3,227.0) (2,657.0)
---------------------------------------------------------------------
Deficit $ (502.9) $ (465.9)
Accumulated other comprehensive income (loss) 1.9 (2.9)
---------------------------------------------------------------------
Deficit and accumulated other comprehensive
income (loss) $ (501.0) $ (468.8)
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Unrealized gains and losses on financial
instruments designated as cash flow hedges $ 2.0 $ (2.8)
Net unrealized gains and losses on
available-for-sale reclamation funds'
investments (0.1) (0.1)
---------------------------------------------------------------------
Accumulated other comprehensive income
(loss), end of year $ 1.9 $ (2.9)
---------------------------------------------------------------------
---------------------------------------------------------------------

19. 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 Twelve Months Ended
December 31 December 31
2008 2007 2008 2007
---------------------------------------------------------------------
Cash flow from
operating
activities $ 209.4 $ 173.7 $ 944.4 $ 704.9
Deduct:
Cash withheld
to fund
current period
capital
expenditures (80.9) (48.1) (372.2) (211.6)
Net reclamation
fund
(contributions)
withdrawals (1.3) 0.2 (2.2) 4.7
---------------------------------------------------------------------
Distributions(1) 127.2 125.8 570.0 498.0
Accumulated
distributions,
beginning of
period 3,099.8 2,531.2 2,657.0 2,159.0
---------------------------------------------------------------------
Accumulated
distributions,
end of period $ 3,277.0 $ 2,657.0 $ 3,227.0 $ 2,657.0
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions
per unit(2) $ 0.59 $ 0.60 $ 2.67 $ 2.40
Accumulated
distributions
per unit,
beginning of
period $ 23.11 $ 20.43 $ 21.03 $ 18.63
Accumulated
distributions
per unit, end
of period(3) $ 23.70 $ 21.03 $ 23.70 $ 21.03
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Distributions include accrued and non-cash amounts of
$9.7 million and $111.2 million for the three and twelve months
ended December 31, 2008, respectively ($27 million and
$110 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.

20. TRUST UNIT INCENTIVE RIGHTS PLAN

The Trust Unit Incentive Rights Plan (the "Rights Plan") was
established in 1999 and authorized the Trust to grant up to 8,000,000
rights to its employees, independent directors and long-term
consultants to purchase Trust units, of which 7,866,088 were granted
before the plan was discontinued in 2004 and replaced with a Whole
Unit Plan (See Note 21). During 2008 the remaining 238 thousand
rights were exercised, at a weighted average exercise price of
$10.40. As of December 31, 2008 all rights issued under the Rights
Plan have been exercised or cancelled.

The Trust did not record any compensation expense for 2008 (a nominal
amount in 2007) for the cost associated with the rights.

Upon exercise of the rights, the remaining $1.7 million balance in
contributed surplus was reduced to $nil and a corresponding increase
was booked to unitholders' capital.

21. WHOLE TRUST UNIT INCENTIVE PLAN

In March 2004, the Board of Directors, upon recommendation of the
Compensation Committee, approved a new Whole Trust Unit Incentive
Plan (the "Whole Unit Plan") to replace the existing Trust Unit
Incentive Rights Plan for new awards granted subsequent to March 31,
2004. The new Whole Unit Plan results in employees, officers and
directors (the "plan participants") receiving cash compensation in
relation to the value of a specified number of underlying notional
trust units. The Whole Unit Plan consists of Restricted Trust Units
("RTUs") for which the number of trust units is fixed and will vest
evenly over a period of three years and Performance Trust Units
("PTUs") for which the number of trust units is variable and will
vest at the end of three years.

Upon vesting, the plan participant receives 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 future performance of the Trust compared to its
peers based on a performance multiplier. The performance multiplier
is based on the percentile rank of the Trust's Total Unitholder
Return. The cash compensation issued upon vesting of the PTUs may
range from zero to two times the value of the PTUs originally
granted.

The fair value associated with the RTUs and PTUs is expensed in the
statement of income over the vesting period. As the value of the RTUs
and PTUs is dependent upon the trust unit price, the expense recorded
in the statement of income may fluctuate over time.

The Trust recorded non-cash compensation expense of $1.1 million and
$(0.1) million to general and administrative and operating expenses,
respectively, and capitalized $0.6 million to property, plant and
equipment in the twelve months ended December 31, 2008 for the
estimated cost of the plan ($3.2 million, $0.3 million, and
$0.7 million for the twelve months ended December 31, 2007). The non-
cash compensation expense was based on the December 31, 2008 unit
price of $20.10 ($20.40 in 2007), accrued distributions, an average
performance multiplier of 1.6 (1.7 in 2007), and the estimated number
of units to be issued on maturity.

The following table summarizes the RTU and PTU movement for the year
ended December 31, 2008:

---------------------------------------------------------------------
Number of Number of
RTUs PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of year 746 903
Vested (347) (252)
Granted 403 352
Forfeited (46) (44)
---------------------------------------------------------------------
Balance, end of year 756 959
---------------------------------------------------------------------
---------------------------------------------------------------------

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

---------------------------------------------------------------------
December 31, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of year $ 30.3 $ 26.1
Change in net liabilities in the year
General and administrative expense 1.1 3.2
Operating expense (0.1) 0.3
Property, plant and equipment 0.6 0.7
---------------------------------------------------------------------
Balance, end of year(1) $ 31.9 $ 30.3
---------------------------------------------------------------------
Current portion of liability 18.8 18.2
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 14.2 $ 12.1
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Includes $1.1 million of recoverable amounts recorded in accounts
receivable as at December 31, 2008 (nil for 2007).

During the year cash payments of $28.2 million were made to employees
relating to the Whole Unit Plan ($12.7 million in 2007).

22. COMMITMENTS AND CONTINGENCIES

Following is a summary of the Trust's contractual obligations and
commitments as at December 31, 2008:

---------------------------------------------------------------------
Payments Due by Period
---------------------------------------------------------------------
2010- 2012- There-
($ millions) 2009 2011 2013 after Total
---------------------------------------------------------------------
Debt repayments(1) 22.2 696.0 79.1 104.5 901.8
Interest payments(2) 12.8 22.2 15.4 10.0 60.4
Reclamation fund
contributions(3) 5.2 9.5 8.3 67.9 90.9
Purchase commitments 13.0 15.4 5.0 4.9 38.3
Transportation
commitments(4) - 14.9 21.9 21.0 57.8
Operating leases 7.0 9.8 14.3 81.8 112.9
Risk management contract
premiums(5) 19.3 - - - 19.3
---------------------------------------------------------------------
Total contractual
obligations 79.5 767.8 144.0 290.1 1,281.4
---------------------------------------------------------------------
---------------------------------------------------------------------

(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property.
(4) Fixed payments for transporting production from the Dawson gas
plant, expected to be operational in early 2010.
(5) Fixed premiums to be paid in future periods on certain commodity
risk management contracts.

In addition to the above Risk management contract premiums, the Trust
has commitments related to its risk management program (see Note 13).
As the premiums are part of the underlying risk management contract,
they have been recorded at fair market value at December 31, 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 expenditures in a future
period. The Trust's 2009 capital budget has been approved by the
Board at $450 million. This commitment has not been disclosed in the
commitment table as it is of a routine nature and is part of normal
course of operations for active oil and gas companies and trusts.

The 2009 capital budget of $450 million includes approximately
$11 million for leasehold development costs related to the Trust's
new office space in downtown Calgary. These costs will be incurred
throughout 2009 with additional amounts to be incurred in 2010. The
operating lease commitments for the new space are included in the
table above.

The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending
litigation will not have a material adverse impact on the Trust's
financial position or results of operations and therefore the above
table does not include any commitments for outstanding litigation and
claims.

23. SUBSEQUENT EVENTS

On January 21, 2009 the Trust announced that it had entered into an
agreement, on a bought deal basis, with a syndicate of underwriters
for an offering of 13,456,000 trust units at $16.35 per trust unit,
for gross proceeds of $220 million as well as an over-allotment
option to purchase, on the same terms and conditions, up to an
additional 2,018,400 trust units. This option was exercised in whole
prior to closing of the offering on February 6, 2009. The gross
proceeds raised under this offering were $253 million and proceeds
net of underwriter and transaction fees were approximately
$240 million. The proceeds were used to repay debt, thereby freeing
up borrowing capacity to fund a portion of the Trust's 2009 capital
program.

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.
>>

FORWARD-LOOKING INFORMATION AND STATEMENTS

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

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with a current enterprise value of approximately $4.1 billion.
The Trust expects full year 2009 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.

<<
ARC RESOURCES LTD.

John P. Dielwart,
Chief Executive Officer
>>

%SEDAR: 00001245E %CIK: 0001029509