ARC Energy Trust announces second quarter 2007 results



    CALGARY, Aug. 1 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") announces the results for the second quarter ending June 30,
2007.

    
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
                                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    FINANCIAL
    ($CDN millions, except per unit
     and per boe amounts)
    Revenue before royalties             305.6     306.7     613.4     625.7
      Per unit(1)                         1.46      1.51      2.94      3.09
      Per boe                            54.48     54.54     53.88     54.70
    Cash Flow(2)                         167.6     194.7     351.4     385.9
      Per unit(1)                         0.80      0.96      1.68      1.90
      Per boe                            29.88     34.61     30.87     33.73
    Net income                           184.9     182.5     268.2     286.6
      Per unit(3)                         0.90      0.91      1.30      1.43
    Distributions                        124.1     120.6     247.2     240.5
      Per unit(1)                         0.60      0.60      1.20      1.20
      Per cent of Cash Flow                 74        62        70        62
    Net debt outstanding(4)              653.9     567.4     653.9     567.4
    Total capital expenditures            48.5      58.6     126.0     137.7

    OPERATING
    Production
      Crude oil (bbl/d)                 28,099    27,805    28,806    28,723
      Natural gas (mmcf/d)               176.7     178.5     179.8     181.7
      Natural gas liquids (bbl/d)        4,088     4,247     4,124     4,184
      Total (boe/d)                     61,637    61,803    62,899    63,194
    Average prices
      Crude oil ($/bbl)                  65.21     71.86     62.96     65.53
      Natural gas ($/mcf)                 7.38      6.35      7.57      7.39
      Natural gas liquids ($/bbl)        52.76     54.44     50.39     53.69
      Oil equivalent ($/boe)(5)          54.48     54.54     53.88     54.70
    Operating netback ($/boe)
      Commodity and other revenue
       (before hedging)                  54.48     54.54     53.88     54.70
      Transportation costs               (0.72)    (0.66)    (0.77)    (0.64)
      Royalties                          (9.43)    (9.78)    (9.54)   (10.25)
      Operating costs                    (9.63)    (8.20)    (9.30)    (8.00)
      Netback (before hedging)           34.70     35.90     34.27     35.81
    -------------------------------------------------------------------------

    TRUST UNITS
    (millions)
    Units outstanding, end of period     207.3     201.5     207.3     201.5
    Units issuable for exchangeable
     shares                                2.9       2.9       2.9       2.9
    Total units outstanding and
     issuable for exchangeable
     shares, end of period               210.2     204.4     210.2     204.4
    Weighted average units(6)            209.5     203.7     208.7     203.1
    -------------------------------------------------------------------------

    TRUST UNIT TRADING STATISTICS
    ($CDN, except volumes)
    based on intra-day trading
    High                                 23.86     28.61     23.86     28.61
    Low                                  20.78     24.35     20.05     24.35
    Close                                21.74     28.00     21.74     28.00
    Average daily volume (thousands)       599       548       629       546
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares. Per unit distributions are based on
        the number of trust units outstanding at each distribution date.
    (2) Cash Flow is a non-GAAP measure. Refer to the non-GAAP measure
        section in the MD&A for a reconciliation of Cash Flow to cash flow
        from operating activities as prescribed by GAAP.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Net debt excludes unrealized risk management contracts.
    (5) Includes other revenue.
    (6) Includes trust units issuable for outstanding exchangeable shares at
        period end.

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

    -   Production averaged 61,637 boe per day in the second quarter of 2007,
        relatively unchanged from 61,803 boe per day achieved in the second
        quarter of 2006. The second quarter is normally the low point for the
        year as maintenance activities at both ARC operated and third party
        operated facilities result in production being shut-in. During the
        second quarter of 2007 approximately 2,000 boe per day of production
        was shut-in due to maintenance activities and other operational
        disruptions. Production in the third quarter is expected to return to
        normal levels. The Trust has maintained its full year production
        guidance of 63,000 boe per day.

    -   The Trust drilled eight wells during the quarter including the third
        well of a four-well horizontal drilling program at Dawson in
        northeast British Columbia, keeping the Trust on track to reach
        natural gas production of 40 mmcf/d for this property by the fourth
        quarter. Achieving this goal is dependent upon the completion of a
        third party gas plant that is currently under construction with an
        anticipated start-up date of November 1, 2007.

    -   Capital expenditures for the quarter were $48.5 million, 86 per cent
        of which was funded from Cash Flow with the remainder funded with
        proceeds from the distribution re-investment program (DRIP). Year-to-
        date capital expenditures are $126 million, all which have been
        funded from Cash Flow and the proceeds from the DRIP. The Trust
        expects to spend approximately $350 million on capital expenditures
        during 2007.

    -   Prior to hedging activities, ARC's total realized commodity price was
        $54.48 per boe in the second quarter of 2007, relatively unchanged
        from the $54.54 per boe received prior to hedging in the second
        quarter of 2006. The Trust benefited from a balanced production mix,
        whereby a 16 per cent increase in natural gas prices offset a nine
        per cent decrease in oil prices in the second quarter of 2007
        compared to the second quarter of 2006.

    -   In addition to the fluctuations in the commodity price, the Canadian
        dollar appreciated significantly against the U.S. dollar, reaching a
        30 year high of CDN/USD $0.94 at the end of the second quarter. The
        average CDN/USD for the second quarter of 2007 was $0.91, a seven per
        cent increase from CDN/USD $0.85 in the first quarter of 2007. The
        Trust has seen a negative impact to revenue, and therefore Cash Flow,
        during the quarter because commodity prices are derived from U.S.
        dollar posted prices for both oil and natural gas. Future revenues
        may be negatively impacted due to the continued strengthening of the
        Canadian dollar. In July 2007, the dollar has continued to appreciate
        with the latest record high being USD/CDN $0.96 on July 16, 2007.
        Conversely, the Trust has benefited from management's decision to
        hold a major portion of the Trust's subsidiaries' debt in U.S.
        dollars. The Trust has seen a significant decrease in the Canadian
        dollar equivalent of its debt balance; however, the majority of this
        gain is a non-cash, unrealized gain.

    -   Net income for the quarter was $184.9 million, effectively unchanged
        from $182.5 million in the second quarter of 2006. The Trust has
        recorded a $35.6 million one time increase in earnings and a
        corresponding decrease to its future income tax liability as a result
        of the passage of the previously announced tax on income trusts.

    -   Cash Flow for the quarter was $167.6 million of which $124.1 million
        was distributed to unitholders representing $0.60 per unit based on
        the number of trust units outstanding at each record date. The Trust
        announced third quarter distributions will remain at $0.20 per unit
        per month, a level that has been maintained since October 2005.

    -   The Trust recorded the sale of its long-term investment during the
        second quarter. A gain of $13.3 million dollars was recorded and the
        full proceeds of $33.3 million were recorded in cash flow from
        investing activities during the quarter. The net debt balance
        excluding risk management contract assets and liabilities of
        $653.9 million at June 30, 2007 incorporates the proceeds from the
        sale.
    

    MANAGEMENT'S DISCUSSION AND ANALYSIS
    ------------------------------------

    This management's discussion and analysis ("MD&A") is dated July 31, 2007
and should be read in conjunction with the June 30, 2007 unaudited interim
consolidated financial statements of ARC Energy Trust ("ARC", "the Trust",
"we", "our"), the March 31, 2007 unaudited interim consolidated financial
statements and MD&A, as well as the audited consolidated financial statements
and MD&A for the year ended December 31, 2006.

    Non-GAAP Measures

    Management uses Cash Flow and Cash Flow 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. Management uses the non-GAAP measure of Cash
Flow because we feel that it is a more meaningful measure of the true cash
generated in a period from active operations and therefore have concluded that
it is material and relevant to discuss Cash Flow throughout this MD&A.

    
    The following table reconciles the cash flow from operating activities to
Cash Flow, which is used frequently in this MD&A:

    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
    -------------------------------------------------------------------------
    ($ millions)                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Cash flow from operating
     activities                          179.4     182.2     351.7     371.2
    Changes in non-cash working
     capital                             (19.0)     10.6     (12.2)     11.5
    Expenditures on site restoration
     and reclamation                       7.2       1.9      11.9       3.2
    -------------------------------------------------------------------------
    Cash Flow                            167.6     194.7     351.4     385.9
    -------------------------------------------------------------------------
    Weighted average units including
     exchangeable shares                 209.5     203.7     208.7     203.1
    -------------------------------------------------------------------------
    Cash Flow per Unit                    0.80      0.96      1.68      1.90
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Management uses certain key performance indicators ("KPIs") and industry
benchmarks such as distributions as a per cent of Cash Flow, operating
netbacks ("netbacks"), total capitalization, finding, development and
acquisition costs, recycle ratio, reserve life index, reserves per unit and
production per unit to analyze financial and operating performance. Management
feels that these KPIs and benchmarks are key measures of profitability and
overall sustainability for the Trust. These KPIs and benchmarks as presented
do not have any standardized meaning prescribed by Canadian GAAP and therefore
may not be comparable with the calculation of similar measures for other
entities.

    Update on Legislation Changes Impacting the Trust

    Federal Government's Trust Tax Legislation

    In April 2007, the Federal Government included the proposed Trust
Taxation in the Federal Budget ("Bill C-52"). Bill C-52 received a third
reading on June 12, 2007 and then Royal Assent on June 22, 2007, thus fully
enacting the tax measures. As a result the Trust has recorded a $35.6 million
one time increase in earnings and a corresponding decrease to its future
income tax liability as a result of timing differences within the Trust that
have not been previously recognized. The initial recognition of $35.6 million
comprises $24.7 million for pre-2007 generated temporary differences and
$10.9 million for temporary differences relating to the current year.
    Our Board of Directors and Management continue to review the impact of
this tax on our business strategy. We expect future technical interpretations
and details will further clarify the legislation. At the present time, ARC
believes that if structural or other similar changes are not made, the
after-tax distribution amount in 2011 to taxable Canadian investors will
remain approximately the same, however, the distribution amount in 2011 to
tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and
foreign investors would fall by an estimated 31.5 percent and 26.5 percent,
respectively.

    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
the 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       Six Months Ended
                                      June 30                 June 30
    (CDN$ millions, except per                    %                       %
     unit and volume data)      2007    2006   Change   2007    2006   Change
    -------------------------------------------------------------------------
    Cash Flow(1)               167.6   194.7     (14)  351.4   385.9      (9)
    Cash Flow per unit(1)       0.80    0.96     (17)   1.68    1.90     (12)
    Net income                 184.9   182.5       1   268.2   286.6      (6)
    Distributions per unit(2)   0.60    0.60       -    1.20    1.20       -
    Distributions as a per cent
     of Cash Flow                 74      62      19      70      62      13
    Daily production
     (boe/d)(3)               61,637  61,803       -  62,899  63,194      (1)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Refer to Non-GAAP Measures.
    (2) Based on number of trust units outstanding at each cash distribution
        date.
    (3) Reported production amount is based on company interest, which
        includes royalty interest and is before royalty burdens. Where
        applicable in this MD&A natural gas has been converted to barrels of
        oil equivalent ("boe") based on 6 mcf: 1 bbl. The boe rate is based
        on an energy equivalent conversion method primarily applicable at the
        burner tip and does not represent a value equivalent at the well
        head. Use of boe in isolation may be misleading.
    

    Net Income

    Net income in the second quarter of 2007 was $184.9 million ($0.90 per
unit), an increase of $2.4 million from $182.5 million ($0.91 per unit) in the
second quarter of 2006. Higher operating costs ($7.9 million), interest costs
($1.7 million) and depletion expense ($4.6 million) in the quarter were almost
entirely offset by an increased gain on foreign exchange ($12.7 million). In
addition, the Trust recorded an increased gain on risk management contracts
($14 million) that was offset by a lower future income tax recovery ($24.5
million) and the recording of a gain on sale of investment ($13.3 million).

    Cash Flow

    Cash Flow was $167.6 million in the second quarter of 2007 a 14 per cent
decrease from $194.7 million recorded in the second quarter of 2006. The
decrease in second quarter Cash Flow was attributed to an $11 million decrease
in realized cash hedging gains, an $8.5 million increase in cash operating
costs and a $5.7 million increase in cash general and administrative ("G&A")
costs. The increase in operating costs, more fully described later in this
MD&A, were due primarily to turnaround and workovers that occurred in the
quarter and the G&A cost increase is attributed to the cash payout under the
Trust's Whole Unit Plan which occurred in the second quarter.

    
    Following is a summary of variances in Cash Flow from 2006 to 2007:

    -------------------------------------------------------------------------
                            Three Months Ended          Six Months Ended
                                  June 30                    June 30
                           $      $ Per      %        $      $ Per      %
                        Millions   Unit   Variance Millions   Unit   Variance
    -------------------------------------------------------------------------
    2006 Cash Flow        194.7     0.96        -    385.9     1.90        -
    -------------------------------------------------------------------------
    Volume variance        (0.8)       -        -     (2.9)   (0.01)      (1)
    Price variance         (0.4)       -        -     (9.4)   (0.05)      (2)
    Cash gains on
     risk management
     contracts(1)         (11.0)   (0.05)      (6)    (2.6)   (0.01)      (1)
    Royalties               2.1     0.01        1      8.6     0.04        2
    Expenses:
      Operating(2)         (8.5)   (0.04)      (4)   (15.4)   (0.08)      (4)
      Transportation       (0.3)   (0.01)       -     (1.5)   (0.01)       -
      Cash G&A             (5.7)   (0.03)      (3)    (6.8)   (0.04)      (2)
      Interest and
       cash taxes          (1.9)   (0.01)      (1)    (3.7)   (0.02)      (1)
      Realized foreign
       exchange (loss)     (0.6)   (0.01)       -     (0.9)       -        -
    Other                     -        -        -      0.1        -        -
    Weighted average
     trust units              -    (0.02)       -        -    (0.04)       -
    -------------------------------------------------------------------------
    2007 Cash Flow        167.6     0.80      (14)   351.4     1.68       (9)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents cash gains 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.
    

    Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

    Production

    Production volume averaged 61,637 boe per day in the second quarter of
2007, relatively unchanged from 61,803 boe per day during the second quarter
of 2006. The Trust experienced significant production loss during the second
quarter as a result of planned turnarounds and workovers. Of the approximately
2,000 boe per day of volumes that were shut-in during the quarter, the Trust
estimates that 1,000 boe per day was lost due to either unscheduled activities
or where turnarounds took significantly longer than expected. The Trust
expects third quarter production to return to normal levels. We have
maintained our full year 2007 production guidance at 63,000 boe per day.
    Throughout the first six months of 2007, the Trust has experienced
production restrictions in the northern Alberta area as a result of gas plant
capacity constraints. A new third party plant is scheduled to be on-line in
the fourth quarter of 2007 to handle existing excess production as well as
additional development production from both Dawson and Pouce South. As of
June 30, the Trust had three horizontal wells in Dawson that were waiting to
be completed. It is anticipated that these wells will be completed during the
third quarter so that they can be brought on production in the fourth quarter
when there is additional 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 second quarter of 2007, the Trust
drilled eight gross wells (six net wells) on operated properties with a 100
per cent success rate; six gross oil wells and two gross natural gas wells.
Normally, the second quarter is the least active quarter for drilling as field
operations are restricted during "spring break-up" and do not get back to
normal levels until late in the quarter when field conditions have improved.

    
    -------------------------------------------------------------------------
                              Three Months Ended          Six Months Ended
                                    June 30                    June 30
                                               %                          %
    Production(1)            2007     2006  Change      2007     2006  Change
    -------------------------------------------------------------------------
    Crude oil (bbl/d)      28,099   27,805      1     28,806   28,723      -
    Natural gas (mcf/d)   176,706  178,504     (1)   179,814  181,721     (1)
    NGL (bbl/d)             4,088    4,247     (4)     4,124    4,184     (1)
    -------------------------------------------------------------------------
    Total production
     (boe/d)               61,637   61,803      -     62,899   63,194     (1)
    -------------------------------------------------------------------------
    % Natural gas
     production                48       48                48       48
    % Crude oil and
     liquids production        52       52                52       52
    -------------------------------------------------------------------------
    (1) Reported production for a period may include minor adjustments from
        previous production periods.


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

    -------------------------------------------------------------------------
                                            Three Months Ended June 30, 2007

    Production                              Total      Oil      Gas      NGL
    Core Area(1)                           (boe/d)  (bbl/d) (mmcf/d)  (bbl/d)
    -------------------------------------------------------------------------
    Central AB                              7,774    1,631     29.0    1,316
    Northern AB & BC                       19,417    5,599     73.9    1,499
    Pembina & Redwater                     13,515    9,188     19.1    1,136
    S.E. AB & S.W. Sask.                    9,915    1,070     53.0        9
    S.E. Sask. & MB                        11,016   10,611      1.7      128
    -------------------------------------------------------------------------
    Total                                  61,637   28,099    176.7    4,088
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                            Three Months Ended June 30, 2006

    Production                              Total      Oil      Gas      NGL
    Core Area(1)                           (boe/d)  (bbl/d) (mmcf/d)  (bbl/d)
    -------------------------------------------------------------------------
    Central AB                              8,082    1,501     30.7    1,464
    Northern AB & BC                       18,345    5,596     67.2    1,554
    Pembina & Redwater                     13,712    9,293     20.0    1,093
    S.E. AB & S.W. Sask.                   10,798    1,043     58.4        9
    S.E. Sask. & MB                        10,866   10,372      2.2      127
    -------------------------------------------------------------------------
    Total                                  61,803   27,805    178.5    4,247
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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

    -------------------------------------------------------------------------
                              Three Months Ended          Six Months Ended
                                    June 30                    June 30
                                               %                          %
    Benchmark prices         2007     2006  Change      2007     2006  Change
    -------------------------------------------------------------------------
    AECO gas (CDN$/mcf)(1)   7.37     6.28     17       7.42     7.78     (5)
    WTI oil (US$/bbl)(2)    65.02    70.70     (8)     61.59    67.14     (8)
    USD/CAD foreign
     exchange rate           0.91     0.89      2       0.88     0.88      -
    WTI oil (CDN$/bbl)      71.35    79.08    (10)     69.78    76.28     (9)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents the AECO monthly posting.
    (2) WTI represents West Texas Intermediate posting as denominated in US$.
    

    The price of oil in U.S. dollars decreased by eight per cent in the
second quarter of 2007 as compared to the second quarter of 2006 while the
price of oil in Canadian dollars decreased by 10 per cent. The strengthening
of the Canadian dollar relative to the U.S. dollar was responsible for the
larger decrease of the price of oil in Canadian dollar terms. ARC's realized
oil price in the second quarter of 2007 was $65.21 per barrel, a nine per cent
decrease over the $71.86 per barrel received in the second quarter of 2006 as
minor changes in differential offset a portion of the decrease due to the
change in foreign exchange.
    Natural gas prices recovered in the second quarter of 2007 with the
Alberta AECO Hub monthly posting averaging $7.37 per mcf as compared to $6.28
per mcf for the comparable period of 2006. The Trust's realized price of $7.38
per mcf in the second quarter of 2007 was 16 per cent higher than the $6.35
per mcf price realized by the Trust in the second quarter of 2006. 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.
    Prior to hedging activities, ARC's total realized commodity price was
$54.48 per boe in the second quarter of 2007, relatively unchanged from the
$54.54 per boe received prior to hedging in the second quarter of 2006. Given
the Trust's balanced production mix, the increases in natural gas prices
offset the decreases in oil prices during the period.

    
    The following is a summary of realized prices:

    -------------------------------------------------------------------------
                              Three Months Ended          Six Months Ended
                                    June 30                    June 30
                                               %                          %
    ARC Realized Prices      2007     2006  Change      2007     2006  Change
    -------------------------------------------------------------------------
    Oil ($/bbl)             65.21    71.86     (9)     62.96    65.63     (4)
    Natural gas ($/mcf)      7.38     6.35     16       7.57     7.39      2
    NGLs ($/bbl)            52.76    54.44     (3)     50.39    53.70     (6)
    -------------------------------------------------------------------------
    Total commodity
     revenue before
     hedging ($/boe)        54.37    54.42      -      53.77    54.58     (1)
    Other revenue ($/boe)    0.11     0.12     (8)      0.11     0.12     (8)
    -------------------------------------------------------------------------
    Total revenue before
     hedging ($/boe)        54.48    54.54      -      53.88    54.70     (1)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Revenue

    Revenue was relatively unchanged at $305.6 million as compared with $306.7
million for the second quarter of 2006 as increased gas revenues were offset
by a decrease in oil and NGL revenue.

    A breakdown of revenue is as follows:

    -------------------------------------------------------------------------
                              Three Months Ended          Six Months Ended
                                    June 30                    June 30
                                               %                          %
    Revenue ($ millions)     2007     2006  Change      2007     2006  Change
    -------------------------------------------------------------------------
    Oil revenue             166.8    181.8     (8)     328.3    340.7     (4)
    Natural gas revenue     118.6    103.2     15      246.3    242.9      1
    NGLs revenue             19.6     21.0     (7)      37.6     40.7     (8)
    -------------------------------------------------------------------------
    Total commodity
     revenue                304.9    306.0      -      612.2    624.3     (2)
    Other revenue             0.6      0.7    (14)       1.2      1.4    (14)
    -------------------------------------------------------------------------
    Total revenue before
     hedging                305.6    306.7      -      613.4    625.7     (2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    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 second quarter ARC realized cash hedging gains of $0.3 million
bringing cash hedging gains for the year-to-date to $7.3 million. Gains on
crude oil puts and foreign exchange positions were offset by settlements on
natural gas basis swaps and premiums paid for natural gas contracts.
    In addition to layering into additional natural gas and crude oil
positions during the quarter, ARC also modified positions that were previously
on the books as part of its active hedging program.
    ARC optimized its crude oil positions by restructuring the long-term
5,000 barrels per day hedge that was entered into to protect the acquisition
metrics of the 2005 Redwater/NPCU properties. ARC increased the floor price on
the 3-way collar from $55.00 to an average of $61.26. This was achieved at no
cost by lowering the ceiling price on the original structure from $90.00 to
$85.00 and raising the sold floor price from $40.00 to $50.00. This raises the
average floor price for crude oil hedges for 2008 to $63.33 per barrel.
    On a forward-looking basis ARC continues to add layers of protection for
both crude oil and natural gas production. During the quarter ARC layered on
additional protection on crude to the end of 2008 and additional natural gas
positions through to Q1 2008.
    On crude oil production ARC has protected approximately 40 per cent of
forecast oil production through year-end 2007, 30 per cent of production
through the first half of 2008, and 20 per cent of production for the second
half of 2008. For natural gas production ARC has protected approximately 32.5
per cent of production during the third quarter of 2007, 20 per cent for the
fourth quarter of 2007, and 15 per cent for the first quarter of 2008.

    
    The following is a summary of the Trust's positions for the next twelve
months as at June 30, 2007.

    -------------------------------------------------------------------------
    Hedge Positions
    as at June 29, 2007(1)(2)              Q3 2007             Q4 2007
    -------------------------------------------------------------------------
    Crude oil                          US$/bbl   bbl/day   US$/bbl   bbl/day
    -------------------------------------------------------------------------
    Sold call                            86.48     8,500     86.48     8,500
    Bought put                           61.92    13,000     61.92    13,000
    Sold put                             48.90    12,500     48.90    12,500
    -------------------------------------------------------------------------
    Natural gas                        CDN$/GJ    GJ/day   CDN$/GJ    GJ/day
    -------------------------------------------------------------------------
    Sold call                             9.08    40,435     11.36    20,986
    Bought put                            7.24    65,275      7.41    42,981
    Sold put                              5.19    55,275      5.19    18,625
    -------------------------------------------------------------------------
    FX                                 CAD/USD  $Million   CAD/USD  $Million
    -------------------------------------------------------------------------
    Bought put                          1.1400      55.8    1.1400      55.8
    Sold put                            1.1096      54.0    1.1096      54.0
    Swap                                1.1371       4.2    1.1371       4.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Hedge Positions
    as at June 29, 2007(1)(2)              Q1 2008             Q2 2008
    -------------------------------------------------------------------------
    Crude oil                          US$/bbl   bbl/day   US$/bbl   bbl/day
    -------------------------------------------------------------------------
    Sold call                            84.75    10,000     84.75    10,000
    Bought put                           63.63    10,000     63.63    10,000
    Sold put                             50.94     8,000   50.9375     8,000
    -------------------------------------------------------------------------
    Natural gas                        CDN$/GJ    GJ/day   CDN$/GJ    GJ/day
    -------------------------------------------------------------------------
    Sold call                            11.35    31,652         -         -
    Bought put                            7.58    31,652         -         -
    Sold put                                 -         -         -         -
    -------------------------------------------------------------------------
    FX                                 CAD/USD  $Million   CAD/USD  $Million
    -------------------------------------------------------------------------
    Bought put                               -         -         -         -
    Sold put                                 -         -         -         -
    Swap                                     -         -         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The prices and volumes noted above represent averages for several
        contracts and the average price for the portfolio of options listed
        above does not have the same payoff profile as the individual option
        contracts. Viewing the average price of a group of options is purely
        for indicative purposes. The natural gas price shown translates all
        NYMEX positions to an AECO equivalent price. In addition to positions
        shown here, ARC has entered into additional basis positions.
    (2) Please refer to note 9 in the Trust's unaudited consolidated
        financial statements as at June 30, 2007 and 2006 for a detailed
        breakdown of the Trust's hedging position as at June 30, 2007.
    

    The above table should be interpreted as follows using the third quarter
2007 crude oil hedges as an example. The Trust has hedged 13,000 barrels per
day at a minimum average price of US$61.92 and participates in prices up to a
maximum average of US$86.48 on 8,500 barrels per day with no limit on the
remaining 4,500 hedged barrels per day and on all other unhedged production
for the period. Finally, ARC's average protected price of $61.92 reduces penny
for penny at an average price below $48.90 on 12,500 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.
    Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

    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
$0.3 million in the second quarter of 2007 compared to a gain of $11.3 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 comparable to the Trust's floor prices for natural gas
resulting in cash hedging losses being the premiums paid in the period. The
$2.2 million cash loss recorded for natural gas was offset by small gains on
the Trust's crude oil and foreign exchange contracts.
    The unrealized gain of $10.8 million was due mostly to a weakening of
forward natural gas prices that have resulted in unrealized gains in natural
gas financial positions through the first quarter of 2008 and strengthening of
the Canadian dollar that has resulted in an increase in unrealized gains on
foreign exchange positions partly offset by strengthening crude oil prices
that have reduced the value of crude oil hedge positions.

    
    The following is a summary of the total gain (loss) on risk management
contracts for the second quarter and year to date of 2007:

    -------------------------------------------------------------------------
    Risk Management                            Interest &
    Contracts              Crude Oil   Natural   Foreign   Q2 2007   Q2 2006
    ($ millions)           & Liquids       Gas  Currency     Total     Total
    -------------------------------------------------------------------------
    Realized cash gain
     (loss) on contracts(1)      0.8      (2.2)      1.7       0.3      11.3
    Unrealized gain (loss)
     on contracts(2)            (8.6)     16.3       3.1      10.8     (14.2)
    -------------------------------------------------------------------------
    Total gain (loss) on
     risk management
     contracts                  (7.8)     14.1       4.8      11.1      (2.9)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Risk Management                            Interest &
    Contracts              Crude Oil   Natural   Foreign  YTD 2007  YTD 2006
    ($ millions)           & Liquids       Gas  Currency     Total     Total
    -------------------------------------------------------------------------
    Realized cash gain
     (loss) on contracts(1)      5.7       1.6         -       7.3       9.9
    Unrealized gain (loss)
     on contracts(2)           (15.3)        -       5.2     (10.1)     (9.1)
    -------------------------------------------------------------------------
    Total gain (loss) on
     risk management
     contracts                  (9.6)      1.6       5.2      (2.8)      0.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Realized cash gains and losses represent actual cash settlements or
        receipts under the respective contracts.
    (2) The unrealized (loss) gain on contracts represents the change in fair
        value of the contracts during the period.

    Operating Netbacks

    The Trust's operating netback, after realized hedging gains, decreased by
eight per cent to $34.75 per boe in the second quarter of 2007 compared to
$37.90 per boe in the same period of 2006. The decrease in netbacks in 2007 is
primarily due to higher operating costs and lower realized hedging gains.
These amounts were partially offset by lower royalty costs.


    The components of operating netbacks are shown below:

    -------------------------------------------------------------------------
                          Crude    Heavy                    Q2 2007  Q2 2006
    Netbacks                Oil      Oil      Gas      NGL    Total    Total
    ($ per boe)          ($/bbl)  ($/bbl)  ($/mcf)  ($/bbl)  ($/boe)  ($/boe)
    -------------------------------------------------------------------------
    Weighted average
     sales price          66.09    47.50     7.38    52.76    54.37    54.42
    Other revenue             -        -        -        -     0.11     0.12
    -------------------------------------------------------------------------
    Total revenue         66.09    47.50     7.38    52.76    54.48    54.54
    Royalties            (10.48)   (4.11)   (1.34)  (14.43)   (9.43)   (9.78)
    Transportation        (0.34)   (0.93)   (0.19)       -    (0.72)   (0.66)
    Operating costs(1)   (12.19)  (15.47)   (1.22)   (7.76)   (9.63)   (8.20)
    -------------------------------------------------------------------------
    Netback prior to
     hedging              43.08    26.99     4.63    30.57    34.70    35.90
    Realized gain (loss)
     on risk management
     contracts             1.04        -    (0.14)       -     0.05     2.00
    -------------------------------------------------------------------------
    Netback after
     hedging              44.12    26.99     4.49    30.57    34.75    37.90
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                          Crude    Heavy                   YTD 2007 YTD 2006
    Netbacks                Oil      Oil      Gas      NGL    Total    Total
    ($ per boe)          ($/bbl)  ($/bbl)  ($/mcf)  ($/bbl)  ($/boe)  ($/boe)
    -------------------------------------------------------------------------
    Weighted average
     sales price          63.86    45.09     7.57    50.39    53.77    54.58
    Other revenue             -        -        -        -     0.11     0.12
    -------------------------------------------------------------------------
    Total revenue         63.86    45.09     7.57    50.39    53.88    54.70
    Royalties            (10.02)   (3.84)   (1.47)  (13.50)   (9.54)  (10.25)
    Transportation        (0.41)   (1.23)   (0.20)       -    (0.77)   (0.64)
    Operating costs(1)   (11.46)  (13.18)   (1.23)   (7.73)   (9.30)   (8.00)
    -------------------------------------------------------------------------
    Netback prior to
     hedging              41.97    26.84     4.67    29.16    34.27    35.81
    Realized gain (loss)
     on risk management
     contracts             1.15        -     0.05        -     0.63     0.86
    -------------------------------------------------------------------------
    Netback after
     hedging              43.12    26.84     4.72    29.16    34.91    36.67
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 $9.43 per boe in the second quarter of 2007
compared to $9.78 per boe in the same period of 2006. Royalties as a
percentage of pre-hedged commodity revenue net of transportation costs
decreased to 17.5 per cent compared to 18 per cent in the second quarter of
2006. The decrease in royalty rates is consistent with the changes in the
Trust's production profile as new production brought on-stream impacts the
overall royalty rates.
    Transportation costs increased nine per cent to $0.72 per boe in the
second quarter of 2007 compared to $0.66 per boe in the second quarter of
2006. The Trust has experienced challenges in Saskatchewan throughout the
second half of 2006 and the first half of 2007 due to shipping restrictions on
the Enbridge pipeline as it is operating at full capacity. During the first
quarter, the Trust had to truck approximately 900 boe per day of operated oil
production at a cost significantly greater than the cost to transport those
volumes by pipeline. While transportation costs came down in the second
quarter of 2007 as compared to the first quarter of 2007, as a result of a
reduction in trucked volumes, costs were still higher than the second quarter
of 2006. An expansion of the Enbridge pipeline is expected to be completed
sometime in late 2007 or early 2008.
    Operating costs increased to $9.63 per boe compared to $8.20 per boe in
the second quarter of 2006. Total operating costs in the second quarter of
2007 increased by $7.9 million compared to the second quarter of 2006. This
increase is due to increased costs for workovers and maintenance ($3 million),
increased labour and LTIP costs ($0.9 million), increased lease rentals for
renewals ($1.5 million), increased property taxes ($1 million), and 13th month
adjustments booked in the quarter ($1.5 million).
    In comparing the Trust's total second quarter 2007 operating costs to the
first quarter of 2007, operating costs have increased by $2 million. This
amount includes higher costs for workovers and maintenance ($3 million) net of
a reduction in processing fees recorded in the period ($1 million).

    General and Administrative Expenses and Incentive Compensation

    Cash G&A before incentive compensation and net of overhead recoveries on
operated properties was relatively unchanged at $8.9 million in the second
quarter of 2007 from $8.8 million in the same period of 2006. Increases in
cash G&A expenses for 2007 were due to additional staff and higher
compensation costs. On a per boe basis, second quarter cash G&A costs
increased two per cent to $1.59 per boe in 2007 from $1.56 per boe in 2006 as
a result of higher cash G&A costs and a slight decrease in production volumes.
    During the second quarter the Trust made a payment under the Whole Unit
Plan that included the first payment for performance units issued under the
Plan in 2004. The cash payment made in April 2007 was $10.5 million of which
$8.3 million was recorded in G&A with the remainder $2.2 million being
recorded to operating costs and capital projects. These amounts were fully
accrued at the end of the first quarter of 2007, however, cash flow from
operating activities in the second quarter of 2007 has been decremented for
the full amount of the cash payment.

    
    The following is a breakdown of G&A and Incentive compensation expense:

    -------------------------------------------------------------------------
    G&A and Incentive         Three Months Ended          Six Months Ended
    Compensation Expense            June 30                    June 30
                                               %                          %
    ($ thousands)            2007     2006  Change      2007     2006  Change
    -------------------------------------------------------------------------
    G&A expenses             12.7     11.4     11       26.2     21.7     21
    Operating recoveries     (3.8)    (2.6)    46       (8.5)    (5.2)    63
    -------------------------------------------------------------------------
    Cash G&A expenses before
     Whole Unit Plan          8.9      8.8      1       17.7     16.5      7
    -------------------------------------------------------------------------
    Cash expense -
     Whole Unit Plan          8.3      2.7    207        8.3      2.7    207
    -------------------------------------------------------------------------
    Cash G&A expenses
     including Whole
     Unit Plan               17.2     11.5     50       26.0     19.2     35
    -------------------------------------------------------------------------
    Accrued compensation -
     Rights Plan                -      0.8                 -      2.5
    Accrued compensation -
     Whole Unit Plan         (4.3)     1.2    458       (4.0)     5.0    180
    -------------------------------------------------------------------------
    Total G&A and trust
     unit compensation
     expense                 12.9     13.5     (4)      22.0     26.7    (18)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    G&A and Incentive         Three Months Ended          Six Months Ended
    Compensation Expense            June 30                    June 30
                                               %                          %
    ($ per boe)              2007     2006  Change      2007     2006  Change
    -------------------------------------------------------------------------
    Cash G&A expenses before
     Whole Unit Plan         1.59     1.56      2       1.55     1.45      7
    Cash G&A expenses
     including Whole
     Unit Plan               3.07     2.05     50       2.28     1.68     36
    Total G&A and trust
     unit compensation
     expense                 2.29     2.39     (4)      1.93     2.33    (17)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    A non-cash incentive compensation expense ("non-cash compensation
expense") of $(4.3) million was recorded in the second quarter of 2007 which
represents the estimated costs of the Whole Unit Plan for the period net of
the accrual reversal for the cash amount paid in April 2007.

    Rights Plan

    The Rights Plan that provides employees, officers and independent
directors the right to purchase trust units at a specified price is being
discontinued. All rights were fully vested and expensed as of March 31, 2007.
At June 30, 2007, 0.2 million rights were outstanding at an average exercise
price of $8.95 per unit.

    Whole 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 that was put in place in 2004 as a
replacement to the Rights Plan. From an accounting perspective, the full cost
of the Whole Unit Plan is reflected in the cash G&A expenses while the cost of
the Rights Plan was represented as a non-cash charge against earnings.

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

    -------------------------------------------------------------------------
    Whole Unit Plan
    (units in thousands and        Number of       Number of           Total
     $ millions except per unit)        RTUs            PTUs   RTUs and PTUs
    -------------------------------------------------------------------------
    Balance, beginning of period         648             683           1,331
    Granted in the period                204             164             368
    Vested in the period                (191)           (111)           (302)
    Forfeited in the period              (25)            (25)            (50)
    -------------------------------------------------------------------------
    Balance, end of period(1)            636             711           1,347
    -------------------------------------------------------------------------
    Estimated distributions to
     vesting date(2)                     171             175             346
    -------------------------------------------------------------------------
    Estimated units upon vesting
     after distributions                 807             886           1,693
    Performance multiplier(3)              -             1.6               -
    -------------------------------------------------------------------------
    Estimated total units upon
     vesting                             807           1,388           2,195
    Trust unit price at
     June 30, 2007                    $21.74          $21.74          $21.74
    Estimated total value upon
     vesting                           $17.5           $30.2           $47.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 June 30, 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 June 30, 2007                       Performance Multiplier
    (units thousands and              ---------------------------------------
     $ millions except per unit)           -             1.0             2.0
    -------------------------------------------------------------------------
    Estimated trust units to vest
      RTUs                               807             807             807
      PTUs                                 -             886           1,771
    -------------------------------------------------------------------------
    Total units(1)                       807           1,693           2,578
    -------------------------------------------------------------------------
      Trust unit price(2)              21.74           21.74           21.74
      Trust unit distributions
       per month(2)                     0.20            0.20            0.20
    -------------------------------------------------------------------------
    Value of Whole Unit Plan
     upon vesting                       17.5            38.6            59.6
    -------------------------------------------------------------------------
      Officers                           2.0            12.1            22.2
      Directors                          1.4             1.4             1.4
      Staff                             14.1            25.1            36.0
    -------------------------------------------------------------------------
    Total Payments Under Whole
     Unit Plan(3)                       17.5            38.6            59.6
    -------------------------------------------------------------------------
      2007                               2.4             2.4             2.4
      2008                               7.8            15.4            23.1
      2009                               5.3            13.8            22.2
      2010                               2.0             7.0            11.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 $21.74 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 operating activities.
    

    Due to the variability in the future payments under the plan, the Trust
estimates that payments could range from $17.5 million to $59.6 million from
2007 through 2010 based on the current trust unit price, distribution levels
and a performance multiplier ranging from zero to two.

    Interest Expense

    Interest expense increased to $9.3 million in the second quarter of 2007
from $7.6 million in the second quarter of 2006 due to an increase in
short-term interest rates, and higher debt balances. Interest expense for the
first six months of 2007 was $19.2 million, an increase of $4 million from
$15.2 million in the first six months of 2006.
    The Trust's debt balance as reflected in Canadian dollars has decreased
significantly since December 31, 2006. This is a result of the nine per cent
appreciation in the Canadian dollar as compared to the U.S. dollar. The Trust
had US$420 million in outstanding debt at December 31 of which US$380 million
was still outstanding at June 30, 2007. The Canadian dollar equivalent of the
US$380 million debt balance has decreased by $38.7 million as a result of the
appreciation of the Canadian dollar against the U.S. dollar from December 31,
2006 to June 30, 2007.
    Once the foreign exchange impact is taken into consideration, the Trust's
debt balance has remained relatively unchanged from year-end as a result of
funding 100 per cent of the year to date capital program with Cash Flow and
proceeds from the Distribution Reinvestment Program ("DRIP"). See "Non-GAAP
Measures" section.
    As at June 30, 2007, the Trust had $644.8 million of debt outstanding, of
which $238.3 million was fixed at a weighted average rate of 5.06 per cent and
$406.5 million was floating at current market rates plus a credit spread of 60
basis points. 63 per cent of the Trust's debt is denominated in U.S. dollars.

    Foreign Exchange Gains and Losses

    The Trust recorded a gain of $35.5 million on foreign exchange
transactions compared to a gain of $22.8 million for the second 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. During the second quarter of
2007, the Canadian dollar reached a 30 year high when compared to the U.S.
dollar. The dollar closed the quarter at $1.06 per U.S. dollar.
    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.
    Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

    Taxes

    In the second quarter of 2007, a future income tax recovery of
$46.4 million was included in income compared to a $70.9 million recovery in
the second quarter of 2006. The second quarter 2006 recovery resulted from the
future tax reductions recorded in the 2006 Federal budget that reduced the
Trust's expected future income tax rate to 29.7 percent from the previous rate
of 33.7 per cent. The corporate income tax rate applicable to 2007 is 32.1 per
cent as compared to the expected future tax rate of 28.9 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 by ARC Resources to 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 organizational
structure and implications to the Trust. As a result of the enactment of bill
C-52, the Trust has recorded a reduction in future income taxes of
$35.6 million related to ARC Energy Trust, as tax pools were in excess of the
net book value of the assets. The initial recognition of $35.6 million
comprises $24.7 million for pre-2007 generated temporary differences and
$10.9 million for temporary differences relating to the current year.
    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
$16.31 per boe in the second quarter of 2007 from $15.43 per boe in the second
quarter of 2006. Year-to-date, the DD&A rate has increased six percent to
$16.33 per boe as compared to $15.38 in 2006. The higher DD&A rate is driven
by an increase in the property, plant and equipment ("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 as follows:

    -------------------------------------------------------------------------
    DD&A Expense              Three Months Ended          Six Months Ended
                                    June 30                    June 30
    ($ millions except                         %                          %
     per boe amounts)        2007     2006  Change      2007     2006  Change
    -------------------------------------------------------------------------
    Depletion of oil &
     gas assets(1)           88.5     84.2      5      180.1    170.7      6
    Accretion of asset
     retirement
     obligation(2)            2.9      2.6     12        5.8      5.2     12
    -------------------------------------------------------------------------
    Total DD&A               91.4     86.8      5      185.9    175.9      6
    -------------------------------------------------------------------------
    DD&A expense per boe    16.31    15.43      6      16.33    15.38      6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes depletion of the capitalized portion of the asset retirement
        obligation that was capitalized to the PP&E balance and is being
        depleted over the life of the reserves.
    (2) Represents the accretion expense on the asset retirement obligation
        during the year.

    Capital Expenditures and Acquisitions

    Total capital expenditures, excluding acquisitions and dispositions,
totaled $48.5 million in the second quarter of 2007 compared to $58.6 million
in the second 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 $14.6 million on minor
property acquisitions in the second quarter of 2007 as compared to
$5.2 million for the same period in 2006.

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

    -------------------------------------------------------------------------
                                       Three Months Ended   Six Months Ended
                                             June 30             June 30
    Capital Expenditures ($ millions)    2007      2006      2007      2006
    -------------------------------------------------------------------------
    Geological and geophysical             4.1       2.8       9.0       5.5
    Land                                   1.7      14.3       1.9      19.2
    Drilling and completions              25.8      29.8      80.9      85.1
    Plant and facilities                  16.3      10.9      33.1      26.5
    Other capital                          0.6       0.8       1.1       1.4
    -------------------------------------------------------------------------
    Total capital expenditures            48.5      58.6     126.0     137.7
    -------------------------------------------------------------------------
    Producing property acquisitions(1)    14.6       5.2      14.8      39.0
    Producing property dispositions(1)    (4.6)     (2.4)     (4.6)     (8.6)
    -------------------------------------------------------------------------
    Total capital expenditures and
     net acquisitions                     58.5      61.4     136.2     168.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Value is net of post-closing adjustments.

    Approximately 86 per cent of the $48.5 million capital program was
financed with Cash Flow in the second quarter of 2007 compared to 100 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. See "Non-GAAP Measures" section.

    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                           Three Months Ended         Three Months Ended
                              June 30, 2007              June 30, 2006
    -------------------------------------------------------------------------
                          Devel-     Net    Total    Devel-     Net    Total
                         opment   Acquis-  Expend-  opment   Acquis-  Expend-
                        Capital   itions   itures  Capital   itions   itures
    -------------------------------------------------------------------------
    Expenditures           48.5     10.0     58.5     58.6      2.8     61.4
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash Flow(1)            86%        -      71%     100%     100%     100%
    Proceeds from DRIP
     and Rights Plan        14%     100%      29%        -        -        -
    Debt                      -        -        -        -        -        -
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                            Six Months Ended           Six Months Ended
                              June 30, 2007              June 30, 2006
    -------------------------------------------------------------------------
                          Devel-     Net    Total    Devel-     Net    Total
                         opment   Acquis-  Expend-  opment   Acquis-  Expend-
                        Capital   itions   itures  Capital   itions   itures
    -------------------------------------------------------------------------
    Expenditures          126.0     10.2    136.2    137.7     30.4    168.1
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash Flow(1)            79%        -      73%     100%       4%      83%
    Proceeds from DRIP
     and Rights Plan        21%     100%      27%        -      96%      17%
    Debt                      -        -        -        -        -        -
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) See Non-GAAP Measures Section
    

    Long-Term Investment

    During the second quarter, the Trust sold its investment in the shares of
a private company that was involved in the acquisition of oil sands leases.
The transaction closed on June 25, 2007. The Trust recorded a cash gain of
$13.3 million with total proceeds of $33.3 million recorded as part of cash
flow from investing activities.

    Asset Retirement Obligation and Reclamation Fund

    At June 30, 2007, the Trust has recorded an Asset Retirement Obligation
("ARO") of $168.8 million as compared to $177.3 million at December 31, 2006
for future abandonment and reclamation of the Trust's properties. The ARO
balance has been reduced by $11.9 million for reclamation spending in the
first half of 2007 ($7.2 million for the second quarter of 2007). This amount
has been offset by accretion of $5.8 million ($2.9 million for the second
quarter of 2007). In addition, a net decrease to the liability of $2.4 million
was recorded relating to a change in estimate net of development activities in
the period. 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.
    Reclamation spending in the second quarter of 2007 was 25 per cent funded
by the reclamation fund. The remaining 75 per cent ($5.4 million) was funded
temporarily through working capital. On a year-to-date basis, reclamation
spending has been 43 per cent funded through the reclamation fund and the
remaining 57 per cent has been funded temporarily through working capital. On
an annual basis, the Trust will adjust the balance of the reclamation fund for
the full amount of reclamation spending in the period.

    
    Capitalization, Financial Resources and Liquidity

    A breakdown of the Trust's capital structure is as follows as at June 30,
2007 and December 31, 2006:

    -------------------------------------------------------------------------
    Capital Structure and Liquidity                    June 30,  December 31,
    ($ millions except per unit and per cent amounts)     2007          2006
    -------------------------------------------------------------------------
    Revolving credit facilities                          406.5         426.1
    Senior secured notes                                 238.3         261.0
    Working capital deficit excluding
     short-term debt(1)                                    9.1          52.0
    -------------------------------------------------------------------------
    Net debt obligations                                 653.9         739.1

    Trust units outstanding and issuable for
     exchangeable shares (millions)                      210.2         207.2
    Market price per unit at end of period               21.74         22.30
    Market value of trust units and exchangeable
     shares at end of period                           4,569.7       4,620.0
    Total capitalization(2)                            5,223.6       5,359.1
    -------------------------------------------------------------------------
    Net debt as a percentage of total
     capitalization                                      12.5%         13.8%
    Net debt obligations                                 653.9         739.1
    Cash Flow(3)                                         351.4         760.6
    Net debt to annualized Cash Flow                       0.9           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.
    (3) See "Non-GAAP Measures" Section
    

    Net debt levels at June 30, 2007 have decreased since December 31, 2006
as a result of funding 100 per cent of the 2007 year to date quarter capital
program with Cash Flow and proceeds of the DRIP program. Lastly, the Trust's
net balance has decreased significantly as a result of the appreciation in the
Canadian dollar, which generated an unrealized gain of $40.5 million for the
six months ended June 30, 2007. As at June 30, 2007, the Trust had $380
million in U.S. denominated debt.
    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 June 30, 2007, the Trust had $394.3 million of
available borrowings under the current credit facility.
    The Trust intends to finance its $350 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 June 30, 2007, there were 210.2 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 2.8 million units issued pursuant to the DRIP during 2007 at an average
price of $20.43 per unit.
    The Trust had 0.2 million rights outstanding as of June 30, 2007 under an
employee plan where further rights issuances were discontinued in 2004. The
remaining rights may be exercised at an average adjusted exercise price of
$8.95 per unit as at June 30, 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 trust
units being issued from treasury. The Trust has made provisions whereby
employees may elect to have trust units purchased for them at prevailing
prices on the market with the cash received upon vesting.
    Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so at a
five per cent discount to the prevailing market price with no additional fees
or commissions. During the second quarter of 2007, the Trust raised proceeds
of $29.1 million and issued 1.4 million trust units pursuant to the DRIP.

    Distributions

    ARC declared distributions of $124.1 million ($0.60 per unit),
representing 74 per cent of second quarter 2007 Cash Flow compared to
distributions of $120.6 million ($0.60 per unit), representing 62 per cent of
Cash Flow in the second quarter of 2006. The remaining 26 per cent of second
quarter 2007 Cash Flow ($43.5 million) was used to fund 86 per cent of ARC's
2007 year to date capital expenditures and make contributions, including
interest, to the reclamation funds ($1.8 million).
    Monthly distributions for the second 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:

    -------------------------------------------------------------------------
                              Three Months Ended         Three Months Ended
                                    June 30                    June 30
                                               %                          %
    Cash Flow and            2007     2006  Change      2007     2006  Change
     Distributions               ($ millions)               ($ per unit)
    -------------------------------------------------------------------------
    Cash Flow               167.6    194.7    (14)      0.80     0.96    (17)
    Reclamation fund
     contributions(1)        (1.8)    (4.7)   (62)     (0.01)   (0.02)   (50)
    Capital expenditures
     funded with
     Cash Flow              (41.7)   (68.1)   (39)     (0.20)   (0.33)   (39)
    Discretionary debt
     repayments                 -     (1.3)     -          -        -      -
    Other(2)                    -        -      -       0.01    (0.01)   200
    -------------------------------------------------------------------------
    Distributions           124.1    120.6      3       0.60     0.60      -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                               Six Months Ended           Six Months Ended
                                    June 30                    June 30
                                               %                          %
    Cash Flow and            2007     2006  Change      2007     2006  Change
     Distributions               ($ millions)               ($ per unit)
    -------------------------------------------------------------------------
    Cash Flow               351.4    385.9     (9)      1.68     1.90    (12)
    Reclamation fund
     contributions(1)        (5.1)    (6.4)   (20)     (0.02)   (0.03)   (33)
    Capital expenditures
     funded with
     Cash Flow              (99.1)  (137.7)   (28)     (0.47)   (0.68)   (31)
    Discretionary debt
     repayments                 -     (1.3)     -          -        -      -
    Other(2)                    -        -      -       0.01     0.01      -
    -------------------------------------------------------------------------
    Distributions           247.2    240.5      3       1.20     1.20      -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes interest income earned on the reclamation fund balances that
        is retained in the reclamation funds.
    (2) Other represents the difference due to distributions paid being based
        on actual trust units outstanding at each distribution date whereas
        per unit Cash Flow, reclamation fund contributions and capital
        expenditures funded with Cash Flow are based on weighted average
        outstanding trust units in the year plus trust units issuable for
        exchangeable shares at year end.

    Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

    2007 Monthly Distributions

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

    -------------------------------------------------------------------------
    Ex-distribution                          Distribution        Total
    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     0.20
    August 29, 2007      August 31, 2007     September 17, 2007  0.20(*)
    September 26, 2007   September 30, 2007  October 15, 2007    0.20(*)
    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 trust units held. For 2007, it is estimated that
distributions paid in the calendar year will be in the range of 95 to 100 per
cent return on capital (taxable) and zero to 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 June 30, 2007:

    -------------------------------------------------------------------------
                           Payments Due By Period
    -------------------------------------------------------------------------
                                                2008-   2010-  There-
    ($ millions)                        2007    2009    2011   after   Total
    -------------------------------------------------------------------------
    Debt repayments(1)                   7.3    23.8   454.2   159.5   644.8
    Interest payments(2)                 6.0    22.9    19.3    22.1    70.3
    Reclamation fund contributions(3)    6.0    11.1     9.5    76.2   102.8
    Purchase commitments                 8.6     8.2     3.1     6.3    26.2
    Operating leases                     2.6     9.0     4.5       -    16.1
    Derivative contract premiums(4)     19.8     8.1       -       -    27.9
    Retention bonuses                    1.0       -       -       -     1.0
    -------------------------------------------------------------------------
    Total contractual obligations       51.3    83.1   490.6   264.1   889.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 other 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 June 30, 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 any given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2007 capital budget has
been approved by the Board at $360 million and subsequently revised downward
to $350 million due to anticipated cost savings. 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 above noted operating leases include amounts for the Trust's head
office lease. The current lease expires in May 2010. The Trust expects to
commit to a new lease within the next 12 months that will then be reflected in
the commitments table.
    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, all of which are reflected in the
Contractual Obligations and Commitments table above, which were entered into
in the normal course of operations. All leases have been treated as operating
leases whereby the lease payments are included in operating expenses or G&A
expenses depending on the nature of the lease. No asset or liability value has
been assigned to these leases in the balance sheet as of June 30, 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 six months 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 notes 2 and 9 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 -
Presentation. 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

    The Trust believes that maintenance of production and reserves per unit
on an ongoing basis are two key factors to assess the sustainability of an oil
and gas royalty trust. On a quarterly basis, the Trust reviews changes in our
production per unit measures while reserves per unit is analyzed on an annual
basis. The Trust acquires, develops and optimizes oil and natural gas
properties in predominantly mature areas to generate a Cash Flow stream. Due
to the risks inherent in the oil and gas business, including particularly the
volatility of commodity prices, there can be no assurance that with the
present or even increased levels of capital expenditures, the Trust will be
successful in achieving sustainability.
    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 utilizing a portion of Cash Flow to fund a portion of
ongoing capital development activities and maintaining moderate debt levels. 
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 ARC believes will maintain
production at approximately current levels for a minimum period of two years.
The Trust anticipates employing a conservative distribution 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 distributions as a per cent of Cash Flow:

    -------------------------------------------------------------------------
                                 Q2     Q1     Q4     Q3     Q2   Trailing 5
    Per Trust Unit Ratios      2007   2007   2006   2006   2006     Quarters
    -------------------------------------------------------------------------
    Production per unit(1):
    Unadjusted                 0.29   0.31   0.31   0.30   0.30            -
    Debt-adjusted(2)           0.26   0.27   0.27   0.28   0.27            -
    Normalized(3)             0.303   0.31   0.31   0.32  0.326            -
    -------------------------------------------------------------------------
    Cash Flow per unit         0.80   0.88   0.85   0.98   0.96            -
    Distributions per unit     0.60   0.60   0.60   0.60   0.60         3.00
    Distributions as a per
     cent of Cash Flow           74     67     70     61     62           66
    Per cent of Cash Flow
     retained                    26     33     30     39     38           34
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents daily average boe of production per thousand units.
        Calculated based on annual daily average production divided by
        weighted average trust 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.
    

    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 second quarter of 2006, the Trust's normalized production per
unit has decreased modestly from 0.326 to 0.303 boe of daily average
production per thousand trust units. The second quarter of 2007 production per
unit of 0.303 was negatively impacted by maintenance activities and shut-in
production.  Production per unit of 0.303 was achieved and the Trust paid
$611.5 million in distributions ($3.00 per trust unit and 66 per cent of Cash
Flow) over a five quarter time period. The normalized 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. Unitholders can replicate this by
participating in the DRIP so that the number of trust units they own increases
over time.
    The Trust's distribution policy centres on the goal of providing a
consistent and sustainable level of distributions to unitholders and to
provide for future growth. The distributions as a per cent of Cash Flow 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 distributions as a per cent of Cash Flow 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.
    Another possible 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 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.

    
    -------------------------------------------------------------------------
    Net Income and
    Distributions
    ($ millions except           Q2     Q1     Q4     Q3     Q2   Trailing 5
     per cent)                 2007   2007   2006   2006   2006     Quarters
    -------------------------------------------------------------------------
    Net income                184.9   83.3   56.6  116.9  182.5        624.2
    Distributions             124.1  123.1  122.3  121.4  120.6        611.5
    -------------------------------------------------------------------------
    Excess (shortfall)         60.8  (39.8) (65.7)  (4.5)  61.9         12.7
    Excess (shortfall)
     as per cent of net income   33    (48)  (116)    (4)    34            2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Please refer to "NON-GAAP MEASURES" that occurs as the first heading in
this MD&A for a reconciliation of Cash Flow to cash flow from operating
activities as prescribed by GAAP.

    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
second quarter of 2007:

    -------------------------------------------------------------------------
                                  2007 Revised  2007 Previous      Actual to
                                      Guidance       Guidance  June 30, 2007
    -------------------------------------------------------------------------
    Production (boe/d)                  63,000         63,000         62,899
    -------------------------------------------------------------------------
    Expenses ($/boe):
      Operating costs                     9.25           8.95           9.30
      Transportation                      0.70           0.70           0.77
      G&A expenses - cash(1)              2.15           2.25           2.28
      G&A expenses - stock
       compensation plans(1)              0.10           0.20          (0.35)
      Interest(1)                         1.70           1.50           1.69
      Taxes                               0.00           0.00           0.00
    Annual capital expenditures
     ($ millions)                          350            360          126.0
    Weighted average trust units
     and trust units issuable
     (millions)(1)                         210            208            209
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Guidance for the noted items were revised in the first quarter of
        2007. See the Trust's first quarter 2007 MD&A for further details.

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

    -   With operating costs higher than guidance for the six months ended
        June 30, 2007 we have revised guidance to $9.25 per boe for the full
        year 2007. The Trust is continually pursuing cost control
        initiatives in order to address ongoing pressures in the service
        industry.

    -   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 higher than guidance due to the fact that the
        Trust paid its April LTIP payment in the second quarter. The cash
        expense is offset by a reversal of the non-cash expense in the
        quarter. The Trust expects cash G&A to be in-line with guidance for
        the full year of 2007.

    -   The Trust is revising its 2007 guidance for annual capital
        expenditures to $350 million as a result of cost savings anticipated
        in drilling costs due to a general slow down of Canadian drilling
        activity.

    -   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)                             2007                2006
    -------------------------------------------------------------------------
    FINANCIAL                               Q2        Q1        Q4        Q3
    Revenue before royalties             305.6     307.8     292.5     312.3
      Per unit(1)                         1.46      1.48      1.42      1.52
    Cash Flow(2)                         167.6     183.8     174.4     200.3
      Per unit - basic(1)                 0.80      0.88      0.85      0.98
      Per unit - diluted                  0.80      0.88      0.84      0.97
    Net income                           184.9      83.3      56.6     116.9
      Per unit - basic(3)                 0.90      0.41      0.28      0.58
      Per unit - diluted                  0.89      0.41      0.28      0.58
    Distributions                        124.1     123.1     122.3     121.4
      Per unit(4)                         0.60      0.60      0.60      0.60
    Total assets                       3,432.8   3,450.1   3,479.0   3,335.8
    Total liabilities                  1,415.3   1,526.6   1,550.6   1,371.3
    Net debt outstanding(5)              653.9     729.7     739.1     579.7
    Weighted average units(6)            209.5     207.9     206.5     205.1
    Units outstanding and issuable(6)    210.2     208.7     207.2     205.7
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical             4.1       4.9       3.7       2.2
    Land                                   1.7       0.2      11.8       1.4
    Drilling and completions              25.8      55.1      79.1      76.2
    Plant and facilities                  16.3      16.8      26.5      24.6
    Other capital                          0.6       0.5       0.8       0.5
    Total capital expenditures            48.5      77.5     121.9     104.9
    Property acquisitions
     (dispositions) net                   10.0       0.2      76.4       8.4
    Corporate acquisitions(7)                -         -      16.6         -
    Total capital expenditures and
     net acquisitions                     58.5      77.7     214.9     113.3
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)                 28,099    29,520    29,605    29,108
      Natural gas (mmcf/d)               176.7     183.0     179.5     173.4
      Natural gas liquids (bbl/d)        4,088     4,161     4,144     4,166
      Total (boe per day 6:1)           61,637    64,175    63,663    62,178
    Average prices
      Crude oil ($/bbl)                  65.21     60.79     58.26     71.84
      Natural gas ($/mcf)                 7.38      7.75      6.99      6.10
      Natural gas liquids ($/bbl)        52.76     48.04     46.51     56.60
      Oil equivalent ($/boe)             54.48     53.29     49.94     54.59
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)

    Unit prices
    High                                 23.86     23.02     29.22     30.74
    Low                                  20.78     20.05     19.20     25.25
    Close                                21.74     21.25     22.30     27.21
    Average daily volume (thousands)       599       658     1,125       614
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    QUARTERLY HISTORICAL REVIEW
    (CDN $ millions, except per
     Unit amounts)                             2006                2005
    -------------------------------------------------------------------------
    FINANCIAL                               Q2        Q1        Q4        Q3
    Revenue before royalties             306.7     318.9     365.3     310.2
      Per unit(1)                         1.51      1.58      1.89      1.62
    Cash Flow(2)                         194.7     191.2     207.6     168.1
      Per unit - basic(1)                 0.96      0.94      1.07      0.88
      Per unit - diluted                  0.95      0.94      1.07      0.87
    Net income                           182.5     104.1     130.5     114.6
      Per unit - basic(3)                 0.91      0.52      0.68      0.61
      Per unit - diluted                  0.91      0.52      0.68      0.59
    Distributions                        120.6     119.9     115.7      92.6
      Per unit(4)                         0.60      0.60      0.60      0.49
    Total assets                       3,277.8   3,279.7   3,251.2   2,483.5
    Total liabilities                  1,339.9   1,434.1   1,415.5     912.2
    Net debt outstanding(5)              567.4     598.9     578.1     357.6
    Weighted average units(6)            203.7     202.5     193.4     191.7
    Units outstanding and issuable(6)    204.4     203.1     202.0     192.1
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical             2.8       2.7       3.0       2.3
    Land                                  14.3       4.9       5.5       2.0
    Drilling and completions              29.8      55.4      60.3      63.6
    Plant and facilities                  10.9      15.6      17.0      14.8
    Other capital                          0.8       0.5       2.0       0.3
    Total capital expenditures            58.6      79.1      87.8      83.0
    Property acquisitions
     (dispositions) net                    2.8      27.6       3.0       5.9
    Corporate acquisitions(7)                -         -     462.8         -
    Total capital expenditures and
     net acquisitions                     61.4     106.7     553.6      88.9
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)                 27,805    29,651    25,534    23,513
      Natural gas (mmcf/d)               178.5     185.0     177.9     168.2
      Natural gas liquids (bbl/d)        4,247     4,120     3,943     4,047
      Total (boe per day 6:1)           61,803    64,600    59,120    55,592
    Average prices
      Crude oil ($/bbl)                  71.86     59.53     62.12     69.37
      Natural gas ($/mcf)                 6.35      8.40     12.05      9.08
      Natural gas liquids ($/bbl)        54.44     52.91     57.14     50.43
      Oil equivalent ($/boe)             54.54     54.86     67.16     60.66
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
    High                                 28.61     27.51     27.58     24.20
    Low                                  24.35     25.09     20.45     19.94
    Close                                28.00     27.36     26.49     24.10
    Average daily volume (thousands)       548       546       653       599
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares.
    (2) See Non-GAAP Measures section.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Based on number of trust units outstanding at each distribution date.
    (5) Net debt excludes unrealized risk management contracts asset and
        liability.
    (6) Includes trust units issuable for outstanding exchangeable shares
        based on the period end exchange ratio.
    (7) Represents total consideration for the corporate acquisition
        including fees but prior to working capital, asset retirement
        obligation and future income tax liability assumed on acquisition.



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

    ($CDN millions)                                       2007          2006
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Cash and cash equivalents                    $      35.0   $       2.8
      Accounts receivable                                114.3         129.8
      Prepaid expenses                                    14.9          18.4
      Risk management contracts (Note 9)                  31.3          25.7
    -------------------------------------------------------------------------
                                                         195.5         176.7
    Reclamation funds (Note 3)                            32.1          30.9
    Property, plant and equipment                      3,047.6       3,093.8
    Long-term investment (Note 4)                            -          20.0
    Goodwill                                             157.6         157.6
    -------------------------------------------------------------------------
    Total assets                                   $   3,432.8   $   3,479.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities
       (Note 5)                                    $     131.8   $     162.1
      Distributions payable                               41.5          40.9
      Risk management contracts (Note 9)                  39.9          34.4
    -------------------------------------------------------------------------
                                                         213.2         237.4
    Long-term debt (Note 6)                              644.8         687.1
    Accrued long-term incentive compensation
     (Note 15)                                             9.1          14.6
    Asset retirement obligations (Note 7)                168.8         177.3
    Future income taxes (Note 8)                         379.4         434.2
    -------------------------------------------------------------------------
    Total liabilities                                  1,415.3       1,550.6
    -------------------------------------------------------------------------

    COMMITMENTS AND CONTINGENCIES (Note 17)

    NON-CONTROLLING INTEREST
      Exchangeable shares (Note 10)                       41.6          40.0

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 11)                   2,409.4       2,349.2
      Contributed surplus (Note 14)                        1.8           2.4
      Deficit (Note 12)                                 (442.2)       (463.2)
      Accumulated other comprehensive income
       (Note 2)                                            6.9             -
    -------------------------------------------------------------------------
    Total unitholders' equity                          1,975.9       1,888.4
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity      $   3,432.8   $   3,479.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to consolidated financial statements.



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

                                       Three Months Ended   Six Months Ended
    ($CDN millions, except                   June 30             June 30
     per unit amounts)                    2007      2006      2007      2006
    -------------------------------------------------------------------------

    Revenues
      Oil, natural gas and natural
       gas liquids                    $  305.6  $  306.7  $  613.4  $  625.7
      Royalties                          (52.8)    (55.0)   (108.6)   (117.3)
    -------------------------------------------------------------------------
                                         252.8     251.7     504.8     508.4
      Gain (loss) on risk management
       contracts (Note 9)
        Realized                           0.3      11.3       7.3       9.9
        Unrealized                        10.8     (14.2)    (10.1)     (9.1)
    -------------------------------------------------------------------------
                                         263.9     248.8     502.0     509.2
    -------------------------------------------------------------------------

    Expenses
      Transportation                       4.0       3.7       8.7       7.3
      Operating                           54.0      46.1     105.9      91.5
      General and administrative          12.9      13.5      22.0      26.7
      Interest on long-term debt
       (Note 6)                            9.3       7.6      19.2      15.2
      Depletion, depreciation
       and accretion                      91.4      86.8     185.9     175.9
      Gain on foreign exchange           (35.5)    (22.8)    (40.5)    (17.2)
    -------------------------------------------------------------------------
                                         136.1     134.9     301.2     299.4
    -------------------------------------------------------------------------
    Operating income                     127.8     113.9     200.8     209.8

    Gain on sale of investment (Note 4)   13.3         -      13.3         -
    Capital and other taxes                  -       0.3         -      (0.3)
    Future income tax recovery (Note 8)   46.4      70.9      57.8      81.2
    -------------------------------------------------------------------------
    Net income before non-controlling
     interest                            187.5     185.1     271.9     290.7
    Non-controlling interest (Note 10)    (2.6)     (2.6)     (3.7)     (4.1)
    -------------------------------------------------------------------------
    Net Income                        $  184.9  $  182.5  $  268.2  $  286.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Deficit, beginning of period      $ (503.0) $ (454.9) $ (463.2) $ (439.1)
    Distributions paid or declared
     (Note 13)                          (124.1)   (120.6)   (247.2)   (240.5)
    -------------------------------------------------------------------------
    Deficit, end of period (Note 12)  $ (442.2) $ (393.0) $ (442.2) $ (393.0)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income per unit (Note 16)
      Basic                           $   0.90  $   0.91  $   1.30  $   1.43
      Diluted                         $   0.89  $   0.91  $   1.30  $   1.43
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to consolidated financial statements.



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

                                       Three Months Ended   Six Months Ended
                                             June 30             June 30
    ($CDN millions)                       2007      2006      2007      2006
    -------------------------------------------------------------------------

    Other comprehensive income,
     net of tax
      Gain on financial instruments
       designated as cash flow hedges  $   1.8   $     -   $   3.0   $     -
      Loss on financial instruments
       designated as cash flow hedges
       in prior periods realized
       in net income in the
       current period                     (0.6)        -      (0.7)        -
      Net unrealized losses on
       available-for-sale reclamation
       funds' investments                 (0.3)        -      (0.3)        -
    -------------------------------------------------------------------------
    Other comprehensive income         $   0.9   $     -   $   2.0   $     -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accumulated other comprehensive
     income, beginning of period       $   6.0   $     -   $     -   $     -
      Application of initial adoption        -         -       4.9         -
    -------------------------------------------------------------------------
    Accumulated other comprehensive
     income, end of period             $   6.9   $     -   $   6.9   $     -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to consolidated financial statements.



    CONSOLIDATED STATEMENTS OF CASH FLOWS
    For the three and six months ended June 30 (unaudited)

                                       Three Months Ended   Six Months Ended
                                             June 30             June 30
    ($CDN millions)                       2007      2006      2007      2006
    -------------------------------------------------------------------------

    CASH FLOW FROM OPERATING ACTIVITIES
    Net Income                         $ 184.9   $ 182.5   $ 268.2   $ 286.6
    Add items not involving cash:
      Non-controlling interest (Note 10)   2.6       2.6       3.7       4.1
      Future income tax recovery
       (Note 8)                          (46.4)    (70.9)    (57.8)    (81.2)
      Depletion, depreciation and
       accretion                          91.4      86.8     185.9     175.9
      Non-cash (gain) loss on risk
       management contracts (Note 9)     (10.8)     14.2      10.1       9.1
      Non-cash (gain) on
       foreign exchange                  (35.6)    (22.2)    (40.8)    (16.5)
      Non-cash trust unit incentive
       compensation (Notes 14 and 15)     (5.2)      1.7      (4.6)      7.9
      Gain on sale of investment         (13.3)        -     (13.3)        -
    Expenditures on site restoration
     and reclamation                      (7.2)     (1.9)    (11.9)     (3.2)
    Change in non-cash working capital    19.0     (10.6)     12.2     (11.5)
    -------------------------------------------------------------------------
                                         179.4     182.2     351.7     371.2
    -------------------------------------------------------------------------

    CASH FLOW FROM FINANCING ACTIVITIES
    Issuance of long-term debt under
     revolving credit facilities, net     (7.8)      0.9         -      17.7
    Issue of trust units                   1.2       5.8       2.3       8.6
    Trust unit issue costs                   -         -         -      (0.2)
    Cash distributions paid (Note 13)    (95.2)    (99.0)   (191.4)   (198.7)
    Change in non-cash working capital    (1.9)     (2.6)     (0.2)      1.4
    -------------------------------------------------------------------------
                                        (103.7)    (94.9)   (189.3)   (171.2)
    -------------------------------------------------------------------------

    CASH FLOW FROM INVESTING ACTIVITIES
    Acquisition of petroleum and
     natural gas properties              (11.2)     (3.6)    (14.7)    (32.4)
    Proceeds on disposition of petroleum
     and natural gas properties            1.2       0.8       4.6       2.0
    Capital expenditures                 (47.8)    (57.9)   (125.2)   (136.5)
    Long-term investment (Note 4)         33.3     (20.0)     33.3     (20.0)
    Net reclamation fund contributions
     (Note 3)                             (0.3)     (3.2)     (1.5)     (3.7)
    Changes in non-cash working capital  (15.9)    (12.1)    (26.7)     (9.4)
    -------------------------------------------------------------------------
                                         (40.7)    (96.0)   (130.2)   (200.0)
    -------------------------------------------------------------------------
    INCREASE (DECREASE) IN CASH AND
     CASH EQUIVALENTS                     35.0      (8.7)     32.2         -
    CASH AND CASH EQUIVALENTS,
     BEGINNING OF PERIOD                     -       8.7       2.8         -
    -------------------------------------------------------------------------
    CASH AND CASH EQUIVALENTS,
     END OF PERIOD                     $  35.0   $     -   $  35.0   $     -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to consolidated financial statements.



    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
    June 30, 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 three 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 six months 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.

        Future Accounting Changes
        On December 1, 2006, the CICA issued three new accounting standards:
        Section 1535, Capital Disclosures, Section 3862, Financial
        Instruments - Disclosures, and Section 3863, Financial Instruments -
        Presentation. 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. These Sections 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

                                   June 30, 2007         December 31, 2006
        ---------------------------------------------------------------------
                                      Un-                     Un-
                              restricted  Restricted  restricted  Restricted
        ---------------------------------------------------------------------
        Balance, beginning
         of period            $     24.8  $      6.1  $     23.5  $        -
        Contributions                4.5           -         6.0         6.1
        Reimbursed
         expenditures(1)            (3.0)       (0.6)       (5.7)          -
        Interest earned on
         funds                       0.5         0.1         1.0           -
        Net unrealized losses
         on available-for-sale
         investments                (0.3)          -           -           -
        ---------------------------------------------------------------------
        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 the second quarter of 2007, the Trust sold its equity
        investment in a private oil sands company for proceeds of
        $33.3 million, resulting in a gain on sale of investment of
        $13.3 million. The original investment was purchased for $20 million.
        The investment in the shares of the private company was considered to
        be a related party transaction due to common directorships of the
        Trust, the private company and the manager of a private equity fund
        that held shares in the private company. 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 had minor
        direct and indirect shareholdings in the private company.

    5.  ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
                                                       June 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Trades payable                             $      33.9   $      39.0
        Accrued liabilities                               83.2         108.8
        Current portion of accrued long-term
         incentive compensation                           12.1          11.5
        Interest payable                                   1.6           1.8
        Retention bonuses                                  1.0           1.0
        ---------------------------------------------------------------------
        Total accounts payable and accrued
         liabilities                               $     131.8   $     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 June 30, 2007 (see Note 15). This amount is
        payable in 2007 and 2008.

    6.  LONG-TERM DEBT

                                                       June 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Revolving credit facilities
          Syndicated credit facility
           - CDN denominated                       $     239.9   $     196.6
          Syndicated credit facility
           - U.S. denominated                            165.9         228.4
          Working capital facility                         0.8           1.1
        Senior secured notes
          5.42% USD Note                                  79.7          87.4
          4.94% USD Note                                  25.5          28.0
          4.62% USD Note                                  66.5          72.8
          5.10% USD Note                                  66.5          72.8
        ---------------------------------------------------------------------
        Total long term debt outstanding           $     644.8   $     687.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        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 June 30, 2007, the Trust was in compliance with
        all covenants and had $4.7 million in letters of credit and no
        subordinated debt.

        The weighted average effective interest rate under the credit
        facility was 5.4 percent for the three months ended June 30, 2007
        (5.4 per cent in 2006) and 5.5 per cent for the six months ended
        June 30, 2007 (5.0 per cent in 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:

                                                       June 30,  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                            0.6           2.8
        (Decrease) Increase in liabilities
         relating to change in estimate                   (3.0)          4.0
        Settlement of liabilities during the year        (11.9)        (10.6)
        Accretion expense                                  5.8          11.1
        ---------------------------------------------------------------------
        Balance, end of period                     $     168.8   $     177.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Trust's weighted average credit adjusted risk free rate as at
        June 30, 2007 was 6.4 per cent (6.5 per cent as at December 31,
        2006).

    8.  INCOME TAXES

        On June 12, 2007, Bill C-52 ("Bill") received third reading in the
        House of Commons and, therefore, was considered "substantively
        enacted" for Canadian GAAP. The Bill enacts the October 31, 2006
        proposals to impose a new tax on distributions from publicly traded
        income trusts. As a result, the future tax position of the Trust, the
        parent entity, is now required to be reflected in the consolidated
        future income tax calculation.

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

                                                       June 30,      June 30,
                                                          2007          2006
        ---------------------------------------------------------------------
        Income before future income tax expense
         and recovery                              $     214.1   $     209.5
        ---------------------------------------------------------------------
        Expected income tax expense at
         statutory rates                                  67.2          72.2
        Effect on income tax of:
          Net income of the Trust                        (76.8)        (79.3)
          Non-taxable portion of gains/losses             (8.5)            -
          Effect of change in corporate tax rate          (7.3)        (58.5)
          Resource allowance                                 -          (5.5)
          Change in estimated pool balances               (7.0)         (6.4)
          Non-deductible crown charges                       -           0.5
          Capital Tax                                        -           0.1
          Other non-deductible items                      (0.7)         (4.3)
          Initial recognition of Trust tax pools         (24.7)            -
        ---------------------------------------------------------------------
        Future income tax recovery                 $     (57.8)  $     (81.2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

                                                       June 30,      June 30,
                                                          2007          2006
        ---------------------------------------------------------------------
        Future tax liabilities:
          Capital assets in excess of tax value    $     437.6   $     494.0
          Long-term debt                                   9.7             -
          Other comprehensive income                       3.0             -
        Future tax assets:
          Non-capital losses                              (4.3)         (1.6)
          Asset retirement obligations                   (48.7)        (42.3)
          Accrued long-term incentive compensation        (6.1)            -
          Risk management contracts                       (5.4)         (3.9)
          Attributed Canadian royalty income              (4.6)        (11.5)
          Deductible share issue costs                    (1.8)            -
        ---------------------------------------------------------------------
        Net future income tax liability            $     379.4   $     434.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The following is a summary of the Trust's estimated consolidated tax
        pools, as of June 30, 2007:

        ---------------------------------------------------------------------
        Canadian oil and gas property expenses                   $     735.6
        Canadian development expenses                                  298.5
        Canadian exploration expenses                                   43.5
        Undepreciated capital cost                                     405.9
        Non-capital losses                                              13.8
        Provincial tax pools                                           161.1
        Other                                                           13.5
        ---------------------------------------------------------------------
        Estimated tax basis                                      $   1,671.9
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    9.  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 risk management contracts in place as
        at June 30, 2007:

        Financial WTI Crude Oil Contracts

                                                  Bought      Sold      Sold
                                         Volume      put       put      call
        Term                   Contract   bbl/d  US$/bbl   US$/bbl   US$/bbl
        ---------------------------------------------------------------------
        Jul 07 - Dec 07      Put Spread   1,000    75.00     60.00         -
        Jul 07 - Dec 07    3-Way Collar   2,500    65.00     52.50     80.00
        Jul 07 - Dec 07      Put Spread   2,500    65.00     52.50         -
        Jul 07 - Dec 07      Put Spread   1,000    65.00     55.00         -
        Jul 07 - Dec 07    3-Way Collar   1,000    65.00     52.50     85.00
        Jul 07 - Dec 07    3-Way Collar   5,000    55.00     40.00     90.00
        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
        Jan 08 - Jun 08          Collar   1,000    65.00         -     85.00
        Jan 08 - Dec 08    3-Way Collar   1,000    67.50     52.50     85.00
        Jan 08 - Dec 08          Collar   1,000    67.50         -     85.00
        Jan 08 - Dec 08    3-Way Collar   2,000    61.50     50.00     85.00
        Jan 08 - Dec 08    3-Way Collar   1,000    61.30     50.00     85.00
        Jan 08 - Dec 08    3-Way Collar   2,000    61.00     50.00     85.00
        Jan 08 - Dec 09    3-Way Collar   5,000    55.00     40.00     90.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Financial AECO Natural Gas Contracts

                                                  Bought      Sold      Sold
                                         Volume      put       put      call
        Term                   Contract    GJ/d  CDN$/GJ   CDN$/GJ   CDN$/GJ
        ---------------------------------------------------------------------
        Jul 07 - Aug 07          Collar  10,000     7.75         -     10.00
        Jul 07 - Aug 07    3-Way Collar  10,000     7.50      5.50      9.50
        Jul 07 - Aug 07    3-Way Collar  10,000     7.25      5.25      9.00
        Jul 07 - Aug 07    3-Way Collar  30,000     7.00      5.00      8.65
        Sep 07 - Oct 07      Bought Put  10,000     7.75         -         -
        Sep 07 - Oct 07      Put Spread  10,000     7.50      5.50         -
        Sep 07 - Oct 07      Put Spread  10,000     7.25      5.25         -
        Sep 07 - Oct 07      Put Spread  30,000     7.00      5.00         -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Financial NYMEX Natural Gas Contracts

                                                  Bought      Sold      Sold
                                                     put       put      call
                                         Volume     US$/      US$/      US$/
        Term                   Contract mmbtu/d    mmbtu     mmbtu     mmbtu
        ---------------------------------------------------------------------
        Jul 07 - Oct 07      Put Spread   5,000     8.25      6.75         -
        Nov 07 - Mar 08          Collar  20,000     8.50         -     12.50
        Nov 07 - Mar 08          Collar  10,000     9.25         -     12.50
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

                                                   Basis
                                                    Swap
                                         Volume     US$/
        Term                   Contract mmbtu/d    mmbtu
        ---------------------------------------------------------------------
        Jul 07 - Oct 08      Basis Swap  50,000  (1.1930)
        Nov 08 - Oct 10      Basis Swap  50,000  (1.0430)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        Financial Foreign Exchange Contracts

                                                              Bought    Sold
                                   Notional    Swap     Swap     Put     Put
                                     Volume    CDN$/     US$/   CDN$/   CDN$/
        Term               Contract  MM US$     US$     CDN$     US$     US$
        ---------------------------------------------------------------------
        USD Sales Contracts
        Jul 07 - Dec 07        Swap     8.4  1.1371  (0.8794)      -       -

        USD Option Contracts
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1220  1.0970
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1180  1.0980
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1320  1.1020
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1380  1.1030
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1332  1.1032
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1400  1.1050
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1380  1.1080
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1300  1.1100
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1400  1.1100
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1420  1.1120
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1520  1.1120
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1440  1.1140
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1460  1.1160
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1480  1.1180
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1545  1.1195
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1765  1.1465
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1280  1.0980
        Jul 07 - Dec 07  Put Spread     6.0       -        -  1.1250  1.1000
        Jul 07 - Dec 07  Bought Put     6.0       -        -  1.1600       -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Financial Electricity Contracts(1)
                                               Swap
                                     Volume    CDN$/
        Term                Contract    MWh     MWh
        ---------------------------------------------------------------------
        Jul 07 - Dec 07        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
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Contracted volume is based on a 24/7 term.

        Financial Interest Rate Contracts(2)
                                              Fixed
                                             Annual
                                   Principal   Rate        Spread on
        Term               Contract  MM US$      (%)     3 Mo. LIBOR
        ---------------------------------------------------------------------
        Jul 07 - Apr 14        Swap    30.5    4.62           38 bps
        Jul 07 - Apr 14        Swap    32.0    4.62        (25.5 bps)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (2) 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 and $0.7 million for the three months
        and six months ended June 30, 2007 respectively ($0.4 million and
        $0.5 respectively in 2006) on the electricity contracts has been
        included in operating costs. The unrealized fair value gain on the
        electricity contracts of $10.2 million has been recorded on the
        consolidated balance sheet at June 30, 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. Prior to 2007,
        these contracts were designated as effective accounting hedges on the
        contract date. At January 1, 2007 the Trust elected to cease applying
        hedge accounting to these contracts. As a result, the unrealized fair
        value loss on the interest rate swap contracts of $2.4 million has
        been reflected in the income statement for the six months ended
        June 30, 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:

                                                       June 30,      June 30,
                                                          2007          2006
        ---------------------------------------------------------------------
        Fair value, beginning of period(1)         $      (8.7)  $      (4.0)
        Fair value, end of period(1)                     (18.8)        (13.1)
        ---------------------------------------------------------------------
        Change in fair value of contracts
         in the period                                   (10.1)         (9.1)
        Realized gains in the period                       7.3           9.9
        ---------------------------------------------------------------------
        (Loss) gain on risk management
         contracts(1)                              $      (2.8)  $       0.8
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) For 2007 the fixed price electricity contracts that were
            accounted for as effective accounting hedges were excluded. For
            2006 the fixed price electricity contract and interest rate swap
            contracts that were accounted for as effective accounting hedges
            were excluded.

        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:

                                                       June 30,      June 30,
                                                          2007          2006
        ---------------------------------------------------------------------
        Fair value, beginning of period(2)         $       7.0   $         -
        Fair value, end of period                         10.2             -
        ---------------------------------------------------------------------
        Change in fair value of contracts
         in the period                                     3.2             -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (2) Fair value of fixed price electricity contracts recognized
            prospectively on January 1, 2007.

        At June 30, 2007, the fair value of the contracts that were not
        designated as accounting hedges was a loss of $18.8 million. The
        Trust recorded a loss on risk management contracts of $2.8 million in
        the statement of income for the first six months of 2007
        ($0.8 million gain in 2006). This amount includes the realized and
        unrealized gains and losses on risk management contracts that do not
        qualify as effective accounting hedges.

    10. EXCHANGEABLE SHARES

                                                       June 30,  December 31,
        ARL EXCHANGEABLE SHARES (thousands)               2007          2006
        ---------------------------------------------------------------------
        Balance, beginning of period                     1,433         1,595
        Exchanged for trust units(1)                       (72)         (162)
        ---------------------------------------------------------------------
        Balance, end of period                           1,361         1,433
        Exchange ratio, end of period                  2.12420       2.01251
        ---------------------------------------------------------------------
        Trust units issuable upon conversion,
         end of period                                   2,892         2,884
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) During the first six months of 2007, 71,741 ARC Resources
            exchangeable shares ("ARL exchangeable shares") were converted to
            trust units at an average exchange ratio of 2.07802.

        Following is a summary of the non-controlling interest for June 30,
        2007 and December 31, 2006:
                                                       June 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Non-controlling interest,
         beginning of period                       $      40.0   $      37.5
        Reduction of book value for conversion
         to Trust units                                   (2.1)         (4.1)
        Current period net income attributable
         to non-controlling interest                       3.7           6.6
        ---------------------------------------------------------------------
        Non-controlling interest, end of period    $      41.6   $      40.0
        ---------------------------------------------------------------------
        Accumulated earnings attributable to
         non-controlling interest                  $      31.0   $      27.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. UNITHOLDERS' CAPITAL

                                        June 30, 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 10)     149       2.1       310       4.1
        Issued on exercise of
         employee rights (Note 14)         122       2.0       978      18.4
        Distribution reinvestment
         program                         2,749      56.1     3,896      96.1
        Trust unit issue costs               -         -         -      (0.2)
        ---------------------------------------------------------------------
        Balance, end of period         207,309   2,409.4   204,289   2,349.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    12. DEFICIT

        The deficit balance is composed of the following items:

                                                       June 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Accumulated earnings                       $   1,964.0   $   1,695.8
        Accumulated distributions                     (2,406.2)     (2,159.0)
        ---------------------------------------------------------------------
        Deficit                                    $    (442.2)  $    (463.2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    13. 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 fund
        contributions including interest earned on the funds and a portion of
        capital expenditures, and debt repayments. The portion of cash flow
        withheld to fund capital expenditures and to make debt repayments is
        at the discretion of the Board of Directors.

                                       Three Months Ended   Six Months Ended
                                             June 30             June 30
                                          2007      2006      2007      2006
        ---------------------------------------------------------------------
        Cash flow from operating
         activities                   $  179.4  $  182.2  $  351.7  $  371.2
        Change in non-cash
         working capital                 (19.0)     10.6     (12.2)     11.5
        Expenditures on site
         reclamation and restoration       7.2       1.9      11.9       3.2
        ---------------------------------------------------------------------
        Cash flow from operating
         activities after the above
         adjustments                     167.6     194.7     351.4     385.9
        Deduct:
          Cash withheld to fund
           current period
          capital expenditures           (41.7)    (68.1)    (99.1)   (137.7)
          Reclamation fund
           contributions and interest
           earned on fund balances        (1.8)     (4.7)     (5.1)     (6.4)
        Discretionary debt repayments        -      (1.3)        -      (1.3)
        ---------------------------------------------------------------------
        Distributions(1)                 124.1     120.6     247.2     240.5
        Accumulated distributions,
         beginning of period           2,282.1   1,794.7   2,159.0   1,674.8
        ---------------------------------------------------------------------
        Accumulated distributions,
         end of period                $2,406.2  $1,915.3  $2,406.2  $1,915.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Distributions per unit(2)     $  0 .60  $   0.60  $   1.20  $   1.20
        Accumulated distributions
         per unit, beginning
         of period(3)                 $  19.23  $  16.83  $  18.63  $  16.23
        ---------------------------------------------------------------------
        Accumulated distributions
         per unit, end of period(3)   $  19.83  $  17.43  $  19.83  $  17.43
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Distributions include non-cash amounts of $28 million and
            $54 million for the three and six months ended June 30, 2007,
            respectively ($21 million and $42 million for the same periods in
            2006, respectively) relating to the distribution reinvestment
            program.
        (2) Distributions per trust unit reflect the sum of the per trust
            unit amounts declared monthly to unitholders.
        (3) Accumulated distributions per unit reflect the sum of the per
            trust unit amounts declared monthly to unitholders since the
            inception of the Trust in July 1996.

    14. TRUST UNIT INCENTIVE RIGHTS PLAN

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

                                                                    Weighted
                                                        Number       Average
                                                     of Rights      Exercise
                                                    (thousands)     Price ($)
        ---------------------------------------------------------------------
        Balance, beginning of period                       369          9.47
        Exercised                                         (122)        10.86
        ---------------------------------------------------------------------
        Balance before reduction of exercise price         247          9.40
        Reduction of exercise price(1)                       -         (0.45)
        ---------------------------------------------------------------------
        Balance, end of period                             247          8.95
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (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
        six months of 2007 ($2.5 million in the first six 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 second
        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 2,410,269 rights have been exercised
        to June 30, 2007.

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

                                                       June 30,  December 31,
        CONTRIBUTED SURPLUS                               2007          2006
        ---------------------------------------------------------------------
        Balance, beginning of period               $       2.4   $       6.4
        Compensation expense                                 -           2.5
        Net benefit on rights exercised(1)                (0.6)         (6.5)
        ---------------------------------------------------------------------
        Balance, end of period                     $       1.8   $       2.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Upon exercise, the net benefit is reflected as a reduction of
            contributed surplus and an increase to unitholders' capital.

    15. WHOLE UNIT INCENTIVE PLAN

        The Trust recorded compensation expense of $4.3 million and
        $0.6 million to general and administrative and operating expenses,
        respectively, and capitalized $0.8 million to property, plant and
        equipment in the six months ended June 30, 2007 for the estimated
        cost of the plan ($7.8 million, $1.4 million and $1.6 million for the
        six months ended June 30, 2006). The compensation expense was based
        on the June 30, 2007 unit price of $21.74 ($28.00 at June 30, 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 six months ended
        June 30, 2007:

        ---------------------------------------------------------------------
                                                     Number of     Number of
                                                          RTUs          PTUs
                                                    (thousands)   (thousands)
        ---------------------------------------------------------------------
        Balance, beginning of period                       648           683
        Vested                                            (191)         (111)
        Granted                                            204           164
        Forfeited                                          (25)          (25)
        ---------------------------------------------------------------------
        Balance, end of period                             636           711
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

                                                       June 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Balance, beginning of period               $      26.1   $      15.0
        Change in liabilities in the period
          General and administrative expense              (4.1)          8.2
          Operating expense                               (0.5)          1.1
          Property, plant and equipment                   (0.3)          1.8
        ---------------------------------------------------------------------
        Balance, end of period                     $      21.2   $      26.1
        ---------------------------------------------------------------------
        Current portion of liability                      12.1          11.5
        ---------------------------------------------------------------------
        Accrued long-term incentive compensation   $       9.1   $      14.6
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    16. BASIC AND DILUTED PER UNIT CALCULATIONS

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

                                       Three Months Ended   Six Months Ended
                                             June 30             June 30
                                          2007      2006      2007      2006
        ---------------------------------------------------------------------
        Weighted average trust
         units(1)                      206,562   200,814   205,780   200,202
        ---------------------------------------------------------------------
        Trust units issuable on
         conversion of exchangeable
         shares(2)                       2,892     2,895     2,892     2,895
        Dilutive impact of rights(3)       179       740       212       817
        ---------------------------------------------------------------------
        Diluted trust units            209,633   204,449   208,884   203,914
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (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 all have been
            included in the diluted trust 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 outstanding. Diluted net income per unit has been calculated
        based on net income before non-controlling interest divided by
        diluted trust units.

    17. COMMITMENTS AND CONTINGENCIES

        Following is a summary of the Trust's contractual obligations and
        commitments as at June 30, 2007:
        ---------------------------------------------------------------------
                                             Payments Due By Period
        ---------------------------------------------------------------------
                                             2008-    2010-   There-
        ($ millions)                2007     2009     2011    after    Total
        ---------------------------------------------------------------------
        Debt repayments(1)           7.3     23.8    454.2    159.5    644.8
        Interest payments(2)         6.0     22.9     19.3     22.1     70.3
        Reclamation fund
         contributions(3)            6.0     11.1      9.5     76.2    102.8
        Purchase commitments         8.6      8.2      3.1      6.3     26.2
        Operating leases             2.6      9.0      4.5        -     16.1
        Derivative contract
         premiums(4)                19.8      8.1        -        -     27.9
        Retention bonuses            1.0        -        -        -      1.0
        ---------------------------------------------------------------------
        Total contractual
         obligations                51.3     83.1    490.6    264.1    889.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Long-term and short-term debt, excluding interest.
        (2) Fixed interest payments on senior secured notes.
        (3) Contribution commitments to a restricted reclamation fund
            associated with the Redwater property.
        (4) Fixed premiums to be paid in future periods on certain commodity
            derivative contracts.

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

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

    ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with 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.

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

    ADVISORY - In the interests of providing ARC unitholders and potential
investors with information regarding ARC, including management's assessment of
ARC's future plans and operations, certain information contained in this
document are forward-looking statements within the meaning of the "safe
harbour" provisions of the United States Private Securities Litigation Reform
Act of 1995 and the Ontario Securities Commission. Forward-looking statements
in this document include, but are not limited to, ARC's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; the production and growth potential of its various assets,
estimated total production and production growth for 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 RE

SOURCES LTD. John P. Dielwart, President and Chief Executive Officer

For further information:

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


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