ARC Energy Trust announces first quarter 2008 results, including record production volumes and cash flow and a 20 per cent increase in distributions

CALGARY, May 7, 2008 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust
("ARC" or "the Trust") announces the results for the first quarter ended March
31, 2008, including record production volumes and cash flow and a 20 per cent
increase in distributions.

<<
Three Months Ended
March 31
2008 2007
-------------------------------------------------------------------------
FINANCIAL
($Cdn millions, except per unit and per
boe amounts)
Revenue before royalties 407.9 307.8
Per unit(1) 1.91 1.48
Per boe 66.94 53.29
Cash flow from operating activities(2) 209.9 172.3
Per unit(1) 0.98 0.83
Per boe 34.44 29.83
Net income 81.3 83.3
Per unit(3) 0.39 0.41
Distributions 126.8 123.1
Per unit(1) 0.60 0.60
Per cent of cash flow from operating activities(2) 60 71
Net debt outstanding(4) 770.1 729.7
Total capital expenditures and net acquisitions 121.4 77.7
OPERATING
Production
Crude oil (bbl/d) 29,064 29,520
Natural gas (mmcf/d) 204.3 183.0
Natural gas liquids (bbl/d) 3,856 4,161
Total (boe/d) 66,976 64,175
Average prices
Crude oil ($/bbl) 89.72 60.79
Natural gas ($/mcf) 7.80 7.75
Natural gas liquids ($/bbl) 68.54 48.04
Oil equivalent ($/boe) 66.67 53.18
Operating netback ($/boe)
Commodity and other revenue (before hedging)(5) 66.94 53.29
Transportation costs (0.73) (0.81)
Royalties (11.85) (9.65)
Operating costs (9.55) (8.99)
Netback (before hedging) 44.81 33.84
-------------------------------------------------------------------------
TRUST UNITS
(millions)
Units outstanding, end of period(6) 214.7 208.7
Weighted average units(7) 213.8 207.9
-------------------------------------------------------------------------
TRUST UNIT TRADING STATISTICS
($Cdn, except volumes) based on intra-day trading
High 27.06 23.02
Low 20.00 20.05
Close 26.38 21.25
Average daily volume (thousands) 863 658
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(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. 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 first quarter of 2008 would be
$227.4 million ($1.06 per unit). Distributions as a percentage of
Cash Flow would be 56 per cent for the first quarter of 2008. Please
refer to the non-GAAP measures section in the MD&A for further
details.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Net debt excludes current unrealized amounts pertaining to risk
management contracts and the current portion of future income taxes.
(5) Includes other revenue.
(6) Includes 1.2 million exchangeable shares exchangeable into 2.31374
trust units each for an aggregate 2.7 million trust units.
(7) Includes trust units issuable for outstanding exchangeable shares at
period end.

HIGHLIGHTS AND ACCOMPLISHMENTS
------------------------------
- In light of the strong commodity price environment, the Board of
Directors have re-affirmed our base distribution of $0.20 per unit
and have approved a monthly "top-up" distribution of $0.04 per
unit. This will bring ARC's total distribution to $0.24 per unit per
month beginning with the June 16, 2008 payment. The "top-up"
distribution will be reviewed on a quarterly basis but is expected
to stay in place as long as commodity prices maintain their current
strength.
- Cash flow from operating activities for the quarter was
$209.9 million ($0.98 per unit). Using the more traditional non-GAAP
measure of Cash Flow that excludes changes in non-cash working
capital and site restoration spending for the quarter, the Cash Flow
was $227.4 million ($1.06 per unit). The 2008 first quarter Cash Flow
increased 24 per cent over the $183.8 million reported in the first
quarter of 2007. The increase is as a result of a 48 per cent
increase in the Trust's realized oil price for the quarter and a
four per cent increase in production volumes.

- The Trust posted record production for the quarter at 66,976 boe per
day, up 2,801 boe per day (4.4 per cent) over the first quarter of
2007. These production volumes were achieved from internal, organic
development of the Trust's properties as no major acquisitions have
been completed since December 2005. The most significant areas with
increased production were at Dawson and southeast Saskatchewan. The
Trust expects a decrease in second quarter production as a result of
large-scale turnarounds that have been scheduled for some of the
Trust's facilities.

- Total capital spending for the quarter including undeveloped land and
net property acquisitions of $38.9 million was $121.4 million. This
amount was funded 89 per cent by the Trust's cash flow from
operating activities and proceeds from the distribution re-
investment program ("DRIP").

- During the first quarter of 2008, the Trust spent $20.3 million on
development of its resource play inventory. In the greater Dawson
area, ARC has spent $16.6 million (excluding the cost of land
purchases) of the $85 million that was budgeted for the area in 2008.
Four horizontal infill wells were drilled in the quarter and are
expected to be completed during the second and third quarters of
2008. In addition, the Trust drilled two vertical delineation wells
at Dawson. At Sunrise, the Trust began shooting seismic and tested
commercial quantities of gas from its 9-13 discovery well. The Trust
spent $13.6 million to add seven gross (4.5 net) sections of land
contiguous with the 15 sections of land the Trust purchased in 2007.
The Trust also expanded its land base at Sundown by pooling its 18
sections of land with seven sections of land from a third party on a
pro-rata basis - consequently the Trust now owns a 72 per cent
working interest in 25 sections of land. The pooling provides ARC
with exposure to additional lands while offsetting some of the
exploration risk. The result of these and other land purchases are
that as of March 31, 2008 the Trust has an interest in 120 sections
of undeveloped land (100 sections net) in the Montney play in
British Columbia, this is up from 96 sections of undeveloped land
(87 sections net) at year-end 2007. The Board approved an additional
$40 million of capital for the Dawson area, increasing the 2008
budget for this area to $125 million.

- Including first quarter land purchases and the $40 million of
incremental capital being allocated to delineating the Trust's
undeveloped Montney lands in northeast British Columbia, the Trust's
2008 capital budget has been increased from $395 million to
$470 million.

- The Trust spent $10 million during the first quarter of 2008 on
enhanced oil recovery ("EOR") initiatives, including development
capital for the Weyburn and Midale CO(2) floods in Saskatchewan. The
Trust has been actively working on the CO(2) pilot project at
Redwater and is on schedule to begin injecting CO(2) mid-year 2008.
We expect that it will take 12 to 18 months before we know if the
pilot has been successful.
>>

In Memoriam

It is with much regret and sadness that we announce that ARC has lost an
important member of its Board of Directors. Mr. Fred Coles passed away on
May 1, 2008. He was a member of ARC's Board since inception and contributed
his wealth of knowledge and experience to ARC and the community at large. He
will be missed.

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 May 6, 2008
and should be read in conjunction with the unaudited Consolidated Financial
Statements for the period ended March 31, 2008 and the audited Consolidated
Financial Statements and MD&A for the period ended December 31, 2007 as well
as the Trust's Annual Information Form.
The MD&A contains forward-looking statements and readers are cautioned
that the MD&A should be read in conjunction with the Trust's disclosure under
"Forward-Looking Statements" included at the end of this MD&A.

Executive Overview

ARC Energy Trust ("ARC") is one of the top 20 producers of conventional
oil and gas in western Canada. ARC as at March 31, 2008 held interests in
excess of 18,000 wells with approximately 5,500 wells operated by ARC and the
remainder operated primarily by other major oil and gas companies. ARC's
production has averaged between 61,000 and 67,000 boe per day in each quarter
for the last three years. The total capitalization of ARC Energy Trust which
trades on the Toronto Stock Exchange as at March 31, 2008 was $6.4 billion as
set forth on Table 21.
ARC's objective as an energy company is to provide superior and
sustainable long-term returns to unitholders. Key attributes to the business
plan include:

<<
- Pay a portion of cash flow to unitholders annually. Currently the
Trust distributes $0.20 per unit per month. The remainder of the cash
flow is used to fund reclamation costs and a portion of capital
expenditures. Since the Trust's inception in July 1996 to March 31,
2008, the Trust has distributed $21.63 per unit.

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

Table 1 illustrates ARC's production and reserves per unit that have
been achieved while making distributions since January 1, 2006, of
$5.40 per unit or $1.1 billion.

Table 1
-------------------------------------------------------------------------
Per Trust Unit Q1 2008 2007 2006
-------------------------------------------------------------------------
Normalized production per unit(1) 0.33 0.30 0.31
Normalized reserves per unit(1) - 1.35 1.40
Distributions per unit $0.60 $2.40 $2.40
-------------------------------------------------------------------------
(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.

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

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

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

ARC's business plan and operating practices also include the following
strategies and action plans that are being under taken 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 stake holders and conducting business in a fair
and equitable manner.

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

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

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

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

Table 2
-------------------------------------------------------------------------
Total Returns Trailing Trailing Trailing
($ per unit except for per cent) One Year Three Year Five Year
-------------------------------------------------------------------------
Distributions per unit $ 2.40 $ 6.94 $ 10.54
Capital appreciation per unit $ 3.49 $ 8.23 $ 14.79
Total return per unit $ 5.89 $ 15.17 $ 25.33
Annualized total return per unit 38.3% 25.0% 31.2%
-------------------------------------------------------------------------

2008 Guidance

Table 3 is a summary of the Trust's 2008 Guidance issued by way of news
release on November 7, 2007 (posted on www.sedar.com) and a review of 2008
actual results compared to guidance:

Table 3
-------------------------------------------------------------------------
February Actual 2008
2008 2008 Revised
Guidance YTD Guidance(3)
-------------------------------------------------------------------------
Production (boe/d) 63,000 66,976 63,000
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 10.20 9.55 10.20
Transportation 0.80 0.73 0.80
G&A expenses(1) 2.55 3.47 3.00
Interest 1.90 1.44 1.90
Capital expenditures
($ millions)(2) 395 111 470
Weighted average trust units
and units issuable (millions) 216 214 216
-------------------------------------------------------------------------
(1) Cash G&A expenses for the first quarter were $1.52 per boe. The
components of the $ 3.00 per boe G&A guidance for the full year are
as follows: cash G&A - $1.80/boe; cash component of LTIP - $1.00 per
boe; non-cash LTIP component - $0.20 per boe.
(2) 2008 Capital Expenditure Guidance has been revised to reflect
additional monies to be allocated to land expenditures and resource
play development in the Dawson area.
(3) Production, operating costs, transportation and interest expense are
subject to ARC's mid-year review. Revisions to guidance, if
necessary, will be reflected in conjunction with the second quarter
results.

The 2008 Guidance provides unitholders with information as to management's
expectations for results of operations for 2008. Readers are cautioned that
the 2008 Guidance may not be appropriate for other purposes. ARC has announced
a $470 million capital expenditure budget for 2008 that comprises a robust
drilling and development program on its diverse asset base, funding of EOR
projects and an allocation of funds to purchase undeveloped lands.
Actual results for the first quarter of 2008 were in line with 2008
guidance with some minor exceptions as follows:

- Non-cash G&A expenses of $1.95/boe were greater than anticipated due
to the strong increase in the Trust's unit price during the quarter,
which increased the Trust's non-cash LTIP expense.

- Production of 66,976 boe per day was greater than anticipated due to
better than expected drilling results and approximately 1,000 boe per
day adjustment related to prior periods primarily as a result of
payout being reached on some farmed out properties.
>>

Non-GAAP Measures

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

<<
2008 First Quarter Financial and Operational Results

Financial Highlights

Table 4
-------------------------------------------------------------------------
Three Months Ended March 31
-------------------------------------------------------------------------
(Cdn $ millions, except per
unit and volume data) 2008 2007 % Change
-------------------------------------------------------------------------
Cash flow from operating activities 209.9 172.3 22
Cash flow from operating activities
per unit(1) 0.98 0.83 18
Net income 81.3 83.3 (2)
Net income per unit(2) 0.39 0.41 (5)
Distributions per unit(3) 0.60 0.60 -
Distributions as a per cent of
cash flow from operating activities 60 71 (15)
Average daily production (boe/d)(4) 66,976 64,175 4
-------------------------------------------------------------------------
(1) Per unit amounts are based on weighted average trust units
outstanding plus trust units issuable for exchangeable shares at
year-end.
(2) Based on net income after non-controlling interest divided by
weighted average trust units outstanding excluding trust units
issuable for exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf:1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the well head. Use of the term boe in isolation may be
misleading.
>>

Net Income

Net income in the first quarter of 2008 was $81.3 million ($0.39 per
unit), a decrease of $2 million from $83.3 million ($0.41 per unit) in 2007.
Although revenues in the first quarter of 2008 increased by over $100 million,
this amount was off set by a $34.3 million increase in the loss on risk
management contracts, a $16.4 million increase in royalty expense, a
$12.1 million increase in G&A expense and a $6.3 million increase in operating
expenses. In addition, the Trust recorded a $15 million foreign exchange loss
on its U.S. denominated debt as compared to a $5 million gain recorded in the
same period of 2007 as a result of the movement in the Canadian dollar in
relation to the U.S. dollar. Finally, the Trust recorded a $0.5 million income
tax expense for the first quarter of 2008 as compared to a recovery of
$11.4 million for the first quarter of 2007.
A measure of sustainability is the comparison of net income to
distributions. Net income incorporates all costs including depletion expense
and other non-cash expenses whereas cash flow from operating activities
measures the cash generated in a given period before the cost of acquiring or
replacing the associated reserves produced. Therefore, net income may be more
representative of the profitability of the entity and thus a relevant measure
against which to measure distributions to illustrate sustainability. As net
income is sensitive to fluctuations in commodity prices and the impact of risk
management contracts, currency fluctuations and other non-cash items, it is
expected that there will be deviations between annual net income and
distributions. Table 5 illustrates the annual shortfall of distributions to
net income as a measure of long-term sustainability.

<<
Table 5
-------------------------------------------------------------------------
Net income and Distributions
($ millions except per cent) Q1 2008 2007 2006
-------------------------------------------------------------------------
Net income 81.3 495.3 460.1
Distributions 126.8 498.0 484.2
-------------------------------------------------------------------------
Excess (shortfall) (45.5) (2.7) (24.1)
Excess (shortfall) as per cent
of net income 56% (1%) (5%)
Distributions as a per cent of
cash flow from operating activities 60% 71% 66%
-------------------------------------------------------------------------

Cash Flow from Operating activities

Cash flow from operating activities increased by 22 per cent in 2008 to
$209.9 million from $172.3 million in the first quarter of 2007. The increase
in 2008 cash flow from operating activities is detailed in Table 6.

Table 6
-------------------------------------------------------------------------
($ per
trust (%
($ millions) unit) variance)
-------------------------------------------------------------------------
Q1 2007 Cash flow from Operating
Activities 172.3 0.83
-------------------------------------------------------------------------
Volume variance 17.0 0.08 10
Price variance 83.2 0.40 48
Cash (losses) on risk management
contracts (36.5) (0.18) (21)
Royalties (16.4) (0.08) (10)
Expenses:
Transportation 0.3 - -
Operating(1) (4.9) (0.02) (3)
Cash G&A (0.5) - -
Interest 1.1 0.01 1
Realized foreign exchange gain 0.3 - -
Weighted average trust units - (0.03) -
Non-cash and other items(2) (6.0) (0.03) (3)
-------------------------------------------------------------------------
Q1 2008 Cash flow from Operating
Activities 209.9 0.98 22
-------------------------------------------------------------------------
(1) Excludes non-cash portion of LTIP expense recorded in operating
costs.
(2) Includes the changes in non-cash working capital and expenditures on
site restoration and reclamation.

2008 Cash Flow from Operating Activities Sensitivity

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

Table 7
-------------------------------------------------------------------------
Impact on Annual
Cash flow from operating activities(2)
Business Environment Assumption Change $/Unit
-------------------------------------------------------------------------
Oil price (US$WTI/bbl)(1) $ 85.00 $ 1.00 $ 0.04
Natural gas price (Cdn $AECO/mcf)(1) $ 6.50 $ 0.10 $ 0.03
Cdn$/US$ exchange rate $ 1.03 $ 0.01 $ 0.05
Interest rate on debt % 5.75 % 1.0 $ 0.02
Operational
Liquids production volume (bbl/d) 32,100 % 1.0 $ 0.03
Natural gas production volumes (mmcf/d) 185.0 % 1.0 $ 0.02
Operating expenses per boe $ 10.20 % 1.0 $ 0.01
Cash G&A expenses per boe $ 2.55 % 10.0 $ 0.03
-------------------------------------------------------------------------

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

Production

Table 8
-------------------------------------------------------------------------
Three Months Ended March 31
-------------------------------------------------------------------------
Production 2008 2007 % Change
-------------------------------------------------------------------------
Light & medium crude oil (bbl/d) 27,718 28,094 (1)
Heavy oil (bbl/d) 1,346 1,426 (6)
Natural gas (mcf/d) 204,328 182,962 12
NGL (bbl/d) 3,856 4,161 (7)
-------------------------------------------------------------------------
Total production (boe/d)(1) 66,976 64,175 4
% Natural gas production 51 48 6
% Crude oil and liquids production 49 52 (6)
-------------------------------------------------------------------------
(1) Reported production for a period may include minor adjustments from
previous production periods.
>>

Production volumes averaged 66,976 boe per day in the first quarter of
2008 up four per cent from the same period in 2007. The Dawson area produced
7,250 boe per day throughout the first quarter as a result of wells drilled in
2007 that were brought on stream in December 2007 once the new West Doe third
party processing facility was brought on-line. Strong operational performance
has resulted in increased volumes in southeast Saskatchewan and the Pouce
Coupe area. Looking ahead to the second quarter, the Trust is anticipating a
decrease in volumes resulting from scheduled turnarounds, including a planned
turnaround at Redwater which is expected to shut in production of 4,100 boe
per day for at least 15 days in June 2008. A turnaround of this magnitude has
not been completed for several years at Redwater and there is uncertainty as
to the amount of time that will be required to complete all the necessary
work. At this time, the Trust is maintaining its annual production guidance of
63,000 boe per day and will plan to reforecast full year volumes in
conjunction with the second quarter release.
Table 9 summarizes the Trust's first quarter production by core area:
<<
Table 9

Three Months Ended Three Month Ended
March 31, 2008 March 31, 2007
-------------------------------------------------------------------------
Production
Core Total Oil Gas NGL Total Oil Gas NGL
Area(1) (boe/d) (bbl/d)(mmcf/d)(bbl/d) (boe/d) (bbl/d)(mmcf/d)(bbl/d)
-------------------------------------------------------------------------
Central AB 7,770 1,460 30.3 1,263 8,492 1,782 31.9 1,390
Northern AB
& BC 23,474 5,906 96.4 1,500 20,121 6,073 74.7 1,607
Pembina &
Redwater 13,998 9,460 21.6 938 13,731 9,535 18.9 1,046
S.E. AB &
S.W. Sask. 10,041 985 54.2 16 10,322 1,119 55.2 8
S.E. Sask.
& MB 11,693 11,253 1.8 139 11,509 11,011 2.3 110
-------------------------------------------------------------------------
Total 66,976 29,064 204.3 3,856 64,175 29,520 183.0 4,161
-------------------------------------------------------------------------

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

Revenue

Revenue increased to a historical high of $407.9 million in the first
quarter of 2008. The increase in revenue was attributable to both higher
realized oil prices and overall increased production volumes. Prior to hedging
activities, ARC's total realized commodity price was $66.67 per boe in the
first quarter of 2008, a 25 per cent increase from the $53.18 per boe received
prior to hedging in 2007.
A breakdown of revenue is as follows:

<<
Table 10
-------------------------------------------------------------------------
Revenue Three months ended March 31
($ millions) 2008 2007 % Change
-------------------------------------------------------------------------
Oil revenue 237.3 161.5 47
Natural gas revenue 145.0 127.7 14
NGL revenue 24.1 18.0 34
-------------------------------------------------------------------------
Total commodity revenue 406.4 307.2 32
Other revenue 1.5 0.6 150
Total revenue 407.9 307.8 33
-------------------------------------------------------------------------
>>

The oil and natural gas prices realized by the Trust are based upon
quality and transportation differentials from major North American commodity
postings. The Trust's realized oil price was 93 per cent of the Edmonton
posted oil prices, the same as that received in the comparable quarter of
2007, however the differential widened out to $7.07 per barrel as a result of
higher posted prices. The Trust's natural gas prices of $7.80 per mcf was
higher than the AECO monthly average in the quarter of $7.13 per mcf as a
result of volumes sold at the AECO daily index that on average was higher than
the monthly index for the first quarter of 2008.

<<
Table 11
-------------------------------------------------------------------------
Three months ended March 31
-------------------------------------------------------------------------
2008 2007 % Change
-------------------------------------------------------------------------
Average Benchmark Prices
AECO gas ($/mcf)(1) 7.13 7.46 (4)
WTI oil (US$/bbl)(2) 97.96 58.12 69
Cdn$/US$ foreign exchange rate 1.01 1.18 16
Edmonton Posted oil (Cdn $/bbl) 97.34 68.09 43
-------------------------------------------------------------------------
ARC Realized Prices Prior to Hedging
Oil ($/bbl) 89.72 60.79 48
Natural gas ($/mcf) 7.80 7.75 1
NGL ($/bbl) 68.54 48.04 43
-------------------------------------------------------------------------
Total commodity revenue before
hedging ($/boe) 66.67 53.18 25
Other revenue ($/boe) 0.27 0.11 145
Total revenue before hedging ($/boe) 66.94 53.29 26
-------------------------------------------------------------------------
(1) Represents the AECO monthly posting.
(2) WTI represents West Texas Intermediate posting as denominated in US$.
>>

Risk Management and Hedging Activities

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

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

Risk Management Crude Foreign
Contracts Oil & Natural Curr- Q1 2008 Q1 2007
($ millions) Liquids Gas ency(3) Interest Total Total
-------------------------------------------------------------------------
Realized cash
gain (loss) on
contracts(1) (16.5) 0.4 0.1 (13.5) (29.5) 7.0
Unrealized gain
(loss) on
contracts(2) (15.7) (12.3) 6.6 2.7 (18.7) (20.9)
-------------------------------------------------------------------------
Total gain (loss)
on risk management
contracts (32.2) (11.9) 6.7 (10.8) (48.2) (13.9)
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.
(3) Unrealized gain on foreign currency contracts includes a $7.5 million
dollar gain on contracts related to repayments of the Trust's U.S.
denominated long-term debt as well as a $0.9 million loss for foreign
currency contracts related the Trust's crude oil contracts. See the
Foreign Exchange Gains and Losses section of this MD&A for further
details on the debt related contracts.
>>

During the first quarter of 2008, the Trust decided not to proceed with
its planned private note debt issuance due to the continued uncertainty in the
U.S. financial markets. As a result, the Trust unwound the treasury lock
contracts that had been entered into to manage the interest rate exposure for
the planned debt issuance. At December 31, 2007, the mark-to-market value of
the treasury lock contracts was a loss of $7.4 million. These contracts were
considered an effective hedge at year-end therefore, the loss was recorded as
part of Other Comprehensive Income. Upon canceling the debt issuance, the
Trust was no longer able to apply hedge accounting and as a result the full
cost of $13.6 million to unwind the transactions was recorded as a realized
loss on risk management contracts which decreased net income and cash flow
from operating activities in the first quarter of 2008.
The most significant change of ARC's total unrealized mark-to-market
position at quarter end was a $15.1 million loss relating to the Redwater and
NPCU hedged volumes of 5,000 bbl per day, which limits US$ WTI price potential
to $85 and $90 per barrel in 2008 and 2009 respectively. When these properties
were acquired in 2005, the acquisition economics were based on crude oil
prices of approximately US$57.50 per barrel.
For the remainder of 2008 the percentage of forecast volumes protected
is: 50 per cent in the second quarter, 32 per cent in the third quarter and
29 per cent in the fourth quarter.
Table 13 is an indicative summary of the Trust's positions for crude oil,
natural gas and related foreign exchange for the next twelve months as at
March 31, 2008:

<<
Table 13
-------------------------------------------------------------------------
Hedge Positions
As at March 31, 2008(1)(2)
Q2 2008 Q3 2008
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 89.04 13,000 90.00 10,000
Bought Put 70.93 16,000 68.13 10,000
Sold Put 55.58 12,000 51.07 7,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 8.75 92,202 8.51 61,101
Bought Put 6.95 92,202 6.85 61,101
Sold Put 5.10 31,101 5.10 31,101
-------------------------------------------------------------------------
Foreign Exchange Cdn$/US$ $Million Cdn$/US$ $Million
-------------------------------------------------------------------------
Bought Put 1.075 3.00 1.075 3.00
Sold Put 1.030 3.00 1.030 3.00
Swap 1.015 12.00 1.015 12.00
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Hedge Positions
As at March 31, 2008(1)(2)
Q4 2008 Q1 2009
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 90.00 10,000 90.00 5,000
Bought Put 68.13 10,000 55.00 5,000
Sold Put 51.07 7,000 40.00 5,000
-------------------------------------------------------------------------
Natural Gas Cdn$/GJ GJ/day Cdn$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 9.48 48,570 10.22 42,202
Bought Put 7.26 48,570 7.59 42,202
Sold Put 5.17 10,480 - -
-------------------------------------------------------------------------
Foreign Exchange Cdn$/US$ $Million Cdn$/US$ $Million
-------------------------------------------------------------------------
Bought Put 1.075 3.00 - -
Sold Put 1.030 3.00 - -
Swap 1.015 12.00 - -
-------------------------------------------------------------------------
(1) The prices and volumes noted above represent averages for several
contracts and the average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. Viewing the average price of a group of options is purely
for indicative purposes. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price. In addition to positions
shown here, ARC has entered into additional basis positions.
(2) Please refer to note 9 to the Notes to the Consolidated Financial
Statements for full details of the Trust's hedging positions as at
March 31, 2008.

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

- If the market price is below $55.58, ARC will receive $70.93 less the
difference between $55.58 and the market price on 12,000 barrels per
day. For example if the market price is $55.57, the Trust will
receive $70.92 on 12,000 barrels per day.
- If the market price is between $55.58 and $70.93, ARC will receive
$70.93 on 16,000 barrels per day.
- If the market price is between $70.93 and $89.04, ARC will receive
the market price on 16,000 barrels per day.
- If the market price exceeds $89.04, ARC will receive $89.04 on
13,000 barrels per day and the market price for the remaining
3,000 hedged volumes.
>>

Operating Netbacks

The Trust's operating netback, after realized commodity and related
foreign exchange hedging losses increased 20 per cent to $42.18 per boe in the
first quarter of 2008 compared to $35.05 per boe in 2007. The increase in
netbacks in 2008 is primarily due to a 26 per cent increase in the Trust's
weighted average sales price. The large increase in revenue was partially
offset by an increase in royalty costs and operating costs. In addition, the
Trust's realized hedging loss of $2.63 per boe in the first quarter of 2008
decreased the netback as compared to realized hedging gains of $1.21 per boe
that were recorded in the first quarter of 2007 as an increase to the netback.
The components of operating netbacks are shown in Table 14:

<<
Table 14
-------------------------------------------------------------------------
Crude Heavy Q1 2008 Q1 2007
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 90.95 64.43 7.80 68.54 66.67 53.08
Other revenue - - - - 0.27 0.11
Total revenue 90.95 64.43 7.80 68.54 66.94 53.29
Royalties (14.20) (6.71) (1.54) (19.64) (11.85) (9.65)
Transportation (0.03) (1.31) (0.22) - (0.73) (0.81)
Operating costs(1) (11.35) (10.90) (1.37) (8.11) (9.55) (8.99)
-------------------------------------------------------------------------
Netback prior to
hedging 65.37 45.51 4.67 40.79 44.81 33.84
Realized gain (loss)
on risk management
contracts(2) (6.50) - 0.02 - (2.63) 1.21
-------------------------------------------------------------------------
Netback after
hedging 58.87 45.51 4.69 40.79 42.18 35.05
-------------------------------------------------------------------------
(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
(2) Realized loss on risk management contracts excludes the settlement
amount for the treasury interest rate lock contracts that were
unwound during the first quarter of 2008.
>>

Royalties as a percentage of pre-hedged commodity revenue net of
transportation costs remained constant at 18 per cent for both 2008 and 2007
at $11.85 per boe and $9.65 per boe, respectively. The Trust's current
estimate, using forward prices as of the date of this MD&A, is that under the
New Royalty Framework ("Framework"), the corporate average royalty rate for
the Trust will increase from 18 per cent to approximately 23 per cent of
revenue. This estimate will vary based on prices, production decline of
existing wells and performance and location of new wells drilled.
On April 10, 2008, the Alberta Government announced revisions to the
Framework, that will take effect on January 1, 2009. The revisions to the
Framework include a deep resource program that will provide royalty relief for
high cost oil and natural gas development. The program only applies to oil
wells greater than 2,000 metres in depth and natural gas wells greater than
2,500 metres in depth. The Trust does not perceive that this revision will
benefit the Trust's current drilling portfolio.
The Trust is actively working with its production accounting system
provider to ensure that the proper infrastructure will be in place to allow
the Trust to accurately calculate royalties in accordance with the new
Framework starting on January 1, 2009.
Operating costs increased to $9.55 per boe in the first quarter of 2008
compared to $8.99 per boe in 2007. For 2008, the Trust has budgeted $10.20 per
boe based on production of 63,000 barrels per day. The Trust expects a large
increase in second quarter operating costs as a result of significant
turnarounds that are scheduled for the summer months. Total operating costs
are still projected to be approximately $235 million for the full year of
2008.
Transportation costs were constant year over year and averaged $0.73 per
boe in the first quarter of 2008.

General and Administrative Expenses and Trust Unit Incentive Compensation

Cash G&A expenses net of overhead recoveries on operated properties
increased six per cent to $9.3 million in the first quarter of 2008 from
$8.8 million in 2007. Increases in G&A expenses for 2008 were due to increased
staff levels and higher compensation costs.
The Trust accrued $11.9 million under the Whole Trust Unit Incentive Plan
("Whole Unit Plan") in first quarter of 2008 compared to $0.3 million in 2007.
The large increase in the accrued expense for 2007 was as a result of the
appreciation in the trust unit price which closed at $26.38 on March 31, 2008
as compared to $21.25 on March 31, 2007 and $20.40 on December 31, 2007. At
this time, the Trust is revising 2008 full year guidance for G&A to $3.00 per
boe, an increase of $0.45 per boe. The revision is due to the increase in LTIP
expense resulting from the appreciation in the unit price and relative
performance amongst the Trust's peers.
The Trust did not make any payments under the Whole Unit Plan for the
first quarter of 2008. A cash payment occurred in April 2008 and included a
payout for the performance units issued in April of 2005. The actual payment
for April was $18.3 million of which $14.5 million was recorded in G&A with
the remainder $3.8 million being recorded to operating costs and capital
projects. Cash flow from operating activities will be reduced by the full cash
payment amount in the second quarter.
Table 15 is a breakdown of G&A and trust unit incentive compensation
expense:

<<
Table 15
Three Months Ended March 31
-------------------------------------------------------------------------
G&A and Trust Unit Incentive
Compensation Expense
($ millions except per boe) 2008 2007 % Change
-------------------------------------------------------------------------
G&A expenses 13.2 13.4 (2)
Operating recoveries (3.9) (4.6) (15)
Whole Unit Plan - cash - - -
- accrued 11.9 0.3 3867
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense 21.2 9.1 133
Total G&A and trust unit incentive
compensation expense per boe 3.47 1.58 120
-------------------------------------------------------------------------
>>

Whole Unit Plan

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

<<
Table 16
-------------------------------------------------------------------------
Whole Unit Plan
(units in thousands and $ millions Number Number Total RTUs
except per unit) of RTUs of PTUs and PTUs
-------------------------------------------------------------------------
Balance, beginning of period 746 903 1,649
Forfeited in the period (10) (2) (12)
-------------------------------------------------------------------------
Balance, end of period(1) 736 901 1,637
-------------------------------------------------------------------------
Estimated distributions to vesting date(2) 189 308 497
Estimated units upon vesting after
distributions 925 1,209 2,134
Performance multiplier(3) - 1.6 -
-------------------------------------------------------------------------
Estimated total units upon vesting 925 1,934 2,859
-------------------------------------------------------------------------
Trust unit price at March 31, 2008 $26.38 $26.38 $26.38
Estimated total value upon vesting $24.4 $51.0 $75.4
-------------------------------------------------------------------------
(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 March 31, 2008 based on a weighted average calculation of
all outstanding grants. The performance multiplier is assessed each
period end based on actual results of the Trust relative to its
peers.

The value associated with the RTUs and PTUs is expensed in the statement
of income over the vesting period with the expense amount being determined by
the unit price, the number of PTUs to be issued on vesting, and distributions.
Therefore, the expense recorded in the statement of income fluctuates over
time.
Table 17 is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier and units
outstanding as at March 31, 2008:

Table 17
-------------------------------------------------------------------------
Value of Whole Unit Plan as at
March 31, 2008 Performance multiplier
(units thousands and $ millions ----------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated units to vest
RTUs 925 925 925
PTUs - 1,209 2,418
-------------------------------------------------------------------------
Total units(1) 925 2,134 3,343
-------------------------------------------------------------------------
Trust unit price(2) 26.38 26.38 26.38
Trust unit distributions per month(2) 0.20 0.20 0.20
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting 24.4 56.3 88.2
-------------------------------------------------------------------------
Officers 2.6 17.3 32.0
Directors 1.9 1.9 1.9
Staff 19.9 37.1 54.3
-------------------------------------------------------------------------
Total payments under Whole Unit Plan(3) 24.4 56.3 88.2
-------------------------------------------------------------------------
2008 11.1 20.3 29.5
2009 8.4 18.5 28.5
2010 4.9 17.5 30.2
-------------------------------------------------------------------------
(1) Includes additional estimated units to be issued for accrued
distributions to vesting date.
(2) Values will fluctuate over the vesting period based on the volatility
of the underlying trust unit price and distribution levels. Assumes
future trust unit price of $26.38 per trust unit and distributions of
$0.20 per unit per month based on current levels.
(3) Upon vesting, a cash payment is made equivalent to the value of the
underlying trust units. The payment is made on vesting dates in April
and October of each year and at that time is reflected as a reduction
of cash flow from operating activities.
>>

Due to the variability in the future payments under the plan, the Trust
estimates that between $24.4 million and $88.2 million will be paid out from
2008 through 2010 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.

Interest Expense

Interest expense decreased to $8.8 million in the first quarter of 2008
from $9.9 million in 2007 due to a decrease in interest rates. Current U.S.
treasury interest rates have decreased by two per cent in the first four
months of 2008 resulting in lower borrowing costs for the Trust in 2008. In
addition, the Bank of Canada followed the U.S. by posting rate reductions of
75 basis points. As at March 31, 2008, the Trust had $720 million of debt
outstanding, of which $224 million was fixed at a weighted average rate of
five per cent and $496 million was floating at current market rates plus a
credit spread of 60 basis points. Fifty-three per cent of the Trust's debt is
denominated in U.S. dollars.

Foreign Exchange Gains and Losses

In the first quarter of 2008, the Trust recorded a loss of $15 million on
foreign exchange transactions compared to a gain of $5 million in 2007. These
amounts include both realized and unrealized foreign exchange gains and
losses.
Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements.
Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The movement of the Canadian dollar at the end
of the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain/loss impacts net income but
does not impact cash flow from operating activities as it is a non-cash
amount. From December 31, 2007 to March 31, 2008, the Cdn$/US$ exchange rate
decreased from 1.01 to 0.97 creating an unrealized loss of $15 million on U.S.
dollar denominated debt. ARC has entered into forward contracts to lock in
exchange rates for principle repayments on US$127.2 million of the
US$218 million debt outstanding. The forward contracts had a mark-to-market
gain position at March 31, 2008 of $9.6 million. This amount has been included
in the unrealized risk management contracts on the Consolidated Statement of
Income and Deficit.

Taxes

In the first quarter of 2008 the Trust recorded a future income tax
expense of $0.5 million versus an income tax recovery of $11.4 million in the
first quarter of 2007. The future tax liability on the balance sheet reflects
the estimated tax liability associated with the Trust's income tax pools being
less than the net book value of the Trust's assets. Each quarter as the Trust
makes distributions it effectively passes the taxable income in the current
period on to it's unitholders.
On February 26, 2008, the Federal Government announced as part of the
Federal budget that the provincial component of the Trust tax is to be
calculated based on the general provincial rate in each province in which the
Trust has a permanent establishment. This is the same way a corporation would
calculate its provincial tax rate, and is different than the original
calculation of the Trust tax which had a deemed provincial rate of 13 per cent
rather than Alberta's provincial rate of 10 per cent. There will no longer be
a difference in the provincial rate applicable to a Trust as compared to a
corporation. At the time of writing this MD&A, the Federal budget had not been
substantively enacted and therefore, a reduction in the tax rate used for the
Trust's future income tax calculation has not been reflected. Management and
the Board of Directors continue to review the impact of this tax on our
business strategy and while there has not been a decision as to ARC's future
direction, at this time we are of the opinion that the conversion from trust
to a corporation may be the most logical and tax efficient alternative for ARC
unitholders. We expect future technical interpretations and details will
further clarify the legislation. At the present time, ARC believes that if
structural or other similar changes are not made, the after-tax distribution
amount in 2011 to taxable Canadian investors will remain approximately the
same, however, will decline for both tax-deferred Canadian investors (RRSPs,
RRIFs, pension plans, etc.) and foreign investors.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate decreased to
$15.92 per boe in the first quarter of 2008 from $16.36 per boe in 2007. The
lower DD&A rate is driven by the Trust's increased amount of undeveloped land
which is excluded from the depletable base when calculating the rate. Total
depletion of oil & gas assets increased by $3.1 million due to an increase in
the Trust's production volumes for the quarter.
A breakdown of the DD&A rate is as follows:

<<
Table 18
-------------------------------------------------------------------------
Three Months Ended March 31
-------------------------------------------------------------------------
DD&A Rate
($ millions except per boe amounts) 2008 2007 % Change
-------------------------------------------------------------------------
Depletion of oil & gas assets(1) 94.7 91.6 3
Accretion of asset retirement
obligation(2) 2.3 2.9 (21)
-------------------------------------------------------------------------
Total DD&A expense 97.0 94.5 3
DD&A rate per boe 15.92 16.36 (3)
-------------------------------------------------------------------------
(1) Includes depletion of the capitalized portion of the asset retirement
obligation that was capitalized to the PP&E balance and is being
depleted over the life of the reserves.
(2) Represents the accretion expense on the asset retirement obligation
during the year.
>>

Capital Expenditures and Net Acquisitions

During the first quarter of 2008, the Trust spent $111.3 million on
capital expenditures which includes $28.8 million for purchases of undeveloped
land at land sales. In addition, $10.1 million was spent on net acquisitions
of both producing property acquisitions and undeveloped land property
acquisitions. The following summarizes the Trust's first quarter spending as
it relates to our key strategic focus areas:

Resource Plays
Total spending of $20.3 million excluding land purchases for projects in
the Montney resource play as well as the Trust's natural gas from coal ("NGC")
projects. In the Montney, ARC spent a total of $16.6 million during the
quarter that included costs to drill four horizontal wells in Dawson that are
expected to be completed in the third quarter as well as costs for seismic in
the Sunrise area. In addition, $3.7 million was spent on NGC projects during
the quarter.

EOR Initiatives
Total spending of $10 million included $2.3 million spent towards
completing a 40 well infill drilling program at Weyburn where the Trust
participates in the CO(2) flooding project that is operated by EnCana. In
addition, the Trust has spent $2.6 million on the Redwater CO(2) injection
pilot project.

Conventional Assets
Total spending of $52.2 million, excluding land purchases, for various
projects including drilling and completing 11 oil wells (7.3 net) in the
Pembina Cardium area, eight of which were brought on production during the
quarter, in southwest Saskatchewan, 22 shallow gas wells were drilled with a
total 24 wells brought on production including two wells that were drilled in
the fourth quarter of 2007. In addition, the Trust spent approximately $3
million on seismic in Ante Creek and other core areas as well as $3.7 million
on a horizontal injection well at Ante Creek as part of a secondary recovery
waterflood project.

Acquisitions and Dispositions
Total net spending in the quarter was $10.1 million. The Trust acquired
undeveloped lands through property acquisitions for $13.9 million. This was
offset by minor undeveloped land property dispositions of $3.7 million.
A breakdown of capital expenditures and net acquisitions is shown in
Table 19:

<<
Table 19
-------------------------------------------------------------------------
Three Months Ended March 31
-------------------------------------------------------------------------
Capital Expenditures
($ millions) 2008 2007 % Change
-------------------------------------------------------------------------
Geological and geophysical 5.5 4.9 12
Drilling and completions 64.4 55.1 17
Plant and facilities 11.6 16.8 (31)
Undeveloped land 28.8 0.2 14,300
Other capital 1.0 0.5 100
-------------------------------------------------------------------------
Total capital expenditures 111.3 77.5 44
-------------------------------------------------------------------------
Producing property acquisitions(1) - 0.2 (100)
Undeveloped land property acquisitions 13.9 - 100
Producing property dispositions(1) (0.2) - 100
Undeveloped land property dispositions (3.6) - 100
-------------------------------------------------------------------------
Total capital expenditures and net
acquisitions 121.4 77.7 56
-------------------------------------------------------------------------
(1) Value is net of post-closing adjustments.
>>

Approximately 72 per cent of the $111.3 million capital program in the
first quarter of 2008 was financed with cash flow from operating activities
compared to 59 per cent in 2007. Property acquisitions were financed through
debt and working capital.

<<
Table 20
-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2008 March 31, 2007
-------------------------------------------------------------------------
Develop- Net Total Develop- Net Total
ment Acquisi- Expendi- ment Acquisi- Expendi-
Capital tions tures Capital tions tures
-------------------------------------------------------------------------
Expenditures 111.3 10.1 121.4 77.5 0.2 77.7
-------------------------------------------------------------------------
Cash flow from
operating
activities 72% - 66% 59% - 59%
Proceeds from
DRIP and
Rights Plan 25% - 23% 36% - 36%
Debt 3% 100% 11% 5% 100% 5%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
>>

Asset Retirement Obligation and Reclamation Fund

The Asset Retirement Obligation ("ARO") decreased by $0.8 million in the
first quarter of 2008 to $139.2 million ($140 million at December 31, 2007)
for future abandonment and reclamation of the Trust's properties.
Included in the March 31, 2008 ARO balance is a $0.6 million increase
related to development activities in the first quarter of 2008. The ARO
liability was also increased by $2.3 million for accretion expense in the
first quarter and was reduced by $3.7 million for actual abandonment
expenditures incurred in the first quarter of 2008.
The Trust maintains two reclamation funds that together held $26.1
million at March 31, 2008, one exclusively for the reclamation of the Redwater
property and the other for all of the Trust's other properties.
In total, ARC contributed $3 million cash to its reclamation funds in the
first quarter of 2008 and earned interest of $0.3 million on the fund
balances. The fund balances were reduced by $3.6 million for cash-funded
abandonment expenditures in the first quarter of 2008.

Capitalization, Financial Resources and Liquidity

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

<<
Table 21
-------------------------------------------------------------------------
Capital Structure and Liquidity March 31, December 31,
($ millions except per cent and ratio amounts) 2008 2007
-------------------------------------------------------------------------
Net debt obligations(1) 770.1 752.7
Market value of trust units and exchangeable
shares(2) 5,663.8 4,349.3
-------------------------------------------------------------------------
Total capitalization(3) 6,433.9 5,102.0
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 12.0% 14.8%
Net debt to annualized cash flow from operating
activities 0.9 1.1
-------------------------------------------------------------------------
(1) Net debt is a non-GAAP measure and is calculated as long-term debt
plus current liabilities less the current assets as they appear on
the Consolidated Balance Sheets. Net debt excludes current unrealized
amounts pertaining to risk management contracts and the current
portion of future income taxes.
(2) Calculated using the total units outstanding at March 31, 2008
including the total number of units issuable for exchangeable shares
at March 31, 2008 multiplied by the closing trust unit price of
$26.38.
(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 has a Cdn$800 million syndicated credit facility that expires
in April 2010 and a Cdn$25 million demand working capital facility in addition
to US$218 million in senior secured notes currently outstanding. On April 15,
2008 ARC extended the credit facility to April 2011 under the same terms. This
facility was arranged by RBC Capital Markets and Scotia Capital and includes
an additional nine domestic and international banks. The Trust's debt
agreements contain a number of covenants all of which were met as at March 31,
2008; these agreements are available at www.SEDAR.com. The major financial
covenants are described below:

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

As at March 31, 2008 ARC has approximately $300 million available under
its bank credit facility and the ability to issue an additional $100 million
of long-term notes under an agreement with one lender. This option, which will
expire in May 2009, would allow the Trust to issue long-term notes at a rate
equal to the related U.S. treasuries corresponding to the term of the notes
plus an appropriate credit risk adjustment at the time of issuance.

Unitholders' Equity

At March 31, 2008, there were 214.7 million trust units issued and
issuable for exchangeable shares, an increase of 1.5 million trust units from
December 31, 2007. The increase in number of trust units outstanding is mainly
attributable to the 1.2 million trust units issued pursuant to the DRIP during
the first quarter of 2008 at an average price of $21.49 per unit.
The Trust had 28 thousand rights outstanding as of March 31, 2008 under
an employee plan where further rights issuances were discontinued in 2004. The
rights have a five-year term and vested equally over three years from the date
of grant. The remaining rights may be exercised to purchase trust units at an
average adjusted exercise price of $9.36 per unit as at March 31, 2008. All of
the rights were fully vested at December 31, 2007 and will expire on or before
December 31, 2008.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so at a
five per cent discount to the prevailing market price with no additional fees
or commissions. During the first quarter of 2008, the Trust raised proceeds of
$25.8 million and issued 1.2 million trust units pursuant to the DRIP.

Distributions

ARC declared distributions of $126.8 million ($0.60 per unit),
representing 60 per cent of 2008 first quarter cash flow from operating
activities compared to distributions of $123.1 million ($0.60 per unit),
representing 71 per cent of cash flow from operating activities in 2007.
Monthly distributions for the first quarter of 2008 were $0.20 per unit.
In light of the strong commodity price environment, the Board of Directors
have re-affirmed our base distribution of $0.20 per unit and have approved a
monthly "top-up" distribution of $0.04 per unit. This will bring ARC's total
distribution to $0.24 per unit per month beginning with the June 16, 2008
payment. The "top-up distribution will be reviewed on a quarterly basis but is
expected to stay in place as long as commodity prices maintain their current
strength. Revisions are approved at the discretion of the Board of Directors
and are normally announced on a quarterly basis in the context of prevailing
and anticipated commodity prices at that time. The following items, outlined
in Table 22, may be deducted from cash flow from operating activities to
arrive at distributions to unitholders: the portion of capital expenditures
that are funded with cash flow from operating activities, an annual
contribution to the reclamation funds, debt principal repayments from time to
time as determined by the board of directors and income taxes that are not
passed on to unitholders.
Cash flow from operating activities and distributions in total and per
unit are detailed in Table 22:

<<
Table 22
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31 March 31
($millions) ($ per unit)
Cash flow from
operating activities
and distributions 2008 2007 % Change 2008 2007 % Change
-------------------------------------------------------------------------
Cash flow from
operating activities 209.9 172.3 22 0.98 0.83 18
Reclamation fund
contributions(1) (3.3) (3.3) - (0.02) (0.02) -
Capital expenditures
funded with cash
flow from operating
activities (79.8) (45.9) 74 (0.37) (0.22) 68
Other(2) - - - 0.01 0.01 -
-------------------------------------------------------------------------
Distributions 126.8 123.1 3 0.60 0.60 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes interest income earned on the reclamation fund balances that
is retained in the reclamation funds.
(2) Other represents the difference due to distributions paid being based
on actual trust units outstanding at each distribution date whereas
per unit cash flow from operating activities, reclamation fund
contributions and capital expenditures funded with cash flow from
operating activities are based on weighted average outstanding trust
units in the year plus trust units issuable for exchangeable shares
at year-end.
>>

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

Environmental Legislation impacting the Trust

The Alberta government announced legislation (Bill 3) to reduce
greenhouse gas emissions on March 8, 2007. At this time, the Trust has
determined that the impact of this legislation is minimal and limited to ARC's
very minor working interest in several facilities subject to this legislation.
As a follow-up to the Federal Government's previously announced
"Greenhouse Gas Regulatory Framework" additional information has been provided
as of March 2008. Proposed regulations are expected to come into force on
January 1, 2010. In all sectors, the required reduction from 2006 emission
intensity will be 18 per cent by the beginning of 2010, with two per cent
continuous improvement every year after that, as laid out in the April 2007
framework. For the upstream oil and gas sector, each facility receives an
individual target of an 18 per cent reduction from its own 2006 emission
intensity.
On February 19, 2008 the British Columbia government introduced a
consumer-based carbon tax. ARC will be required to pay tax on all fuel used in
the course of operations in that province. The legislation takes effect on
July 1, 2008.
ARC continues to monitor the regulatory landscape in order to assess
current and potential future impacts on our business. At present, the Trust
has assessed that the above mentioned legislation will negatively impact the
Trust by less than $1 million per year.

Contractual Obligations and Commitments

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

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

Table 23
-------------------------------------------------------------------------
Payments Due by Period
-------------------------------------------------------------------------
($ millions) 2008 2009-2010 2011-2012 Thereafter Total
-------------------------------------------------------------------------
Debt repayments(1) 6.2 539.3 53.5 121.0 720.0
Interest payments(2) 11.1 20.8 16.0 14.1 62.0
Reclamation fund
contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase commitments 7.3 5.2 4.3 6.3 23.1
Operating leases 5.1 8.6 12.3 88.0 114.0
Derivative contract
premiums(4) 9.7 2.9 - - 12.6
-------------------------------------------------------------------------
Total contractual
obligations (1) 45.2 587.0 95.0 301.3 1,028.5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest. On April 15,
2008, ARC extended the credit facility to 2011 under the same
terms. With this extension, the total contractual obligations in
years 2009 - 2010 are decreased to $91 million and increased to $591
million in years 2011 - 2012.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
>>

The risk management contract premiums noted in Table 23 are part of the
Trust's commitments related to its risk management program. In addition to
these premiums, the Trust has 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 March 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 2008 capital budget has
been approved by the Board at $435 million. This commitment has not been
disclosed in the commitment table (Table 23) as it is of a routine nature and
is part of normal course of operations for active oil and gas companies and
trusts.
The operating leases noted in Table 23 include amounts for the Trust's
head office lease. The current lease expires in May 2010. In December 2007,
the Trust entered into a 13 year lease commitment beginning in 2010 for office
space in a new building that is under construction in downtown Calgary. The
new lease commitment is reflected in Table 23. In addition to the lease
commitments included in Table 23, the Trust will incur additional costs to
design and construct the office space. No material commitments have been
entered into at this time, however the Trust has currently committed to costs
of less than $1 million for consulting costs related to the build out of the
office space.
The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the commitment table does not include any
commitments for outstanding litigation and claims.
The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table as
it is of a routine nature and is part of normal course of operations.

Off Balance Sheet Arrangements

The Trust has certain lease agreements, all of which are reflected in the
Contractual Obligations and Commitments table (Table 23), which were entered
into in the normal course of operations. All leases have been treated as
operating leases whereby the lease payments are included in operating expenses
or G&A expenses depending on the nature of the lease. No asset or liability
value has been assigned to these leases in the balance sheet as of March 31,
2008.

Critical Accounting Estimates

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

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

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

Internal Controls over Financial Reporting & Disclosure Controls and
Procedures

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

Financial Reporting Update

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.

Capital Disclosures

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

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

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

Forward-Looking Statements

This discussion and analysis contains forward-looking statements as to
the Trust's internal projections, expectations or beliefs relating to future
events or future performance within the meaning of the "safe harbour"
provisions of the United States Private Securities Litigation Reform Act of
1995 and the Securities Act (Ontario). In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions and, in
particular, includes the material under the heading "2007 Review and 2008
Guidance". These statements represent management's expectations or beliefs
concerning, among other things, future operating results and various
components thereof or the economic performance of ARC Energy Trust ("ARC" or
"the Trust"). The projections, estimates and beliefs contained in such
forward- looking statements are based on management's assumptions relating to
the production performance of ARC's oil and gas assets, the cost and
competition for services throughout the oil and gas industry in 2007, the
continuation of ARC's historical experience with expenses and production,
changes in the capital expenditure budgets relating to undeveloped land or
reserve acquisitions, and the continuation of the current regulatory and tax
regime in Canada, and necessarily involve known and unknown risks and
uncertainties, including the business risks discussed in this MD&A, and
related to management's assumptions set forth herein, which may cause actual
performance and financial results in future periods to differ materially from
any projections of future performance or results expressed or implied by such
forward-looking statements. Accordingly, readers are cautioned that events or
circumstances could cause actual results to differ materially from those
predicted. Other than the 2008 Guidance which is updated and discussed
quarterly, the Trust does not undertake to update any forward looking
information in this document whether as to new information, future events or
otherwise except as required by securities laws and regulations.

Additional Information

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

<<
QUARTERLY HISTORICAL REVIEW
-------------------------------------------------------------------------
(Cdn $ millions, except
per unit amounts) 2008 2007
-------------------------------------------------------------------------
FINANCIAL Q1 Q4 Q3 Q2 Q1
Revenue before royalties 407.9 338.0 300.2 305.6 307.8
Per unit(1) 1.91 1.59 1.42 1.46 1.48
Cash flow from operating
activities(2) 209.9 173.7 179.6 179.4 172.3
Per unit - basic(1) 0.98 0.82 0.85 0.86 0.83
Per unit - diluted 0.98 0.82 0.85 0.86 0.83
Net income 81.3 106.3 120.8 184.9 83.3
Per unit - basic(3) 0.39 0.51 0.58 0.90 0.41
Per unit - diluted 0.38 0.51 0.58 0.89 0.41
Distributions 126.8 125.8 125.0 124.1 123.1
Per unit - basic(4) 0.60 0.60 0.60 0.60 0.60
Total assets 3,592.6 3,533.0 3,460.8 3,432.8 3,540.1
Total liabilities 1,560.4 1,491.3 1,421.4 1,415.3 1,526.6
Net debt outstanding(5) 770.1 752.7 699.8 653.9 729.7
Weighted average trust
units(6) 213.8 212.5 210.9 209.5 207.9
Trust units outstanding
and issuable(6) 214.7 213.2 211.7 210.2 208.7
-------------------------------------------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 5.5 3.0 2.9 4.1 4.9
Land 28.8 42.6 33.0 1.7 0.2
Drilling and completions 64.4 75.2 73.4 25.8 55.1
Plant and facilities 11.6 17.9 21.1 16.3 16.8
Other capital 1.0 0.6 1.5 0.6 0.5
Total capital
expenditures 111.3 139.3 131.9 48.5 77.5
Property acquisitions
(dispositions) net 10.1 5.0 27.3 10.0 0.2
Corporate acquisitions(7) - - - - -
Total capital
expenditures and
net acquisitions 121.4 144.3 159.2 58.5 77.7
-------------------------------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 29,064 28,682 28,437 28,099 29,520
Natural gas (mmcf/d) 204.3 187.4 173.3 176.7 183.0
Natural gas liquids
(bbl/d) 3,856 4,067 3,795 4,088 4,161
Total (boe per day
6:1) 66,976 63,989 61,108 61,637 64,175
Average prices
Crude oil ($/bbl) 89.72 77.53 73.40 65.21 60.79
Natural gas ($/mcf) 7.80 6.32 5.52 7.38 7.75
Natural gas liquids
($/bbl) 68.54 62.75 55.64 52.76 48.04
Oil equivalent ($/boe) 66.67 57.26 53.28 54.37 53.18
-------------------------------------------------------------------------
TRUST UNIT TRADING
(based on intra-day
trading) unit prices
High 27.06 21.55 22.60 23.86 23.02
Low 20.00 18.90 19.00 20.78 20.05
Close 26.38 20.40 21.17 21.74 21.25
Average daily volume
(thousands) 863 624 503 599 658
-------------------------------------------------------------------------

-----------------------------------------------------
(Cdn $ millions, except
per unit amounts) 2006
-----------------------------------------------------
FINANCIAL Q4 Q3 Q2
Revenue before royalties 292.5 312.3 306.7
Per unit(1) 1.42 1.52 1.51
Cash flow from operating
activities(2) 159.4 203.4 182.2
Per unit - basic(1) 0.77 0.99 0.89
Per unit - diluted 0.77 0.98 0.89
Net income 56.6 116.9 182.5
Per unit - basic(3) 0.28 0.58 0.91
Per unit - diluted 0.28 0.58 0.91
Distributions 122.3 121.4 120.6
Per unit - basic(4) 0.60 0.60 0.60
Total assets 3,479.0 3,335.8 3,277.8
Total liabilities 1,550.6 1,371.3 1,339.9
Net debt outstanding(5) 739.1 579.7 567.4
Weighted average trust
units(6) 206.5 205.1 203.7
Trust units outstanding
and issuable(6) 207.2 205.7 204.4
-----------------------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 3.7 2.2 2.8
Land 11.8 1.4 14.3
Drilling and completions 79.1 76.2 29.8
Plant and facilities 26.5 24.6 10.9
Other capital 0.8 0.5 0.8
Total capital
expenditures 121.9 104.9 58.6
Property acquisitions
(dispositions) net 76.4 8.4 2.8
Corporate acquisitions(7) 16.6 - -
Total capital
expenditures and
net acquisitions 214.9 113.3 61.4
-----------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 29,605 29,108 27,805
Natural gas (mmcf/d) 179.5 173.4 178.5
Natural gas liquids
(bbl/d) 4,144 4,166 4,247
Total (boe per day
6:1) 63,663 62,178 61,803
Average prices
Crude oil ($/bbl) 58.26 71.84 71.86
Natural gas ($/mcf) 6.99 6.10 6.35
Natural gas liquids
($/bbl) 46.51 56.60 54.44
Oil equivalent ($/boe) 49.82 54.45 54.42
-----------------------------------------------------
TRUST UNIT TRADING
(based on intra-day
trading) unit prices
High 29.22 30.74 28.61
Low 19.20 25.25 24.35
Close 22.30 27.21 28.00
Average daily volume
(thousands) 1,125 614 548
-----------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average trust units outstanding plus trust units
issuable for exchangeable shares.
(2) This is a GAAP measure and a change from the non-GAAP measure
reported in prior reports. Refer to non-GAAP section.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average trust units outstanding
(excluding trust units issuable for exchangeable shares).
(4) Based on number of trust units outstanding at each distribution date.
(5) Net debt excludes the current unrealized risk management contracts
asset and liability and the current portion of future income taxes.
(6) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(7) Represents total consideration for the corporate acquisition
including fees but prior to working capital, asset retirement
obligation and future income tax liability assumed on acquisition.

CONSOLIDATED BALANCE SHEETS (unaudited)
As at March 31 and December 31

(Cdn$ millions) 2008 2007
-------------------------------------------------------------------------
ASSETS
Current assets
Cash $ 2.4 $ 7.0
Accounts receivable (Note 3) 173.9 162.5
Prepaid expenses 18.0 15.0
Risk management contracts (Note 9) 5.8 13.1
Future income taxes 22.4 4.0
-------------------------------------------------------------------------
222.5 201.6
Reclamation funds (Note 4) 26.1 26.1
Risk management contracts (Note 9) 16.1 4.7
Property, plant and equipment 3,170.3 3,143.0
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,592.6 $ 3,533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 5) $ 202.0 $ 180.6
Distributions payable 42.4 42.1
Risk management contracts (Note 9) 77.5 57.6
-------------------------------------------------------------------------
321.9 280.3
Risk management contracts (Note 9) 21.9 28.2
Long-term debt (Note 6) 720.0 714.5
Accrued long-term incentive compensation (Note 15) 19.6 12.1
Asset retirement obligations (Note 7) 139.2 140.0
Future income taxes 337.8 316.2
-------------------------------------------------------------------------
Total liabilities 1,560.4 1,491.3
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 17)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 10) 40.1 43.1

UNITHOLDERS' EQUITY
Unitholders' capital (Note 11) 2,499.3 2,465.7
Contributed surplus (Note 14) 0.2 1.7
Deficit (Note 12) (511.4) (465.9)
Accumulated other comprehensive income (loss)
(Note 12) 4.0 (2.9)
-------------------------------------------------------------------------
Total unitholders' equity 1,992.1 1,998.6
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,592.6 $ 3,533.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
For the three months ended March 31

(Cdn$ millions, except per unit amounts) 2008 2007
-------------------------------------------------------------------------
REVENUES
Oil, natural gas, and natural gas liquids $ 407.9 $ 307.8
Royalties (72.2) (55.8)
-------------------------------------------------------------------------
335.7 252.0
(Loss) gain on risk management contracts (Note 9)
Realized (29.5) 7.0
Unrealized (18.7) (20.9)
-------------------------------------------------------------------------
287.5 238.1
-------------------------------------------------------------------------

EXPENSES
Transportation 4.4 4.7
Operating 58.2 51.9
General and administrative 21.2 9.1
Interest on long-term debt (Note 6) 8.8 9.9
Depletion, depreciation and accretion 97.0 94.5
Loss (gain) on foreign exchange 15.0 (5.0)
-------------------------------------------------------------------------
204.6 165.1
-------------------------------------------------------------------------

Future income tax (expense) recovery (0.5) 11.4
-------------------------------------------------------------------------
Net income before non-controlling interest 82.4 84.4
Non-controlling interest (Note 10) (1.1) (1.1)
-------------------------------------------------------------------------
Net income $ 81.3 $ 83.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Deficit, beginning of period $ (465.9) $ (463.2)
Distributions paid or declared (Note 13) (126.8) (123.1)
-------------------------------------------------------------------------
Deficit, end of period (Note 12) $ (511.4) $ (503.0)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 16)
Basic $ 0.39 $ 0.41
Diluted $ 0.39 $ 0.41
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements

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

(Cdn$ millions) 2008 2007
-------------------------------------------------------------------------
Net income $ 81.3 $ 83.3

Other comprehensive income, net of tax
(Loss) gain on financial instruments
designated as cash flow hedges(1) (2.9) 1.2
De-designation of cash flow hedge(2) (Note 9) 10.0 -
Gains and losses on financial instruments
designated as cash flow hedges in prior
periods realized in net income in the
current period(3) (Note 9) (0.4) (0.1)
Net unrealized gains on available-for-sale
reclamation funds' investments(4) 0.2 -
-------------------------------------------------------------------------
Other comprehensive income 6.9 1.1
-------------------------------------------------------------------------
Comprehensive income $ 88.2 $ 84.4
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other comprehensive loss, beginning
of period (2.9) -
Application of initial adoption - 4.9
Other comprehensive income 6.9 1.1
-------------------------------------------------------------------------
Accumulated other comprehensive income, end of
period (Note 12) $ 4.0 $ 6.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Amount is net of future tax recovery of $1.1 million for the period
ended March 31, 2008 (net of tax liability of $0.5 million in 2007).
(2) Amount is net of future tax recovery of $3.6 million for the period
ended March 31, 2008.
(3) Amount is net of future tax expense of $0.1 million for the period
ended March 31, 2008 (nominal in 2007).
(4) Amount is net of future tax expense of $0.1 million for the period
ended March 31, 2008 (nominal in 2007).

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
For the three months ended March 31

(Cdn$ millions) 2008 2007
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 81.3 $ 83.3
Add items not involving cash:
Non-controlling interest (Note 10) 1.1 1.1
Future income tax expense (recovery) 0.5 (11.4)
Depletion, depreciation and accretion 97.0 94.5
Non-cash loss on risk management contracts
(Note 9) 18.7 20.9
Non-cash loss (gain) on foreign exchange 15.0 (5.2)
Non-cash trust unit incentive compensation
(Notes 14 and 15) 13.8 0.6
Expenditures on site restoration and reclamation
(Note 7) (3.7) (4.7)
Change in non-cash working capital (13.8) (6.8)
-------------------------------------------------------------------------
209.9 172.3
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES
(Repayment) issuance of long-term debt under
revolving credit facilities, net (9.3) 7.8
Issue of trust units 2.8 1.1
Cash distributions paid (Note 13) (101.3) (96.2)
Change in non-cash working capital 0.9 1.7
-------------------------------------------------------------------------
(106.9) (85.6)
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural gas
properties (10.1) (0.2)
Proceeds on disposition of petroleum and natural gas
properties 0.1 -
Capital expenditures (109.4) (77.3)
Net reclamation fund withdrawals (contributions)
(Note 4) 0.2 (1.2)
Change in non-cash working capital 11.6 (10.8)
-------------------------------------------------------------------------
(107.6) (89.5)
-------------------------------------------------------------------------
DECREASE IN CASH (4.6) (2.8)
CASH, BEGINNING OF PERIOD 7.0 2.8
CASH, END OF PERIOD $ 2.4 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements

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

1. SUMMARY OF ACCOUNTING POLICIES

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

2. NEW ACCOUNTING POLICIES

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.

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

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
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.

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

3. FINANCIAL ASSETS AND CREDIT RISK

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

Receivables from oil and natural gas marketers are normally collected
on the 25th day of the month following production. The Trust
historically has not experienced any collection issues with its oil
and natural gas marketers. Joint venture receivables are typically
collected within one to three months of the joint interest billing
being issued to the partner. When determining whether amounts that
are past due are collectable, management assesses the
creditworthiness and past payment history of the
partner/counterparty, as well as the nature of the past due amount.
ARC considers all amounts greater than 90 days to be past due. As at
March 31, 2008 $3.4 million of accounts receivable are past due, all
of which are considered to be collectable. As at March 31, 2008 and
December 31, 2007, the Trust's allowance for doubtful accounts
balance is nil.

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

March 31, December 31,
2008 2007
---------------------------------------------------------------------
Accounts Receivable $ 170.4 $ 159.5
Risk Management Contracts 21.9 6.8
---------------------------------------------------------------------
Maximum Credit Exposure $ 192.3 $ 166.3
---------------------------------------------------------------------
---------------------------------------------------------------------

In order to mitigate concentration of credit risk, the Trust reviews
counterparty exposure on a quarterly basis. The majority of the
$170.4 million and $159.5 million credit exposure on accounts
receivable pertains to the revenue accrual for March 2008 and
December 2007 production volumes, respectively. The Trust markets its
production to a variety of counterparties of which, at March 31,
2008, no one counterparty owed more than 30 per cent of the total
exposure.

4. RECLAMATION FUNDS

March 31, 2008 December 31, 2007
---------------------------------------------------------------------
Un- Un-
restricted Restricted restricted Restricted
---------------------------------------------------------------------
Balance, beginning
of period $ 14.4 $ 11.7 $ 24.8 $ 6.1
Contributions 2.8 0.2 6.2 5.9
Reimbursed
expenditures(1) (2.6) (1.0) (17.5) (0.6)
Interest earned on
funds 0.2 0.1 1.1 0.3
Net unrealized gains
and losses on
available-for-sale
sale investments 0.3 - (0.2) -
---------------------------------------------------------------------
Balance, end of
period(2) $ 15.1 $ 11.0 $ 14.4 $ 11.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by the Trust due
to timing differences and discretionary reimbursements.
(2) As at March 31, 2008 the unrestricted reclamation fund held
$0.5 million in cash and cash equivalents ($1.5 million at
December 31, 2007), with the balance held in investment grade
assets.

For the three and twelve months ended March 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 the statement of income. The fair value of
reclamation fund assets classified as held-to-maturity is
$17.1 million as at March 31, 2008 ($17.8 million as at December 31,
2007). Fair values are obtained from third parties, determined
directly by reference to quoted market prices.

5. FINANCIAL LIABILITIES AND LIQUIDITY RISK

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

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

---------------------------------------------------------------------
$ millions 1 year 2 - 3 4 - 5 Beyond Total
years years 5 years
---------------------------------------------------------------------
Accounts payable and
accrued liabilities 202.0 - - - 202.0
Distributions payable 42.4 - - - 42.4
Risk management contracts 77.5 21.9 - - 99.4
Senior secured notes 6.2 43.4 53.4 121.0 224.0
Syndicated credit
facilities(1) - 496.0 - - 496.0
Accrued long-term
incentive compensation - 19.6 - - 19.6
---------------------------------------------------------------------
Total financial
liabilities (1) 328.1 580.9 53.4 121.0 1,083.4
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) On April 15, 2008, ARC extended the credit facility to 2001
under the same terms. With this extension the total financial
liabilities in years 2 - 3 are decreased to $84.9 million and
increased to $549.4 million in years 4 - 5.

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

6. LONG-TERM DEBT

March 31, December 31,
2008 2007
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility -
Cdn$ denominated $ 335.6 $ 344.9
Syndicated credit facility -
US$ denominated 160.4 154.1
Senior secured notes
5.42% US$ Note 77.1 74.1
4.94% US$ Note 18.5 17.8
4.62% US$ Note 64.2 61.8
5.10% US$ Note 64.2 61.8
---------------------------------------------------------------------
Total long-term debt outstanding $ 720.0 $ 714.5
---------------------------------------------------------------------
---------------------------------------------------------------------

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

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

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

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

During the first quarter of 2008, the weighted-average effective
interest rate under the credit facility was 4.5 per cent
(5.5 per cent in the first three months of 2007).

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

Amounts due under the senior secured notes in the next 12 months of
US$6 million have not been included in current liabilities as
management has the ability and intent to refinance this amount
through the syndicated credit facility. The fair value of senior
secured notes as at March 31, 2008 is $243 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 $0.8 million less than interest
expense. The difference between interest paid and interest expense
for the first three months of 2007 was nominal.

7. ASSET RETIREMENT OBLIGATIONS

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

March 31, December 31,
2008 2007
---------------------------------------------------------------------
Balance, beginning of period $ 140.0 $ 177.3
Increase in liabilities relating to
development activities 0.6 3.8
Decrease in liabilities relating to
change in estimate - (34.4)
Settlement of liabilities during the period (3.7) (18.2)
Accretion expense 2.3 11.5
---------------------------------------------------------------------
Balance, end of period $ 139.2 $ 140.0
---------------------------------------------------------------------
---------------------------------------------------------------------

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

8. CAPITAL MANAGEMENT

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

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

The Trust manages the following capital:

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

When evaluating the Trust's capital structure, management's objective
is to limit net debt to under 2.0 times annualized cash flow from
operating activities and 20 per cent of total capitalization. As at
March 31, 2008 the Trust's net debt to cash flow from operating
activities ratio is 0.9 and its net debt to total capitalization
ratio is 12 per cent.

---------------------------------------------------------------------
($ millions except per unit March 31, December 31,
and per cent amounts) 2008 2007
---------------------------------------------------------------------
Long-term debt 720.0 714.5
Accounts payable and accrued liabilities 202.0 180.6
Distributions payable 42.4 42.1
Cash, accounts receivable and prepaid expenses (194.3) (184.5)
---------------------------------------------------------------------
Net debt obligations(1) 770.1 752.7
---------------------------------------------------------------------

Trust units outstanding and issuable for
exchangeable shares 214.7 213.2
Trust unit price 26.38 20.40
---------------------------------------------------------------------
Market capitalization (1) 5,663.8 4,349.3
Net debt obligations(1) 770.1 752.7
---------------------------------------------------------------------
Total capitalization(1) 6,433.9 5,102.0
---------------------------------------------------------------------

Net debt as a percentage of total
capitalization 12.0% 14.8%
Net debt obligations to annualized cash flow from
operating activities 0.9 1.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Market capitalization, net debt obligations and 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.

Distributions have been held constant at $0.20/unit since
October 2005 and no current taxes have been paid by the Trust in the
three months ended March 31, 2008.

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

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 March 31, 2008
the Trust is in compliance with all covenants. Refer to Note 6 for
further details.

9. MARKET RISK MANAGEMENT

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

In the sections below management has prepared sensitivity analysis 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 analysis, 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, recent trends have shown a correlation between the movement
in the foreign exchange rate of the Canadian dollar to the US dollar
and the West Texas Intermediate posting ("WTI").

Commodity price risk

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

ARC manages the risks associated with changes in commodity prices by
entering into a variety of risk management contracts (see risk
management contracts below). The following table illustrates the
effects of movement in commodity prices on net income due to changes
in the fair value of risk management contracts in place at March 31,
2008. The sensitivity is based on a $20 increase and $10 decrease in
WTI and $1.50 increase and $1.50 decrease in AECO. The commodity
price assumptions are based on management's assessment of reasonably
possible changes in oil and natural gas prices that could occur
between March 31, 2008 and the Trust's next reporting date (June 30,
2008).

---------------------------------------------------------------------
Increase in Decrease in
commodity price commodity price
---------------------------------------------------------------------
Crude Natural Crude Natural
$ millions oil gas oil gas
---------------------------------------------------------------------
Net Income
(Decrease) Increase (54.1) (17.7) 22.9 15.5
---------------------------------------------------------------------

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

Interest Rate Risk

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

If interest rates applicable to floating rate debt and interest rate
swaps were to have increased by 100 bps (1 per cent) it is estimated
that the Trust's net income would decrease by $3.9 million, of which
$0.9 million is the result of increased interest expense and $3
million is due to the change in fair value of risk management
contracts in place at March 31, 2008. An opposite change in interest
rates will result in an opposite impact on net income.

Foreign Exchange Risk

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

ARC has entered into certain risk management contracts to mitigate
these risks (see risk management contracts below). The following
table demonstrates the effect of exchange rate movement on net income
due to changes in the fair value of risk management contracts in
place at March 31, 2008 as well as the unrealized gain or loss on
revaluation of outstanding U.S. denominated debt. The sensitivity is
based on a $0.03 Cdn$/US$ increase and $0.03 Cdn$/US$ decrease in the
foreign exchange rate.

---------------------------------------------------------------------
Cdn$/US$ exchange rate
---------------------------------------------------------------------
$ millions Increase in Decrease in
Cdn$/US$ rate Cdn$/US$ rate
---------------------------------------------------------------------
Gain/Loss on risk management contracts
Increase (Decrease) 1.1 (3.0)
---------------------------------------------------------------------
Gain/Loss on foreign exchange
(Decrease) Increase (8.3) 8.3
---------------------------------------------------------------------
Net Income (Decrease) Increase (7.2) 5.3
---------------------------------------------------------------------

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

Risk Management Contracts

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

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

Financial WTI Crude Oil Contracts

Bought Sold Sold Bought
Volume Put Put Call Call
Term Contract Bbl/d US$/bbl US$/bbl US$/bbl US$/bbl
-------------------------------------------------------------------------
Apr 08 - Jun 08 Collar 2,000 90.00 - 110.00 -
Apr 08 - Jun 08 Put Spread 1,000 85.00 70.00 - -
Apr 08 - Jun 08 Put Spread 500 85.00 69.00 - -
Apr 08 - Jun 08 Put Spread 500 84.00 68.00 - -
Apr 08 - Jun 08 Put Spread 1,000 79.00 66.00 - -
Apr 08 - Jun 08 3 - Way Collar 1,000 65.00 52.50 82.50 -
Apr 08 - Jun 08 3 - Way Collar 1,000 65.00 52.50 85.00 -
Apr 08 - Jun 08 Collar 1,000 65.00 - 85.00 -
Apr 08 - Dec 08 3 - Way Collar 1,000 70.00 55.00 90.00 -
Apr 08 - Dec 08 3 - Way Collar 1,000 67.50 52.50 85.00 -
Apr 08 - Dec 08 Collar 1,000 67.50 - 85.00 -
Jul 08 - Dec 08 Collar 2,000 85.00 - 107.50 -
-------------------------------------------------------------------------

Financial WTI Crude Oil Contracts In Conjunction with 2005 Redwater and
North Pembina Cardium Unit Acquisition

Bought Sold Sold Bought
Volume Put Put Call Call
Term Contract Bbl/d US$/bbl US$/bbl US$/bbl US$/bbl
-------------------------------------------------------------------------
Apr 08 - Dec 08 3 - Way Collar 2,000 61.50 50.00 85.00 -
Apr 08 - Dec 08 3 - Way Collar 1,000 61.30 50.00 85.00 -
Apr 08 - Dec 08 3 - Way Collar 2,000 61.00 50.00 85.00 -
Jan 09 - Dec 09 3 - Way Collar 5,000 55.00 40.00 90.00 -
-------------------------------------------------------------------------

Financial AECO Natural Gas Option Contracts

Bought Sold Sold
Volume Put Put Call
Term Contract GJ/d Cdn$/GJ Cdn$/GJ Cdn$/GJ
-------------------------------------------------------------------------
Apr 08 - Jun 08 Collar 10,000 7.25 - 8.50
Apr 08 - Oct 08 Collar 10,000 7.25 - 8.50
Apr 08 - Oct 08 Collar 10,000 7.00 - 9.00
Apr 08 - Oct 08 3 - Way Collar 10,000 7.00 5.75 9.00
Apr 08 - Oct 08 Collar 10,000 6.75 - 8.25
-------------------------------------------------------------------------

Financial NYMEX Natural Gas Contracts

Bought Sold Sold
Volume Put Put Call
mmbtu US$ US$ US$
Term Contract /d /mmbtu /mmbtu /mmbtu
-------------------------------------------------------------------------
Apr 08 - Jun 08 Collar 10,000 8.50 - 10.00
Apr 08 - Jun 08 Collar 10,000 8.50 - 12.00
Apr 08 - Oct 08 3 - Way Collar 10,000 8.00 6.00 9.60
Apr 08 - Oct 08 3 - Way Collar 10,000 7.80 6.20 9.50
Nov 08 - Mar 09 Collar 10,000 9.25 - 12.00
Nov 08 - Mar 09 Collar 10,000 9.00 - 12.00
Nov 08 - Mar 09 Collar 20,000 8.50 - 11.00
-------------------------------------------------------------------------

Financial Basis Swap Contract: receive NYMEX Last Day (Ld) or Last 3 Day
(L3d); pay AECO (Monthly)

Basis
Volume Swap
mmbtu US$
Term Contract /d /mmbtu
-------------------------------------------------------------------------
Apr 08 - Oct 08 Basis Swap-L3d 50,000 (1.1930)
Nov 08 - Oct 10 Basis Swap-L3d 50,000 (1.0430)
Nov 10 - Oct 11 Basis Swap-Ld 20,000 (0.4850)
Nov 11 - Oct 12 Basis Swap-Ld 20,000 (0.4050)
-------------------------------------------------------------------------

Energy Equivalent Swap

Term Contract Volume Swap
-------------------------------------------------------------------------
Financial WTI Crude Oil Purchase Contract
Apr 08 - Oct 08 Swap 1,000 bbl/d 73.95 Cdn$/bbl

Financial AECO Natural Gas Sales Contract
Apr 08 - Oct 08 Swap 10,000 GJ/d 7.10 Cdn$/GJ
-------------------------------------------------------------------------

Financial Foreign Exchange Contracts

Bought Sold
Notional Swap Swap Put Put
Volume Cdn$ US$ Cdn$ Cdn$
Term Contract MM US$ /US$ /Cdn$ /US$ /US$
-------------------------------------------------------------------------
USD Sales Contracts
Apr 08 - Dec 08 Swap 36.0 1.0150 (0.9852) - -
USD Option Contracts
Apr 08 - Dec 08 Put Spread 9.0 - - 1.0750 1.0300
-------------------------------------------------------------------------

USD Long-term Principal Debt Repayment Contracts

Bought Sold
Notional Swap Swap Put Put
Volume Cdn$ US$ Cdn$ Cdn$
Settlement Date Contract MM US$ /US$ /Cdn$ /US$ /US$
-------------------------------------------------------------------------
December 17, 2012 Forward 9.38 0.9324 (1.0725) - -
April 27, 2013 Forward 10.42 0.9454 (1.0578) - -
April 27, 2013 Forward 12.50 0.9430 (1.0604) - -
December 15, 2013 Forward 9.38 0.9520 (1.0504) - -
April 27, 2014 Forward 10.42 0.9743 (1.0264) - -
April 27, 2014 Forward 12.50 0.9615 (1.0400) - -
December 15, 2014 Forward 9.38 0.9825 (1.0178) - -
April 27, 2015 Forward 12.50 0.9825 (1.0178) - -
December 15, 2015 Forward 9.40 0.9980 (1.0020) - -
April 27, 2016 Forward 12.50 1.0180 (0.9823) - -
December 15, 2017 Forward 9.40 1.0184 (0.9819) - -
December 15, 2016 Collar 9.40 - - 1.0600 1.0000
-------------------------------------------------------------------------

Financial Interest Rate Contracts(1)(2)

Prin- Fixed
cipal Annual Spread on
Term Contract MM US$ Rate(%) 3 Mo. LIBOR
-------------------------------------------------------------------------

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

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

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

At March 31, 2008, the fair value of the contracts that were not
designated as accounting hedges was a loss of $83.3 million. The
Trust recorded a loss on risk management contracts of $48.2 million
in the statement of income for the three months ended March 31, 2008
($13.9 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:

March 31, March 31,
2008 2007
---------------------------------------------------------------------
Fair value, beginning of period $ (64.6) $ (8.7)
Fair value, end of period(1) (83.3) (29.6)
---------------------------------------------------------------------
Change in fair value of contracts
in the period (18.7) (20.9)
Realized (losses) gains in the period (29.5) 7.0
---------------------------------------------------------------------
Loss on risk management contracts $ (48.2) $ (13.9)
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Intrinsic value of risk management contracts not designated as
effective accounting hedges equals a loss of $57.5 million at
March 31, 2008 ($38 million loss at March 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. In the first quarter of 2008 it was determined that the
previously anticipated debt issuance was no longer expected to occur
and the associated rate lock contracts were unwound at a cost of
$13.6 million. These contracts were designated as effective
accounting hedges on their respective contract dates and hedge
accounting was applied. As at March 31, 2008 the $13.6 million loss
was removed from Other Comprehensive Income ("OCI"), net of tax and
recognized in net income.

The Trust's fixed price electricity contracts are intended to manage
price risk on electricity consumption. All fixed price electricity
contracts were designated as effective accounting hedges on their
respective contract dates. A realized gain of $0.5 million for the
first three months of 2008 (loss of $0.1 million in 2007) on the
electricity contracts has been included in operating costs. The
unrealized fair value gain on the electricity contracts of
$5.8 million has been recorded on the consolidated balance sheet at
March 31, 2008 with the movement in fair value recorded in OCI, net
of tax. The fair value movement as at March 31, 2008 amounts to an
unrealized gain of $1.8 million. $3.1 million of the unrealized fair
value gain is expected to be recognized in income over the next
12 months.

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

March 31, March 31,
2008 2007
---------------------------------------------------------------------
Fair value, beginning of period(1) $ (3.4) $ 7.0
Change in fair value of financial
electricity contracts 1.8 1.5
Change in fair value of treasury rate
lock contracts prior to de-designation (6.2) -
Reclassification of loss on treasury rate
lock contracts to net income 13.6 -
---------------------------------------------------------------------
Fair value, end of period $ 5.8 $ 8.5
---------------------------------------------------------------------
(1) Includes $7.4 million unrealized loss on treasury rate lock
contracts and $4.0 million unrealized gain on electricity
contracts.

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

10. EXCHANGEABLE SHARES

March 31, December 31,
ARL EXCHANGEABLE SHARES (thousands) 2008 2007
---------------------------------------------------------------------
Balance, beginning of period 1,310 1,433
Exchanged for trust units(1) (123) (123)
---------------------------------------------------------------------
Balance, end of period 1,187 1,310
Exchange ratio, end of period 2.31374 2.24976
Trust units issuable upon conversion,
end of period 2,746 2,947
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first three months of 2008, 123,020 ARL exchangeable
shares were converted to trust units at an average exchange ratio
of 2.29448.

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

March 31, December 31,
2008 2007
---------------------------------------------------------------------
Non-controlling interest, beginning
of period $ 43.1 $ 40.0
Reduction of book value for conversion
to trust units (4.1) (3.7)
Current period net income attributable to
non-controlling interest 1.1 6.8
---------------------------------------------------------------------
Non-controlling interest, end of period 40.1 43.1
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 35.2 $ 34.1
---------------------------------------------------------------------
---------------------------------------------------------------------

11. UNITHOLDERS' CAPITAL

March 31, 2008 December 31, 2007
---------------------------------------------------------------------
Number of Number of
trust units trust units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning
of period 210,232 2,465.7 204,289 2,349.2
Issued on conversion
of ARL exchangeable
shares (Note 10) 288 4.1 261 3.7
Issued on exercise
of employee rights
(Note 14) 210 3.7 131 2.1
Distribution
reinvestment program 1,201 25.8 5,551 110.7
---------------------------------------------------------------------
Balance, end of period 211,931 2,499.3 210,232 2,465.7
---------------------------------------------------------------------
---------------------------------------------------------------------

12. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE INCOME

The deficit balance is composed of the following items:

March 31, December 31,
2008 2007
---------------------------------------------------------------------
Accumulated earnings $ 2,272.4 $ 2,191.1
Accumulated distributions (2,783.8) (2,657.0)
---------------------------------------------------------------------
Deficit $ (511.4) (465.9)
Accumulated other comprehensive
income (loss) 4.0 (2.9)
---------------------------------------------------------------------
Deficit and accumulated other
comprehensive income (loss) $ (507.4) $ (468.8)
---------------------------------------------------------------------
---------------------------------------------------------------------

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

March 31, December 31,
2008 2007
---------------------------------------------------------------------
Unrealized losses on financial instruments
designated as cash flow hedges $ 3.9 $ (2.8)
Net unrealized gains and losses on
available-for-sale reclamation funds'
investments 0.1 (0.1)
---------------------------------------------------------------------
Accumulated other comprehensive income
(loss), end of period $ 4.0 $ (2.9)
---------------------------------------------------------------------
---------------------------------------------------------------------

13. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
DISTRIBUTIONS

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

March 31, March 31,
2008 2007
---------------------------------------------------------------------
Cash flow from operating activities $ 209.9 $ 172.3
Deduct:
Cash withheld to fund current period
capital expenditures (79.8) (45.9)
Reclamation fund contributions and
interest earned on fund balances (3.3) (3.3)
---------------------------------------------------------------------
Distributions(1) 126.8 123.1
Accumulated distributions, beginning
of period 2,657.0 2,159.0
---------------------------------------------------------------------
Accumulated distributions, end of period $ 2,783.8 $ 2,282.1
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per unit(2) $ 0.60 $ 0.60
Accumulated distributions per unit,
beginning of period $ 21.03 $ 18.63
Accumulated distributions per unit,
end of period(3) $ 21.63 $ 19.23
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include non-cash amounts of $26 million
($27 million in 2007) relating to the distribution reinvestment
program.
(2) Distributions per trust unit reflect the sum of the per trust
unit amounts declared monthly to unitholders.
(3) Accumulated distributions per unit reflect the sum of the per
trust unit amounts declared monthly to unitholders since the
inception of the Trust in July 1996.

14. TRUST UNIT INCENTIVE RIGHTS PLAN

A summary of the changes in rights outstanding under the plan for the
period ending March 31, 2008 is as follows:

Weighted
Number Average
of Rights Exercise
(thousands) Price ($)
---------------------------------------------------------------------
Balance, beginning of period 238 8.50
Exercised 210 10.19
---------------------------------------------------------------------
Balance before reduction of exercise price 28 9.59
Reduction of exercise price(1) - (0.23)
---------------------------------------------------------------------
Balance, end of period 28 9.36
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The holder of the right has the option to exercise rights held at
the original grant price or a reduced exercise price.

Of the 3,013,569 rights issued on or after January 1, 2003 that were
subject to recording compensation expense, 357,999 rights have been
cancelled and 2,627,970 rights have been exercised to March 31, 2008.

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

March 31, December 31,
CONTRIBUTED SURPLUS 2008 2007
---------------------------------------------------------------------
Balance, beginning of period $ 1.7 $ 2.4
Net benefit on rights exercised(1) (1.5) (0.7)
---------------------------------------------------------------------
Balance, end of period $ 0.2 $ 1.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to unitholders' capital.

15. WHOLE TRUST UNIT INCENTIVE PLAN

The Trust recorded non-cash compensation expense of $11.9 million and
$1.9 million to general and administrative and operating expenses,
respectively, and capitalized $2.0 million to property, plant and
equipment in the first quarter of 2008 for the estimated cost of the
plan ($0.3 million, $0.3 million and $0.1 million for the three
months ended March 31, 2007). The non-cash compensation expense was
based on the March 31, 2008 unit price of $26.38 ($21.25 at March 31,
2007), accrued distributions, a weighted average performance
multiplier of 1.6 (1.6 in 2007), and the number of units to be issued
on maturity.

The following table summarizes the Restricted Trust Unit ("RTU") and
Performance Trust Unit ("PTU") movement for the three months ended
March 31, 2008:

Number Number
of RTUs of PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of period 746 903
Forfeited (10) (2)
---------------------------------------------------------------------
Balance, end of period 736 901
---------------------------------------------------------------------
---------------------------------------------------------------------

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

March 31, December 31,
2008 2007
---------------------------------------------------------------------

Balance, beginning of period $ 30.3 $ 26.1
Change in liabilities in the period
General and administrative expense 11.9 3.2
Operating expense 1.9 0.3
Property, plant and equipment 2.0 0.7
---------------------------------------------------------------------
Balance, end of period $ 46.1 $ 30.3
---------------------------------------------------------------------
Current portion of liability 26.5 18.2
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 19.6 $ 12.1
---------------------------------------------------------------------
---------------------------------------------------------------------

16. BASIC AND DILUTED PER TRUST UNIT CALCULATIONS

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

March 31, March 31,
2008 2007
---------------------------------------------------------------------
Weighted average trust units(1) 211,028 204,990
Trust units issuable on conversion of
exchangeable shares(2) 2,746 2,863
Dilutive impact of rights(3) 172 217
---------------------------------------------------------------------
Diluted trust units and exchangeable shares 213,946 208,070
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Weighted average trust units excludes trust units issuable for
exchangeable shares.
(2) Diluted trust units include trust units issuable for outstanding
exchangeable shares at the period end exchange ratio.
(3) All outstanding rights were dilutive and therefore 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.

17. COMMITMENTS AND CONTINGENCIES

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

---------------------------------------------------------------------
Payments Due by Period
---------------------------------------------------------------------
2009- 2011- There-
($ millions) 2008 2010 2012 after Total
---------------------------------------------------------------------
Debt repayments(1) 6.2 539.3 53.5 121.0 720.0
Interest payments(2) 11.1 20.8 16.0 14.1 62.0
Reclamation fund
contributions(3) 5.8 10.2 8.9 71.9 96.8
Purchase commitments 7.3 5.2 4.3 6.3 23.1
Operating leases 5.1 8.6 12.3 88.0 114.0
Derivative contract
premiums(4) 9.7 2.9 - - 12.6
---------------------------------------------------------------------
Total contractual
obligations (1) 45.2 587.0 95.0 301.3 1,028.5
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest. On April 15,
2008, the credit facility was extended to 2011 under the same
terms. With this extension, the total contractual obligations in
years 2009 - 2010 are decreased to $91 million and increased to
$591 million in years 2011 - 2012.
(2) Fixed interest payments on senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.

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

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

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $6.8 billion. The
Trust expects full year 2008 oil and gas production to average approximately
63,000 barrels of oil equivalent per day from six core areas in western
Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN and its
exchangeable shares trade under the symbol ARX.

Note: Barrels of oil equivalent (boe) may be misleading, particularly if
used in isolation. In accordance with NI 51-101, a boe conversion ratio for
natural gas of 6 mcf:1 bbl has been used, which is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
ADVISORY - In the interests of providing ARC unitholders and potential
investors with information regarding ARC, including management's assessment of
ARC's future plans and operations, certain information contained in this
document are forward-looking statements within the meaning of the "safe
harbour" provisions of the United States Private Securities Litigation Reform
Act of 1995 and the Ontario Securities Commission. Forward-looking statements
in this document include, but are not limited to, ARC's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; the production and growth potential of its various assets,
estimated total production and production growth for 2008 and beyond; the
sources, deployment and allocation of expected capital in 2008; and the
success of future development drilling prospects. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause ARC's actual performance and financial results in future periods to
differ materially from any estimates or projections of future performance or
results expressed or implied by such forward-looking statements.

ARC RESOURCES LTD.

John P. Dielwart,
President and Chief Executive Officer