ARC Energy Trust announces March 31, 2007 first quarter financial results

May 8, 2007

CALGARY, May 8 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") released today its March 31, 2007 first quarter financial
results.

<<
Three Months Ended
March 31
2007 2006
-------------------------------------------------------------------------
FINANCIAL
($CDN millions, except per unit and per
boe amounts)
Revenue before royalties 307.8 318.9
Per unit(1) 1.48 1.58
Per boe 53.29 54.86
Cash flow(2) 183.8 191.2
Per unit(1) 0.88 0.94
Per boe 31.82 32.89
Net income 83.3 104.1
Per unit(3) 0.41 0.52
Distributions 123.1 119.9
Per unit(1) 0.60 0.60
Payout ratio(4) 67% 63%
Net debt outstanding(5) 729.7 598.9
Total capital expenditures and net acquisitions 77.7 106.7

OPERATING
Production
Crude oil (bbl/d) 29,520 29,651
Natural gas (mmcf/d) 183.0 185.0
Natural gas liquids (bbl/d) 4,161 4,120
Total (boe per day) 64,175 64,600
Average prices
Crude oil ($/bbl) 60.79 59.53
Natural gas ($/mcf) 7.75 8.40
Natural gas liquids ($/bbl) 48.04 52.91
Oil equivalent ($/boe)(6) 53.29 54.86
Operating netback ($/boe)
Commodity and other revenue (before hedging) 53.29 54.86
Transportation costs (0.81) (0.61)
Royalties (9.65) (10.71)
Operating costs (8.99) (7.80)
Netback (before hedging) 33.84 35.74
-------------------------------------------------------------------------
TRUST UNITS
(thousands)
Units outstanding, end of period 205,794 200,194
Units issuable for exchangeable shares 2,863 2,896
Total units outstanding and issuable for
exchangeable shares, end of period 208,657 203,090
Weighted average units(7) 207,853 202,479
-------------------------------------------------------------------------
TRUST UNIT TRADING STATISTICS
($CDN, except volumes) based on intra-day trading
High 23.02 27.51
Low 20.05 25.09
Close 21.25 27.36
Average daily volume (thousands) 658 546
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average units plus units issuable for exchangeable
shares. Per unit distributions are based on the number of trust units
outstanding at each distribution date.
(2) All references to cash flow throughout this report are based on cash
flow from operating activities before changes in non-cash working
capital and expenditures on site restoration and reclamation.
(3) Net income per unit is based on net income after non-controlling
interest divided by weighted average outstanding units (excluding
units issuable for exchangeable shares).
(4) Distributions divided by cash flow from operations.
(5) Net debt excludes unrealized risk management contracts.
(6) Includes other revenue.
(7) Includes units issuable for outstanding exchangeable shares at period
end.

FINANCIAL & OPERATIONAL HIGHLIGHTS
----------------------------------
- Production averaged 64,175 boe per day in the first quarter of 2007,
down slightly from 64,600 boe per day achieved in the first quarter
of 2006, but an increase of one percent from the 63,663 boe per day
reported in the fourth quarter of 2006. Production declines were
largely replaced through a successful and active drilling program
during 2006 and the first quarter of 2007. Production per unit
remained relatively unchanged at 0.31 boe per day per thousand units
in 2007, from 0.32 boe per day per thousand units in 2006. The Trust
has maintained its 2007 full year production guidance of 63,000 boe
per day.

- The Trust spent $77.5 million on capital development activities in
the first quarter of 2007 compared to $79 million in the first
quarter of 2006. A significant portion of the first quarter capital
development activity was focused in Northern Alberta and British
Columbia where the Trust drilled 14 gross wells (12 net wells). In
total, the Trust drilled 42 gross wells (32 net wells) on operated
properties with a 90 per cent success rate in the first quarter. The
Trust funded 74 per cent of the first quarter 2007 capital
development program with cash flow and the remainder was funded with
proceeds of the Distribution Reinvestment Program. Highlights of the
capital program included:

a) The Trust executed a successful drilling program at Dawson in
northeastern British Columbia late in 2006 and in the first
quarter of 2007. In total, seven horizontal wells have been
drilled of which four are currently producing approximately
2,000 boe per day and the remaining wells will be tied-in during
the third quarter. At present, production from the four producing
wells is restricted due to capacity constraints at a third party
gas processing facility that is scheduled to be expanded.

b) The Trust drilled a successful gas well at Chinchaga in
northeastern British Columbia, a deep vertical gas well in the
Slave Point pool. The well was drilled and came on production in
February at a rate of 500 boe per day. Based on current rates,
this is the largest single producing well drilled by the Trust
this year.

- The Trust has realized significant production gains at the Redwater
property acquired in late 2005. During 2006 and into the first
quarter of 2007, the Trust executed an extensive optimization program
which resulted in the reactivation of approximately 40 wells. As a
result, the Trust's production at Redwater has increased by
approximately 14 per cent to 4,000 boe per day in the first quarter
of 2007 from 3,500 boe per day upon acquisition in December 2005. The
incremental production had a significant impact on the quarter as the
property yields a high netback due to the high quality of oil.

- During the first quarter, the Trust completed construction of a
14 kilometer gas gathering system and installed a new compression
facility at Ante Creek. The new gas line was constructed to tie-in
ARC's main Ante Creek field gas processing facility which was
purchased by the Trust in 2006. Previously, the Trust had
approximately 3 mmcf per day of stranded natural gas production
behind pipe due to capacity constraints at the existing gas
processing facility. The Trust commenced gas shipments to the new
facility in early March 2007 and all production that was previously
stranded was brought on production during the quarter.

- ARC realized cash flow from operations of $183.8 million ($0.88 per
unit) in the first quarter of 2007 compared to $191.2 million
($0.94 per unit) in 2006. The four per cent decrease in 2007 cash
flow was due to lower production volumes, a slightly lower realized
price and increased operating costs, offset in part by higher cash
hedging gains in 2007.

- The Trust recorded net income before taxes of $73 million in 2006
compared to $95.9 million in 2006. In addition to slightly lower
commodity prices and production volume, a non-cash loss on risk
management contracts contributed to the decrease in net income for
the first quarter of 2006.

- The Trust declared distributions of $123.1 million in the first
quarter of 2007 ($0.60 per unit), resulting in a payout ratio of
67 per cent compared to 63 per cent in the first quarter of 2006. The
remaining 33 per cent of 2007 cash flow ($60.7 million) was used to
fund 74 per cent of ARC's capital development program and to
contribute $3.3 million, inclusive of interest income, to ARC's
reclamation funds.

- The Trust announced second quarter 2007 distributions will remain at
$0.20 per unit per month, a level that has been maintained since
October 2005. The Trust's first quarter 2007 payout ratio of 67 per
cent is in line with the long-term objective to employ a low payout
ratio that will enable the Trust to maintain distributions levels
through commodity price cycles and also maintain a strong balance
sheet by financing a portion of its capital program with cash flow.

MANAGEMENT'S DISCUSSION AND ANALYSIS
------------------------------------
This management's discussion and analysis ("MD&A") is dated April 27, 2007
and should be read in conjunction with the attached March 31, 2007 unaudited
interim consolidated financial statements and the audited consolidated
financial statements and MD&A for the year ended December 31, 2006.

Non-GAAP Measures
Management uses cash flow, cash flow from operations and cash flow from
operations per unit derived from cash flow from operating activities (before
changes in non-cash working capital and expenditures on site reclamation and
restoration) to analyze operating performance and leverage. Cash flow as
presented does not have any standardized meaning prescribed by Canadian
generally accepted accounting principles, ("GAAP") and therefore it may not be
comparable with the calculation of similar measures for other entities. Cash
flow as presented is not intended to represent operating cash flow or
operating profits for the period nor should it be viewed as an alternative to
cash flow from operating activities, net earnings or other measures of
financial performance calculated in accordance with Canadian GAAP.
The following table reconciles the cash flow from operating activities to
cash flow from operations which is used frequently in this MD&A:

Management uses certain key performance indicators ("KPI's") and industry
benchmarks such as payout ratio, 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 KPI's and
benchmarks are a key measure of profitability and overall sustainability for
the Trust. These KPI's 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.

Update on Legislation Changes Impacting the Trust

Federal Government's Proposed Trust Tax Legislation
On October 31, 2006, the Federal Government announced proposed
legislation regarding taxation of Income Trusts. Currently, distributions paid
to unitholders, other than returns of capital, are claimed as a deduction by
the Trust in arriving at taxable income whereby tax is eliminated at the Trust
level and is paid by the unitholders. The proposed Trust tax legislation would
result in a two-tiered tax structure whereby distributions would first be
subject to a 31.5 per cent tax at the Trust level commencing in 2011, and then
unitholders would be subject to tax on the distribution as if it were a
taxable dividend paid by a taxable Canadian corporation. If enacted, the
legislation would apply to the Trust effective January 1, 2011.
In December 2006, the Federal Government issued guidance with respect to
limitations on future growth of the Trust in conjunction with the proposed
Trust taxation. The Trust does not anticipate that the guidelines will impair
the Trust's ability to annually replace or grow reserves in the next four
years as the guidelines allow sufficient growth targets. Key attributes of the
future growth constraints are as follows:

<<
- Trusts may grow in size by 100 per cent cumulatively for the period
2007 through 2010 as measured by the value of equity based on the
October 31, 2006 market capitalization. The cumulative limit starts
at 40 per cent in 2007 and increases by 20 per cent per year in 2008
through 2010.
- The merger of two Trusts will not be impacted by the growth
limitations.
- The growth limits are not impacted by non-convertible debt-financed
growth but rather focus solely on the issuance of equity to
facilitate growth.

In April 2007, the Federal Government included the proposed Trust Taxation
in the Federal Budget. The April Budget has already passed through the House
of Commons, and the Budget Bill (C-52) has been given first and second reading
in the House of Commons. The Bill must pass through the Finance Standing
Committee before it can go to third and final reading. Once it is approved by
the House, it will go to the Senate for approval prior to receiving Royal
Assent at which point it will be considered substantively enacted. If the
proposed legislation is enacted, the Trust estimates that there would be a
modest, one time increase in earnings and a future tax asset would be
recognized as a result of timing differences within the Trust that have not
been previously recognized.

Climate Change Programs
On March 8, 2007, the Alberta government introduced legislation to reduce
greenhouse gas emission intensity. Bill 3 states that facilities emitting more
than 100,000 tonnes of greenhouse gases per year must reduce their emissions
intensity by 12 per cent over the average emissions levels of 2003, 2004 and
2005; if they are not able to do so, these facilities will be required to pay
$15 per tonne for every tonne above the 12 per cent target, beginning on
July 1, 2007. At this time, the Trust has determined that the impact of this
legislation would be minimal based on ARC's existing facilities ownership.
In April 2007, the Federal Government announced a new climate change plan
that calls for greenhouse gas emissions to be reduced by 20 per cent below
current levels by 2020. Firms may employ the following strategies to achieve
the targets. They will be able to:

- make in-house reductions,
- take advantage of domestic emissions trading,
- purchase offsets,
- use the Clean Development Mechanism under the Kyoto Protocol; and,
- invest in a technology fund.

The Trust is waiting for additional information so as to fully assess what
impact, if any, this new legislation will have on our operations.

United States Proposed Changes to Qualifying Dividends
A bill was introduced into United States Congress on March 23, 2007 that
could deny qualified dividend income treatment to the distributions made by
ARC Energy Trust to its U.S. unitholders. The bill is in the first step of the
legislative process and it is uncertain whether it will eventually be passed
into law in its current form. If the bill is passed in its current form,
distributions received by U.S. unitholders would no longer qualify for the
15 per cent qualified dividend tax rate.

Financial Highlights

-------------------------------------------------------------------------
Three Months Ended March 31
-------------------------------------------------------------------------
(CDN $ millions, except per unit
and volume data) 2007 2006 % Change
-------------------------------------------------------------------------
Cash flow from operations 183.8 191.2 (4)
Cash flow from operations per unit(1) 0.88 0.94 (6)
Net income before taxes 73.0 95.9 (25)
Net income 83.3 104.1 (21)
Net income per unit(2) 0.41 0.52 (24)
Distributions per unit(3) 0.60 0.60 -
Payout ratio per cent(4) 67 63 6
Average daily production (boe/d)(5) 64,175 64,600 (1)
-------------------------------------------------------------------------
(1) Per unit amounts are based on weighted average units plus units
issuable for exchangeable shares at year-end.
(2) Based on net income after non-controlling interest divided by
weighted average units outstanding excluding units issuable for
exchangeable shares.
(3) Based on number of trust units outstanding at each cash distribution
date.
(4) Based on distributions divided by cash flow from operations.
(5) Reported production amount is based on company interest before
royalty burdens. Where applicable in this MD&A natural gas has been
converted to barrels of oil equivalent ("boe") based on 6 mcf:1 bbl.
The boe rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a value
equivalent at the well head. Use of boe in isolation may be
misleading.
>>

Impact of New Financial Instruments Accounting Standards
On January 1, 2007, the Trust adopted, on a prospective basis, three new
accounting standards relating to financial instruments that were issued by the
Canadian Institute of Chartered Accountants ("CICA"). The standards require
the recognition of all financial instruments on the Consolidated Balance
Sheet. In addition, certain categories on the Consolidated Balance Sheet are
required to be measured at fair value. With the exception of financial
instruments classified as available for sale and derivatives designated as
cash flow hedges, changes in the fair values over the reporting period of
financial instruments are reported in net income. The changes in fair value of
financial instruments classified as available for sale and derivatives
designated as cash flow hedges are reported in Other Comprehensive Income
(OCI). The new standards also require the Trust to measure the ineffective
portion of all designated hedges and this amount must be recorded in net
income for the period.
As a result of these changes in accounting policies, on January 1, 2007
the Trust has recorded $4.9 million in application of initial adoption in
Accumulated Other Comprehensive Income ("AOCI") to reflect the opening fair
value of its cash flow hedges, net of tax, which was previously not recorded
on the consolidated financial statements. The Trust has also recorded an
increase of $7 million to its risk management asset and an increase of $2.1
million to its future income tax liability.
For further details please refer to notes 2 and 8 of the unaudited
interim consolidated financial statements.

Net Income
Net income in the first quarter of 2007 was $83.3 million ($0.41 per
unit), a decrease of $20.8 million from $104.1 million ($0.52 per unit) in the
first quarter of 2006 primarily as a result of non-cash hedging losses on the
risk management hedging program of $20.9 million compared to a non-cash gain
of $5.1 million for the first quarter of 2006 and weaker natural gas prices
throughout the first quarter of 2007.

Cash Flow from Operations
Cash flow from operations was $183.8 million in the first quarter of 2007
a four per cent decrease from $191.2 million recorded in the first quarter of
2006. The decrease in 2007 cash flow was the result of a one per cent decrease
in production volumes and lower natural gas prices as compared to the same
period in 2006. The decrease in first quarter 2007 cash flow was partially
offset by cash hedging gains of $7 million in 2007 compared to a cash hedging
loss of $1.4 million in the first quarter of 2006. Per unit cash flow from
operations decreased six per cent to $0.88 per unit from $0.94 per unit in the
first quarter of 2006.
Following is a summary of variances in cash flow from operations from Q1
2006 to Q1 2007:

<<
-------------------------------------------------------------------------
($ ($ per (%
millions) trust unit) variance)
-------------------------------------------------------------------------
Q1 2006 Cash flow from Operations 191.2 0.94
-------------------------------------------------------------------------
Volume variance $ (2.1) $ (0.01) (1)
Price variance (9.0) (0.04) (5)
Cash gains on risk management
contracts(1) 8.4 0.04 4
Royalties 6.5 0.03 3
Expenses:
Transportation (1.1) (0.01) (1)
Operating(2) (6.9) (0.03) (4)
Cash G&A (1.1) (0.01) (1)
Interest (2.3) (0.01) (1)
Taxes 0.6 - -
Realized foreign exchange gain (loss) (0.3) - -
Weighted average trust units - (0.02) -
Other (0.1) - -
-------------------------------------------------------------------------
Q1 2007 Cash flow from Operations $ 183.8 $ 0.88 4
-------------------------------------------------------------------------
(1) Represents cash gains (losses) on risk management contracts including
cash settlements on termination of risk management contracts.
(2) Excludes non-cash portion of the Whole Unit Plan expense recorded in
operating costs.

Production
Production volume averaged 64,175 boe per day in the first quarter of 2007
compared to 64,600 boe per day during the first quarter of 2006. The 2006
drilling program largely replaced declines for the period resulting in a
modest year over year decline in production.
To the end of the first quarter in 2007, the Trust has experienced
production restrictions in the northern Alberta area as a result of gas plant
capacity constraints. A new plant is scheduled to be on-line by the fourth
quarter of 2007 to handle existing excess production as well as additional
development production from both Dawson and Pouce South. Currently, the Trust
has three horizontal wells in Dawson that will not be completed until there is
processing capacity for the resulting production.
The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During the first quarter of 2007, the Trust
drilled 42 gross wells (32 net wells) on operated properties with a
90 per cent success rate; 31 gross oil wells and seven gross natural gas
wells.

The following table summarizes the Trust's production by core area:

-------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2007 March 31, 2006
-------------------------------------------------------------------------
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 8,492 1,782 31.9 1,390 8,588 1,656 32.2 1,561
Northern
AB & BC 20,121 6,073 74.7 1,607 19,557 6,527 69.5 1,454
Pembina &
Redwater 13,731 9,535 18.9 1,046 13,932 9,516 20.5 987
S.E. AB &
S.W. Sask. 10,322 1,119 55.2 8 11,219 1,087 60.8 6
S.E. Sask.
& MB 11,509 11,011 2.3 110 11,304 10,865 2.0 112
-------------------------------------------------------------------------
Total 64,175 29,520 183.0 4,161 64,600 29,651 185.0 4,120
-------------------------------------------------------------------------
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
is Saskatchewan, MB is Manitoba, S.E. is southeast, S.W. is
southwest.

Commodity Prices Prior to Hedging

WTI U.S. dollar oil posted prices decreased by nine per cent in the first
quarter of 2007 as compared to the first quarter of 2006, however, there was a
slight weakening of the Canadian dollar relative to the U.S. dollar as well as
a large decrease in the differential to Edmonton posted prices. As a result,
the Trust realized a higher Canadian dollar denominated oil price in the first
quarter of 2007 of $60.79 as compared to $59.53 for the first quarter of 2006.
Natural gas prices recovered significantly in the first quarter of 2007
with the Alberta AECO Hub monthly posting averaging $7.46 per mcf as compared
to $6.36 per mcf for the fourth quarter of 2006. The Trust's realized price of
$7.75 per mcf was only eight per cent lower than the realized price in the
first quarter of 2006 as the Trust's realized gas price is based on prices
received at the various markets in which the Trust sells its natural gas.
ARC's natural gas sales portfolio consists of gas sales priced at the AECO
monthly index, the AECO daily spot market, eastern and mid-west United States
markets and a portion to aggregators. While the AECO monthly index price was
20 per cent lower in 2007 ($7.46 as compared to $9.30) the daily spot price
was relatively unchanged.
Prior to hedging activities, ARC's total realized commodity price was
$53.29 per boe in the first quarter of 2007, a three per cent decrease from
the $54.86 per boe received prior to hedging in the first quarter of 2006.

The following is a summary of realized prices:

Revenue
Revenue decreased slightly to $307.8 million from $318.9 million for the
first quarter of 2006. The decrease in revenue was attributable to lower
natural gas prices and slightly lower volumes.

A breakdown of revenue is as follows:

-------------------------------------------------------------------------
Revenue Three Months Ended March 31
($ millions) 2007 2006 % Change
-------------------------------------------------------------------------
Oil revenue 161.5 158.8 2
Natural gas revenue 127.7 139.8 (9)
NGL revenue 18.0 19.6 (8)
-------------------------------------------------------------------------
Total commodity revenue 307.2 318.2 (4)
Other revenue 0.6 0.7 (14)
Total revenue 307.8 318.9 (4)
-------------------------------------------------------------------------

Risk Management and Hedging Activities

The Trust continues to maintain a strong hedging position with an emphasis
on protecting cash flow and distributions to unitholders.
During the first quarter of 2007 ARC realized cash hedging gains of
$7 million from protection contracts on crude oil and natural gas production.
On a forward-looking basis ARC continues to add layers of protection for
both crude oil and natural gas production. ARC has protected approximately
40 per cent of forecast oil production through year end 2007 and 20 per cent
of forecast oil production for the first quarter of 2008. For natural gas ARC
has protected 60 per cent of forecast volumes for the second quarter of 2007
and has layered on volumes as far out as one year, protecting 10 per cent of
forecasted production for the first quarter of 2008.

The following is a summary of the Trust's positions for the next twelve
months as at March 31, 2007.

-------------------------------------------------------------------------
2007 Hedge Positions
as at March 31, 2007(1)(2)
Q2 2007 Q3 2007
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 84.00 12,000 87.11 8,500
Bought Put 63.46 13,000 61.92 13,000
Sold Put 50.02 13,000 48.46 13,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 8.54 123,028 9.08 60,000
Bought Put 7.04 123,028 7.25 60,000
Sold Put 5.15 50,000 5.15 50,000
-------------------------------------------------------------------------
FX CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought Put 1.1612 21.0 1.1474 8.0
Sold Put 1.1289 18.0 1.1148 6.0
Swap 1.1353 49.2 1.1353 32.8
-------------------------------------------------------------------------

-------------------------------------------------------------------------
2007 Hedge Positions
as at March 31, 2007(1)(2)
Q4 2007 Q1 2008
-------------------------------------------------------------------------
Crude Oil US$/bbl bbl/day US$/bbl bbl/day
-------------------------------------------------------------------------
Sold Call 87.11 8,500 88.21 7,000
Bought Put 61.92 13,000 57.86 7,000
Sold Put 48.46 13,000 43.57 7,000
-------------------------------------------------------------------------
Natural Gas CDN$/GJ GJ/day CDN$/GJ GJ/day
-------------------------------------------------------------------------
Sold Call 10.41 34,208 12.34 21,101
Bought Put 7.56 34,208 8.02 21,101
Sold Put 5.15 16,848 - -
-------------------------------------------------------------------------
FX CAD/USD $Million CAD/USD $Million
-------------------------------------------------------------------------
Bought Put 1.1474 8.0 - -
Sold Put 1.1148 6.0 - -
Swap 1.1353 32.8 - -
-------------------------------------------------------------------------
(1) The prices and volumes noted above represents averages for several
contracts and the average price for the portfolio of options listed
above does not have the same payoff profile as the individual option
contracts. Viewing the average price of a group of options is purely
for indicative purposes. The natural gas price shown translates all
NYMEX positions to an AECO equivalent price. In addition to positions
shown here, ARC has entered into additional basis positions.
(2) Please refer to the Trust's website at www.arcenergytrust.com under
"Hedging Program" within the "Investor Relations" section for details
on the Trust's hedging positions as of March 31, 2007.

The above table should be interpreted as follows using the Q2 2007 Crude
Oil Hedges as an example. The Trust has hedged 13,000 barrels per day at a
minimum average price of US$63.46 and participates in prices up to a maximum
average of US$84.00 on 12,000 barrels per day with no limit on the remaining
1,000 barrels per day hedged. Finally, ARC's average protected price of $63.46
reduces penny for penny at an average price below $50.02 on 13,000 barrels per
day.
As a result of commodity hedging contracts denominated in U.S. dollars,
ARC systematically enters into foreign exchange agreements to offset this
exposure. In addition, ARC manages these foreign exchange positions by
converting the forwards to U.S. dollar put spreads whereby ARC achieves a
position that is a net asset.
For a complete summary of the Trust's oil, natural gas and foreign
exchange hedges, please refer to "Hedging Program" under the "Investor
Relations" section of the Trust's website at www.arcenergytrust.com.

Gain or Loss on Risk Management Contracts
Gain or loss on risk management contracts comprise realized and unrealized
gains or losses on risk management contracts that do not meet the accounting
definition requirements of an effective hedge, even though the Trust considers
all risk management contracts to be effective economic hedges. Accordingly,
gains and losses on such contracts are shown as a separate category in the
statement of income.
The Trust recorded a realized cash gain on risk management contracts of $7
million in the first quarter of 2007 compared to a loss of $1.4 million
recorded in for the same period of 2006. The Trust had a similar hedging
strategy in place for the first quarters of 2007 and 2006, however, 2007
market prices were below the Trust's floor prices resulting in cash hedging
gains whereas 2006 prices were in excess of the floor prices resulting in
hedging losses representing the cost of premiums paid in the period.

The following is a summary of the total gain (loss) on risk management
contracts for the first quarter of 2007:

-------------------------------------------------------------------------
Risk management Interest &
contracts Crude Oil Natural Foreign Q1 2007 Q1 2006
($ millions) & Liquids Gas Currency Total Total
-------------------------------------------------------------------------
Realized cash gain (loss)
on contracts(1) 4.8 3.8 (1.6) 7.0 (1.4)
Unrealized gain (loss)
on contracts(2) (6.6) (16.4) 2.1 (20.9) 5.1
-------------------------------------------------------------------------
Total gain (loss) on risk
management contracts (1.8) (12.6) 0.5 (13.9) 3.7
-------------------------------------------------------------------------
(1) Realized cash gains and losses represent actual cash settlements or
receipts under the respective contracts.
(2) The unrealized (loss) gain on contracts represents the change in fair
value of the contracts during the period.

Operating Netbacks
The Trust's operating netback, after realized hedging gains or losses,
decreased by only one per cent to $35.05 per boe in the first quarter of 2007
compared to $35.50 per boe in the same period of 2006. The decrease in
netbacks in 2007 is primarily due to lower realized gas prices in 2007, an
increase in operating and transportation costs which was partially offset by a
decrease in royalty rates and a slight increase in realized oil prices.
Realized cash gains on risk management contracts increased the 2007 first
quarter netback by $1.21 per boe as compared to a loss of $0.24 per boe
recorded for the same period in 2006.

The components of operating netbacks are shown below:

-------------------------------------------------------------------------
Crude Heavy Q1 2007 Q1 2006
Netbacks Oil Oil Gas NGL Total Total
($ per boe) ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
-------------------------------------------------------------------------
Weighted average
sales price 61.71 42.81 7.75 48.04 53.18 54.74
Other revenue - - - - 0.11 0.12
-------------------------------------------------------------------------
Total revenue 61.71 42.81 7.75 48.04 53.29 54.86
Royalties (9.58) (3.57) (1.60) (12.57) (9.65) (10.71)
Transportation (0.48) (1.50) (0.20) - (0.81) (0.61)
Operating costs(1) (10.85) (11.07) (1.20) (8.83) (8.99) (7.80)
-------------------------------------------------------------------------
Netback prior to
hedging 40.80 26.67 4.75 26.64 33.84 35.74
Realized gain (loss)
on risk management
contracts 1.26 - 0.23 - 1.21 (0.24)
-------------------------------------------------------------------------
Netback after
hedging 42.06 26.67 4.98 26.64 35.05 35.50
-------------------------------------------------------------------------
(1) Operating expenses are composed of direct costs incurred to operate
oil and gas wells. A number of assumptions have been made in
allocating these costs between oil, heavy oil, natural gas and
natural gas liquids production.
>>

Royalties decreased to $9.65 per boe in the first quarter of 2007
compared to $10.71 per boe in the same period of 2006. Royalties as a
percentage of pre-hedged commodity revenue net of transportation costs
decreased to 18.4 per cent compared to 19.7 per cent in for the first quarter
of 2006. The decrease in royalty rates is partially attributable to the
decrease in gas prices, as gas royalties are largely price dependant. In
addition, changes in the Trust's production mix as well as changes in the
Trust's production profile as new production is brought on-stream impacts the
overall royalty rates. Finally, reductions to the Saskatchewan royalty
surcharge rates have contributed to the overall reduction in the Trust's
royalty rates.
Transportation costs increased 33 per cent to $0.81 per boe in the first
quarter of 2007 compared to $0.61 per boe in the first quarter of 2006. The
Trust has experienced challenges in Saskatchewan throughout the second half of
2006 and the first quarter of 2007 due to shipping restrictions on the
Enbridge pipeline that is currently operating at full capacity. During the
first quarter, the Trust had to truck approximately 900 boe per day of
operated oil production at an increased pipeline transportation cost. An
expansion of the Enbridge pipeline is expected to be completed sometime in
late 2007 or early 2008.
Operating costs increased to $8.99 per boe compared to $7.80 per boe in
the first quarter of 2006. The industry began to experience significant cost
increases throughout 2006 with fourth quarter 2006 operating costs reported at
$9.13 per boe. The increase is due to higher labour costs as well as rising
costs for materials and services particularly in the northern Alberta area.

General and Administrative Expenses and Trust Unit Incentive Compensation
Cash G&A net of overhead recoveries on operated properties increased
14 per cent to $8.8 million in the first quarter of 2007 from $7.7 million in
the same period of 2006. Increases in cash G&A expenses for 2007 were due to
additional staff and higher compensation costs. The increase in G&A costs was
partially offset by higher overhead recoveries attributed to high levels of
capital and operating activity throughout the first quarter of 2007 and as a
result of incremental overhead charged on new and existing operated
properties. On a per boe basis, cash G&A costs increased 15 per cent to $1.52
per boe from $1.32 per boe as a result of higher cash G&A costs and a slight
decrease in production volumes.
The Trust did not make any payments under the Whole Unit Plan in the
first quarter of 2007. The next cash payment is scheduled to occur in April
2007 and will include the first payment for performance units issued under the
plan in 2004. The April 2007 cash payment was $10.3 million of which
$8.2 million was recorded in G&A with the remainder $2.1 million being
recorded to operating costs and capital projects. Cash flow in the second
quarter will be decremented for the full cash payment amount.

The following is a breakdown of G&A and trust unit incentive compensation
expense:

<<
-------------------------------------------------------------------------
Three Months Ended March 31
-------------------------------------------------------------------------
G&A and Trust Unit Incentive
Compensation Expense
($ millions except per boe) 2007 2006 % Change
-------------------------------------------------------------------------
G&A expenses 13.4 10.3 30
Operating recoveries (4.6) (2.6) 77
-------------------------------------------------------------------------
Cash G&A expenses before Whole Unit Plan 8.8 7.7 14
Cash Expense - Whole Unit Plan - - -
-------------------------------------------------------------------------
Cash G&A expenses including Whole
Unit Plan 8.8 7.7 14
-------------------------------------------------------------------------
Accrued compensation - Rights Plan - 1.8 (100)
Accrued compensation - Whole Unit Plan 0.3 3.8 (92)
-------------------------------------------------------------------------
Total G&A and trust unit incentive
compensation expense 9.1 13.3 (32)
-------------------------------------------------------------------------
Cash G&A expenses per boe 1.52 1.32 15
Total G&A and trust unit incentive
compensation expense per boe 1.58 2.28 (31)
-------------------------------------------------------------------------

A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $0.3 million ($0.06 per boe) was recorded in the
first quarter of 2007 compared to $5.6 million ($0.96 per boe) in the first
quarter of 2006. This non-cash amount relates to estimated costs of the Trust
Unit Incentive Rights Plan ("Rights Plan") and the Whole Trust Unit Incentive
Plan ("Whole Unit Plan") for the period. A decrease in the Trust's unit price
from December 31, 2006 to March 31, 2007 and a reduction in the performance
multiplier for PTUs resulted in a lower expense for the first quarter.

Rights Plan
The Rights Plan which provides employees, officers and independent
directors the right to purchase units at a specified price is being
discontinued. In the first quarter 2007, 0.1 million rights were exercised and
0.3 million rights remained outstanding as at March 31, 2007. All rights were
fully vested and expensed as of March 31, 2007.

Whole Trust Unit Incentive Plan ("Whole Unit Plan")
Please refer to our MD&A for the year ended December 31, 2006 for a
detailed description of the Whole Unit Plan.

The following table shows the changes during the quarter of RTUs and PTUs
outstanding:

-------------------------------------------------------------------------
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 648 683 1,331
Granted in the period - - -
Vested in the period - - -
Forfeited in the period (15) (18) (33)
-------------------------------------------------------------------------
Balance, end of period(1) 633 665 1,298
-------------------------------------------------------------------------
Estimated distributions to vesting date(2) 169 169 338
Estimated units upon vesting after
distributions 802 834 1,636
Performance multiplier(3) - 1.6 -
-------------------------------------------------------------------------
Estimated total units upon vesting 802 1,365 2,167
-------------------------------------------------------------------------
Trust unit price at March 31, 2007 21.25 21.25 21.25
Estimated total value upon vesting 17.0 29.0 46.0
-------------------------------------------------------------------------
(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, 2007 based on a weighted average calculation of
all outstanding grants. The performance multiplier is assessed at
each period end based on management's best estimate of the
performance multiplier at the time of vesting.

The value associated with the RTUs and PTUs is expensed in the statement
of income over the vesting period with the expense amount being determined by
the trust unit price, the number of PTUs to be issued on vesting, and
distributions. Therefore, the expense recorded in the statement of income
fluctuates over time.

Below is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier:

-------------------------------------------------------------------------
Value of Whole Unit Plan as at
March 31, 2007 Performance Multiplier
(units thousands and $ millions ----------------------------------
except per unit) - 1.0 2.0
-------------------------------------------------------------------------
Estimated trust units to vest
RTUs 802 802 802
PTUs - 834 1,668
-------------------------------------------------------------------------
Total units(1) 802 1,636 2,470
-------------------------------------------------------------------------
Trust unit price(2) 21.25 21.25 21.25
Trust unit distributions per month(2) 0.20 0.20 0.20
-------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting 17.0 36.3 55.6
-------------------------------------------------------------------------
Officers 2.1 11.6 21.1
Directors 1.3 1.3 1.3
Staff 13.6 23.4 33.2
-------------------------------------------------------------------------
Total Payments Under Whole Unit Plan(3) 17.0 36.3 55.6
-------------------------------------------------------------------------
2007 7.3 10.5 13.6
2008 6.2 13.8 21.5
2009 3.5 12.0 20.5
-------------------------------------------------------------------------
(1) Includes an estimate of additional 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. Assumed
future trust unit price of $21.25 per trust unit and distributions of
$0.20 per trust 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 operations.

Due to the variability in the future payments under the plan, the Trust
estimates that payments could range from $17 million to $55.6 million from
2007 through 2009 based on the current trust unit price, distribution levels
and a performance multiplier ranging from zero to two.

Interest Expense
Interest expense increased to $9.9 million in the first quarter of 2007
from $7.6 million in the first quarter of 2006 due to an increase in short-
term interest rates, and higher debt balances. The Trust's debt balance has
remained relatively unchanged from year end as a result of funding
100 per cent of the first quarter capital program with cash flow and proceeds
from the Distribution Reinvestment Program ("DRIP") program. As at March 31,
2007, the Trust had $689.7 million of debt outstanding, of which $258.3
million was fixed at a weighted average rate of 5.1 per cent and $431.4
million was floating at current market rates plus a credit spread of 65 basis
points. 71 per cent of the Trust's debt is denominated in U.S. dollars.

The following is a summary of the debt balance and interest expense for
the first quarters of 2007 and 2006:

Foreign Exchange Gains and Losses
The Trust recorded a gain of $5 million ($0.86 per boe) on foreign
exchange transactions compared to a loss of $5.6 million ($0.96 per boe) in
for the first quarter of 2006. These amounts include both realized and
unrealized foreign exchange gains and losses. Unrealized foreign exchange
gains and losses are due to revaluation of U.S. denominated debt balances. The
volatility of the Canadian dollar during the reporting period has a direct
impact on the unrealized component of the foreign exchange gain or loss. The
unrealized gain/loss impacts net income but does not impact cash flow as it is
a non-cash amount. Realized foreign exchange gains or losses arise from U.S.
denominated transactions such as interest payments, debt repayments and
hedging settlements.

Taxes
In the first quarter of 2007, a future income tax recovery of
$11.4 million was included in income compared to a $10.3 million recovery in
the first quarter of 2006. The corporate income tax rate applicable to 2007 is
32.1 per cent as compared to the expected future tax rate of 29.3 per cent.
ARC does not anticipate any material cash income taxes will be paid for
fiscal 2007. Due to the Trust's structure, currently, both income tax and
future tax liabilities are passed on to the unitholders by means of royalty
and interest payments made between ARC Resources and the Trust.
The Trust is currently assessing various alternatives with respect to the
potential implications of the proposed Trust taxation, therefore the Trust has
not arrived at a final conclusion with respect to future Trust structure and
implications to the Trust. As the tax proposals had not yet been substantively
enacted as of March 31, 2007, the consolidated financial statements do not
reflect the impact of the proposed taxation. If the proposed legislation is
enacted, the Trust estimates that there would be a modest, one time increase
in earnings and a future tax asset would be recognized as a result of timing
differences within the Trust which have not been previously recognized.
Capital taxes were eliminated effective January 1, 2006 pursuant to the
Federal Government budget of May 2, 2006.

Depletion, Depreciation and Accretion of Asset Retirement Obligation
The depletion, depreciation and accretion ("DD&A") rate increased to
$16.36 per boe in the first quarter of 2007 from $15.34 per boe in the first
quarter of 2006. The higher DD&A rate is driven by an increase in the PP&E
value on the Trust's balance sheet along with an increase in the future
development costs and a slight decrease in proved reserves recorded in the
Trust's January 1, 2007 reserve report.

A breakdown of the DD&A rate is a follows:

Capital Expenditures and Net Acquisitions
Total capital expenditures, excluding acquisitions and dispositions,
totaled $77.5 million in the first quarter of 2007 compared to $79 million in
the first quarter of 2006. This amount was incurred on drilling and
completions, geological, geophysical and facilities expenditures, and the
purchase of undeveloped acreage. The Trust also spent $0.2 million on minor
property acquisitions in the first quarter of 2007 as compared to
$27.6 million for the same period in 2006.

A breakdown of capital expenditures and net acquisitions is shown below:

Approximately 74 per cent of the $77.5 million capital program was
financed with cash flow from operations in the first quarter of 2007 compared
to 88 per cent in the same period of 2006. The remainder of the program was
financed through proceeds from the 2007 distribution reinvestment program and
employee rights plan.

-------------------------------------------------------------------------
Source of Funding of Capital Expenditures and Net Acquisitions
($ millions)
-------------------------------------------------------------------------
Three Months Ended Three Months Ended
March 31, 2007 March 31, 2006
-------------------------------------------------------------------------
Develop- Net Total Develop- Net Total
ment Acquisi- Expendi- ment Acquisi- Expendi-
Capital tions tures Capital tions tures
-------------------------------------------------------------------------

Expenditures 77.5 0.2 77.7 79.0 27.6 106.6
-------------------------------------------------------------------------
Per cent
funded by:
Cash flow 74% - 74% 88% - 65%
Proceeds from
DRIP and
Rights Plan 26% 100% 26% 12% 49% 22%
Debt - - - - 51% 13%
-------------------------------------------------------------------------
100% 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
>>

Long-Term Investment
The Trust continues to hold a $20 million investment in the shares of a
private company that is involved in the acquisition of oil sands leases with
development potential as at March 31, 2007. On April 27, 2007, the private
company announced that they had entered into negotiations to sell all
outstanding shares of the company in a transaction that is expected to close
in June 2007. Based on the offer price, ARC would expect to record a cash gain
of approximately $13 million in the second quarter of 2007, with total
proceeds of $33 million recorded as part of cash flow from investing
activities.

Asset Retirement Obligation and Reclamation Fund
At March 31, 2007, the Trust has recorded an Asset Retirement Obligation
("ARO") of $173 million ($167 million at March 31, 2006) for future
abandonment and reclamation of the Trust's properties. The 2007 ARO increased
as a result of wells drilled during 2006 and the first quarter of 2007 as well
as property and corporate acquisitions completed in 2006 and the first quarter
of 2007. The ARO further increased by $2.9 million for accretion expense in
the first quarter of 2007 ($2.6 million in the first quarter of 2006) and was
reduced by $4.7 million ($1.3 million in 2006) for actual abandonment
expenditures incurred throughout the first quarter. The Trust did not record a
gain or loss on actual abandonment expenditures incurred as the costs closely
approximated the liability value included in the ARO.
In total, ARC contributed $3 million cash to its reclamation funds in the
first quarter of 2007 ($1.5 million in 2006) and earned interest of
$0.3 million ($0.2 million in 2006) on the fund balances. The increase in
funding is attributed to the Redwater fund. The fund balances were reduced by
$2.1 million for cash-funded abandonment expenditures in the first quarter of
2007 ($1.2 million in 2006).

A breakdown of the Trust's capital structure is as follows as at
March 31, 2007 and December 31, 2006:

Capitalization, Financial Resources and Liquidity

<<
-------------------------------------------------------------------------
Capital Structure and Liquidity
($ millions except per unit and per March 31, December 31,
cent amounts) 2007 2006
-------------------------------------------------------------------------
Revolving credit facilities 431.4 426.1
Senior secured notes 258.3 261.0
Working capital deficit excluding
short-term debt(1) 40.0 52.0
-------------------------------------------------------------------------
Net debt obligations 729.7 739.1
Units outstanding and issuable for exchangeable
shares (thousands) 208.7 207.2
Market price per unit at end of period 21.25 22.30
Market value of units and exchangeable shares
at end of period 4,434.9 4,620.0
Total capitalization(2) 5,164.6 5,359.1
-------------------------------------------------------------------------
Net debt as a percentage of total capitalization 14.1% 13.8%
Net debt obligations 729.7 739.1
Cash flow from operations 183.8 760.6
Net debt to annualized cash flow 1.0 1.0
-------------------------------------------------------------------------
(1) The working capital deficit excludes the balances for risk management
contracts.
(2) 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.
>>

Net debt levels at March 31, 2007 have remained constant as a percentage
of total capitalization since December 31, 2006 as a result of funding
100 per cent of the 2007 first quarter capital program with cash flow and
proceeds of the DRIP program.
The Trust has a syndicated three year revolving credit facility allowing
for maximum borrowing of up to $800 million. This was increased from
$572 million at year end 2006. The debt is secured by all the Trust's oil and
gas properties and is subject to the same major covenants as the prior credit
facility described in the MD&A as at December 31, 2006.
In addition to the $800 million credit facility, the Trust has issued
senior secured notes that do not reduce the available borrowings under the
credit facility. As at March 31, 2007, the Trust had $376.3 million of
available borrowings under the current credit facility.
The Trust intends to finance its $360 million 2007 capital program with
cash flow and the proceeds of the distribution reinvestment program with any
remainder being financed with debt.

Unitholders' Equity
At March 31, 2007, there were 208.7 million units issued and issuable for
exchangeable shares, an increase from 207.2 million units from December 31,
2006. The increase in number of units outstanding is mainly attributable to
the 1.4 million units issued pursuant to the DRIP during 2007 at an average
price of $20.07 per unit.
The Trust had 0.3 million rights outstanding as of March 31, 2007 under
an employee plan where further rights issuances were discontinued in 2004. The
remaining rights may be purchased at an average adjusted exercise price of
$9.24 per unit as at March 31, 2007. All of the rights were fully vested at
March 31, 2007. The contractual life of the rights varies by series but all
will expire on or before March 22, 2009.
The Whole Unit Plan introduced in 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any units
being issued from treasury. The Trust has made provisions whereby employees
may elect to have units purchased for them on the market with the cash
received upon vesting.
Unitholders electing to reinvest distributions or make optional cash
payments to acquire 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 2007, the Trust raised proceeds of
$27.1 million and issued 1.4 million units pursuant to the DRIP.

Distributions
ARC declared distributions of $123.1 million ($0.60 per unit),
representing 67 per cent of first quarter 2007 cash flow from operations
compared to distributions of $119.9 million ($0.60 per unit), representing
63 per cent of cash flow from operations in the first quarter of 2006. The
remaining 33 per cent of first quarter 2007 cash flow ($60.7 million) was used
to fund 74 per cent of ARC's 2007 year to date capital expenditures and make
contributions, including interest, to the reclamation funds ($3.3 million).
Monthly distributions for the first quarter of 2007 were $0.20 per unit.
Revisions, if any, to the monthly distribution are normally announced on a
quarterly basis in the context of prevailing and anticipated commodity prices
at that time.
The items that may be deducted from cash flow to arrive at distributions
to unitholders and the methodology used to determine distributions is detailed
in the Trust's December 31, 2006 MD&A.

Cash flow and distributions in total and per unit were as follows:

<<
-------------------------------------------------------------------------
Cash flow and Three Months Ended Three Months Ended
distributions March 31 March 31
($ millions) ($ per unit)
-----------------------------------------------------
($ millions and
$ per unit) 2007 2006 % Change 2007 2006 % Change
-------------------------------------------------------------------------
Cash flow from
operations 183.8 191.2 (4) 0.88 0.94 (6)
Reclamation fund
contributions(1) (3.3) (1.7) 94 (0.02) (0.01) 100
Capital expenditures
funded with
cash flow (57.4) (69.6) (18) (0.28) (0.34) (18)
Other(2) - - - 0.02 0.01 100
-------------------------------------------------------------------------
Distributions 123.1 119.9 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 units at each distribution date whereas per unit cash flow,
reclamation fund contributions and capital expenditures funded with
cash flow are based on weighted average outstanding units in the year
plus units issuable for exchangeable shares at year end.

2007 Monthly Distributions

Actual distributions paid and payable in 2007 along with relevant payment
dates are as follows:

-------------------------------------------------------------------------
Distribution Total
Ex-distribution Date Record Date Payment Date Distribution
-------------------------------------------------------------------------
January 29, 2007 January 31, 2007 February 15, 2007 0.20
February 26, 2007 February 28, 2007 March 15, 2007 0.20
March 28, 2007 March 31, 2007 April 16, 2007 0.20
April 26, 2007 April 30, 2007 May 15, 2007 0.20
May 29, 2007 May 31, 2007 June 15, 2007 0.20(*)
June 27, 2007 June 30, 2007 July 16, 2007 0.20(*)
July 27, 2007 July 31, 2007 August 15, 2007
August 29, 2007 August 31, 2007 September 17, 2007
September 26, 2007 September 30, 2007 October 15, 2007
October 29, 2007 October 31, 2007 November 15, 2007
November 28, 2007 November 30, 2007 December 17, 2007
December 27, 2007 December 31, 2007 January 15, 2008
-------------------------------------------------------------------------
(*) Estimated

Please refer to the Trust's website at www.arcenergytrust.com for details
on distributions dates for 2007.

Taxation of Distributions
Distributions comprise a return of capital portion (tax deferred) and a
return on capital portion (taxable). The return of capital component reduces
the cost basis of the units held. For 2007, it is estimated that distributions
paid in the calendar year will be 95 per cent return on capital (taxable) and
five per cent return of capital (tax deferred). For a more detailed breakdown,
please visit our website at www.arcenergytrust.com.

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. These obligations are of a recurring and consistent nature
and impact cash flow 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, 2007:

-------------------------------------------------------------------------
Payments Due By Period
-------------------------------------------------------------------------
($ millions) 2007 2008-2009 2010-2011 Thereafter Total
-------------------------------------------------------------------------
Debt repayments(1) 17.4 25.8 473.6 172.9 689.7
Interest payments(2) 10.0 21.5 18.1 20.8 70.4
Reclamation fund
contributions(3) 4.5 11.1 9.5 76.2 101.3
Purchase commitments 10.1 8.4 3.4 6.8 28.7
Operating leases 3.8 9.0 4.4 - 17.2
Derivative contract
premiums(4) 13.3 5.5 - - 18.8
Retention bonuses 1.0 - - - 1.0
-------------------------------------------------------------------------
Total contractual
obligations 60.1 81.3 509.0 276.7 927.1
-------------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on Senior secured notes.
(3) Contribution commitments to a restricted reclamation fund associated
with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.
>>

The above noted debt repayments include the revolving credit facility.
The lenders review the credit facility each year and determine whether they
will extend the revolving periods for another year. In the event that the
credit facility is not extended at any time before the maturity date, the loan
balance will become payable on the maturity date which is April 15, 2010.
The above noted derivative contract premiums are part of the Trust's
commitments related to its risk management program. In addition to the above
premiums, the Trust has commitments related to its risk management program. As
the premiums are part of the underlying derivative contract, they have been
recorded at fair market value at March 31, 2007 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 2007 capital budget has
been approved by the Board at $360 million. This commitment has not been
disclosed in the commitment table as it is of a routine nature and is part of
normal course of operations for active oil and gas companies and trusts.
The 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 following 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 which aggregate to less than
$0.5 million and 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, 2007.

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

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

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

Internal Controls Update
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 2007 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 quarter of 2007.

Financial Reporting Update
During 2007, the Trust completed the implementation of the new CICA
Handbook Section 3855, Financial Instruments - Recognition and Measurement,
Section 1530, Comprehensive Income and Section 3865, Hedges that deal with the
recognition and measurement of financial instruments at fair value and
comprehensive income. See the "Impact of New Financial Instruments Accounting
Standards" in this MD&A and notes 2 and 8 in the Notes to the Unaudited
Consolidated Financial Statements for further details.
During the second quarter of 2006, presentation changes were made to
combine the previously reported accumulated earnings and accumulated cash
distribution figures on the balance sheet into a single deficit balance.
Numbers presented for comparative purposes have been restated to reflect this
change in presentation.

Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if they
result in financial statements that provide more reliable and relevant
information. Changes in policy are applied retrospectively unless it is
impractical to determine the period or cumulative impact of the change.
Corrections of prior period errors are applied retrospectively and changes in
accounting estimates are applied prospectively by including these changes in
net income. In addition, disclosure is required for all future accounting
changes when an entity has not applied a new source of GAAP that has been
issued but is not yet effective.

Future Accounting Changes
On December 1, 2006, the CICA issued three new accounting standards:
Handbook Section 1535, Capital Disclosures, Section 3862, Financial
instruments - Disclosures, and Section 3863, Financial instruments -
Presentations. These new standards will be effective on January 1, 2008.
Section 1535 specifies the disclosure of an entity's objectives, policies
and processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such non-
compliance. This Section is expected to have minimal impact on the Trust's
financial statements.
Sections 3862 and 3863 specify a revised and enhanced disclosure on
financial instruments. Increased disclosure will be required on the nature and
extent of risks arising from financial instruments and how the entity manages
those risks.

Objectives and 2007 Outlook

Sustainability
It is the Trust's objective to provide superior and sustainable long-term
returns to unitholders by focusing on the key strategic objectives of the
business plan. The Trust acquires, develops and optimizes oil and natural gas
properties in predominantly mature areas to generate a cash flow stream. Due
to natural production declines, the Trust must continually develop its
reserves and/or acquire new reserves in an effort to maintain reserves,
production and cash flow levels on which distributions are paid. The Trust
facilitates this by withholding a portion of cash flow to fund a portion of
ongoing capital development activities and maintaining moderate debt levels;
this is evidenced by the Trust's low payout ratio. Oil and gas royalty trusts
hold assets that are depleting and unitholders should expect production,
revenue, cash flow and distributions to decline over the long-term if reserves
cannot be economically replaced. The Trust has an inventory of internal
development prospects that will enable the Trust to maintain production at
approximately current levels for a minimum period of two years. The Trust
anticipates employing a conservative payout policy to provide for cash funding
of a portion of ongoing capital development programs and maintaining low debt
levels to facilitate further growth. The Trust measures its sustainability and
success in terms of per unit distributions, production, reserves, and cash
flow in addition to the ability to maintain low debt levels and the annual
replacement of reserves.

Following is a summary of the historical quarterly production per unit,
cash flow and payout ratios:

<<
-------------------------------------------------------------------------
Per trust unit Trailing 5
ratios Q1 2007 Q4 2006 Q3 2006 Q2 2006 Q1 2006 Quarters
-------------------------------------------------------------------------
Production
per unit(1):
Unadjusted 0.31 0.31 0.30 0.30 0.32 -
Debt-adjusted(2) 0.27 0.27 0.28 0.27 0.29 -
Normalized(3) 0.31 0.31 0.32 0.33 0.34 -
-------------------------------------------------------------------------
Cash flow
per unit 0.88 0.85 0.98 0.96 0.94 -
Distributions
per unit 0.60 0.60 0.60 0.60 0.60 3.00
Payout ratio
per cent(4) 67 70 61 62 63 64
Per cent of cash
flow retained 33 30 39 38 37 36
-------------------------------------------------------------------------
(1) Represents daily average production per thousand units. Calculated
based on annual daily average production divided by weighted average
units outstanding including trust units issuable for exchangeable
shares.
(2) Debt-adjusted indicates that all years as presented have been
adjusted to reflect a nil net debt to capitalization. It is assumed
that additional trust units were issued 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 reduce the net debt
balance to zero in each year. The debt-adjusted amounts are presented
to enable comparability of annual per unit values.
(3) 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 units were issued (or repurchased) at a quarterly
average price for the production per unit calculation in order to
reduce the net debt balance to 15 per cent of total capitalization
each quarter. The normalized amounts are presented to enable
comparability of annual per unit values.
(4) Calculated as distributions divided by cash flow from operations.
>>

Please refer to the Trust's 2006 year end MD&A for a summary of the
annual historical debt-adjusted and normalized reserves per unit and reserve
life index on which the Trust assesses performance and sustainability.
Since the first quarter of 2006, the Trust's normalized production per
unit has decreased only slightly from 0.34 to 0.31 boe of daily average
production per thousand trust units. The maintenance of production per unit
occurred even with the payout of $607.3 million of distributions ($3.00 per
trust unit and 64 per cent of cash flow) during the same time period. This
indicates that the Trust has grown production levels to offset natural
production declines. The debt-adjusted production per unit is a key measure as
it indicates the ability to generate cash flow from core operations which in
turn impacts the level of cash that may be distributed to unitholders. The
Trust expects to replace production during the rest of 2007 from internal
development opportunities.
To compare the Trust's results with oil and gas companies that retain all
of their cash flow to grow production and reserves, the Trust looks at
normalized and distribution-adjusted production per unit that calculates the
total production per initial investment with the assumption that distributions
are reinvested through the DRIP plan. Consequently, the production per initial
investment increases over time as the investor's number of trust units
increases with distribution reinvestment. A unitholder can replicate this by
participating in the DRIP so that the number of units they own increases over
time.
The Trust's distribution policy centres around the goal of providing a
consistent and sustainable level of distributions to unitholders and to
provide for future growth. The payout ratio is indicative of the Trust's
commitment to fund a portion of ongoing development activities with cash flow
to enable long-term sustainability. On an annual basis, the Trust's payout
ratio has declined over time as the Trust has addressed the issue of long-term
sustainability while setting distribution levels. This has allowed the Trust
to maintain stable distributions during the last five quarters.
An additional measure of sustainability is the comparison of net income
to distributions. Net income is an accounting measure that incorporates all
costs including depletion expense and other non-cash expenses whereas cash
flow from operations measures the cash generated in a given period before the
cost of the associated reserves. As net income is sensitive to fluctuations in
commodity prices, it is expected that there will be deviations between annual
net income and distributions. The following table illustrates the annual
excess or shortfall of distributions to net income as a measure of long-term
sustainability.

<<
-------------------------------------------------------------------------
Net income and
distributions
($ millions
except Trailing 5
per cent) Q1 2007 Q4 2006 Q3 2006 Q2 2006 Q1 2006 Quarters
-------------------------------------------------------------------------
Net income 83.3 56.6 116.9 182.5 104.1 543.4
Distributions 123.1 122.3 121.4 120.6 119.9 607.3
-------------------------------------------------------------------------
Excess
(shortfall) (39.8) (65.7) (4.5) 61.9 (15.8) (63.9)
Excess
(shortfall)
as per cent
of net income (48) (116) (4) 34 (15) (12)
Payout ratio
(per cent) 67 70 61 62 63 64
-------------------------------------------------------------------------

2007 Guidance
Following is a summary of the Trust's 2007 Guidance issued by way of news
release on November 2, 2006, revised 2007 guidance and actual results for the
first quarter of 2007:

-------------------------------------------------------------------------
2007 2007
Revised Previous Actual
Guidance Guidance Q1 2007
-------------------------------------------------------------------------
Production (boe/d) 63,000 63,000 64,175
-------------------------------------------------------------------------
Expenses ($/boe):
Operating costs 8.95 8.95 8.99
Transportation 0.70 0.70 0.81
G&A expenses - cash 2.15 2.25 1.52
G&A expenses - stock compensation
plans 0.10 0.20 0.06
Interest 1.70 1.50 1.72
Taxes 0.00 0.00 0.00
Annual capital expenditures ($ millions) 360 360 77.5
Weighted average trust units and units
issuable (millions) 210 208 208
-------------------------------------------------------------------------

Variances in the 2007 actual results as compared to guidance are as
follows:

- Operating costs were in line with guidance. The Trust is continually
investigating cost control initiatives in order to address ongoing
pressures in the service industry. Second and third quarter operating
costs are expected to be higher than guidance due to scheduled
maintenance activities, however, annual operating costs are currently
expected to be in line with our published guidance of $8.95 per boe.

- Transportation costs were higher than guidance due to an increase in
oil volumes being trucked in Saskatchewan in response to the Enbridge
pipeline restrictions. Annual costs are still expected to be in line
with our guidance of $0.70 per boe.

- Cash G&A expenses were lower than guidance due to higher operating
recoveries attributed to high levels of capital and operating
activity in the first quarter. In addition, guidance figures include
the cash LTIP payments that only occur in April and October and were
originally forecast to be approximately $0.55 per boe for 2007. Due
to the devaluation of the unit price in the fourth quarter of 2006,
we now forecast the LTIP cash payment amounts to be approximately
$0.45 per boe and thus we have revised our cash G&A guidance for 2007
downwards to $2.15 per boe.

- Non-cash G&A expenses were lower than guidance due to the decline in
the value of the Trust's whole unit plan following the Federal
Government's proposed Trust taxation announcement on October 31,
2006. As the value of the whole unit plan is dependent upon the trust
unit price, there was a considerable decrease in the first quarter
non-cash whole unit plan expense. Accordingly, we have lowered our
guidance for the non-cash portion of the whole unit plan to $0.10 per
boe for 2007.

- Interest expense was higher than guidance due to increased short-term
interest rates and bank fees associated with the annual credit
facility renewal that occurred in the first quarter. In addition,
ARC's net debt balance has increased compared to original guidance
levels as a result of lower commodity prices in the fourth quarter of
2006 and the first quarter of 2007. As a result we have increased
interest expense guidance to $1.70 per boe.

- We have increased our guidance for weighted average trust units and
units issuable to 210 million from 208 million for 2007 as a result
of units issued under the DRIP program during the first quarter of
2007 that exceeded our original estimates.

- The Trust expects to spend the full $360 million capital budget
throughout 2007.

- See the "Objectives and 2007 Outlook" section in the Trust's annual
2006 MD&A for additional discussion on the Trust's key objectives.
>>

Assessment of Business Risks
The ARC management team is focused on long-term strategic planning and
has identified the key risks, uncertainties and opportunities associated with
the Trust's business that can impact the financial results. See "Assessment of
Business Risks" in the Trust's 2006 Annual Report MD&A for a detailed
assessment.

Forward-Looking Statement
This discussion and analysis contains forward-looking statements as to
the Trusts 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. 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 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, 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 results to
differ materially from those predicted. The Trust does not undertake to update
any forward looking information in this document whether as to new
information, future events or otherwise.

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

<<
QUARTERLY HISTORICAL REVIEW
----------------------- (CDN $ millions, except
per unit amounts) ----------------------- FINANCIAL Revenue before royalties 307.8 Per unit(1) Cash flow Per unit - basic(1) Per unit - diluted Net income Per unit - basic(2) Per unit - diluted Distributions Per unit(3) Total assets Total liabilities Net debt outstanding(4) 729.7 Weighted average
units(5) Units outstanding and
issuable(5) ----------------------- CAPITAL EXPENDITURES
Geological and
geophysical Land Drilling and completions 55.1 Plant and facilities Other capital Total capital
expenditures Property acquisitions
(dispositions) net Corporate acquisitions(6) Total capital
expenditures and net
acquisitions ----------------------- OPERATING
Production
Crude oil (bbl/d) Natural gas (mmcf/d) Natural gas liquids
(bbl/d) Total (boe per
day 6:1) Average prices
Crude oil ($/bbl) Natural gas ($/mcf) Natural gas liquids
($/bbl) Oil equivalent ($/boe) 53.29 ----------------------- TRUST UNIT TRADING
(based on intra-day
trading)
Unit prices
High Low Close Average daily volume
(thousands) ----------------------- --------------------------------------------------
2007 2006
--------------------------------------------------
Q1 Q4 Q3 Q2 Q1
292.5 312.3 306.7 318.9
1.48 1.42 1.52 1.51 1.58
183.8 174.4 200.3 194.7 191.2
0.88 0.85 0.98 0.96 0.94
0.88 0.84 0.97 0.95 0.94
83.3 56.6 116.9 182.5 104.1
0.41 0.28 0.58 0.91 0.52
0.41 0.28 0.58 0.91 0.52
123.1 122.3 121.4 120.6 119.9
0.60 0.60 0.60 0.60 0.60
3,450.1 3,479.0 3,335.8 3,277.8 3,279.7
1,526.6 1,550.6 1,371.3 1,339.9 1,434.1
739.1 579.7 567.4 598.9
207.9 206.5 205.1 203.7 202.5
208.7 207.2 205.7 204.4 203.1
--------------------------------------------------
4.9 3.7 2.2 2.8 2.7
0.2 11.8 1.4 14.3 4.9
79.1 76.2 29.8 55.4
16.8 26.5 24.6 10.9 15.6
0.5 0.8 0.5 0.8 0.5
77.5 121.9 104.9 58.6 79.1
0.2 76.4 8.4 2.8 27.6
- 16.6 - - -
77.7 214.9 113.3 61.4 106.7
--------------------------------------------------
29,520 29,605 29,108 27,805 29,651
183.0 179.5 173.4 178.5 185.0
4,161 4,144 4,166 4,247 4,120
64,175 63,663 62,178 61,803 64,600
60.79 58.26 71.84 71.86 59.53
7.75 6.99 6.10 6.35 8.40
48.04 46.51 56.60 54.44 52.91
49.94 54.59 54.54 54.86
--------------------------------------------------
23.02 29.22 30.74 28.61 27.51
20.05 19.20 25.25 24.35 25.09
21.25 22.30 27.21 28.00 27.36
658 1,125 614 548 546
--------------------------------------------------

-----------------------------------------------------
(CDN $ millions, except
per unit amounts) 2005
-----------------------------------------------------
FINANCIAL Q4 Q3 Q2
Revenue before royalties 365.3 310.2 251.6
Per unit(1) 1.89 1.62 1.32
Cash flow 207.6 168.1 121.8
Per unit - basic(1) 1.07 0.88 0.64
Per unit - diluted 1.07 0.87 0.63
Net income 130.5 114.6 73.2
Per unit - basic(2) 0.68 0.61 0.39
Per unit - diluted 0.68 0.59 0.39
Distributions 115.7 92.6 84.5
Per unit(3) 0.60 0.49 0.45
Total assets 3,251.2 2,483.5 2,427.5
Total liabilities 1,415.5 912.2 895.2
Net debt outstanding(4) 578.1 357.6 366.2
Weighted average
units(5) 193.4 191.7 190.3
Units outstanding and
issuable(5) 202.0 192.1 191.3
-----------------------------------------------------
CAPITAL EXPENDITURES
Geological and
geophysical 3.0 2.3 2.7
Land 5.5 2.0 0.8
Drilling and completions 60.3 63.6 32.7
Plant and facilities 17.0 14.8 8.7
Other capital 2.0 0.3 0.6
Total capital
expenditures 87.8 83.0 45.5
Property acquisitions
(dispositions) net 3.0 5.9 78.7
Corporate acquisitions(6) 462.8 - 42.2
Total capital
expenditures and net
acquisitions 553.6 88.9 166.4
-----------------------------------------------------
OPERATING
Production
Crude oil (bbl/d) 25,534 23,513 22,046
Natural gas (mmcf/d) 177.9 168.2 173.1
Natural gas liquids
(bbl/d) 3,943 4,047 3,962
Total (boe per
day 6:1) 59,120 55,592 54,860
Average prices
Crude oil ($/bbl) 62.12 69.37 58.37
Natural gas ($/mcf) 12.05 9.08 7.42
Natural gas liquids
($/bbl) 57.14 50.43 46.13
Oil equivalent ($/boe) 67.16 60.66 50.40
-----------------------------------------------------
TRUST UNIT TRADING
(based on intra-day
trading)
Unit prices
High 27.58 24.20 20.30
Low 20.45 19.94 16.88
Close 26.49 24.10 19.94
Average daily volume
(thousands) 653 599 605
-----------------------------------------------------
(1) Per unit amounts (with the exception of per unit distributions) are
based on weighted average units plus units issuable for exchangeable
shares.
(2) Net income per unit is based on net income after non-controlling
interest divided by weighted average units (excluding units issuable
for exchangeable shares).
(3) Based on number of trust units outstanding at each distribution
date.
(4) Net debt excludes unrealized risk management contracts asset and
liability.
(5) Includes trust units issuable for outstanding exchangeable shares
based on the period end exchange ratio.
(6) 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
As at March 31 and December 31 (unaudited)

($CDN millions) 2007 2006
-------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ - $ 2.8
Accounts receivable 130.4 129.8
Prepaid expenses 19.4 18.4
Risk management contracts (Note 8) 13.0 25.7
-------------------------------------------------------------------------
162.8 176.7
Reclamation funds (Note 3) 32.1 30.9
Property, plant and equipment 3,077.6 3,093.8
Long-term investment (Note 4) 20.0 20.0
Goodwill 157.6 157.6
-------------------------------------------------------------------------
Total assets $ 3,450.1 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------

LIABILITIES
Current liabilities
Accounts payable and accrued liabilities
(Note 5) $ 148.6 $ 162.1
Distributions payable 41.2 40.9
Risk management contracts (Note 8) 34.1 34.4
-------------------------------------------------------------------------
223.9 237.4
Long-term debt (Note 6) 689.7 687.1
Accrued long-term incentive compensation
(Note 14) 14.7 14.6
Asset retirement obligations (Note 7) 173.0 177.3
Future income taxes 425.3 434.2
-------------------------------------------------------------------------
Total liabilities 1,526.6 1,550.6
-------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Note 16)

NON-CONTROLLING INTEREST
Exchangeable shares (Note 9) 39.7 40.0

UNITHOLDERS' EQUITY
Unitholders' capital (Note 10) 2,378.6 2,349.2
Contributed surplus (Note 13) 2.2 2.4
Deficit (Note 11) (503.0) (463.2)
Accumulated other comprehensive income (Note 2) 6.0 -
-------------------------------------------------------------------------
Total unitholders' equity 1,883.8 1,888.4
-------------------------------------------------------------------------
Total liabilities and unitholders' equity $ 3,450.1 $ 3,479.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements

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

($CDN millions, except per unit amounts) 2007 2006
-------------------------------------------------------------------------
Revenues
Oil, natural gas and natural gas liquids $ 307.8 $ 318.9
Royalties (55.8) (62.2)
-------------------------------------------------------------------------
252.0 256.7
Gain (loss) on risk management contracts
(Note 8)
Realized 7.0 (1.4)
Unrealized (20.9) 5.1
-------------------------------------------------------------------------
238.1 260.4
-------------------------------------------------------------------------
Expenses
Transportation 4.7 3.5
Operating 51.9 45.4
General and administrative 9.1 13.2
Interest on long-term debt (Note 6) 9.9 7.6
Depletion, depreciation and accretion 94.5 89.2
(Gain) loss on foreign exchange (5.0) 5.6
-------------------------------------------------------------------------
165.1 164.5
-------------------------------------------------------------------------
Income before taxes 73.0 95.9
Capital and other taxes - (0.6)
Future income tax recovery 11.4 10.3
-------------------------------------------------------------------------
Net income before non-controlling interest 84.4 105.6
Non-controlling interest (Note 9) (1.1) (1.5)
-------------------------------------------------------------------------
Net Income $ 83.3 $ 104.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Deficit, beginning of period $ (463.2) $ (439.1)
Distributions paid or declared (Note 12) (123.1) (119.9)
-------------------------------------------------------------------------
Deficit, end of period (Note 11) $ (503.0) $ (454.9)
-------------------------------------------------------------------------
-------------------------------------------------------------------------

-------------------------------------------------------------------------
Net income per unit (Note 15)
Basic $ 0.41 $ 0.52
Diluted $ 0.41 $ 0.52
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements

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

($CDN millions, except per unit amounts) 2007 2006
-------------------------------------------------------------------------

Other comprehensive income, net of tax
Gain on financial instruments designated as
cash flow hedges $ 1.2 $ -
Loss on financial instruments designated as
cash flow hedges in prior periods realized
in net income in the current period (0.1) -
-------------------------------------------------------------------------
Other comprehensive income $ 1.1 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------

Accumulated other comprehensive income,
beginning of period $ - $ -
Application of initial adoption 4.9 -
-------------------------------------------------------------------------
Accumulated other comprehensive income,
end of period $ 6.0 $ -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements

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

($CDN millions) 2007 2006
-------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 83.3 $ 104.1
Add items not involving cash:
Non-controlling interest (Note 9) 1.1 1.5
Future income tax recovery (11.4) (10.3)
Depletion, depreciation and accretion 94.5 89.2
Non-cash loss (gain) on risk management
contracts (Note 8) 20.9 (5.1)
Non-cash (gain) loss on foreign exchange (5.2) 5.6
Non-cash trust unit incentive compensation
(Notes 13 and 14) 0.6 6.2
Expenditures on site restoration and
reclamation (Note 7) (4.7) (1.3)
Change in non-cash working capital (6.8) (0.9)
-------------------------------------------------------------------------
172.3 189.0
-------------------------------------------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt under revolving
credit facilities, net 7.8 16.8
Issue of trust units 1.1 2.8
Trust unit issue costs - (0.2)
Cash distributions paid, net of distribution
reinvestment (Note 12) (96.2) (99.7)
Change in non-cash working capital 1.7 4.0
-------------------------------------------------------------------------
(85.6) (76.3)
-------------------------------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of petroleum and natural gas
properties (0.2) (28.8)
Proceeds on disposition of petroleum and natural
gas properties - 1.2
Capital expenditures (77.3) (78.6)
Net reclamation fund contributions (Note 3) (1.2) (0.4)
Change in non-cash working capital (10.8) 2.6
-------------------------------------------------------------------------
(89.5) (104.0)
-------------------------------------------------------------------------
(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (2.8) 8.7
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 2.8 -
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ - $ 8.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to consolidated financial statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2007 and 2006 (unaudited)
(all tabular amounts in CDN$ millions, except per unit and volume
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 2006
annual report.

2. NEW ACCOUNTING POLICIES

Effective January 1, 2007, the Trust adopted four new accounting
standards that were issued by the Canadian Institute of Chartered
Accountants ("CICA"): Handbook Section 1530, Comprehensive Income,
Section 3855, Financial Instruments - Recognition and Measurement,
Section 3865, Hedges, and Section 1506, Accounting Changes. These new
accounting standards have been adopted prospectively and, accordingly,
comparative amounts for prior periods have not been restated. The
standards provide requirements for the recognition and measurement of
financial instruments and the use of hedge accounting.

Comprehensive Income
Section 1530 introduces Comprehensive Income, which consists of Net
Income and Other Comprehensive Income ("OCI"). OCI represents changes in
Unitholders' Equity from transactions and other events with non-owner
sources, and includes unrealized gains and losses on financial assets
classified as available-for-sale and changes in the fair value of the
effective portion of cash flow hedging instruments that qualify for
hedge accounting. These items are excluded from Net Income calculated in
accordance with GAAP. We have included in our Interim Consolidated
Financial Statements a Consolidated Statement of Other Comprehensive
Income for the changes in these items during the first quarter of 2007,
while the cumulative changes in OCI are included in Accumulated Other
Comprehensive Income ("AOCI"), which is presented as a new category
within Unitholders' Equity on the Consolidated Balance Sheet.

Financial Instruments - Recognition and Measurement
Section 3855 establishes standards for recognizing and measuring
financial assets, financial liabilities and non-financial derivatives.
Under this standard, all financial instruments are required to be
measured at fair value on initial recognition. Measurement in subsequent
periods depends on whether the financial instrument has been classified
as held-for-trading, available-for-sale, held-to-maturity, loans and
receivables, or other financial liabilities. Transaction costs are
expensed as incurred for financial instruments classified or designated
as held-for-trading. For other financial instruments, transaction costs
are capitalized on initial recognition. Financial assets and liabilities
held-for-trading are measured at fair value with changes in those fair
values recognized in Net Income. Financial assets held-to-maturity, loans
and receivables, and other financial liabilities are measured at
amortized cost using the effective interest method of amortization.
Available-for-sale financial assets are measured at fair values with
unrealized gains and losses recognized in OCI. Investments in equity
instruments classified as available-for-sale that do not have a quoted
market price in an active market are measured at cost.

Derivative instruments are recorded on the Consolidated Balance Sheet at
fair value, including those derivatives that are embedded in financial or
non-financial contracts that are not closely related to the host
contracts. Changes in fair values of derivative instruments are
recognized in Net Income with the exception of derivatives designated as
effective cash flow hedges.

Hedges
Section 3865 specifies the criteria that must be satisfied in order for
hedge accounting to be applied and the accounting for fair value and cash
flow hedges. Hedge accounting is discontinued prospectively when the
derivative no longer qualifies as an effective hedge, or the derivative
is terminated or sold, or upon the sale or early termination of the
hedged item. The Trust has currently designated its financial electricity
contracts as an effective cash flow hedge.

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

Impact
As a result of these changes in accounting policies, on January 1, 2007
the Trust has recorded $4.9 million in application of initial adoption in
AOCI to reflect the opening fair value of its cash flow hedges, net of
tax, which was previously not recorded on the consolidated financial
statements. The Trust has also recorded an increase of $7 million to
its risk management asset and an increase of $2.1 million to its future
income tax liability.

Accounting Changes
Section 1506 permits voluntary changes in accounting policy only if they
result in financial statements that provide more reliable and relevant
information. Changes in policy are applied retrospectively unless it is
impractical to determine the period or cumulative impact of the change.
Corrections of prior period errors are applied retrospectively and
changes in accounting estimates are applied prospectively by including
these changes in Net Income. In addition, disclosure is required for all
future accounting changes when an entity has not applied a new source of
GAAP that has been issued but is not yet effective.

Section 1535 specifies the disclosure of an entity's objectives, policies
and processes for managing capital, quantitative data about what the
entity regards as capital, whether the entity has complied with any
capital requirements, and if it has not complied, the consequences of
such non-compliance. This Section is expected to have minimal impact on
the Trust's financial statements.

Sections 3862 and 3863 specifies a revised and enhanced disclosure on
financial instruments. This Section will require the Trust to increase
disclosure on the nature and extent of risks arising from financial
instruments and how the entity manages those risks.

3. RECLAMATION FUNDS

March 31, 2007 December 31, 2006
---------------------------------------------------------------------
Un- Un-
restricted Restricted restricted Restricted
---------------------------------------------------------------------
Balance, beginning
of period $ 24.8 $ 6.1 $ 23.5 $ -
Contributions 3.0 - 6.0 6.1
Reimbursed
expenditures(1) (1.5) (0.6) (5.7) -
Interest earned on
funds 0.2 0.1 1.0 -
---------------------------------------------------------------------
Balance, end of
period $ 26.5 $ 5.6 $ 24.8 $ 6.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Amount differs from actual expenditures incurred by the Trust
due to timing differences and discretionary reimbursements.

4. LONG-TERM INVESTMENT

During 2006 the Trust entered into an equity investment in a private
oil sands company in the amount of $20 million. The investment in the
shares of the private company has been considered to be a related
party transaction due to common directorships of the Trust, the
private company and the manager of a private equity fund that holds
shares in the private company. The $20 million investment was part of
a $325 million private placement of the private company. In addition,
certain directors and officers of the Trust have minor direct and
indirect shareholdings in the private company.

5. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

March 31, December 31,
2007 2006
---------------------------------------------------------------------
Trades payable $ 32.8 $ 39.0
Accrued liabilities 99.2 108.8
Current portion of accrued long-term
incentive compensation 12.1 11.5
Interest payable 3.5 1.8
Retention bonuses 1.0 1.0
---------------------------------------------------------------------
Total accounts payable and accrued
liabilities $ 148.6 $ 162.1
---------------------------------------------------------------------
---------------------------------------------------------------------

The current portion of accrued long-term incentive compensation
represents the current portion of the Trust's estimated liability for
the Whole Unit Plan as at March 31, 2007 (see Note 14). This amount
is payable in 2007.

6. LONG-TERM DEBT

March 31, December 31,
2007 2006
---------------------------------------------------------------------
Revolving credit facilities
Syndicated credit facility(1) $ 423.7 $ 425.0
Working capital facility 7.7 1.1
Senior secured notes
5.42% USD Note 86.4 87.4
4.94% USD Note 27.7 28.0
4.62% USD Note 72.1 72.8
5.10% USD Note 72.1 72.8
---------------------------------------------------------------------
Total long term debt outstanding $ 689.7 $ 687.1
---------------------------------------------------------------------
(1) Amount borrowed under the syndicated credit facility includes
$2.8 million of outstanding cheques in excess of bank balance.

During the first quarter for 2007, the Trust renewed its secured,
extendible, financial covenant-based syndicated credit facility. In
conjunction with the renewal, the Trust increased the total
commitment available under the credit facility from $572 million to
$800 million and extended its maturity date to April 15, 2010. As at
March 31, 2007, the Trust had $423.7 million drawn on this facility.
The credit facility is extendible annually and security is in the
form of floating charges on all lands and assignments.

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 represents the significant financial covenants
governing the credit facility:

- 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, respectively for a maximum period of
two fiscal quarters following the closing of the material
acquisition. As at March 31, 2007, the Trust was in compliance with
all covenants and had $4.7 million in letters of credit and no
subordinated debt.

During the first quarter of 2007, the weighted-average effective
interest rate under the credit facility was 5.5 per cent
(4.4 per cent in the first three months of 2006).

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.

Interest paid during the period did not differ significantly from
interest expense.

7. ASSET RETIREMENT OBLIGATIONS

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

March 31, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $ 177.3 $ 165.1
Increase in liabilities relating to
corporate acquisitions - 4.9
Increase in liabilities relating to
development activities 0.5 2.8
(Decrease) increase in liabilities relating
to change in estimate (3.0) 4.0
Settlement of liabilities during the year (4.7) (10.6)
Accretion expense 2.9 11.1
---------------------------------------------------------------------
Balance, end of period $ 173.0 $ 177.3
---------------------------------------------------------------------
---------------------------------------------------------------------

The Trust's weighted average credit adjusted risk free rate as at
March 31, 2007 was 6.4 per cent (6.5 per cent as at December 31,
2006).

8. FINANCIAL INSTRUMENTS

The Trust uses a variety of derivative instruments to reduce its
exposure to fluctuations in commodity prices and foreign exchange
rates. 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 derivative contracts in place as at
March 31, 2007:

Financial WTI Crude Oil Contracts

Volume Bought Put Sold Put Sold Call
Term Contract bbl/d US$/bbl US$/bbl US$/bbl
---------------------------------------------------------------------
Apr 07 -
Jun 07 3 - Way Collar 1,500 65.00 52.50 70.00
Apr 07 -
Jun 07 3 - Way Collar 1,000 65.00 52.50 70.00(1)
Apr 07 -
Jun 07 Put Spread 1,000 75.00 62.70 -
Apr 07 -
Jun 07 Put Spread 1,000 75.00 65.00 -
Apr 07 -
Dec 07 3 - Way Collar 2,500 65.00 52.50 80.00
Apr 07 -
Dec 07 Put Spread 1,000 75.00 60.00 -
Apr 07 -
Dec 09 3 - Way Collar 5,000 55.00 40.00 90.00
Jul 07 -
Dec 07 Put Spread 2,500 65.00 52.50 -
Jul 07 -
Dec 07 3 - Way Collar 1,000 65.00 52.50 85.00
Jul 07 -
Dec 07 Put Spread 1,000 65.00 55.00 -
Jan 08 -
Jun 08 3 - Way Collar 1,000 65.00 52.50 85.00
Jan 08 -
Jun 08 3 - Way Collar 1,000 65.00 52.50 82.50
---------------------------------------------------------------------
(1) Sold call portion of the contract settled quarterly; all other
components settled monthly.

Financial AECO Natural Gas Contracts

Volume Bought Put Sold Put Sold Call
Term Contract GJ/d CDN$/GJ CDN$/GJ CDN$/GJ
---------------------------------------------------------------------
Apr 07 -
Jun 07 Collar 5,000 7.25 - 8.50
Apr 07 -
Jun 07 Collar 10,000 7.75 - 8.80
Apr 07 -
Oct 07 3 - Way Collar 30,000 7.00 5.00 8.65
Apr 07 -
Oct 07 3 - Way Collar 10,000 7.25 5.25 9.00
Apr 07 -
Oct 07 3 - Way Collar 10,000 7.50 5.50 9.50
Apr 07 -
Oct 07 Collar 10,000 7.75 - 10.00
---------------------------------------------------------------------

Financial NYMEX Natural Gas Contracts

Volume Bought Put Sold Put Sold Call
Term Contract mmbtu/d US$/mmbtu US$/mmbtu US$/mmbtu
---------------------------------------------------------------------
Apr 07 - Jun 07 Collar 25,000 7.25 - 8.00
Apr 07 - Jun 07 Collar 10,000 7.25 - 8.25
Apr 07 - Jun 07 Collar 20,000 7.50 - 8.50
Nov 07 - Mar 08 Collar 20,000 8.50 - 12.50
---------------------------------------------------------------------

Financial Natural Gas AECO (monthly) to NYMEX (last 3 day) Basis
Contracts

Volume Basis Swap
Term Contract mmbtu/d US$/mmbtu
---------------------------------------------------------------------
Apr 07 - Oct 08 Swap 50,000 (1.1160)
Nov 08 - Oct 10 Swap 50,000 (1.0430)
---------------------------------------------------------------------

Financial Foreign Exchange Contracts
Bought Sold
Volume Swap Swap Put Put
Term Contract MM US$ CDN$/US$ US$/CDN$ CDN$/US$ CDN$/US$
---------------------------------------------------------------------
USD Sales
Contracts
Apr 07 -
Dec 07 Swap 148.0 1.1353 0.8810 - -

USD Option
Contracts
Apr 07 -
Jun 07 Put Spread 3.0 - - 1.1788 1.1388
Apr 07 -
Jun 07 Put Spread 3.0 - - 1.1800 1.1475
Apr 07 -
Jun 07 Put Spread 3.0 - - 1.1800 1.1425
Apr 07 -
Dec 07 Put Spread 9.0 - - 1.1250 1.1000
Apr 07 -
Dec 07 Put Spread 9.0 - - 1.1280 1.0980
Apr 07 -
Dec 07 Put Spread 9.0 - - 1.1765 1.1465
Apr 07 -
Dec 07 Bought Put 5.0 - - 1.1600 -
---------------------------------------------------------------------

Financial Electricity Contracts(2)

Volume Swap
Term Contract MWh CDN$/MWh
---------------------------------------------------------------------
Apr 07 - Dec 10 Swap 20.0 64.63
Jan 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
---------------------------------------------------------------------
(2) Contracted volume is based on a 24/7 term.

Financial Interest Rate Contracts(3)
Fixed
Principal Annual Spread on
Term Contract MM US$ Rate (%) 3 Mo. LIBOR
---------------------------------------------------------------------
Apr 07 - Apr 14 Swap 30.5 4.62 38.5 bps
Apr 07 - Apr 14 Swap 32.0 4.62 (25.5 bps)
---------------------------------------------------------------------
(3) 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.

The Trust has designated all fixed price electricity contracts as
effective accounting hedges on their respective contract dates. A
realized loss of $0.1 million for the first three months of 2007
($0.1 million in 2006) on the electricity contracts has been included
in operating costs. The unrealized fair value gain on the electricity
contracts of $8.5 million has been recorded on the consolidated
balance sheet at March 31, 2007 with the movement in fair value
recorded in OCI, net of tax.

The Trust has entered into interest rate swap contracts to manage the
Company's interest rate exposure on debt instruments. In previous
periods, these contracts were designated as effective accounting
hedges on the contract date. The Trust has elected to cease applying
hedge accounting to these contracts. As a result, the unrealized fair
value loss on the interest rate swap contracts of $0.9 million has
been reflected in the income statement for the first quarter of 2007.

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,
2007 2006
---------------------------------------------------------------------
Fair value, beginning of period(1) $ (8.7) $ (4.0)
Fair value, end of period(1) (29.6) 1.1
---------------------------------------------------------------------
Change in fair value of contracts in
the period (20.9) 5.1
Realized gains (losses) in the period 7.0 (1.4)
---------------------------------------------------------------------
Gain (loss) on risk management
contracts(1) $ (13.9) $ 3.7
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Excludes the fixed price electricity contracts that were
accounted for as effective accounting hedges.

The following table reconciles the movement in the fair value of the
Trust's financial electricity contracts that have been designated as
effective accounting hedges:

March 31, March 31,
2007 2006
---------------------------------------------------------------------
Fair value, beginning of period(2) $ 7.0 $ -
Fair value, end of period 8.5 -
---------------------------------------------------------------------
Change in fair value of contracts
in the period $ 1.5 -
---------------------------------------------------------------------
---------------------------------------------------------------------
(2) Fair value of fixed price electricity contracts recognized
prospectively on January 1, 2007.

At March 31, 2007, the fair value of the contracts that were not
designated as accounting hedges was a loss of $29.6 million. The
Trust recorded a loss on risk management contracts of $13.9 million
in the statement of income for the first three months of 2007
($3.7 million gain in 2006). This amount includes the realized and
unrealized gains and losses on derivative contracts that do not
qualify as effective accounting hedges. All derivative contracts have
been reflected on the balance sheet.

9. EXCHANGEABLE SHARES

March 31, December 31,
ARL EXCHANGEABLE SHARES (thousands) 2007 2006
---------------------------------------------------------------------
Balance, beginning of period 1,433 1,595
Exchanged for Trust units(1) (49) (162)
---------------------------------------------------------------------
Balance, end of period 1,384 1,433
Exchange ratio, end of period 2.06763 2.01251
---------------------------------------------------------------------
Trust units issuable upon conversion,
end of period 2,863 2,884
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) During the first three months of 2007, 48,667 ARL exchangeable
shares were converted to trust units at an average exchange ratio
of 2.05788.

Following is a summary of the non-controlling interest for March 31,
2007 and December 31, 2006:

March 31, December 31,
2007 2006
---------------------------------------------------------------------
Non-controlling interest, beginning
of period $ 40.0 $ 37.5
Reduction of book value for conversion
to Trust units (1.4) (4.1)
Current period net income attributable
to non-controlling interest 1.1 6.6
---------------------------------------------------------------------
Non-controlling interest, end of period $ 39.7 $ 40.0
---------------------------------------------------------------------
Accumulated earnings attributable to
non-controlling interest $ 28.4 $ 27.3
---------------------------------------------------------------------
---------------------------------------------------------------------

10. UNITHOLDERS' CAPITAL

March 31, 2007 December 31, 2006
---------------------------------------------------------------------
Number of Number of
Trust Units Trust Units
(thousands) $ (thousands) $
---------------------------------------------------------------------
Balance, beginning
of period 204,289 2,349.2 199,104 2,230.8
Issued for cash - - 1 -
Issued on conversion
of ARL exchangeable
shares (Note 9) 100 1.4 310 4.1
Issued on exercise of
employee rights
(Note 13) 55 0.9 978 18.4
Distribution
reinvestment program 1,350 27.1 3,896 96.1
Trust unit issue costs - - - (0.2)
---------------------------------------------------------------------
Balance, end of period 205,794 2,378.6 204,289 2,349.2
---------------------------------------------------------------------
---------------------------------------------------------------------

11. DEFICIT

The deficit balance is composed of the following items:

March 31, December 31,
2007 2006
---------------------------------------------------------------------
Accumulated earnings $ 1,779.1 $ 1,695.8
Accumulated distributions (2,282.1) (2,159.0)
---------------------------------------------------------------------
Deficit $ (503.0) $ (463.2)
---------------------------------------------------------------------
---------------------------------------------------------------------

12. RECONCILIATION OF CASH FLOW AND DISTRIBUTIONS

Distributions are calculated in accordance with the Trust Indenture.
To arrive at distributions, cash flow from operations adjusted for
changes in non-cash working capital and expenditures on site
restoration and reclamation, is reduced by reclamation funds
contributions including interest earned on the funds and a portion of
capital expenditures. The portion of cash flow withheld to fund
capital expenditures is at the discretion of the Board of Directors.

March 31, March 31,
2007 2006
---------------------------------------------------------------------
Cash flow from operating activities $ 172.3 $ 189.0
Change in non-cash working capital 6.8 0.9
Expenditures on site reclamation and
restoration 4.7 1.3
---------------------------------------------------------------------
Cash flow from operating activities after
the above adjustments 183.8 191.2
Deduct:
Cash withheld to fund current period
capital expenditures (57.4) (69.6)
Reclamation fund contributions and
interest earned on fund balances (3.3) (1.7)
---------------------------------------------------------------------
Distributions(1) 123.1 119.9
Accumulated distributions, beginning
of period 2,159.0 1,674.8
---------------------------------------------------------------------
Accumulated distributions, end of period $ 2,282.1 $ 1,794.7
---------------------------------------------------------------------
---------------------------------------------------------------------
Distributions per unit(2) $ 0.60 $ 0.60
Accumulated distributions per unit,
beginning of period 18.63 16.23
---------------------------------------------------------------------
Accumulated distributions per unit,
end of period(3) $ 19.23 $ 16.83
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Distributions include non-cash amounts of $26.9 million
($20.2 million in 2006) 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.

13. TRUST UNIT INCENTIVE RIGHTS PLAN

A summary of the changes in rights outstanding under the plan is as
follows:

Weighted
Number Average
of Rights Exercise
(thousands) Price ($)
---------------------------------------------------------------------
Balance, beginning of period 369 9.47
Exercised (55) 11.28
---------------------------------------------------------------------
Balance before reduction of exercise price 314 9.46
Reduction of exercise price(1) - (0.22)
---------------------------------------------------------------------
Balance, end of period 314 9.24
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) The holder of the right has the option to exercise rights held
at the original grant price or a reduced exercise price.

The Trust recorded nominal compensation expense for the first three
months of 2007 ($1.8 million in the first three months of 2006) for
the cost associated with the rights. The compensation expense was
based on the fair value of all outstanding rights in the first
quarter of 2007 and is amortized over the remaining vesting period of
such rights. 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 2,359,369 rights have been
exercised to March 31, 2007.

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

March 31, December 31,
CONTRIBUTED SURPLUS 2007 2006
---------------------------------------------------------------------
Balance, beginning of period $ 2.4 $ 6.4
Compensation expense - 2.5
Net benefit on rights exercised(1) (0.2) (6.5)
---------------------------------------------------------------------
Balance, end of period $ 2.2 $ 2.4
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to unitholders' capital.

14. WHOLE TRUST UNIT INCENTIVE PLAN

The Trust recorded compensation expense of $0.3 million and
$0.3 million to general and administrative and operating expenses,
respectively, and capitalized $0.1 million to property, plant and
equipment in the first quarter of 2007 for the estimated cost of the
plan ($3.8 million, $0.7 million and $0.4 million for the three
months ended March 31, 2006). The compensation expense was based on
the March 31, 2007 unit price of $21.25 ($27.36 at March 31, 2006),
accrued distributions, a weighted average performance multiplier of
1.6 (2.0 in 2006), 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, 2007:

Number Number
of RTUs of PTUs
(thousands) (thousands)
---------------------------------------------------------------------
Balance, beginning of period 648 683
Vested - -
Granted - -
Forfeited (15) (18)
---------------------------------------------------------------------
Balance, end of period 633 665
---------------------------------------------------------------------
---------------------------------------------------------------------

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

March 31, December 31,
2007 2006
---------------------------------------------------------------------
Balance, beginning of period $ 26.1 $ 15.0
Change in liabilities in the period:
General and administrative expense 0.3 8.2
Operating expense 0.3 1.1
Property, plant and equipment 0.1 1.8
---------------------------------------------------------------------
Balance, end of period 26.8 26.1
---------------------------------------------------------------------
Current portion of liability 12.1 11.5
---------------------------------------------------------------------
Accrued long-term incentive compensation $ 14.7 $ 14.6
---------------------------------------------------------------------
---------------------------------------------------------------------

15. BASIC AND DILUTED PER TRUST UNIT CALCULATIONS

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

March 31, March 31,
2007 2006
---------------------------------------------------------------------
Weighted average trust units(1) 204,990 199,583
Trust units issuable on conversion of
exchangeable shares(2) 2,863 2,896
Dilutive impact of rights(3) 217 856
---------------------------------------------------------------------
Diluted trust units and exchangeable shares 208,070 203,335
---------------------------------------------------------------------
---------------------------------------------------------------------
(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 2007 and 2006.

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.

16. COMMITMENTS AND CONTINGENCIES

Following is a summary of the Trust's contractual obligations and
commitments as at March 31, 2007:

---------------------------------------------------------------------
Payments Due By Period
---------------------------------------------------------------------
2008- 2010- There-
($ millions) 2007 2009 2011 after Total
---------------------------------------------------------------------
Debt repayments(1) 17.4 25.8 473.6 172.9 689.7
Interest payments(2) 10.0 21.5 18.1 20.8 70.4
Reclamation fund
contributions(3) 4.5 11.1 9.5 76.2 101.3
Purchase commitments 10.1 8.4 3.4 6.8 28.7
Operating leases 3.8 9.0 4.4 - 17.2
Derivative contract
premiums(4) 13.3 5.5 - - 18.8
Retention bonuses 1.0 - - - 1.0
---------------------------------------------------------------------
Total contractual
obligations 60.1 81.3 509.0 276.7 927.1
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Long-term and short-term debt, excluding interest.
(2) Fixed interest payments on Senior secured notes.
(3) Contribution commitments to a restricted reclamation fund
associated with the Redwater property.
(4) Fixed premiums to be paid in future periods on certain commodity
derivative contracts.

In addition to the above, the Trust has commitments related to its
risk management program (See Note 8).

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.

17. SUBSEQUENT EVENTS

On April 27, 2007, an offer was announced to purchase a private oil
sands company in which the Trust holds an equity interest for
$33 million in a transaction that is expected to close in June 2007.
Based on the offer price, the Trust would expect to record a cash
gain of approximately $13 million in the second quarter of 2007 that
would be recorded as part of cash flow from investing activities.
>>

ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $5.4 billion.
The Trust currently has an interest in oil and gas production of
approximately 63,000 barrels of oil equivalent per day from six core
areas in western Canada. The royalty trust structure allows net cash flow
to be distributed to unitholders in a tax efficient manner. ARC Energy
Trust trades on the TSX under the symbol AET.UN.

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 2007 and beyond; the sources,
deployment and allocation of expected capital in 2007; 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

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