ARC Energy Trust announces third quarter 2007 results



    CALGARY, Nov. 7 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") announces the results for the third quarter ending September 30,
2007.

    
                                    Three Months Ended     Nine Months Ended
                                         September 30          September 30
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    FINANCIAL
    ($CDN millions, except per
     unit and per boe amounts)
    Revenue before royalties          300.2      312.3      913.6      937.9
      Per unit(1)                      1.42       1.52       4.36       4.60
      Per boe                         53.40      54.59      53.72      54.66
    Cash flow from operating
      activities(2)                   179.6      203.4      531.2      574.6
      Per unit(1)                      0.85       0.95       2.54       2.82
      Per boe                         31.95      35.56      31.23      33.49
    Net income                        120.8      116.8      389.0      403.4
      Per unit(3)                      0.58       0.58       1.88       2.01
    Distributions                     125.0      121.4      372.2      361.9
      Per unit(1)                      0.60       0.60       1.80       1.80
      Per cent of cash flow from
        operating activities(2)         70%        60%        70%        63%
    Net debt outstanding(4)           699.8      579.7      699.8      579.7
    Total capital expenditures        131.9      104.9      257.9      242.6

    OPERATING
    Production
      Crude oil (bbl/d)              28,437     29,108     28,682     28,852
      Natural gas (mmcf/d)            173.3      173.4      177.6      178.9
      Natural gas liquids (bbl/d)     3,795      4,166      4,013      4,178
      Total (boe/d)                  61,108     62,178     62,296     62,851
    Average prices
      Crude oil ($/bbl)               73.40      71.84      66.45      67.68
      Natural gas ($/mcf)              5.52       6.10       6.90       6.97
      Natural gas liquids ($/bbl)     55.64      56.60      52.07      54.67
      Oil equivalent ($/boe)(5)       53.41      54.59      53.73      54.66
    Operating netback ($/boe)
      Commodity and other revenue
       (before hedging)               53.41      54.59      53.73      54.66
      Transportation costs            (0.65)     (0.60)     (0.73)     (0.62)
      Royalties                       (8.76)     (9.34)     (9.28)     (9.95)
      Operating costs                 (9.93)     (8.82)     (9.51)     (8.27)
      Netback (before hedging)        34.07      35.83      34.21      35.82
    -------------------------------------------------------------------------

    TRUST UNITS
    (millions)
    Units outstanding, end of period  208.8      202.8      208.8      202.9
    Units issuable for
     exchangeable shares                2.9        2.9        2.9        2.9
    Total units outstanding and
     issuable for exchangeable
     shares, end of period            211.7      205.7      211.7      205.8
    Weighted average units(6)         210.9      205.1      209.4      203.8
    -------------------------------------------------------------------------

    TRUST UNIT TRADING STATISTICS
    ($CDN, except volumes) based on
     intra-day trading
    High                              22.60      30.74      23.86      30.74
    Low                               19.00      25.25      19.00      24.35
    Close                             21.17      27.21      21.17      27.21
    Average daily volume (thousands)    503        615        588        569
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares. Per unit distributions are based on
        the number of trust units outstanding at each distribution record
        date.
    (2) Cash flow from operating activities is a GAAP measure. Historically,
        management has disclosed Cash Flow as a non-GAAP measure calculated
        using cash flow from operating activities less the change in non-cash
        working capital and the expenditures on site restoration and
        reclamation as they appear on the Consolidated Statements of Cash
        Flows. Cash Flow for Q3 2007 would be $183.5 million and year-to-date
        Cash Flow would be $534.8 million. Distributions as a percentage of
        Cash Flow would be 68 per cent for Q3 2007 and 62 per cent for year-
        to-date 2007. Please refer to the non-GAAP measures section in the
        MD&A for further details.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Net debt excludes unrealized amounts pertaining to risk management
        contracts
    (5) Includes other revenue.
    (6) Includes trust units issuable for outstanding exchangeable shares at
        period end.

    ACCOMPLISHMENTS/FINANCIAL UPDATE
    --------------------------------
    -   Production averaged 61,108 boe per day in the third quarter of 2007,
        down two per cent from 62,178 boe per day achieved in the third
        quarter of 2006. The Trust's 2007 production has been hampered by
        restricted access to third party processing facilities for new
        production and downtime on existing properties where turnarounds took
        longer than expected. A third party gas plant that the Trust had
        expected to be operational by early October is now scheduled to start
        up in mid-November. Consequently, the Trust has lowered its fourth
        quarter production expectations to approximately 64,000 boe per day.
        The Trust is still on target for full year guidance of approximately
        63,000 boe per day.

    -   The Trust drilled 151 gross wells (113 net wells) on operated
        properties during the third quarter with a 100 per cent success rate.
        Of the gross wells drilled, 30 were oil wells and 121 were natural
        gas wells.

    -   Capital expenditures for the quarter, including $33 million for land
        purchases, were $131.9 million, bringing year-to-date capital
        expenditures to $257.9 million. Ninety-one per cent of year-to-date
        capital expenditures have been funded from cash flow from operating
        activities and the proceeds from the Distribution Re-investment Plan
        ("DRIP"). Despite spending $32.7 million on unbudgeted land
        acquisitions in the quarter, the Trust still expects to spend
        approximately $350 million on capital expenditures during 2007.

    -   The Trust completed minor property acquisitions of $27.3 million
        during the quarter. These acquisitions added approximately 380 boe
        per day of production and 1.4 million boe of proved plus probable
        reserves. The majority of the acquired volumes is in our southeast
        Saskatchewan core area and closed on September 13, 2007.

    -   Prior to hedging activities, ARC's total realized commodity price was
        $53.28 per boe in the third quarter of 2007, compared to $54.45 per
        boe received prior to hedging in the third quarter of 2006 as a
        result of softer gas prices in 2007. The seven per cent increase in
        the U.S. WTI oil prices was completely offset by a seven per cent
        appreciation in the Canadian dollar versus the U.S. dollar resulting
        in essentially no change to the Canadian dollar of WTI $78.80 in both
        the third quarter of 2007 and 2006.

    -   Cash flow from operating activities for the quarter was $179.6
        million of which $125 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 fourth quarter
        distributions will remain at $0.20 per unit per month, a level that
        has been maintained since October 2005.

    -   On October 25, 2007, the Alberta Government announced the New Royalty
        Framework increasing provincial royalty rates. The Trust has made a
        preliminary assessment of the impact of this legislation effective
        January 1, 2009 and we estimate that the total royalties payable on
        the Trust's production will increase by approximately 10 per cent at
        current commodity prices calculated using expected 2009 production
        rates. This estimate will vary based on prices, production decline of
        existing wells and performance and location of new wells drilled. The
        10 per cent increase in royalties payable which equates to
        approximately a two per cent increase in the Trust's royalty rate
        takes into account that 30 per cent of the Trust's production is
        outside the Province of Alberta. The royalty change in 2009 on a
        property by property basis is highly variable with decreased
        royalties on some properties, primarily shallow gas wells, and a
        doubling of royalties on Alberta high rate oil production properties.
        The New Alberta Royalty Framework will impact future drilling in
        order for the Trust to maintain acceptable rates of return on its
        capital deployed.

    -   On October 30, 2007, the Federal Government presented the fall
        economic statement that proposed significant reductions in corporate
        income tax rates from 22.1 per cent to 15 per cent. If enancted, the
        reductions will be phased in between 2007 and 2012. In addition, the
        Government announced that it plans to collaborate with the
        provinces and territories to reach a 25 per cent combined federal-
        provincial-territorial statutory corporate income tax rate.
    

    ONE YEAR UPDATE ON THE FEDERAL GOVERNMENT'S TRUST TAX LEGISLATION
    -----------------------------------------------------------------
    On October 31, 2006, the Federal Government announced proposed
legislation regarding taxation of Income Trusts. Currently, distributions paid
to unitholders, other than return of capital, are claimed as a deduction by
the Trust in arriving at taxable income whereby tax is eliminated at the Trust
level and is paid by the unitholders.
    The Trust tax legislation, which received Royal assent on June 22, 2007
will result in a two-tiered tax structure whereby distributions would first be
subject to a 31.5 per cent tax at the Trust level commencing in 2011, and then
unitholders would be subject to tax on the distribution as if it were a
taxable dividend paid by a taxable Canadian corporation.
    On October 30, 2007, the Finance Minister announced significant changes
to the tax system including reductin of the corporate income tax rate to 15
per cent by 2012. At the very least, we would expect the proposed tax on trust
distributions to be reduced accordingly since it was based upon combined
federal and provincial tax rates. More importantly  with this corporate tax
reduction any claim of tax leakage in the trust sector, which was tenuous at
best, based upon our assessment of the data compiled, can no longer be claimed
to exist. We continue to lobby the government on behalf of our unitholders to
exempt the energy trust sector from the proposed tax or eliminate it
altogether.
    Our Board of Directors and management continue to review the impact of
this tax on our business strategy and the merits of converting to a
corporation on or before January 1, 2011. We expect future technical
interpretations and details will further clarify the legislation. At the
present time, ARC believes that if structural or other similar changes are not
made, the after-tax distribution amount in 2011 to taxable Canadian investors
will remain approximately the same, however, will decline for both
tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and
foreign investors.
    Another recent development occurred on October 30, 2007 when an American
couple, Mr. and Mrs. Marvin Gottlieb, filed a Notice of Intent to submit a
claim to arbitration under the North American Free Trade Agreement (NAFTA).
U.S. investors wishing to learn more about the Gottlieb's NAFTA challenge to
the Government of Canada can visit their website at www.naftatrustclaims.com.

    MANAGEMENT'S DISCUSSION AND ANALYSIS
    ------------------------------------
    This management's discussion and analysis ("MD&A") is dated November 6,
2007 and should be read in conjunction with the September 30, 2007 unaudited
interim consolidated financial statements of ARC Energy Trust ("ARC", "the
Trust", "we", "our"), the June 30, 2007 and the March 31, 2007 unaudited
interim consolidated financial statements and MD&As, as well as the audited
consolidated financial statements and MD&A for the year ended December 31,
2006.

    Non-GAAP Measures

    Historically, management used the non-GAAP measure Cash Flow or cash flow
from operations to analyze operating performance, leverage and liquidity. We
have now switched to utilize the GAAP measure cash flow from operating
activities instead of Cash Flow. There are two differences between the two
measures with cash flow from operating activities including positive or
negative changes in non-cash working capital and the deduction of expenditures
on site restoration and reclamation as they appear on the Consolidated
Statements of Cash Flows. Although management feels that Cash Flow is a valued
measure of funds generated by the Trust during the reported quarter, we have
changed our disclosure to only discuss the GAAP measure in the MD&A in order
to avoid any potential confusion by readers of our financial information and
in our opinion, to more fully comply with the intent of certain regulatory
requirements.
    Our historical measure of Cash Flow reflected revenues and costs for the
three months reported in the quarter. This amount, however, was comprised of
accruals for at least one month of revenue and approximately two months of
costs. The oil and gas industry is designed such that revenues are typically
collected on the 25th day of the month following the actual production month.
Royalties are typically paid two months following the actual production month
and operating costs are paid as the invoices are received. This can take
several months; however, most invoices for operated properties are paid within
approximately two months of the production month.
    At the time of writing this MD&A, substantially all revenues have been
collected for the production period of September 2007. Management performs
analysis on the amounts collected to ensure that the amounts accrued for
September are accurate. Analysis is also performed regularly on royalties and
operating costs to ensure that amounts have been accurately accrued.
    Management uses certain key performance indicators ("KPIs") and industry
benchmarks such as distributions as a per cent of cash flow from operating
activities, operating netbacks ("netbacks"), total capitalization, finding,
development and acquisition costs, recycle ratio, reserve life index, reserves
per unit and production per unit to analyze financial and operating
performance. Management feels that these KPIs and benchmarks are key measures
of profitability and overall sustainability for the Trust. These KPIs and
benchmarks as presented do not have any standardized meaning prescribed by
Canadian GAAP and therefore may not be comparable with the calculation of
similar measures for other entities.

    Update on Legislation Changes Impacting the Trust

    Broad-based Federal Tax Reductions

    On October 30, 2007 the Federal Government presented the fall economic
statement that proposed significant reductions in corporate income tax rates
from 22.1 per cent to 15 per cent. The reductions will be phased in between
2007 and 2012. In addition, the Government announced that it plans to
collaborate with the provinces and territories to reach a 25 per cent combined
federal-provincial-territorial statutory corporate income tax rate.

    Alberta Government Royalty Regime

    In September 2007, the Alberta Government announced the results of the
royalty review that was performed by an independent panel. The report proposed
that the royalty rates in Alberta should be increased by $2 billion dollars.
The proposed increases pertained to conventional oil and gas production as
well as oil sands production.
    On October 25, 2007, the Alberta Government announced The New Royalty
Framework, ("framework"), which will take effect on January 1, 2009 and is
projected by the government to increase royalties by approximately $1.4
billion in 2010 or an increase of 20 per cent over revenue forecasts by the
Alberta Government for that year. These increases comprise a 57 per cent
increase in conventional oil royalties and a 10 per cent increase in gas
royalties. The framework proposes new, simplified royalty formulas for
conventional oil and natural gas that will operate on sliding scales which are
determined by commodity prices and well productivity. The formulas eliminate
the need for conventional oil and natural gas tiers and several royalty
exemption programs.

    
    The main aspects of the framework as it impacts the Trust include the
following:

    -   Conventional Oil Royalties - The New Royalty Framework accepts almost
        all of the royalty review panel's recommendations. They will
        eliminate almost all royalty relief programs and the existing "tiers"
        and move to a price and production sensitive royalty system. Rate
        caps on price will be raised in the conventional oil royalty formulas
        to $120 per barrel to provide for a royalty system that is sensitive
        over a broader range of prices. Overall, this will result in maximum
        royalty rates increasing from the current maximums of 30 per cent and
        35 per cent for old and new tier rates respectively to rates that
        will range up to 50 per cent. Enhanced Oil Recovery and Innovative
        Energy Technology Program Royalty relief programs have been retained.

    -   Conventional Gas Royalties - The New Royalty Framework accepts most
        of the royalty review panel's recommendations for increased gas
        royalties. They will eliminate several special royalty programs and
        the current "tiers" and move to a price and production sensitive
        royalty system, however, they will keep the deep gas drilling program
        and the "Otherwise Flared Solution Gas Royalty Waiver Program". The
        province expects a 10 per cent increase in gas royalties in 2010 -
        down from the 14 per cent increase the panel recommended.
    

    Based on our current estimates, the Trust expects that the total
corporate royalties payable will increase by approximately 10 per cent in
2009. This estimate will vary based on prices, production decline of existing
wells and performance and location of new wells drilled. The 10 per cent
increase in royalties payable which equates to approximately a two per cent
increase in the Trust's royalty rate takes into account that 30 per cent of
the Trust's production is outside the Province of Alberta. The royalty change
in 2009 on a property by property basis is highly variable with decreased
royalties on some properties, primarily shallow gas wells, and a doubling of
royalties on Alberta high rate oil production properties. The New Alberta
Royalty Framework will impact future drilling in order for the Trust to
maintain acceptable rates of return on its capital deployed.
    The Trust reviews all of its capital expenditures on a project by project
basis; with higher royalties in the Province of Alberta, projects previously
deemed economic may no longer meet the Trust's investment objectives. Already,
the Trust has cancelled a $4 million investment in northern Alberta,
re-allocating the money to British Columbia where it believes it can get a
better return on its investment. The Trust will be reviewing the proposals in
detail in order to assess the full impact to the Trust's future cash flows and
investment opportunities and determine ways in which it can mitigate the
negative impact.

    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 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. This amount was
recorded in the second quarter results and is reflected in the 2007
year-to-date results.
    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, will decline for both tax-deferred
Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign investors.

    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 are required to pay
$15 per tonne for every tonne above the 12 per cent target, effective as of
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 its 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      Nine Months Ended
    (CDN$ millions,                 September 30            September 30
     except per unit                            %                       %
     and volume data)           2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    Cash flow from operating
     activities(1)             179.6   203.4     (12)  531.2   574.6      (8)
    Cash flow from operating
     activities per unit(1)     0.85    0.99     (14)   2.54    2.82     (10)
    Net income                 120.8   116.8       3   389.0   403.4      (4)
    Distributions per unit(2)   0.60    0.60       -    1.80    1.80       -
    Distributions as a per
     cent of cash flow from
     operating activities         70      60      17      70      63      11
    Daily production
     (boe/d)(3)               61,108  62,178      (2) 62,296  62,851      (1)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) This is a GAAP measure and a change from the non-GAAP measure
        reported in prior quarters; refer to Non-GAAP Measures.
    (2) Based on the number of trust units outstanding at each cash
        distribution record 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 the term "boe" in isolation may be misleading.
    


    Net Income

    Net income in the third quarter of 2007 was $120.8 million ($0.58 per
unit), an increase of $4 million from $116.8 million ($0.58 per unit) in the
third quarter of 2006. A $25.7 million gain on foreign exchange as well as a
$4.3 million decrease in royalties more than offset decreased revenues and
increased costs for the Trust.

    Cash Flow from Operating Activities

    Cash flow from operating activities was $179.6 million in the third
quarter of 2007, a 12 per cent decrease from $203.4 million recorded in the
third quarter of 2006. The decrease in third quarter cash flow from operating
activities was attributed to a $5.4 million volume variance, a $6.7 million
price variance, a $5.2 million increase in operating costs that were partially
offset by a $4.3 million decrease in royalties. In addition, the Trust had a
$7 million increase in non-cash working capital and other items that further
decreased the cash flow from operating activities in the quarter.

    Following is a summary of variances in cash flow from operating
activities from 2006 to 2007:

    
    -------------------------------------------------------------------------
                                Three Months Ended      Nine Months Ended
                                   September 30            September 30
                                $      $ Per % Vari-    $      $ Per % Vari-
                             Millions   Unit   ance  Millions   Unit   ance
    -------------------------------------------------------------------------
    2006 Cash flow from
     operating activities      203.4    0.99           574.6    2.82
    -------------------------------------------------------------------------
    Volume variance             (5.4)  (0.03)     (3)   (8.2)  (0.04)     (1)
    Price variance              (6.7)  (0.03)     (3)  (15.9)  (0.08)     (3)
    Cash gains on risk
     management contracts(1)    (1.6)  (0.01)     (1)   (4.1)  (0.02)     (1)
    Royalties                    4.3    0.02       2    12.9    0.06       2
    Expenses:
      Operating(2)              (5.2)  (0.03)     (3)  (20.9)  (0.10)     (4)
      Transportation            (0.1)      -       -    (1.7)  (0.01)      -
      Cash G&A                  (1.5)  (0.01)     (1)   (8.3)  (0.04)     (1)
      Interest and cash taxes   (0.7)      -       -    (4.3)  (0.02)     (1)
      Realized foreign
       exchange gain/(loss)      0.1       -       -    (0.8)      -       -
    Weighted average trust
     units                         -   (0.02)      -       -   (0.07)      -
    Non-cash and other
     items(3)                   (7.0)  (0.03)     (3)    7.9    0.04       1
    -------------------------------------------------------------------------
    2007 Cash flow from
     operating activities      179.6    0.85     (12)  531.2    2.54      (8)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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.
    (3) Includes the changes in non-cash working capital and expenditures on
        site restoration and reclamation.
    


    Production

    Production volume averaged 61,108 boe per day in the third quarter of
2007, down slightly from 62,178 boe per day during the third quarter of 2006.
The Trust experienced significant production losses during the third quarter
due in part to planned turnarounds but also due to unplanned compressor
failures, power outages and unplanned turnarounds on some of our non-operated
properties. As of September 30, 2007, most of these items have been resolved
and production has resumed to normal levels. At the end of the third quarter
the Trust has approximately 2,500 boe per day of volumes that are scheduled to
come on production during the fourth quarter. In addition, fourth quarter
production will benefit by an estimated 350 boe per day from a third quarter
property acquisition of $24.8 million that closed on September 13, 2007. We
have maintained our full year 2007 production guidance at approximately
63,000 boe per day.
    Throughout the first nine months of 2007, the Trust has experienced
production restrictions in the northern Alberta and British Columbia areas 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 areas. As of September 30, the Trust had three
horizontal wells in Dawson that were waiting to be brought on production. It
is anticipated that these wells will be brought on production in the fourth
quarter when there is additional processing capacity for the resulting
production. The expected date for the gas plant to commence operations is
approximately mid November 2007. The Trust expects to see at least 1,200 boe
per day in incremental production once these wells come on production. This
amount is included in the 2,500 boe per day of incremental fourth quarter
production quoted above.
    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 third quarter of 2007, the Trust
drilled 151 gross wells (113 net wells) on operated properties with a 100 per
cent success rate; 30 gross oil wells and 121 gross natural gas wells.

    
    -------------------------------------------------------------------------
                                 Three Months Ended      Nine Months Ended
                                    September 30            September 30
                                                %                       %
    Production(1)               2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    Crude oil (bbl/d)         28,437  29,108      (2) 28,682  28,852      (1)
    Natural gas (mmcf/d)       173.3   173.4       -   177.6   178.9      (1)
    NGL (bbl/d)                3,795   4,166      (9)  4,013   4,178      (4)
    -------------------------------------------------------------------------
    Total production (boe/d)  61,108  62,178      (2) 62,296  62,851      (1)
    -------------------------------------------------------------------------
    % Natural gas production      47      46              48     47
    % Crude oil and liquids
     production                   53      54              52     53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 September 30, 2007
    Production                        Total        Oil        Gas        NGL
    Core Area(1)                     (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
    -------------------------------------------------------------------------
    Central AB                        7,694      1,522       29.6      1,234
    Northern AB & BC                 19,106      5,776       71.2      1,475
    Pembina & Redwater               13,497      9,411       18.7        971
    S.E. AB & S.W. Sask.              9,679      1,008       52.0         10
    S.E. Sask. & MB                  11,132     10,720        1.8        105
    -------------------------------------------------------------------------
    Total                            61,108     28,437      173.3      3,795
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                       Three Months Ended September 30, 2006
    Production                        Total        Oil        Gas        NGL
    Core Area(1)                     (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
    -------------------------------------------------------------------------
    Central AB                        8,029      1,537       30.9      1,344
    Northern AB & BC                 18,354      6,308       64.0      1,373
    Pembina & Redwater               14,063      9,443       19.6      1,357
    S.E. AB & S.W. Sask.             10,551      1,090       56.7         10
    S.E. Sask. & MB                  11,181     10,730        2.2         82
    -------------------------------------------------------------------------
    Total                            62,178     29,108      173.4      4,166
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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      Nine Months Ended
                                    September 30            September 30
                                                %                       %
    Benchmark Prices            2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    AECO gas (CDN$/mcf)(1)      5.61    6.03      (7)   6.81    7.19      (5)
    WTI oil (US$/bbl)(2)       75.33   70.55       7   66.22   68.29      (3)
    USD/CAD foreign
     exchange rate              0.96    0.90       7    0.91    0.89       2
    WTI oil (CDN$/bbl)         78.70   78.80       -   72.95   77.14      (5)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Although oil prices have achieved record highs throughout the quarter,
the strengthening of the Canadian dollar relative to the U.S. dollar was
responsible for eroding the gains in the U.S. dollar WTI price by decreasing
the price of oil in Canadian dollar terms. The price of oil in U.S. dollars
increased by seven per cent in the third quarter of 2007 as compared to the
third quarter of 2006 while the price of oil in Canadian dollars was
essentially unchanged. ARC's realized oil price in the third quarter of 2007
was $73.40 per barrel, a two per cent increase over the $71.84 per barrel
received in the third quarter of 2006 due to minor changes in quality
differentials. Subsequent to quarter end both the price of oil and the
Canadian dollar continued to strengthen in relation to the U.S. dollar.
Investors should monitor both factors in assessing future revenues of the
Trust.
    Natural gas prices weakened in the third quarter of 2007 with the Alberta
AECO Hub monthly posting averaging $5.61 per mcf as compared to $6.03 per mcf
for the comparable period of 2006. The Trust's realized price of $5.52 per mcf
in the third quarter of 2007 was 10 per cent lower than the $6.10 per mcf
price realized by the Trust in the third 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
$53.28 per boe in the third quarter of 2007, down two per cent from the
$54.45 per boe received prior to hedging in the third quarter of 2006. Given
the Trust's balanced production mix, the increases in oil prices partially
offset the decreases in natural gas prices during the period.

    
    The following is a summary of realized prices:

    -------------------------------------------------------------------------
                                 Three Months Ended      Nine Months Ended
                                    September 30            September 30
                                                %                       %
    ARC Realized Prices         2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    Oil ($/bbl)                73.40   71.84       2   66.45   67.68      (2)
    Natural gas ($/mcf)         5.52    6.10     (10)   6.90    6.97      (1)
    NGLs ($/bbl)               55.64   56.60      (2)  52.07   54.67      (5)
    -------------------------------------------------------------------------
    Total commodity revenue
     before hedging ($/boe)    53.28   54.45      (2)  53.61   54.54      (2)
    Other revenue ($/boe)       0.13    0.14      (7)   0.12    0.12       -
    -------------------------------------------------------------------------
    Total revenue before
     hedging ($/boe)           53.41   54.59      (2)  53.73   54.66      (2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Revenue

    Revenue for the third quarter of 2007 was down four per cent at
$300.2 million as compared with $312.3 million for the third quarter of 2006.
Increased oil prices were offset by lower natural gas prices and lower volumes
in the quarter.

    A breakdown of revenue is as follows:

    -------------------------------------------------------------------------
                                 Three Months Ended      Nine Months Ended
                                    September 30            September 30
                                                %                       %
    Revenue ($ millions)        2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    Oil revenue                192.0   192.4       -   520.3   533.0      (2)
    Natural gas revenue         88.1    97.4     (10)  334.3   340.3      (2)
    NGLs revenue                19.4    21.7     (11)   57.0    62.4      (9)
    -------------------------------------------------------------------------
    Total commodity revenue    299.5   311.5      (4)  911.6   935.7      (3)
    Other revenue                0.7     0.8     (13)    2.0     2.2      (9)
    -------------------------------------------------------------------------
    Total revenue
     before hedging            300.2   312.3      (4)  913.6   937.9      (3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Risk Management and Hedging Activities

    The Trust hedges crude oil prices, natural gas prices and the Canadian
versus U.S. dollar exchange rate with the objective of protecting cash flows
and distributions to unitholders.
    On a forward-looking basis ARC continues to add to its hedging position
for both crude oil and natural gas production. During the quarter ARC layered
on additional protection on crude oil to the end of 2008 and additional
natural gas positions through to the first quarter of 2008.
    In addition to these normal course transactions, ARC has entered into an
energy equivalent swap in order to shift its price exposure to be more heavily
weighted towards crude oil for the period of April 1 through October 31, 2008.
Through the use of financial contracts, ARC has rebalanced its price exposure
from a forecasted 50:50 to a 52:48 oil-gas weighting. ARC achieved this
rebalancing by selling AECO natural gas at $7.10 per GJ and buying crude oil
at CDN$73.95 per barrel. A summary of all hedged volumes and prices for oil,
natural gas and related foreign exchange are detailed in the table below. The
details of these transactions are provided in note 9 in the Notes to the
Unaudited Consolidated Financial Statements.
    On crude oil production ARC has hedged approximately 44 per cent of
forecast oil production in the fourth quarter of 2007, 35 per cent of
production through the first half of 2008, and 25 per cent of production for
the second half of 2008. For natural gas production ARC has protected
approximately 22 per cent of forecasted production during the fourth quarter
of 2007, 10 per cent for the first quarter of 2008, and 10 per cent for the
period from April 1 through October 31, 2008.
    The following is a summary of the Trust's positions for crude oil,
natural gas and related foreign exchange for the next twelve months as at
September 30, 2007.

    
    -------------------------------------------------------------------------
    Hedge Positions
    as at September 30, 2007 (1)(2)
                                         Q4 2007               Q1 2008
    -------------------------------------------------------------------------
    Crude Oil                       US$/bbl    bbl/day    US$/bbl    bbl/day
    -------------------------------------------------------------------------
    Sold Call                         86.47      8,500      85.23     11,000
    Bought Put                        70.00     14,000      64.21     11,000
    Sold Put                          58.57     14,000      51.39      9,000
    -------------------------------------------------------------------------
    Natural Gas                     CDN$/GJ     GJ/day    CDN$/GJ     GJ/day
    -------------------------------------------------------------------------
    Sold Call                         10.64     20,986      10.64     31,652
    Bought Put                         7.16     42,981       7.11     31,652
    Sold Put                           5.05     25,621       4.76     10,551
    -------------------------------------------------------------------------
    Foreign Exchange                CAD/USD   $Million    CAD/USD   $Million
    -------------------------------------------------------------------------
    Bought Put                       1.1397       55.2     1.0750        3.0
    Sold Put                         1.1096       54.0     1.0300        3.0
    Swap                             1.1400        4.8
    -------------------------------------------------------------------------

                                         Q2 2008               Q3 2008
    -------------------------------------------------------------------------
    Crude Oil                       US$/bbl    bbl/day    US$/bbl    Bbl/day
    -------------------------------------------------------------------------
    Sold Call                         85.23     11,000      85.63      8,000
    Bought Put                        64.21     11,000      63.91      8,000
    Sold Put                          51.39      9,000      51.07      7,000
    -------------------------------------------------------------------------
    Natural Gas                     CDN$/GJ     GJ/day    CDN$/GJ     GJ/day
    -------------------------------------------------------------------------
    Sold Call                          9.00     20,000       9.00     20,000
    Bought Put                         7.00     20,000       7.00     20,000
    Sold Put                           5.75     10,000       5.75     10,000
    -------------------------------------------------------------------------
    Foreign Exchange                CAD/USD   $Million    CAD/USD   $Million
    -------------------------------------------------------------------------
    Bought Put                       1.0750        3.0     1.0750        3.0
    Sold Put                         1.0300        3.0     1.0300        3.0
    -------------------------------------------------------------------------

                                         Q4 2008               2009
    -------------------------------------------------------------------------
    Crude Oil                       US$/bbl    bbl/day     US$/bbl   Bbl/day
    -------------------------------------------------------------------------
    Sold Call                         85.63      8,000       90.00     5,000
    Bought Put                        63.91      8,000       55.00     5,000
    Sold Put                          51.07      7,000       40.00     5,000
    -------------------------------------------------------------------------
    Natural Gas                     CDN$/GJ     GJ/day     CDN$/GJ    GJ/day
    -------------------------------------------------------------------------
    Sold Call                          9.00      6,739           -         -
    Bought Put                         7.00      6,739           -         -
    Sold Put                           5.75      3,370           -         -
    -------------------------------------------------------------------------
    Foreign Exchange                CAD/USD   $Million     CAD/USD  $Million
    -------------------------------------------------------------------------
    Bought Put                       1.0750       3.00           -         -
    Sold Put                         1.0300       3.00           -         -
    -------------------------------------------------------------------------

    (1) The prices and volumes noted above represents averages for several
        contracts. The average price for the portfolio of options listed
        above does not have the same payoff profile as the individual option
        contracts. The natural gas price shown translates all
        NYMEX positions to an AECO equivalent price. In addition to positions
        shown here, ARC has entered into additional basis positions.
    (2) Please refer to the Trust's website at www.arcenergytrust.com under
        "Hedging Program" within the "Investor Relations" section for details
        on the Trust's hedging positions as of September 30, 2007.
    

    The above table should be interpreted as follows using the Q4 2007 Crude
Oil Hedges as an example. To accurately analyze the Trust's hedge position,
contracts need to be modeled separately as using average prices and volumes
may be misleading.

    
    -   If the market price is below $58.57, ARC will receive $70 less the
        difference between $58.57 and the market price on 14,000 barrels per
        day. For example if the market price is $58.55, the Trust will
        receive $69.98 on 14,000 barrels per day.
    -   If the market price is between $58.57 and $70, ARC will receive $70
        on 14,000 barrels per day.
    -   If the market price is between $70 and $86.47, ARC will receive the
        market price on 14,000 barrels per day.
    -   If the market price exceeds $86.47, ARC will receive $86.47 on 8,500
        barrels per day and the market price for the remaining 5,500 hedged
        volumes.
    

    In light of the significant increase in value of the Canadian dollar
during the last 12 months, ARC implemented a program to lock in exchange rates
on future principal repayments on U.S. dollar denominated senior secured
notes. These transactions effectively lock in the unrealized foreign exchange
gains on the U.S. denominated debt. Although the unrealized foreign exchange
gains will continue to fluctuate quarter-to-quarter with changes in the
exchange rate, these financial transactions have effectively fixed the
economic gains of the change in exchange rates from the rate at which the U.S.
denominated debt was issued and the rate at which the future payments have
been committed. At the end of the quarter ARC had $223 million of U.S.
denominated senior secured debt outstanding requiring annual principal
repayments of varying amounts extending until December 15, 2017. As at the
quarter end, ARC had locked in the foreign exchange rate for a total of
US$62.6 million of its principal repayments in years 2014 through 2017 at an
average rate with the Canadian dollar slightly greater than par (1.00
USD/CAD). The details of these transactions are provided in the financial
note.
    For a complete summary of the Trust's oil, natural gas and foreign
exchange hedges, please refer to "Hedging Program" under the "Investor
Relations" section of the Trust's website at www.arcenergytrust.com.

    Gain or Loss on Risk Management Contracts

    Gain or loss on risk management contracts comprise realized and
unrealized gains or losses on risk management contracts that do not meet the
accounting definition requirements of an effective hedge, even though the
Trust considers all risk management contracts to be effective economic hedges.
Accordingly, gains and losses on such contracts are shown as a separate
category in the statement of income.
    The Trust recorded a realized cash gain on risk management contracts of
$8 million in the third quarter of 2007 compared to a gain of $9.6 million
recorded in for the same period of 2006. The Trust realized gains of
$8.9 million on natural gas prices and $2.2 million on foreign exchange
contracts which were partially offset by $2.9 million in losses realized on
the Trust's oil contracts as well as a loss of $0.2 million on interest rate
positions.
    The total unrealized gain of $2.1 million was due mostly to a weakening
of forward natural gas prices that have resulted in unrealized gains of
$4.6 million in natural gas financial positions through to October of 2008 and
a gain on the Trust's interest rate swap of $1.9 million. These gains have
been offset by unrealized losses for the Trust's oil contracts of $2.5 million
due to an increase in crude oil prices, which reduces the value of crude oil
protection and an unrealized loss on foreign exchange contracts that were
entered into during the quarter to pay off long-term US dollar debt
commitments ($1.9 million).
    The following is a summary of the total gain (loss) on risk management
contracts for the third quarter and year to date of 2007:

    
    -------------------------------------------------------------------------
                                                    Interest     Q3       Q3
    Risk Management Contracts  Crude Oil  Natural  & Foreign   2007     2006
    ($ millions)               & Liquids      Gas   Currency  Total    Total
    -------------------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(1)                (2.9)     8.9      2.0      8.0      9.6
    Unrealized gain (loss)
     on contracts(2)                (2.5)     4.6        -      2.1      0.5
    -------------------------------------------------------------------------
    Total gain (loss) on risk
     management contracts           (5.4)    13.5      2.0     10.1     10.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                                    Interest    YTD      YTD
    Risk Management Contracts  Crude Oil  Natural  & Foreign   2007     2006
    ($ millions)               & Liquids      Gas   Currency  Total    Total
    -------------------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(1)                 2.8     10.4      2.1     15.3     19.4
    Unrealized gain (loss)
     on contracts(2)               (17.7)     4.6      5.1     (8.0)    (8.5)
    -------------------------------------------------------------------------
    Total gain (loss) on risk
     management contracts          (14.9)    15.0      7.2      7.3     10.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Realized cash gains and losses represent actual cash settlements or
        receipts under the respective contracts.
    (2) The unrealized (loss) gain on contracts represents the change in fair
        value of the contracts during the period.


    Operating Netbacks

    The Trust's operating netback, after realized hedging gains, decreased by
five per cent to $35.52 per boe in the third quarter of 2007 compared to
$37.50 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                 Q3 2007 Q3 2006
    Netbacks                     Oil     Oil     Gas     NGL   Total   Total
    ($ per boe)               ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
    -------------------------------------------------------------------------
    Weighted average
     sales price               74.40   51.23    5.52   55.64   53.28   54.45
    Other revenue                  -       -       -       -    0.13    0.14
    -------------------------------------------------------------------------
    Total revenue              74.40   51.23    5.52   55.64   53.41   54.59
    Royalties                 (11.75)  (4.35)  (0.87) (15.44)  (8.76)  (9.34)
    Transportation             (0.10)  (1.21)  (0.20)      -   (0.65)  (0.60)
    Operating costs(1)        (12.32) (11.85)  (1.30)  (8.19)  (9.93)  (8.82)
    -------------------------------------------------------------------------
    Netback prior to hedging   50.23   33.82    3.15   32.01   34.07   35.83
    Realized gain (loss) on
     risk management
     contracts                 (0.28)      -    0.56       -    1.45    1.67
    -------------------------------------------------------------------------
    Netback after hedging      49.95   33.82    3.71   32.01   35.52   37.50
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                                                 YTD     YTD
                               Crude   Heavy                    2007    2006
    Netbacks                     Oil     Oil     Gas     NGL   Total   Total
    ($ per boe)               ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
    -------------------------------------------------------------------------
    Weighted average
     sales price               67.39   47.00    6.90   52.07   53.61   54.54
    Other revenue                  -       -       -       -    0.12    0.12
    -------------------------------------------------------------------------
    Total revenue              67.39   47.00    6.90   52.07   53.73   54.66
    Royalties                 (10.53)  (4.00)  (1.28) (14.12)  (9.28)  (9.95)
    Transportation             (0.31)  (1.22)  (0.20)      -   (0.73)  (0.62)
    Operating costs(1)        (11.73) (12.73)  (1.26)  (7.74)  (9.51)  (8.27)
    -------------------------------------------------------------------------
    Netback prior to hedging   44.82   29.05    4.16   30.21   34.21   35.82
    Realized gain on risk
     management contracts       0.71       -    0.22       -    0.93    1.13
    -------------------------------------------------------------------------
    Netback after hedging      45.53   29.05    4.38   30.21   35.14   36.95
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 $8.76 per boe in the third quarter of 2007
compared to $9.34 per boe in the same period of 2006. Royalties as a
percentage of pre-hedged commodity revenue net of transportation costs
decreased to 16.6 per cent compared to 17.3 per cent in the third quarter of
2006. The decrease in royalty rates is due to approximately $2.3 million of
credits for prior periods for Gas Cost Allowance recorded in the third quarter
along with credits received for the Trust's BC gas production. The Trust
expects fourth quarter royalty rates to return to normal levels of
approximately 18 percent of pre-hedged commodity revenue net of transportation
costs.
    Transportation costs in 2007 continue to exceed prior year costs as a
result of the ongoing challenges in Saskatchewan where shipping restrictions
are in place for the Enbridge pipeline. Third quarter 2007 transportation
costs decreased to $0.65 per boe from $0.72 per boe in the second quarter of
2007 as natural declines in the area decreased our trucking requirements;
however, the Trust is still required to truck any new production that exceeds
our historical capacity for the Enbridge pipeline. Investors can expect
transportation prices to increase again once the winter drilling program
begins and new production levels increase. An expansion of the Enbridge
pipeline is expected to be completed sometime in early 2008.
    Operating costs increased to $9.93 per boe compared to $8.82 per boe in
the third quarter of 2006. Total operating costs in the third quarter of 2007
increased by $5.3 million compared to the third quarter of 2006. This increase
is partially due to increased labor costs for field staff and some service
providers particularly in Northern Operations. In addition, the Trust has
increased electricity consumption as a result of well re-activations in the
Redwater and NPCU areas. The Trust incurred $1.3 million for an unanticipated
injection pump repair in the Berrymoor area and unbudgeted compressor repairs
in the Delburne, Pouce Coupe and Gilby areas. Acquisitions completed in the
fourth quarter of 2006 and the first nine months of 2007 have increased
operating costs by approximately $1 million in the third quarter of 2007.
There is a high percentage of fixed operating costs for the Trust's properties
resulting in a trend of increased operating costs on a per boe basis as the
properties' production declines over time. The Trust is revising its full year
guidance for operating costs to approximately $9.50 per boe based on annual
production of approximately 63,000 boe per day.

    General and Administrative Expenses and Incentive Compensation

    Cash G&A before incentive compensation and net of overhead recoveries on
operated properties increased to $8.4 million in the third quarter of 2007
from $6.9 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, third quarter cash G&A costs excluding the whole unit plan
increased 23 per cent to $1.49 per boe in 2007 from $1.21 per boe in 2006 as a
result of higher cash G&A costs and a decrease in production volumes.
    Year-to-date G&A costs include a payment under the Whole Unit Plan in the
second quarter 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 remaining $2.2 million
being recorded to operating costs and capital projects.
    The following is a breakdown of G&A and Incentive compensation expense:

    
    -------------------------------------------------------------------------
                                 Three Months Ended      Nine Months Ended
    G&A and Incentive               September 30            September 30
     Compensation Expense                       %                       %
    ($ millions)                2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    G&A expenses                12.0    10.6      13    38.1    32.3     (18)
    Operating recoveries        (3.6)   (3.7)     (3)  (12.0)   (8.9)     35
    -------------------------------------------------------------------------
    Cash G&A expenses before
     Whole Unit Plan             8.4     6.9      22    26.1    23.4      12
    -------------------------------------------------------------------------
    Cash expense -
     Whole Unit Plan               -       -       -     8.3     2.7     207
    -------------------------------------------------------------------------
    Cash G&A expenses
     including Whole Unit Plan   8.4     6.9      22    34.4    26.1      32
    -------------------------------------------------------------------------
    Accrued compensation -
     Rights Plan                   -       -       -       -     2.5    (100)
    Accrued compensation -
     Whole Unit Plan             3.7     3.4       9    (0.3)    8.4    (104)
    -------------------------------------------------------------------------
    Total G&A and trust unit
     compensation expense       12.1    10.3      17    34.1    37.0      (8)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                 Three Months Ended      Nine Months Ended
    G&A and Incentive               September 30            September 30
     Compensation Expense                       %                       %
    ($ per boe)                 2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    Cash G&A expenses before
     Whole Unit Plan            1.49    1.21      23    1.53    1.36      13
    Cash G&A expenses
     including Whole Unit Plan  1.50    1.21      24    2.02    1.52      33
    Total G&A and trust unit
     compensation expense       2.16    1.81      19    2.00    2.16      (7)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    A non-cash incentive compensation expense ("non-cash compensation
expense") of $3.7 million was recorded in the third quarter of 2007 that
represents the estimated costs of the Whole Unit Plan for the period.

    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 September 30, 2007, 0.2 million rights were outstanding at an average
exercise price of $8.72 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 to Restricted Trust Units ("RTUs")
and Performance Trust Units ("PTUs") outstanding during the first nine months
of 2007:

    
    -------------------------------------------------------------------------
    Whole Unit Plan  (units in thousands     Number of  Number of Total RTUs
     and $ millions except per unit)              RTUs       PTUs   and PTUs
    -------------------------------------------------------------------------
    Balance, beginning of period                   648        683      1,331
    Granted in the period                          206        167        373
    Vested in the period                          (191)      (110)      (301)
    Forfeited in the period                        (25)       (26)       (51)
    -------------------------------------------------------------------------
    Balance, end of period(1)                      638        714      1,352
    -------------------------------------------------------------------------
    Estimated distributions to vesting date(2)     179        215        394
    -------------------------------------------------------------------------
    Estimated units upon vesting after
     distributions                                 817        929      1,746
    Performance multiplier(3)                        -        1.6          -
    -------------------------------------------------------------------------
    Estimated total units upon vesting             817      1,456      2,273
    -------------------------------------------------------------------------
    Trust unit price at September 30, 2007      $21.17     $21.17     $21.17
    Estimated total value upon vesting          $ 17.3     $ 30.8     $ 48.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 September 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
     September 30, 2007                            Performance Multiplier
                                               ------------------------------
    (units thousands and $ millions
     except per unit)                                -        1.0        2.0
    -------------------------------------------------------------------------
    Estimated trust units to vest
       RTUs                                        817        817        817
       PTUs                                          -        987      1,974
    -------------------------------------------------------------------------
    Total units(1)                                 817      1,804      2,791
    -------------------------------------------------------------------------
       Trust unit price(2)                       21.17      21.17      21.17
       Trust unit distributions per month(2)      0.20       0.20       0.20
    -------------------------------------------------------------------------
    Value of Whole Unit Plan upon vesting         17.3       38.2       59.1
    -------------------------------------------------------------------------
       Officers                                    2.0       12.1       22.2
       Directors                                   1.3        1.3        1.3
       Staff                                      14.0       24.8       35.6
    -------------------------------------------------------------------------
    Total Payments Under Whole Unit Plan(3)       17.3       38.2       59.1
    -------------------------------------------------------------------------
       2007                                        2.3        2.3        2.3
       2008                                        7.8       15.2       22.7
       2009                                        5.2       13.6       22.0
       2010                                        2.0        7.1       12.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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. Assumes
        future trust unit price of $21.17 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 $17.3 million to $59.1 million from
2007 through 2010 based on the current trust unit price, and distribution
levels and a performance multiplier ranging from zero to two.

    Interest Expense

    Interest expense increased to $8.6 million in the third quarter of 2007
from $7.9 million in the third quarter of 2006 due to an increase in
short-term interest rates and higher debt balances. Interest expense for the
first nine months of 2007 was $27.7 million, an increase of $4.6 million from
$23.1 million in the first nine months of 2006.
    The Trust had 61 per cent or $378.6 million of its debt denominated in
U.S. dollars as at September 30, 2007. The Trust's debt balance as reflected
in Canadian dollars has decreased significantly since December 31, 2006. This
is a result of the 12 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 September 30,
2007. The Canadian dollar equivalent of the US$380 million debt balance has
decreased by $64.2 million as a result of the appreciation of the Canadian
dollar against the U.S. dollar from December 31, 2006 to September 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 91 per cent of the year-to-date capital program with cash flow from
operating activities and proceeds from the Distribution Reinvestment Program
("DRIP"). Debt was used to fund nine per cent of the year-to-date development
capital and 100 per cent of the net acquisitions year-to-date, however, this
was offset largely by the $33 million of proceeds on the sale of the Trust's
long-term investment that were applied against the debt balance in the third
quarter.
    As at September 30, 2007, the Trust had $624.4 million of debt
outstanding, of which $223.2 million was fixed at a weighted average rate of
5.06 per cent and $401.2 million was floating at current market rates plus a
credit spread of 60 basis points.

    Foreign Exchange Gains and Losses

    The Trust recorded a net gain of $25.7 million on foreign exchange
transactions compared to a net loss of $0.2 million for the third 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 third quarter of
2007, the Canadian dollar reached a 30 year high when compared to the U.S.
dollar. The dollar closed the quarter just over par where one dollar Canadian
purchased $1.004 U.S.
    The unrealized gain/loss impacts net income but does not impact cash flow
from operating activities as it is a non-cash amount. Realized foreign
exchange gains or losses arise from U.S. denominated transactions such as
interest payments, debt repayments and hedging settlements.

    Taxes

    In the third quarter of 2007, a future income tax recovery of
$6.3 million was included in income compared to a $9.6 million recovery in the
third quarter of 2006. The third 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 29.5 percent from the previous rate
of 33.7 per cent at the beginning of 2006. The corporate income tax rate
applicable to 2007 is 32.1 per cent as compared to the expected future tax
rate of 28.8 per cent based upon enacted tax legislation. If the future tax
reductions announced on October 30, 2007 are enacted by the Canadian
government, corporate taxes may be reduced further to 25 per cent by 2012.
    ARC does not anticipate any material cash income taxes will be paid by
the Trust 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 in the second quarter of 2007, 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. These amounts are reflected in the year-to-date future income
tax recovery of $64.1 million.
    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
$16.11 per boe in the third quarter of 2007 from $15.34 per boe in the third
quarter of 2006. Year-to-date, the DD&A rate has increased six per cent to
$16.26 per boe as compared to $15.37 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     Nine Months Ended
                                    September 30            September 30
    ($ millions except per                      %                       %
     boe amounts)               2007    2006  Change    2007    2006  Change
    -------------------------------------------------------------------------
    Depletion of oil & gas
     assets(1)                  87.7    85.1       3   267.8   256.0       5
    Accretion of asset
     retirement obligation(2)    2.9     2.6      12     8.7     7.8      12
    -------------------------------------------------------------------------
    Total DD&A expense          90.6    87.7       3   276.5   263.8       5
    -------------------------------------------------------------------------
    DD&A expense per boe       16.11   15.34       5   16.26   15.37       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 $131.9 million in the third quarter of 2007 compared to $104.9 million
in the third quarter of 2006. This amount was incurred on drilling and
completions, geological, geophysical and facilities expenditures, and the
purchase of undeveloped acreage. Included in the $131.9 million expenditures
is $33 million spent on the purchase of undeveloped acreage in and around
existing core areas. The Trust also spent $27.3 million on minor net property
acquisitions in the third quarter of 2007 as compared to $8.4 million for the
same period in 2006.

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

    -------------------------------------------------------------------------
                                  Three Months Ended       Nine Months Ended
    Capital Expenditures              September 30           September 30
    ($ millions)                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Geological and geophysical       2.9         2.2        11.9         7.7
    Land                            33.0         1.4        34.9        20.6
    Drilling and completions        73.4        76.2       154.4       161.4
    Plant and facilities            21.1        24.6        54.1        51.1
    Other capital                    1.5         0.5         2.6         1.8
    -------------------------------------------------------------------------
    Total capital expenditures     131.9       104.9       257.9       242.6
    -------------------------------------------------------------------------
    Producing property
     acquisitions (1)               27.3         8.4        42.0        47.5
    Producing property
     dispositions (1)                  -           -        (4.6)       (8.7)
    -------------------------------------------------------------------------
    Total capital expenditures and
     net acquisitions              159.2       113.3       295.3       281.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Approximately 38 per cent of the $131.9 million capital program was
financed with cash flow from operating activities in the third quarter of 2007
compared to 75 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 as well as debt.

    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                             Three Months Ended        Three Months Ended
                             September 30, 2007        September 30, 2006
    -------------------------------------------------------------------------
                          Devel-     Net    Total    Devel-     Net    Total
                         opment   Acquis-  Expend-  opment   Acquis-  Expend-
                        Capital   itions   itures  Capital   itions   itures
    -------------------------------------------------------------------------
    Expenditures          131.9     27.3    159.2    104.9      8.4    113.3
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash flow from
     operating
     activities (1)         38%        -      31%      75%      39%      69%
    Proceeds from DRIP
     and Rights Plan        21%        -      17%      25%        -      26%
    Debt                    41%     100%      52%        -      61%       5%
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                              Nine Months Ended        Nine Months Ended
                              September 30, 2007       September 30, 2006
    -------------------------------------------------------------------------
                          Devel-     Net    Total    Devel-     Net    Total
                         opment   Acquis-  Expend-  opment   Acquis-  Expend-
                        Capital   itions   itures  Capital   itions   itures
    -------------------------------------------------------------------------
    Expenditures          257.9     37.4    295.3    242.6     38.8    281.4
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash flow from
     operating
     activities(1)          58%        -      50%      84%        -      72%
    Proceeds from DRIP
     and Rights Plan        33%        -      29%      16%     100%      28%
    Debt                     9%     100%      21%        -        -        -
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) This is a GAAP measure and a change from the non-GAAP measure
        reported in prior quarters, refer to Non-GAAP Measures.
    

    Long-Term Investment

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

    Asset Retirement Obligation and Reclamation Fund

    At September 30, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $170.9 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 $14.6 million for reclamation
spending in the first nine months of 2007 ($2.7 million for the third quarter
of 2007). This amount has been offset by accretion of $8.7 million
($2.9 million for the third quarter of 2007). In addition, a net decrease to
the liability of $0.5 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 for the first nine months of 2007 has been 100 per
cent funded through the reclamation fund. The Trust performs an analysis
annually to ensure that sufficient funds are being contributed to the
reclamation fund to fund all future reclamation expenditures. The Trust's
spending profile for reclamation in 2007 has been influenced by the Alberta
Energy and Utilities Board ("AEUB")'s inactive well program whereby all
companies are required to complete stringent new well supsension standards on
their inactive wells. Of the Trust's $14.6 million reclamation expenditures in
2007, approximately $12 million was incurred in order to comply with this
legislation. These costs were all included in the Trust's ARO model, however,
the AEUB regulation required the Trust to accelerate the timing of the
expenditures that were originally forecasted to take place in years 2007
through to 2016. The Trust expects 2008 abandonment and reclamation costs to
return to normal levels of approximately $3 million per year.

    
    Capitalization, Financial Resources and Liquidity

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

    -------------------------------------------------------------------------
    Capital Structure and Liquidity
    ($ millions except per unit and                  September      December
     per cent amounts)                                30, 2007      31, 2006
    -------------------------------------------------------------------------
    Revolving credit facilities                          401.2         426.1
    Senior secured notes                                 223.2         261.0
    Working capital deficit(1)                            75.4          52.0
    -------------------------------------------------------------------------
    Net debt obligations                                 699.8         739.1

    Trust units outstanding and issuable for
     exchangeable shares (millions)                      211.7         207.2
    Market price per unit at end of period               21.17         22.30
    Market value of trust units and exchangeable
     shares at end of period                           4,481.7       4,620.0
    Total capitalization (2)                           5,181.5       5,359.1
    -------------------------------------------------------------------------
    Net debt as a percentage of total capitalization     13.5%         13.8%
    Net debt obligations                                 699.8         739.1
    Cash flow from operating activities(3)               531.2         760.6
    Net debt to annualized cash flow from operating
     activities                                            1.0           1.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) The working capital deficit excludes the balances for risk management
        contracts.
    (2) Total capitalization as presented does not have any standardized
        meaning prescribed by Canadian GAAP and therefore it may not be
        comparable with the calculation of similar measures for other
        entities. Total capitalization is not intended to represent the total
        funds from equity and debt received by the Trust.
    (3) This is a GAAP measure and a change from the non-GAAP measure
        reported in prior quarters; refer to Non-GAAP Measures.
    

    Net debt levels at September 30, 2007 have decreased since December 31,
2006 primarily as a result of the appreciation of the Canadian dollar
resulting in a lower Canadian dollar value of debt borrowed in U.S. funds. In
aggregate, U.S. denominated debt has generated an unrealized foreign exchange
gain of $66.2 million for the nine months ended September 30, 2007 thus
reducing the September 30, 2007 debt balance by the same amount. As at
September 30, 2007, the Trust had $380 million in U.S. denominated debt. The
Trust has entered into forward contracts to lock in the Canadian dollar
equivalent amounts for its U.S. denominated debt repayments. Please refer to
the Risk Management and Hedging Activities section for further details.
    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 September 30, 2007, the Trust had $403.6 million of
available borrowings under the current credit facility.
    During the quarter the Trust entered into treasury rate lock contracts in
order to manage its interest rate exposure on future debt issuances. Treasury
locks enable the Trust to synthetically secure current market rates for a
future fixed rate funding. These instruments hedge only the underlying
treasury yield and not the credit spread applicable to ARC which is determined
at the time of issuance. Based on the transactions completed over the quarter
the Trust has locked in an effective U.S. ten year treasury rate of 4.7624 per
cent on a notional amount of US$125 million.
    The Trust intends to finance its $350 million 2007 capital program with
cash flow from operating activities and the proceeds of the distribution
reinvestment program with any remainder being financed with debt.

    Unitholders' Equity

    At September 30, 2007, there were 211.7 million units issued and issuable
for exchangeable shares, an increase from 207.2 million units from
December 31, 2006. The increase in number of units outstanding is mainly
attributable to the 4.1 million units issued pursuant to the DRIP during 2007
at an average price of $20.26 per unit.
    The Trust had 0.2 million rights outstanding as of September 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 $8.72 per unit as at September 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 third quarter of 2007, the Trust raised proceeds of
$27.5 million and issued 1.4 million trust units pursuant to the DRIP.

    Distributions

    ARC declared distributions of $125 million ($0.60 per unit), representing
70 per cent of third quarter 2007 cash flow from operating activities compared
to distributions of $121.4 million ($0.60 per unit), representing 60 per cent
of cash flow from operating activities in the third quarter of 2006. The
remaining 30 per cent of third quarter 2007 cash flow from operating
activities ($54.6 million) was used to fund 38 per cent of ARC's 2007 third
quarter capital expenditures and make contributions, including interest, to
the reclamation funds ($5 million).
    Monthly distributions for the third 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 from operating activities
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 from operating activities and distributions in total and per
unit were as follows:

    
    -------------------------------------------------------------------------
                              Three Months Ended         Three Months Ended
                                 September 30               September 30
    Cash flow from operating                  %                          %
     activities and          2007     2006  Change      2007     2006  Change
     distributions               ($ millions)             ($ per unit)
    -------------------------------------------------------------------------
    Cash flow from operating
     activities             179.6    203.4    (12)      0.85     0.99    (14)
    Reclamation fund
     contributions(1)        (5.0)    (3.3)    48      (0.02)   (0.02)     -
    Capital expenditures
     funded with cash flow
     from operating
     activities             (49.6)   (78.7)   (37)     (0.24)   (0.38)   (37)
    Discretionary debt
     repayments                 -        -      -          -        -      -
    Other(2)                    -        -      -       0.01     0.01    200
    -------------------------------------------------------------------------
    Distributions           125.0    121.4      3       0.60     0.60      -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                               Nine Months Ended          Nine Months Ended
                                 September 30               September 30
    Cash flow from operating                  %                          %
    activities and           2007     2006  Change      2007     2006  Change
    distributions                ($ millions)             ($ per unit)
    -------------------------------------------------------------------------

    Cash flow from operating
     activities             531.2    574.6     (8)      2.54     2.82    (10)
    Reclamation fund
     contributions(1)       (10.1)    (9.7)     3      (0.05)   (0.05)     -
    Capital expenditures
     funded with cash
     flow from operating
     activities            (148.9)  (203.0)   (27)     (0.71)   (1.00)   (29)
    Discretionary debt
     repayments                 -        -      -          -        -      -
    Other(2)                    -        -      -       0.02     0.03    (33)
    -------------------------------------------------------------------------
    Distributions           372.2    361.9      3       1.80     1.80      -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    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    0.20
    November 28, 2007   November 30, 2007   December 17, 2007    0.20(*)
    December 27, 2007   December 31, 2007   January 15, 2008     0.20(*)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (*) 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 flows in an ongoing manner. The Trust also has contractual
obligations and commitments that are of a less routine nature as disclosed in
the following table.

    Following is a summary of the Trust's contractual obligations and
commitments as at September 30, 2007:

    -------------------------------------------------------------------------
                                               Payments Due By Period
    -------------------------------------------------------------------------
                                               2008-   2010-  There-
    ($ millions)                      2007(5)   2009    2011   after   Total
    -------------------------------------------------------------------------
    Debt repayments(1)                  13.6    22.3   439.1   149.4   624.4
    Interest payments(2)                 4.3    21.4    18.0    20.7    64.4
    Reclamation fund contributions(3)    6.0    11.1     9.5    76.2   102.8
    Purchase commitments                 5.0     8.0     2.9     5.8    21.7
    Operating leases                     1.3     9.0     4.5       -    14.8
    Derivative contract premiums(4)      5.3     9.1       -       -    14.4
    -------------------------------------------------------------------------
    Total contractual obligations       35.5    80.9   474.0   252.1   842.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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.
    (5) Amounts listed for 2007 represent contractual obligations and
        committments due in the fourth quarter of 2007.
    

    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 September 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 September 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 "code of business conduct and ethics" and "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 nine months of 2007.

    Financial Reporting Update

    During 2007, the Trust completed the implementation of the new CICA
Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section
3855, Financial Instruments - Recognition and Measurement, Section 3861,
Financial Instruments - Disclosure and Presentation, and Section 3865, Hedges
that deal with the presentation of equity, recognition and measurement of
financial instruments at fair value, and comprehensive income. As required by
the new standards, adoption has been applied prospectively as at January 1,
2007 and prior periods have not been restated. The adoption of these standards
has had no material impact on the Trust's net income or Cash Flows. See notes
2 and 9 in the Notes to the Unaudited Consolidated Financial Statements for
further details.

    During the third 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 from operating activities on which distributions are
paid. The Trust facilitates this by utilizing a portion of cash flow from
operating activities to fund a portion of ongoing capital development
activities and maintaining moderate debt levels. Oil and gas royalty trusts
generally distribute a high percentage of cash flow from operating activities
and hold assets that are depleting and unitholders should expect production,
revenue, cash flow from operating activities and distributions to decline over
the long-term. 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 from operating
activities 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 from operating activities and distributions as a per cent of cash
flow from operating activities:

    
    -------------------------------------------------------------------------
                                 Q3     Q2     Q1     Q4     Q3   Trailing 5
    Per Trust Unit Ratios      2007   2007   2007   2006   2006     Quarters
    -------------------------------------------------------------------------
    Production per unit(1):
    Unadjusted                 0.29   0.29   0.31   0.31   0.30            -
    Debt-adjusted(2)           0.25   0.26   0.27   0.27   0.28            -
    Normalized(3)             0.295   0.30   0.31   0.31  0.322            -
    -------------------------------------------------------------------------
    Cash flow from operations
     per unit                  0.85   0.86   0.83   0.77   0.99            -
    Distributions per unit     0.60   0.60   0.60   0.60   0.60            -
    Distributions as a per
     cent of cash flow from
     operating activities        70     69     71     77     60           69
    Per cent of cash flow from
     operating activities
     retained                    30     31     29     23     40           31
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 quarterly 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 quarterly 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 third quarter of 2006, the Trust's normalized production per
unit has decreased modestly from 0.322 to 0.295 boe of daily average
production per thousand trust units. The third quarter 2007 production per
unit of 0.295 was negatively impacted by maintenance activities and shut-in
production. Production per unit of 0.295 was achieved and the Trust paid
$615.9 million in distributions ($3.00 per trust unit and 69 per cent of cash
flow from operating activities) over a five quarter time period. The
normalized production per unit is a key measure as it indicates the ability to
generate cash flows 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 from operating activities 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 normalized daily
average production per initial investment has increased from 0.329 boe per
thousand trust units in the third quarter of 2006 to 0.336 in the third
quarter of 2007. The increase is attributed to the DRIP factor whereby one
unit purchased on July 1, 2006 would have grown to 1.14 trust units on
September 30, 2007.
    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 from
operating activities are indicative of the Trust's commitment to fund a
portion of ongoing development activities with cash flow from operating
activities to enable long-term sustainability. On an annual basis, the Trust's
distributions as a per cent of cash flow from operating activities 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 increase the amount of cash available to fund capital expenditures.
    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 from operating activities 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           Q3     Q2     Q1     Q4     Q3   Trailing 5
     per cent)                 2007   2007   2007   2006   2006     Quarters
    -------------------------------------------------------------------------

    Net income                120.8  184.9   83.3   56.6  116.9        562.5

    Distributions             125.0  124.1  123.1  122.3  121.4        615.9
    -------------------------------------------------------------------------
    Excess (shortfall) of net
     income over
     distributions             (4.2)  60.8  (39.8) (65.7)  (4.5)       (53.4)
    Excess (shortfall) as per
     cent  of net income       (3)%    33%   (48)%  (116)%  (4)%        (9)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash flow from operating activities is a GAAP measure and a change from
the non-GAAP measure reported in prior quarters; refer to the Non-GAAP
Measures section in this MD&A.

    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
third quarter of 2007:

    -------------------------------------------------------------------------
                                                                   Actual to
                                  2007 Revised  2007 Previous      September
                                      Guidance       Guidance       30, 2007
    -------------------------------------------------------------------------
    Production (boe/d)                  63,000         63,000         62,296
    -------------------------------------------------------------------------
    Expenses ($/boe):
      Operating costs (1)                 9.50           8.95           9.51
      Transportation                      0.70           0.70           0.73
      G&A expenses - cash (1)             2.15           2.25           2.02
      G&A expenses - stock compensation
       plans, non-cash (1)                0.10           0.20          (0.02)
      Interest (1)                        1.70           1.50           1.63
      Taxes                               0.00           0.00           0.00
    Annual capital expenditures
     ($ millions) (1)                      350            360            258
    Weighted average trust units
     and trust units issuable
     (millions) (1)                        210            208            209
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Guidance for the noted items was revised in the first and second
        quarters of 2007. See the Trust's first and second quarter 2007 MD&A
        for further details.

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

    -   Volumes for the first nine months of 2007 have been lower than
        guidance due in part to the Trust not having access to processing
        facilities for some of its wells drilled in the Dawson/Pouce areas.
        The third party plant is expected to be completed in the fourth
        quarter of 2007 and in addition, the Trust is currently looking at
        alternate processing facilities to mitigate the production loss in
        2007. The Trust expects full year 2007 production to reach
        approximately 63,000 boe per day and to average 64,000 boe per day
        during the fourth quarter.

    -   With operating costs higher than guidance for the nine months ended
        September 30, 2007 we have newly revised guidance to $9.50 per boe
        for the full year 2007. The Trust continues to pursue cost control in
        all areas of operations.

    -   Transportation costs on a year-to-date basis have been 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.

    -   Year-to-date Cash G&A expenses were lower than guidance due to the
        fact that the full year guidance includes a fourth quarter payment
        scheduled for the Whole Unit Plan which will increase the amount of
        cash G&A expense for the year. The Trust expects cash G&A to be in-
        line with guidance for the full year of 2007.

    -   Non-cash G&A for stock option plans are expected to be on target for
        $0.10 per boe once the fourth quarter accrual is recorded for the
        whole unit plan.

    -   At the second quarter the Trust revised 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. During the third quarter, the Trust has seen
        additional cost savings and now expects to complete budgeted capital
        expenditures for approximately $320 million. However an unbudgeted
        purchase of undeveloped acreage for $32.7 million occurred in the
        third quarter in and around the Trust's existing core areas resulting
        in capital exenditure guidance remaining at $350 million for the full
        year 2007.

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

    Assessment of Business Risks

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

    Forward-Looking Statement

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

    
    Additional Information

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

    QUARTERLY HISTORICAL REVIEW

    (CDN $ millions, except per
     Unit amounts)                                 2007                 2006
    -------------------------------------------------------------------------
    FINANCIAL                            Q3         Q2         Q1         Q4
    Revenue before royalties          300.2      305.6      307.8      292.5
      Per unit(1)                      1.42       1.46       1.48       1.42
    Cash flow from operating
     activities(2)                    179.6      179.4      172.3      159.4
      Per unit - basic(1)              0.85       0.86       0.83       0.77
      Per unit - diluted               0.85       0.86       0.83       0.77
    Net income                        120.8      184.9       83.3       56.6
      Per unit - basic(3)              0.58       0.90       0.41       0.28
      Per unit - diluted               0.58       0.89       0.41       0.28
    Distributions                     125.0      124.1      123.1      122.3
      Per unit(4)                      0.60       0.60       0.60       0.60
    Total assets                    3,460.8    3,432.8    3,450.1    3,479.0
    Total liabilities               1,421.4    1,415.3    1,526.6    1,550.6
    Net debt outstanding(5)           699.8      653.9      729.7      739.1
    Weighted average units(6)         210.9      209.5      207.9      206.5
    Units outstanding and
     issuable(6)                      211.7      210.2      208.7      207.2
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical          2.9        4.1        4.9        3.7
    Land                               33.0        1.7        0.2       11.8
    Drilling and completions           73.4       25.8       55.1       79.1
    Plant and facilities               21.1       16.3       16.8       26.5
    Other capital                       1.5        0.6        0.5        0.8
    Total capital expenditures        131.9       48.5       77.5      121.9
    Property acquisitions
     (dispositions) net                27.3       10.0        0.2       76.4
    Corporate acquisitions(7)             -          -          -       16.6
    Total capital expenditures and
     net acquisitions                 159.2       58.5       77.7      214.9
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)              28,437     28,099     29,520     29,605
      Natural gas (mmcf/d)            173.3      176.7      183.0      179.5
      Natural gas liquids (bbl/d)     3,795      4,088      4,161      4,144
      Total (boe per day 6:1)        61,108     61,637     64,175     63,663
    Average prices
      Crude oil ($/bbl)               73.40      65.21      60.79      58.26
      Natural gas ($/mcf)              5.52       7.38       7.75       6.99
      Natural gas liquids ($/bbl)     55.64      52.76      48.04      46.51
      Oil equivalent ($/boe)          53.41      54.48      53.29      49.94
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
    High                              22.60      23.86      23.02      29.22
    Low                               19.00      20.78      20.05      19.20
    Close                             21.17      21.74      21.25      22.30
    Average daily volume
     (thousands)                        503        599        658      1,125
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

                                                   2006                 2005
    -------------------------------------------------------------------------
    FINANCIAL                            Q3         Q2         Q1         Q4
    Revenue before royalties          312.3      306.7      318.9      365.3
      Per unit(1)                      1.52       1.51       1.58       1.89
    Cash flow from operating
     activities(2)                    203.4      182.2      189.0      247.3
      Per unit - basic(1)              0.99       0.89       0.93       1.28
      Per unit - diluted               0.98       0.89       0.93       1.28
    Net income                        116.9      182.5      104.1      130.5
      Per unit - basic(3)              0.58       0.91       0.52       0.68
      Per unit - diluted               0.58       0.91       0.52       0.68
    Distributions                     121.4      120.6      119.9      115.7
      Per unit(4)                      0.60       0.60       0.60       0.60
    Total assets                    3,335.8    3,277.8    3,279.7    3,251.2
    Total liabilities               1,371.3    1,339.9    1,434.1    1,415.5
    Net debt outstanding(5)           579.7      567.4      598.9      578.1
    Weighted average units(6)         205.1      203.7      202.5      193.4
    Units outstanding and
     issuable(6)                      205.7      204.4      203.1      202.0
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical          2.2        2.8        2.7        3.0
    Land                                1.4       14.3        4.9        5.5
    Drilling and completions           76.2       29.8       55.4       60.3
    Plant and facilities               24.6       10.9       15.6       17.0
    Other capital                       0.5        0.8        0.5        2.0
    Total capital expenditures        104.9       58.6       79.1       87.8
    Property acquisitions
     (dispositions) net                 8.4        2.8       27.6        3.0
    Corporate acquisitions(7)             -          -          -      462.8
    Total capital expenditures and
     net acquisitions                 113.3       61.4      106.7      553.6
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)              29,108     27,805     29,651     25,534
      Natural gas (mmcf/d)            173.4      178.5      185.0      177.9
      Natural gas liquids (bbl/d)     4,166      4,247      4,120      3,943
      Total (boe per day 6:1)        62,178     61,803     64,600     59,120
    Average prices
      Crude oil ($/bbl)               71.84      71.86      59.53      62.12
      Natural gas ($/mcf)              6.10       6.35       8.40      12.05
      Natural gas liquids ($/bbl)     56.60      54.44      52.91      57.14
      Oil equivalent ($/boe)          54.59      54.54      54.86      67.16
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
    High                              30.74      28.61      27.51      27.58
    Low                               25.25      24.35      25.09      20.45
    Close                             27.21      28.00      27.36      26.49
    Average daily volume
     (thousands)                        614        548        546        653
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares.
    (2) This is a GAAP measure and a change from the non-GAAP measure
        reported in prior quarters. Refer to non-GAAP section.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Based on number of trust units outstanding at each distribution date.
    (5) Net debt excludes 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 September 30 and December 31 (unaudited)

    ($CDN millions)                                       2007          2006
    -------------------------------------------------------------------------
    ASSETS
      Current assets
      Cash and cash equivalents                    $         -   $       2.8
      Accounts receivable                                120.6         129.8
      Prepaid expenses                                    15.7          18.4
      Risk management contracts (Note 9)                  14.7          25.7
    -------------------------------------------------------------------------
                                                         151.0         176.7
    Reclamation funds (Note 3)                            26.2          30.9
    Property, plant and equipment                      3,120.9       3,093.8
    Long-term investment (Note 4)                            -          20.0
    Risk management contracts (Note 9)                     5.1             -
    Goodwill                                             157.6         157.6
    -------------------------------------------------------------------------
    Total assets                                   $   3,460.8   $   3,479.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities
       (Note 5)                                    $     169.9   $     162.1
      Distributions payable                               41.8          40.9
      Risk management contracts (Note 9)                  16.0          34.4
    -------------------------------------------------------------------------
                                                         227.7         237.4
    Long-term debt (Note 6)                              624.4         687.1
    Accrued long-term incentive compensation (Note 15)    11.9          14.6
    Asset retirement obligations (Note 7)                170.9         177.3
    Risk management contracts (Note 9)                    14.7             -
    Future income taxes (Note 8)                         371.8         434.2
    -------------------------------------------------------------------------
    Total liabilities                                  1,421.4       1,550.6
    -------------------------------------------------------------------------

    COMMITMENTS AND CONTINGENCIES (Note 17)

    NON-CONTROLLING INTEREST
      Exchangeable shares (Note 10)                       42.1          40.0

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 11)                   2,438.1       2,349.2
      Contributed surplus (Note 14)                        1.7           2.4
      Deficit (Note 12)                                 (446.4)       (463.2)
      Accumulated other comprehensive income (Note 2)      3.9             -
    -------------------------------------------------------------------------
    Total unitholders' equity                          1,997.3       1,888.4
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity      $   3,460.8   $   3,479.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to consolidated financial statements.



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

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

    Revenues
      Oil, natural gas and
       natural gas liquids    $    300.2   $   312.3   $   913.6   $   937.9
      Royalties                    (49.2)      (53.5)     (157.8)     (170.7)
    -------------------------------------------------------------------------
                                   251.0       258.8       755.8       767.2
      Gain (loss) on risk
       management contracts
       (Note 9)
        Realized                     8.0         9.6        15.3        19.4
        Unrealized                   2.1         0.5        (8.0)       (8.5)
    -------------------------------------------------------------------------
                                   261.1       268.9       763.1       778.1
    -------------------------------------------------------------------------

    Expenses
      Transportation                 3.6         3.5        12.4        10.7
      Operating                     55.7        50.4       161.7       141.9
      General and administrative    12.1        10.3        34.1        37.0
      Interest on long-term
       debt (Note 6)                 8.6         7.9        27.7        23.1
      Depletion, depreciation
       and accretion                90.6        87.7       276.5       263.8
      (Gain) loss on foreign
       exchange                    (25.7)        0.2       (66.2)      (17.0)
    -------------------------------------------------------------------------
                                   144.9       160.0       446.2       459.5
    -------------------------------------------------------------------------
    Operating income               116.2       108.9       316.9       318.6
    Gain on sale of investment
     (Note 4)                          -           -        13.3           -
    Capital and other taxes            -           -           -        (0.3)
    Future income tax recovery
     (Note 8)                        6.3         9.6        64.1        90.8
    -------------------------------------------------------------------------
    Net income before
     non-controlling interest      122.5       118.5       394.3       409.1
    Non-controlling interest
     (Note 10)                      (1.7)       (1.7)       (5.3)       (5.7)
    -------------------------------------------------------------------------
    Net income                $    120.8   $   116.8   $   389.0   $   403.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Deficit, beginning of
     period                   $   (442.2)  $  (393.0)  $  (463.2)  $  (439.1)
    Distributions paid or
     declared (Note 13)           (125.0)     (121.4)     (372.2)     (361.9)
    -------------------------------------------------------------------------
    Deficit, end of period
     (Note 12)                $   (446.4)  $  (397.6)  $  (446.4)  $  (397.6)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income per unit
     (Note 16)
      Basic                   $     0.58   $    0.58   $    1.88   $    2.01
      Diluted                 $     0.58   $    0.58   $    1.88   $    2.00
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to consolidated financial statements.



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


                                   Three Months Ended      Nine Months Ended
                                      September 30            September 30
    ($CDN millions)                 2007        2006        2007        2006
    -------------------------------------------------------------------------
    Net income                $    120.8   $   116.8   $   389.0   $   403.4
    Other comprehensive
     income, net of tax
      Loss on financial
       instruments designated
       as cash flow hedges(1)       (4.0)          -        (1.0)          -
      Gain on financial
       instruments designated as
       cash flow hedges in prior
       periods realized in net
       income in the current
       period(1)                     0.8           -         0.2           -
      Net unrealized gains
       (losses) on
       available-for-sale
       reclamation funds'
       investments(2)                0.2           -        (0.2)          -
    -------------------------------------------------------------------------
    Other comprehensive income      (3.0)          -        (1.0)          -
    -------------------------------------------------------------------------
    Comprehensive income      $    117.8   $   116.8   $   388.0   $   403.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accumulated other
     comprehensive income,
     beginning of period             6.9           -           -           -
    Application of initial
     adoption                          -           -         4.9           -
    Other comprehensive income      (3.0)          -        (1.0)          -
    -------------------------------------------------------------------------
    Accumulated other
     comprehensive income,
     end of period            $      3.9           -   $     3.9           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        (1)  Amounts are net of tax recovery of $1.3 million and $0.4
             million, respectively, for the three and nine months ended
             September 30, 2007.
        (2)  Nominal future income tax impact.

    See accompanying notes to consolidated financial statements.



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

                                   Three Months Ended      Nine Months Ended
                                      September 30            September 30
    ($CDN millions)                 2007        2006        2007        2006
    -------------------------------------------------------------------------

    CASH FLOWS FROM OPERATING
     ACTIVITIES
    Net income                $    120.8   $   116.8   $   389.0   $   403.4
    Add items not involving
     cash:
      Non-controlling interest
       (Note 10)                     1.7         1.7         5.3         5.7
      Future income tax
       recovery (Note 8)            (6.3)       (9.6)      (64.1)      (90.8)
      Depletion, depreciation
       and accretion                90.6        87.7       276.5       263.8
      Non-cash (gain) loss on
       risk management
       contracts (Note 9)           (2.1)       (0.5)        8.0         8.5
      Non-cash (gain) loss on
       foreign exchange            (25.7)        0.1       (66.5)      (16.5)
      Non-cash trust unit
       incentive compensation
       (Notes 14 and 15)             4.5         4.1        (0.1)       12.0
      Gain on sale of
       investment (Note 4)             -           -       (13.3)          -
    Expenditures on site
     restoration and
     reclamation (Note 7)           (2.7)       (3.4)      (14.6)       (6.6)
    Change in non-cash
     working capital                (1.2)        6.5        11.0        (4.9)
    -------------------------------------------------------------------------
                                   179.6       203.4       531.2       574.6
    -------------------------------------------------------------------------

    CASH FLOWS FROM FINANCING
     ACTIVITIES
    Issuance of long-term debt
     under revolving credit
     facilities, net                 5.1       (21.8)        5.1        (4.1)
    Issue of trust units             0.6         3.6         2.9        12.2
    Trust unit issue costs             -           -           -        (0.3)
    Cash distributions paid
     (Note 13)                     (97.9)      (95.2)     (289.3)     (293.9)
    Payment of retention bonuses    (1.0)       (1.0)       (1.0)       (1.0)
    Change in non-cash working
     capital                         1.5         1.2         1.3         2.7
    -------------------------------------------------------------------------
                                   (91.7)     (113.2)     (281.0)     (284.4)
    -------------------------------------------------------------------------

    CASH FLOWS FROM INVESTING ACTIVITIES

    Acquisition of petroleum
     and natural gas
     properties                    (27.3)       (8.4)      (38.6)      (40.8)
    Proceeds on disposition
     of petroleum and natural
     gas properties                    -         0.1         1.2         2.1
    Capital expenditures          (132.5)     (104.4)     (257.6)     (240.8)
    Long-term investment (Note 4)      -           -        33.3       (20.0)
    Net reclamation fund
     withdrawals (contributions)
     (Note 3)                        6.1        (1.8)        4.5        (5.5)
    Change in non-cash working
     capital                        30.8        24.7         4.2        15.2
    -------------------------------------------------------------------------
                                  (122.9)      (89.8)     (253.0)     (289.8)
    -------------------------------------------------------------------------
    (DECREASE) INCREASE IN
     CASH AND CASH EQUIVALENTS     (35.0)        0.4        (2.8)        0.4
    CASH AND CASH EQUIVALENTS,
     BEGINNING OF PERIOD            35.0           -         2.8           -
    -------------------------------------------------------------------------
    CASH AND CASH EQUIVALENTS,
     END OF PERIOD            $        -   $     0.4   $       -   $     0.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to consolidated financial statements.



    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
    September 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 six 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 3861, Financial Instruments - Disclosure and Presentation,
        Section 3865, Hedges, Section 3251, Equity 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, measurement and disclosure of financial instruments, the
        use of hedge accounting and the presentation of equity.

        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 Consolidated Statements of
        Comprehensive Income, Accumulated Other Comprehensive Income
        ("AOCI"), and the changes in these items during the first three and
        nine month periods ended September 30, 2007. Cumulative changes in
        OCI are included in 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, excluding long-term debt, transaction costs
        have been expensed as incurred. The Trust has elected to capitalize
        costs incurred relating to debt issuances and to amortize these costs
        over the term of the associated debt. 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. All risk management contracts have been designated
        as held-for-trading. A portion of the reclamation funds has been
        designated as available-for-sale. All other financial instruments are
        classified as held-to-maturity.

        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 hedges.

        The Trust has elected January 1, 2003 as the effective date to
        recognize embedded derivatives. No adjustments were required for
        embedded derivatives on adoption of this standard.

        Financial Instruments - Disclosure and Presentation
        Section 3861 establishes standards for enhancing financial statement
        users' understanding of the significance of financial instruments to
        an entity's financial position, performance and cash flows. It
        establishes standards for presentation of financial instruments and
        non-financial derivatives, and identifies the information that should
        be disclosed about them. This section sets forth standards on the
        presentation and classification of financial instruments between
        liabilities and equity, the classification of related interest,
        dividends, losses and gains, and the circumstances in which financial
        assets and financial liabilities are offset. The Section dictates
        disclosures surrounding factors that affect the amount, timing and
        certainty of an entity's future cash flows relating to financial
        instruments. This Section also deals with disclosure of information
        about the nature and extent of an entity's use of financial
        instruments, the business purposes they serve, the risks associated
        with them and management's policies for controlling those risks.

        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 and treasury rate lock contracts
        as effective cash flow hedges.

        In a cash flow hedging relationship, the effective portion of the
        change in the fair value of the hedging derivative is recognized in
        OCI while the ineffective portion is recognized in 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.

        Equity
        Section 3251 establishes standards for the presentation of equity and
        changes in equity during the reporting period. This section specifies
        that changes in equity for the period arising from net income, other
        comprehensive income, other changes in retained earnings, changes in
        contributed surplus, and changes in unitholders' capital must be
        presented separately.

        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

                                   September 30, 2007     December 31, 2006
        ---------------------------------------------------------------------
                                  Unrest-                 Unrest-
                                  ricted  Restricted      ricted  Restricted
        ---------------------------------------------------------------------
        Balance, beginning of
         period               $     24.8   $     6.1   $    23.5   $       -
        Contributions                9.0           -         6.0         6.1
        Reimbursed
         expenditures(1)           (14.0)       (0.6)       (5.7)          -
        Interest earned on funds     0.9         0.2         1.0           -
        Net unrealized losses
         on available-for-sale
         investments                (0.2)          -           -           -
        ---------------------------------------------------------------------
        Balance, end of
         period               $     20.5   $     5.7   $    24.8   $     6.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (1)  Amount differs from actual expenditures incurred by the Trust
                due to timing differences and discretionary reimbursements.

        The carrying values of the unrestricted and restricted reclamation
        funds, as at September 30, 2007 were $20.7 million and $5.7 million,
        respectively.

    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

                                                       September    December
                                                        30, 2007    31, 2006
        ---------------------------------------------------------------------
        Trades payable                                 $    40.7   $    39.0
        Accrued liabilities                                111.8       108.8
        Current portion of accrued long-term
         incentive compensation                             14.4        11.5
        Interest payable                                     3.0         1.8
        Retention bonuses                                      -         1.0
        ---------------------------------------------------------------------
        Total accounts payable and accrued liabilities $   169.9   $   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 September 30, 2007 (see Note 15). This
        amount is payable in 2007 and 2008.

    6.  LONG-TERM DEBT

                                                       September    December
                                                        30, 2007    31, 2006
        ---------------------------------------------------------------------
        Revolving credit facilities
          Syndicated credit facility - CDN
           denominated(1)                              $   241.0   $   196.6
          Syndicated credit facility - US denominated      155.4       228.4
          Working capital facility                           4.8         1.1
        Senior secured notes
          5.42% USD Note                                    74.7        87.4
          4.94% USD Note                                    23.9        28.0
          4.62% USD Note                                    62.3        72.8
          5.10% USD Note                                    62.3        72.8
        ---------------------------------------------------------------------
        Total long-term debt outstanding               $   624.4   $   687.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (1)  Amount borrowed under the syndicated credit facility for 2007
                includes $2.7 million of outstanding cheques in excess of
                bank balance.

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

        The following 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 September 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 5.5 percent for the three months ended September 30,
        2007 (5.8 per cent in 2006) and 5.5 per cent for the nine months
        ended September 30, 2007 (5.3 per cent in 2006).

        Both the working capital facility and 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:

                                                       September    December
                                                        30, 2007    31, 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                                          2.7         2.8
        (Decrease) increase in liabilities relating to
         change in estimate                                 (3.2)        4.0
        Settlement of liabilities during the year          (14.6)      (10.6)
        Accretion expense                                    8.7        11.1
        ---------------------------------------------------------------------
        Balance, end of period                         $   170.9   $   177.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Trust's weighted average credit adjusted risk free rate as at
        September 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.

    9.  FINANCIAL INSTRUMENTS

        Financial Instruments

        Financial Instruments of the Trust carried on the Consolidated
        Balance Sheet consist mainly of cash and cash equivalents, accounts
        receivable, reclamation funds, current liabilities, long-term
        liabilities excluding future income taxes, and risk management
        contracts. At September 30, 2007 there were no significant
        differences between the carrying value of these financial instruments
        and their estimated fair values.

        Risk Management Contracts

        The Trust uses a variety of derivative instruments to reduce its
        exposure to fluctuations in commodity prices, foreign exchange and
        interest 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 September 30, 2007 which do not qualify for hedge accounting:

        Financial WTI Crude Oil Contracts

                                           Bought     Sold     Sold
                                 Volume       Put      Put     Call
        Term         Contract     bbl/d   US$/bbl  US$/bbl  US$/bbl
        ---------------------------------------------------------------------
        Oct 07
         - Dec 07  Put Spread     1,000     75.00    60.00        -
        Oct 07        3 - Way
         - Dec 07      Collar     2,500     65.00    52.50    80.00
        Oct 07
         - Dec 07  Put Spread     2,500     65.00    52.50        -
        Oct 07
         - Dec 07  Put Spread     1,000     65.00    55.00        -
        Oct 07        3 - Way
         - Dec 07      Collar     1,000     65.00    52.50    85.00
        Oct 07        3 - Way
         - Dec 07      Collar     5,000     75.00    65.00    90.00
        Oct 07
         - Dec 07  Put Spread     1,000     75.00    65.00        -
        Jan 08        3 - Way
         - Jun 08      Collar     1,000     65.00    52.50    85.00
        Jan 08        3 - Way
         - Jun 08      Collar     1,000     65.00    52.50    82.50
        Jan 08
         - Jun 08      Collar     1,000     65.00        -    85.00
        Jan 08        3 - Way
         - Dec 08      Collar     1,000     70.00    55.00    90.00
        Jan 08        3 - Way
         - Dec 08      Collar     1,000     67.50    52.50    85.00
        Jan 08
         - Dec 08      Collar     1,000     67.50        -    85.00
        Jan 08        3 - Way
         - Dec 08      Collar     2,000     61.50    50.00    85.00
        Jan 08        3 - Way
         - Dec 08      Collar     1,000     61.30    50.00    85.00
        Jan 08        3 - Way
         - Dec 08      Collar     2,000     61.00    50.00    85.00
        Jan 09        3 - Way
         - Dec 09      Collar     5,000     55.00    40.00    90.00
        ---------------------------------------------------------------------

        Financial AECO Natural Gas Option Contracts

                                           Bought     Sold     Sold
                                 Volume       Put      Put     Call
        Term         Contract      GJ/d   CDN$/GJ  CDN$/GJ  CDN$/GJ
        ---------------------------------------------------------------------
        Oct 07
         - Oct 07  Put Spread    30,000      7.00     5.00        -
        Oct 07
         - Oct 07  Put Spread    10,000      7.25     5.25        -
        Oct 07
         - Oct 07  Put Spread    10,000      7.50     5.50        -
        Oct 07
         - Oct 07  Bought Put    10,000      7.75        -        -
        Apr 08
         - Oct 08      Collar    10,000      7.00        -     9.00
        Apr 08        3 - Way
         - Oct 08      Collar    10,000      7.00     5.75     9.00
        ---------------------------------------------------------------------

        Financial AECO Natural Gas Fixed Price Contracts

                                             Sold
                                 Volume      Swap
        Term         Contract      GJ/d   CDN$/GJ
        ---------------------------------------------------------------------
        Oct 07
         - Oct 07        Swap    30,000      5.45
        ---------------------------------------------------------------------

        Financial NYMEX Natural Gas Contracts

                                           Bought     Sold     Sold
                                              Put      Put     Call
                                 Volume      US$/     US$/     US$/
        Term         Contract   mmbtu/d     mmbtu    mmbtu    mmbtu
        ---------------------------------------------------------------------
        Oct 07
         - Oct 07  Put Spread     5,000      8.25     6.75        -
        Nov 07
         - Mar 08      Collar    20,000      8.50        -    12.50
        Nov 07        3 - Way
         - Mar 08      Collar    10,000      9.25     6.25    12.50
        ---------------------------------------------------------------------

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

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


        Financial Basis Swap Contract: receive AECO (Monthly); pay NYMEX
        (Last 3 Day)
                                            Basis
                                             Swap
                                 Volume      US$/
        Term         Contract   mmbtu/d     mmbtu
        ---------------------------------------------------------------------
        Oct 07
         - Oct 07  Basis Swap    30,000   (1.2233)
        ---------------------------------------------------------------------


        Energy Equivalent Swap

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

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


        Financial Foreign Exchange Contracts

                                                             Bought    Sold
                               Notional      Swap     Swap      Put     Put
                                 Volume     CDN$/     US$/    CDN$/   CDN$/
        Term         Contract    MM US$       US$     CDN$      US$     US$
        ---------------------------------------------------------------------
        USD Sales Contracts
        Oct 07
         - Dec 07        Swap       4.8    1.1371  (0.8794)       -       -

        USD Option Contracts
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1220  1.0970
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1180  1.0980
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1320  1.1020
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1380  1.1030
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1332  1.1032
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1400  1.1050
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1380  1.1080
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1300  1.1100
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1400  1.1100
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1420  1.1120
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1520  1.1120
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1440  1.1140
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1460  1.1160
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1480  1.1180
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1545  1.1195
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1765  1.1465
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1280  1.0980
        Oct 07
         - Dec 07  Put Spread       3.0         -        -   1.1250  1.1000
        Oct 07
         - Dec 07  Bought Put       1.2         -        -   1.1600       -
        Jan 08
         - Dec 08  Put Spread      12.0         -        -   1.0750  1.0300


        USD Long-term Principal Debt Repayment Contracts

                                                             Bought    Sold
                               Notional      Swap     Swap     Call     Put
        Settlement               Volume     CDN$/     US$/    CDN$/   CDN$/
        Date         Contract    MM US$       US$     CDN$      US$     US$
        ---------------------------------------------------------------------
        December 15,
         2014         Forward      9.38    0.9825  (1.0178)       -       -
        April 27,
         2015         Forward     12.50    0.9825  (1.0178)       -       -
        December 15,
         2015         Forward      9.40    0.9980  (1.0020)       -       -
        April 27,
         2016         Forward     12.50    1.0180  (0.9823)       -       -
        December 15,
         2017         Forward      9.40    1.0184  (0.9819)       -       -
        December 15,
         2016          Collar      9.40         -        -   1.0600  1.0000
        ---------------------------------------------------------------------

        Financial Interest Rate Contracts(1)

                                            Fixed         Spread on
                              Principal    Annual             3 Mo.
        Term         Contract    MM US$   Rate (%)            LIBOR
        ---------------------------------------------------------------------
        Jul 07
         - Apr 14        Swap      30.5      4.62            38 bps
        Jul 07
         - Apr 14        Swap      32.0      4.62         (25.5 bps)
        ---------------------------------------------------------------------

           (1)  Starting in 2009, the notional amount of the contracts
                decreases annually until 2014. The Trust pays the floating
                interest rate based on a three month LIBOR plus a spread and
                receives the fixed interest rate.

        Following is a summary of all risk management contracts in place as
        at September 30, 2007 which qualify for hedge accounting:

        Financial Electricity Contracts(2)

                                             Swap
                                 Volume     CDN$/
        Term         Contract       MWh       MWh
        ---------------------------------------------------------------------
        Oct 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
        ---------------------------------------------------------------------

           (2)  Contracted volume is based on a 24/7 term.


        USD Note Treasury Rate Locks

        Settlement  Principal                  Locked Rate
        Date           MM US$                  Received (%)
        ---------------------------------------------------------------------
        October 17,
         2007            25.0                       4.6450
        November 15,
         2007           100.0                       4.7943
        ---------------------------------------------------------------------

        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 $0.5 million has
        been reflected in Net Income for the nine months ended September 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:

                                                       September   September
                                                        30, 2007    30, 2006
        ---------------------------------------------------------------------
        Fair value, beginning of period(1)             $    (8.7)  $    (4.0)
        Fair value, end of period(1)                       (16.7)      (12.5)
        ---------------------------------------------------------------------
        Change in fair value of contracts in the period     (8.0)       (8.5)
        Realized gains in the period                        15.3        19.4
        ---------------------------------------------------------------------
        Gain on risk management contracts(1)           $     7.3   $    10.9
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (1)  For 2007 the fixed price electricity and treasury rate lock
                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.

        At September 30, 2007, the fair value of the contracts that were not
        designated as accounting hedges was a loss of $16.7 million. The
        Trust recorded a gain on risk management contracts of $7.3 million in
        the statement of income for the first nine months of 2007
        ($10.9 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.

        During the quarter the Trust entered into treasury rate lock
        contracts in order to manage the Company's interest rate exposure on
        future debt issuances. These contracts have been designated as
        effective accounting hedges on their respective contract dates and
        hedge accounting has been applied. The unrealized fair value loss on
        these contracts of $1.7 million has been recorded on the Consolidated
        Balance Sheet at September 30, 2007 with the movement in the fair
        value recorded in OCI, net of tax. It is expected that a nominal
        amount of this fair value loss will be reclassified to Net Income
        within the next 12 months.

        The Trust's fixed price electricity contracts are intended to manage
        price risk on electricity consumption. All fixed price electricity
        contracts were designated as effective accounting hedges on their
        respective contract dates. A realized gain of $1.2 million and
        $0.5 million for the three months and nine months ended September 30,
        2007 respectively (gain of $1.4 million and $1 million respectively
        in 2006) on the electricity contracts has been included in operating
        costs. The unrealized fair value gain on the electricity contracts of
        $7.5 million has been recorded on the consolidated balance sheet at
        September 30, 2007 with the movement in fair value recorded in OCI,
        net of tax. A $2.6 million gain related to electricity contracts is
        expected to be recognized in income over the next 12 months.

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

                                                       September   September
                                                        30, 2007    30, 2006
        ---------------------------------------------------------------------
        Fair value, beginning of period(2)             $     7.0   $       -
        Fair value, end of period                            5.8           -
        ---------------------------------------------------------------------
        Change in fair value of contracts in the
         period                                        $    (1.2)  $       -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (2)  Fair value of fixed price electricity contracts recognized
                prospectively on January 1, 2007.

        The fair values of all derivative contracts are determined using
        published price quotations in an active market through a valuation
        model.

    10. EXCHANGEABLE SHARES

        ARL EXCHANGEABLE SHARES                        September    December
        (thousands)                                     30, 2007    31, 2006
        ---------------------------------------------------------------------
        Balance, beginning of period                       1,433       1,595
        Exchanged for trust units(1)                        (110)       (162)
        ---------------------------------------------------------------------
        Balance, end of period                             1,323       1,433
        Exchange ratio, end of period                    2.18448     2.01251
        ---------------------------------------------------------------------
        Trust units issuable upon conversion, end
         of period                                         2,889       2,884
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (1)  During the first nine months of 2007, 110,345 ARC Resources
                exchangeable shares ("ARL exchangeable shares") were
                converted to trust units at an average exchange ratio of
                2.114563.

        Following is a summary of the non-controlling interest for September
        30, 2007 and December 31, 2006:

                                                       September    December
                                                        30, 2007    31, 2006
        ---------------------------------------------------------------------
        Non-controlling interest, beginning of period  $    40.0   $    37.5
        Reduction of book value for conversion to
         trust units                                        (3.2)       (4.1)
        Current period net income attributable to
         non-controlling interest                            5.3         6.6
        ---------------------------------------------------------------------
        Non-controlling interest, end of period        $    42.1   $    40.0
        ---------------------------------------------------------------------
        Accumulated earnings attributable to
         non-controlling interest                      $    32.6   $    27.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. UNITHOLDERS' CAPITAL

                                  September 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)            233         3.2         310         4.1
        Issued on exercise of
         employee rights
         (Note 14)                   129         2.1         978        18.4
        Distribution
         reinvestment program      4,122        83.6       3,896        96.1
        Trust unit issue costs         -           -           -        (0.2)
        ---------------------------------------------------------------------
        Balance, end of period   208,773     2,438.1     204,289     2,349.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    12. DEFICIT

        The deficit balance is composed of the following items:

                                                       September    December
                                                        30, 2007    31, 2006
        ---------------------------------------------------------------------
        Accumulated earnings                           $ 2,084.8   $ 1,695.8
        Accumulated distributions                       (2,531.2)   (2,159.0)
        ---------------------------------------------------------------------
        Deficit                                        $  (446.4)  $  (463.2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    13. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
        DISTRIBUTIONS

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

                                   Three Months Ended      Nine Months Ended
                                      September 30            September 30
                                    2007        2006        2007        2006
        ---------------------------------------------------------------------
        Cash flow from
         operating activities $    179.6   $   203.4   $   531.2   $   574.6
        Deduct:
          Cash withheld to fund
           current period
           capital expenditures    (49.6)      (78.7)     (148.9)     (203.0)
          Reclamation fund
           contributions and
           interest earned on
           fund balances            (5.0)       (3.3)      (10.1)       (9.7)
        ---------------------------------------------------------------------
        Distributions(1)           125.0       121.4       372.2       361.9
        Accumulated
         distributions,
         beginning of period     2,406.2     1,915.3     2,159.0     1,674.8
        ---------------------------------------------------------------------
        Accumulated
         distributions, end of
         period               $  2,531.2   $ 2,036.7   $ 2,531.2   $ 2,036.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Distributions per
         unit(2)              $     0.60   $    0.60   $    1.80   $    1.80
        Accumulated
         distributions per
         unit, beginning of
         period(3)            $    19.83   $   17.43   $   18.63   $   16.23
        ---------------------------------------------------------------------
        Accumulated
         distributions per
         unit, end of
         period(3)            $    20.43   $   18.03   $   20.43   $   18.03
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (1)  Distributions include non-cash amounts of $27 million and
                $83 million for the three and nine months ended September 30,
                2007, respectively ($27 million and $70 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                                           (129)      10.82
        ---------------------------------------------------------------------
        Balance before reduction of exercise price           240        9.41
        Reduction of exercise price(1)                         -       (0.69)
        ---------------------------------------------------------------------
        Balance, end of period                               240        8.72
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (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 nine
        months of 2007 ($2.5 million in the first nine 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 third
        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 2,416,669 rights have been exercised
        to September 30, 2007.

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

                                                       September    December
        CONTRIBUTED SURPLUS                             30, 2007    31, 2006
        ---------------------------------------------------------------------
        Balance, beginning of period                   $     2.4   $     6.4
        Compensation expense                                   -         2.5
        Net benefit on rights exercised(1)                  (0.7)       (6.5)
        ---------------------------------------------------------------------
        Balance, end of period                         $     1.7   $     2.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (1)  Upon exercise, the net benefit is reflected as a reduction of
                contributed surplus and an increase to Unitholders' capital.

    15. WHOLE TRUST UNIT INCENTIVE PLAN

        The Trust recorded compensation expense of $8 million and
        $1.3 million to general and administrative and operating expenses,
        respectively, and capitalized $1.4 million to property, plant and
        equipment in the nine months ended September 30, 2007 for the
        estimated cost of the plan ($11.1 million, $2.2 million and
        $2.2 million for the nine months ended September 30, 2006). The
        compensation expense was based on the September 30, 2007 unit price
        of $21.17 ($27.21 at September 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 nine months ended
        September 30, 2007:

                                                       Number of   Number of
                                                            RTUs        PTUs
                                                      (thousands) (thousands)
        ---------------------------------------------------------------------
        Balance, beginning of period                         648         683
        Vested                                              (191)       (110)
        Granted                                              206         167
        Forfeited                                            (25)        (26)
        ---------------------------------------------------------------------
        Balance, end of period                               638         714
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

                                                       September    December
                                                        30, 2007    31, 2006
        ---------------------------------------------------------------------
        Balance, beginning of period                   $    26.1   $    15.0
        Change in liabilities in the period
          General and administrative expense                (0.3)        8.2
          Operating expense                                  0.2         1.1
          Property, plant and equipment                      0.3         1.8
        ---------------------------------------------------------------------
        Balance, end of period                         $    26.3   $    26.1
        ---------------------------------------------------------------------
        Current portion of liability                        14.4        11.5
        ---------------------------------------------------------------------
        Accrued long-term incentive compensation       $    11.9   $    14.6
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    16. BASIC AND DILUTED PER UNIT CALCULATIONS

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

                                   Three Months Ended      Nine Months Ended
                                      September 30            September 30
                                    2007        2006        2007        2006
        ---------------------------------------------------------------------
        Weighted average trust
         units(1)                  208.0       202.2       206.5       200.9
        ---------------------------------------------------------------------
        Trust units issuable on
         conversion of
         exchangeable shares(2)      2.9         2.9         2.9         2.9
        Dilutive impact of
         rights(3)                   0.1         0.4         0.2         0.5
        ---------------------------------------------------------------------
        Diluted trust units        211.0       205.5       209.6       204.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (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 September 30, 2007:

        ---------------------------------------------------------------------
                                             Payments Due By Period
        ---------------------------------------------------------------------
                                            2008-    2010-   There-
        ($ millions)              2007(5)    2009     2011    after    Total
        ---------------------------------------------------------------------
        Debt repayments(1)          13.6     22.3    439.1    149.4    624.4
        Interest payments(2)         4.3     21.4     18.0     20.7     64.4
        Reclamation fund
         contributions(3)            6.0     11.1      9.5     76.2    102.8
        Purchase commitments         5.0      8.0      2.9      5.8     21.7
        Operating leases             1.3      9.0      4.5        -     14.8
        Derivative contract
         premiums(4)                 5.3      9.1        -        -     14.4
        ---------------------------------------------------------------------
        Total contractual
         obligations                35.5     80.9    474.0    252.1    842.5
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

           (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.
           (5)  Amounts listed for 2007 represent contractual obligations and
                committments due in the fourth quarter of 2007.

        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 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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