ARC Energy Trust announces first quarter 2009 results



    CALGARY, May 7 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC" or
"the Trust") announces the results for the first quarter ended March 31, 2009.

    
                                                          Three Months Ended
                                                               March 31
                                                          2009          2008
    -------------------------------------------------------------------------
    FINANCIAL
    (Cdn$ millions, except per unit
     and per boe amounts)
    Revenue before royalties                             225.2         407.9
      Per unit(1)                                         0.98          1.91
      Per boe                                            38.57         66.94
    Cash flow from operating activities(2)               124.3         209.9
      Per unit(1)                                         0.54          0.98
      Per boe                                            21.29         34.44
    Net income                                            22.3          81.3
      Per unit(3)                                         0.10          0.39
    Distributions                                         82.0         126.8
      Per unit(1)                                         0.36          0.60
      Per cent of cash flow from operating
       activities(2)                                        66            60
    Net debt outstanding(4)                              781.5         770.1
    OPERATING
    Production
      Crude oil (bbl/d)                                 28,806        29,064
      Natural gas (mmcf/d)                               193.8         204.3
      Natural gas liquids (bbl/d)                        3,764         3,856
      Total (boe/d)                                     64,872        66,976
    Average prices
      Crude oil ($/bbl)                                  46.44         89.72
      Natural gas ($/mcf)                                 5.20          7.80
      Natural gas liquids ($/bbl)                        38.86         68.54
      Oil equivalent ($/boe)                             38.40         66.67
    Operating netback ($/boe)
      Commodity and other revenue (before hedging)(5)    38.57         66.94
      Transportation costs                               (0.95)        (0.73)
      Royalties                                          (6.34)       (11.85)
      Operating costs                                   (10.12)        (9.55)
      Netback (before hedging)                           21.16         44.81
    -------------------------------------------------------------------------
    TRUST UNITS
    (millions)
    Units outstanding, end of period(6)                  236.0         214.7
    Weighted average trust units(7)                      228.9         213.8
    -------------------------------------------------------------------------
    TRUST UNIT TRADING STATISTICS
    (Cdn$, except volumes) based on intra-day trading
    High                                                 20.90         27.06
    Low                                                  11.73         20.00
    Close                                                14.15         26.38
    Average daily volume (thousands)                     1,240           863
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares. Per unit distributions are based on
        the number of trust units outstanding at each distribution record
        date.
    (2) Cash flow from operating activities is a GAAP measure. Historically,
        management has disclosed Cash Flow as a non-GAAP measure calculated
        using cash flow from operating activities less the change in non-cash
        working capital and the expenditures on site restoration and
        reclamation as they appear on the Consolidated Statements of Cash
        Flows. Cash Flow for the first quarter of 2009 would be
        $116.6 million ($0.51 per unit). Distributions as a percentage of
        Cash Flow would be 70 per cent for the first quarter of 2009. Please
        refer to the non-GAAP measures section in the MD&A for further
        details.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Net debt excludes current unrealized amounts pertaining to risk
        management contracts and the current portion of future income taxes.
    (5) Includes other revenue.
    (6) For the first quarter of 2009, includes 0.9 million (1.2 million in
        2008) exchangeable shares exchangeable into 2.577 trust units (2.314
        in 2008) each for an aggregate 2.4 million (2.7 million in 2008)
        trust units.
    (7) Includes trust units issuable for outstanding exchangeable shares at
        period end.


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

    -   The Trust completed an equity offering of 15.5 million trust units at
        $16.35 per unit for net proceeds of $240 million during the quarter.
        Proceeds of the offering were applied against the Trust's debt
        resulting in a net debt balance of $781.5 million at March 31, 2009,
        a reduction of $180.4 million from year end.

    -   On April 14, 2009, the Trust announced the closing of a private
        placement of long-term debt in the form of senior secured notes
        totaling US$125 million at a blended average interest rate of 7.47
        per cent. The notes were offered in three tranches with repayment
        dates between 2012 and 2021 allowing the Trust to convert a portion
        of its credit facility debt to long term notes that mature over a
        number of years as opposed to being re-financed all in one year.
        Proceeds from the notes were used to reduce the debt outstanding on
        the Trust's $800 million credit facility to $356 million, providing
        the Trust with $444 million of undrawn debt capacity on the bank
        line. The Trust also has $167 million available to it through the
        undrawn portion of a shelf facility with a large insurance company.

    -   The Trust executed a $97.2 million capital expenditure program in the
        first quarter of 2009 that included drilling 81 gross wells on
        operated properties, resulting in 14 oil wells, 66 natural gas wells
        and a 99 per cent success rate. Of the 81 wells drilled in the first
        quarter, the Trust currently has 33 wells waiting on tie-in, of which
        24 wells are awaiting completion. The capital expenditures were
        64 per cent funded by cash flow from operating activities and
        proceeds from the DRIP program and the remaining portion was funded
        through debt.

    -   Production for the quarter was on budget at 64,872 boe per day with
        record production at Dawson and Ante Creek. With the reduction in the
        2009 capital budget, the Trust now expects full year production to
        average between 62,000 and 64,000 boe per day at an operating cost of
        approximately $10.70 per boe.

    -   In light of the weak commodity price environment, particularly
        for natural gas, the monthly distribution has been decreased to
        $0.10 per unit effective with the May distribution payable on
        June 15, 2009. The Board has also approved a reduced capital
        expenditure budget for the Trust of $350 million while affirming its
        commitment to the construction of a 60 mmcf per day gas plant to be
        completed late in the first quarter of 2010 for the Dawson field
        contingent on the timely receipt of regulatory approvals.

    -   The Trust's current plans are to convert to a dividend paying
        Corporation effective December 31, 2010. At this time,
        management believes that this will be most logical and tax efficient
        alternative for ARC unitholders. The potential conversion will be
        subject to regulatory and unitholder approval.

    -   Montney Resource Play Development

        During the first quarter of 2009, the Trust spent $36.3 million on
        development activities in the Dawson area including the drilling of
        five horizontal wells, two of which were completed and tested during
        the quarter. Vertical wells were also drilled at Sundown and Pouce
        Coupe.

        With the completion of a third party compressor in the middle of
        February, total production from the Dawson area grew to an average of
        51.2 mmcf per day in the first quarter of 2009 and exited the quarter
        at approximately 56 mmcf per day.

        The Trust continues to work towards a late first quarter 2010
        completion date for a new 60 mmcf per day gas plant for Dawson.
        Design work is complete, long-lead time items have been ordered and
        the public notification has been completed. Applications have
        been submitted to the appropriate regulatory agencies and are
        currently under review.

    -   Enhanced Oil Recovery Initiatives

        During the first quarter, the Trust spent $7 million on enhanced oil
        recovery ("EOR") initiatives. The Redwater CO(2) pilot project is
        well underway and on schedule with the highlight of the quarter being
        the start-up of the associated production facility. The Trust
        expects that it will take at least until 2010 before it will
        know to what extent the pilot has been successful in increasing oil
        production. While the pilot project may indicate enhanced recovery,
        the current outlook for crude oil prices and the cost and
        availability of CO(2) may hinder the Trust's ability to achieve
        commercial viability for a full scale EOR scheme.


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

    This management's discussion and analysis ("MD&A") is the Trust
management's analysis of its financial performance and significant trends or
external factors that may affect future performance. It is dated May 5, 2009
and should be read in conjunction with the unaudited Consolidated Financial
Statements for the period ended March 31, 2009 and the audited Consolidated
Financial Statements and MD&A as at and for the year ended December 31, 2008
as well as the Trust's Annual Information Form that is filed on SEDAR at
www.sedar.com.
    The MD&A contains Non-GAAP measures and forward-looking statements and
readers are cautioned that the MD&A should be read in conjunction with the
Trust's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements"
included at the end of this MD&A.

    Executive Overview

    ARC Energy Trust ("ARC") is one of the top 20 producers of conventional
oil and gas in western Canada. As at March 31, 2009, ARC held interests in
excess of 18,600 wells with approximately 5,600 wells operated by ARC and the
remainder operated primarily by other major oil and gas companies. ARC's
production has averaged between 61,000 and 67,000 boe per day in each quarter
for the last three years. The total capitalization of ARC, which trades on the
Toronto Stock Exchange, as at March 31, 2009 was $4.1 billion as shown on
Table 22.
    ARC's objective as an energy company is to provide superior and
sustainable long-term returns to unitholders. Key attributes of the business
plan include:

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

    -   Pay a portion of cash flow to unitholders. Currently the Trust
        distributes $0.12 per unit per month but due to current oil and
        natural gas prices the distribution amount has been decreased to
        $0.10 per unit per month starting with the May distribution to be
        paid on June 15, 2009. The remainder of the cash flow is used to fund
        reclamation costs, and a portion of capital expenditures and land
        acquisitions. Since the Trust's inception in July 1996 to March 31,
        2009, the Trust has distributed $3.3 billion or $24.06 per unit.

    -   Declining commodity prices have caused management to defer some
        2009 capital projects to future periods resulting in a reduced
        capital budget of $350 million for 2009. A key focus is to
        construct a gas plant at Dawson and expand production from the
        Montney. Approximately half of ARC's $350 million capital program
        will support this key initiative. The remaining capital is targeted
        at key assets across western Canada. Calculated on a boe basis,
        normalized production per thousand units has decreased slightly from
        0.30 to 0.27 while the Trust has made distributions of $5.43 per
        unit or $1.15 billion from January 1, 2007 through to March 31, 2009.
        Details of the calculations for normalized production and reserves
        per unit are provided in Table 1.

    -   The periodic acquisition of strategic producing and undeveloped
        properties to enhance current production or provide the potential for
        future drilling locations and if successful, additional production
        and reserves.

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

    -   Operational excellence for both routine operating expenditures and
        costs incurred for capital projects. In the current environment ARC
        is aggressively pursuing cost reductions throughout the business. ARC
        expects that the aggregate amount of operating costs will increase
        over time as ARC adds approximately 300 wells per year to its
        operating base to replace the natural decline on existing producing
        wells.

    ARC's business plan and operating practices also include the following
strategies and action plans that are being undertaken to increase ARC's
competitiveness and future profitability:

    -   Continual development of staff expertise and the hiring and retention
        of some of the industry's best and most qualified personnel.

    -   Building relationships with suppliers, joint venture partners,
        government and other stakeholders and conducting business in a fair
        and equitable manner.

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

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

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

    -   Actively supporting local initiatives and charities in the
        communities in which the Trust's employees live and work.


    Table 1
    -------------------------------------------------------------------------
                                                 First
                                               quarter  Full year  Full year
    Per Trust Unit                                2009       2008       2007
    -------------------------------------------------------------------------
    Normalized production per unit(1)(2)          0.27       0.29       0.30
    Normalized reserves per unit(1)(3)             n/a       1.42       1.35
    Distributions per unit                       $0.36      $2.67      $2.40
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Normalized indicates that all years as presented have been adjusted
        to reflect a net debt to capitalization of 15 per cent. It is assumed
        that additional trust units were issued (or repurchased) at a period
        end price for the reserves per unit calculation and at an annual
        average price for the production per unit calculation in order to
        achieve a net debt balance of 15 per cent of total capitalization
        each year. The normalized amounts are presented to enable
        comparability of annual per unit values.
    (2) Production per unit represents daily average production (boe) per
        thousand trust units. Calculated based on daily average production
        divided by the normalized weighted average trust units outstanding
        including trust units issuable for exchangeable shares.
    (3) Reserves per unit are calculated based on proved plus probable
        reserves (boe) divided by period end trust units outstanding
        including trust units issuable for exchangeable shares.


    ARC's business plan has achieved significant operational success. However,
commodity prices and the current economic crisis are significant factors
determining profitability of ARC and capital appreciation of our trust units
in the market place. The negative impact of external factors has led to a
negative return for the trailing one and three years despite the successful
execution of ARC's business plan and operational successes.

    Table 2
    -------------------------------------------------------------------------
    Total Returns(1)                        Trailing    Trailing    Trailing
    ($ per unit except for per cent)        One Year  Three Year   Five Year
    -------------------------------------------------------------------------
    Distributions per unit                $     2.63  $     7.23  $    11.17
    Capital appreciation per unit         $   (12.23) $   (13.21) $    (1.49)
    Total return per unit                 $    (9.60) $    (5.98) $     9.68
    Annualized total return per unit          (40.2)%     (10.9)%       8.6%
    S&P/TSX Capped Energy Trust Index         (40.8)%     (15.0)%       5.2%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Calculated as at March 31, 2009.


    2009 Guidance

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

    Table 3
    -------------------------------------------------------------------------
                                               2009
                                             Actual       %     2009 Revised
                             2009 Guidance      YTD   Change        Guidance
    -------------------------------------------------------------------------
    Production (boe/d)       64,000-65,000   64,872        -   62,000-64,000
    -------------------------------------------------------------------------
    Expenses ($/boe):
      Operating costs                10.70    10.12       (5)          10.70
      Transportation                  1.15     0.95      (17)           1.00
      G&A expenses
       (cash & non-cash)              2.80     0.88      (69)           2.10
      Interest                        1.85     0.99      (46)           1.30
    Capital expenditures
     ($ millions)                      450     97.2        -             350
    Annual weighted average
     trust units and trust
     units issuable (millions)         235      229       (3)            238
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The 2009 Guidance provides unitholders with information on management's
expectations for results of operations for 2009. Readers are cautioned that
the 2009 Guidance may not be appropriate for other purposes.
    The following revisions have been made to the Trust's 2009 guidance.

    -   Production levels have been revised as a result of the Trust's
        reduction in capital expenditures discussed below. The Trust now
        expects that 2009 full year production will be in the range of 62,000
        to 64,000 boe per day. Production guidance numbers for 2010 are under
        review and will change due to the impact of decreased capital
        expenditures in 2009 and the current uncertainty with regards to
        capital plans for 2010.

    -   Transportation expenses have been revised downward to $1.00 per boe.
        Initial guidance was based on expectations of increased oil
        transportation charges resulting from apportionment on the main
        Enbridge pipeline as well as reduced capacity on the Saskatchewan
        Enbridge pipeline. These restrictions have not materialized year-to-
        date and therefore the Trust has re-forecast full year transportation
        expense to be approximately $1.00 per boe.

    -   G&A expenses are expected to decrease to $2.10 per boe most
        significantly as a result of a decrease in the costs for the Trust's
        Whole Unit Plan. The cash whole unit plan expense is expected to
        decrease from $0.85 per boe to $0.55 per boe based on the reduction
        of the trust unit price and distributions in 2009. The non-cash whole
        unit plan expense is expected to decrease from an expense of $0.15
        per boe to a recovery of $0.20 per boe as the cash payout in March
        2009 was based on an actual price of $12.18 per unit as compared to
        the $20.10 that was accrued for this payment at year-end 2008. Cash
        G&A costs, excluding the whole unit plan expense for the full year
        2009 are expected to decrease to $1.75 from $1.80 as a result of a
        reduction in variable compensation costs.

    -   Interest expense has been revised downward to reflect the lower
        interest rates on the Trust's floating rate debt as well as the
        Trust's lower debt balance subsequent to the equity offering
        completed in February 2009. These amounts will be partially offset by
        higher interest rates on the Trust's new senior secured long-term
        notes issued in April 2009 that have a blended average interest rate
        of 7.47 per cent. See Capitalization, Financial Resources and
        Liquidity section of this MD&A for details.

    -   Capital Expenditures have been revised downward to $350 million from
        the previous guidance of $450 million. The Trust has re-evaluated all
        capital projects in light of the ongoing challenges with low
        commodity prices. The key focus for the 2009 capital program remains
        in the Montney area.  For the full year 2009, the Trust plans to
        drill 122 gross wells on operated properties as compared to 191
        gross wells that were planned under the $450 million capital
        expenditure guidance. Items that have been deferred until 2010
        include a 75 well shallow gas drilling program in the Brooks area,
        three horizontal wells in the Redwater area and four horizontal
        wells and two vertical wells in the Dawson area. The Trust is
        anticipating potential cost savings on the planned capital
        expenditures for the remainder of 2009 which, if realized, may
        create an opportunity to fund additional strategic projects. In
        addition, the Trust is currently evaluating the Alberta government's
        corporate royalty drilling credit program that was announced on
        March 3, 2009 in order to assess the viability of additional capital
        programs using the revised royalty rates.


    2009 First Quarter Financial and Operational Results

    Following is a discussion of ARC's 2009 first quarter financial and
operating results.

    Financial Highlights

    Table 4
    -------------------------------------------------------------------------
                                                 Three Months Ended March 31
    -------------------------------------------------------------------------
    (Cdn $ millions, except
     per unit and volume data)                    2009       2008   % Change
    -------------------------------------------------------------------------
    Cash flow from operating activities          124.3      209.9        (41)
    Cash flow from operating activities
     per unit(1)                                  0.54       0.98        (45)
    Net income                                    22.3       81.3        (73)
    Net income per unit(2)                        0.10       0.39        (74)
    Distributions per unit(3)                     0.36       0.60        (40)
    Distributions as a per cent of cash
     flow from operating activities                 66         60         10
    Average daily production (boe/d)(4)         64,872     66,976         (3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Per unit amounts are based on weighted average trust units
        outstanding plus trust units issuable for exchangeable shares at
        year-end.
    (2) Based on net income after non-controlling interest divided by
        weighted average trust units outstanding excluding trust units
        issuable for exchangeable shares.
    (3) Based on number of trust units outstanding at each cash distribution
        date.
    (4) Reported production amount is based on company interest before
        royalty burdens. Where applicable in this MD&A natural gas has been
        converted to barrels of oil equivalent ("boe") based on 6 mcf: 1 bbl.
        The boe rate is based on an energy equivalent conversion method
        primarily applicable at the burner tip and does not represent a value
        equivalent at the well head. Use of boe in isolation may be
        misleading.


    Net Income

    As a result of decreased commodity prices, the Trust's net income and cash
flows were negatively impacted during the first quarter. Net income in the
first quarter of 2009 was $22.3 million ($0.10 per unit), a decrease of $59
million from $81.3 million ($0.39 per unit) in the first quarter of 2008. The
decrease in net income is largely attributed to the $85.6 million decrease in
cash flow from operating activities from the first quarter of 2008 (see Table
6 for details), along with the following non-cash items:

    -   The Trust recorded a $12.1 million non-cash recovery for its long-
        term incentive whole unit plan that increased net income in the first
        quarter of 2009 compared to an expense of $13.8 million for the same
        period of 2008. (See - General and Administrative Expenses and Trust
        Unit Incentive Compensation for details)

    -   The Trust recorded a future income tax recovery of $12.2 million that
        increased net income in the first quarter of 2009 compared to a
        future tax expense of $0.5 million for the first quarter of 2008.

    -   The Trust recorded a $6.6 million non-cash loss on risk management
        contracts in the first quarter of 2009 compared to a loss of
        $18.7 million recorded in the same period of 2008. (See - Risk
        Management and Hedging Activities for details).
    

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

    
    Table 5
    -------------------------------------------------------------------------
                                                 First
    Net income and Distributions               quarter  Full year  Full year
    ($ millions except per cent)                  2009       2008       2007
    -------------------------------------------------------------------------
    Net income                                    22.3      533.0      495.3
    Distributions                                 82.0      570.0      498.0
    -------------------------------------------------------------------------
    Excess (Shortfall)                           (59.7)     (37.0)      (2.7)
    Excess (Shortfall) as per cent
     of net income                               (268%)       (7%)       (1%)
    -------------------------------------------------------------------------
    Cash flow from operating activities          124.3      944.4      704.9
    Distributions as a per cent of cash
     flow from operating activities                66%        60%        71%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash Flow from Operating Activities

    Cash flow from operating activities decreased by 41 per cent in the first
quarter of 2009 to $124.3 million from $209.9 million in the first quarter of
2008. The decrease in 2009 cash flow from operating activities is detailed in
Table 6.

    Table 6
    -------------------------------------------------------------------------
                                                           ($ per
                                                            trust         (%
                                           ($ millions)      unit)  variance)
    -------------------------------------------------------------------------
    Q1 2008 Cash flow from Operating
     Activities                                  209.9       0.98          -
    -------------------------------------------------------------------------
    Volume variance                              (17.2)     (0.08)        (8)
    Price variance                              (165.3)     (0.76)       (79)
    Cash (losses) and gains on
     risk management contracts                    45.8       0.21         22
    Royalties                                     35.2       0.16         17
    Expenses:
      Transportation                              (1.2)     (0.01)        (1)
      Operating(1)                                (4.1)     (0.02)        (2)
      Cash G&A                                    (6.7)     (0.03)        (3)
      Interest                                     3.0       0.01          1
      Realized foreign exchange loss              (0.2)         -          -
    Weighted average trust units                     -      (0.04)         -
    Non-cash and other items(2)                   25.1       0.12         12
    -------------------------------------------------------------------------
    Q1 2009 Cash flow from Operating
     Activities                                  124.3       0.54        (41)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excludes non-cash portion of Whole Unit Plan expense recorded in
        operating costs.
    (2) Includes the changes in non-cash working capital and expenditures on
        site restoration and reclamation.


    2009 Cash Flow from Operating Activities Sensitivity

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

    Table 7
    -------------------------------------------------------------------------
                                                  Impact on Annual
                                       Cash flow from operating activities(2)
    -------------------------------------------------------------------------
    Business Environment                  Assumption      Change      $/Unit
    -------------------------------------------------------------------------
    Oil price (US$WTI/bbl)(1)             $    50.00  $     1.00  $     0.04
    Natural gas price (Cdn $AECO/mcf)(1)  $     4.80  $     0.10  $     0.02
    Cdn$/US$ exchange rate                      1.20  $     0.01  $     0.02
    Interest rate on debt                 %     3.95  %      1.0  $     0.02
    Operational
    Liquids production volume (bbl/d)         31,500  %      1.0  $     0.02
    Gas production volumes (mmcf/d)            189.0  %      1.0  $     0.01
    Operating expenses per boe            $    10.70  %      1.0  $     0.01
    Cash G&A and LTIP expenses per boe    $     2.30  %     10.0  $     0.02
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Analysis does not include the effect of hedging contracts.
    (2) Assumes constant working capital.
    

    Production

    Production volumes averaged 64,872 boe per day in the first quarter of
2009 compared to 66,976 boe per day in the same period of 2008 as detailed in
Table 8. In the first quarter of 2008, the Trust recorded a 1,000 boe per day
natural gas volume adjustment due to prior period measurement errors at the
Ante Creek property made by the facility operator. In the first quarter of
2009, the Trust has posted record production in the Ante Creek and Dawson
areas helping to offset declines in shallow gas production in southeast
Alberta and southwest Saskatchewan. New production in the Delburne area from
the Trust's natural gas from coal drilling program was also realized in the
first quarter of 2009.

    
    Table 8
    -------------------------------------------------------------------------
                                                 Three Months Ended March 31
    -------------------------------------------------------------------------
    Production                                    2009       2008   % Change
    -------------------------------------------------------------------------
    Light & medium crude oil (bbl/d)            27,720     27,718          -
    Heavy oil (bbl/d)                            1,086      1,346        (19)
    Natural gas (mmcf/d)                         193.8      204.3         (5)
    NGL (bbl/d)                                  3,764      3,856         (2)
    -------------------------------------------------------------------------
    Total production (boe/d)(1)                 64,872     66,976         (3)
    % Natural gas production                        50         51         (2)
    % Crude oil and liquids production              50         49          2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Reported production for a period may include minor adjustments from
        previous production periods.
    

    Light and medium crude oil production remained constant at 27,720 boe per
day compared to 27,718 boe per day in 2008, while heavy oil production
declined by 19 per cent. Natural gas production was 193.8 mmcf per day in the
first quarter of 2009, a decrease of five per cent from the 204.3 mmcf per day
produced in the first quarter of 2008.
    The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During the first quarter of 2009, the Trust
drilled 81 gross wells (57 net wells) on operated properties; 14 gross oil
wells, and 66 gross natural gas wells with a 99 per cent success rate.
    The Trust expects that 2009 full year production will be approximately
62,000 to 64,000 boe per day and that 122 gross wells (101 net wells) will be
drilled by ARC on operated properties with participation in an additional 54
gross wells to be drilled on the Trust's non-operated properties. The Trust
estimates that the revised 2009 drilling program will add sufficient
production from new wells to offset the majority of production declines on
existing properties, however, overall production is expected to decrease by
2,000 to 3,000 boe per day. The planned capital expenditures are being
continuously monitored in the context of the current economic environment and
will be revised as required.
    Table 9 summarizes the Trust's production by core area:

    
    Table 9
    -------------------------------------------------------------------------
                                        Three Months Ended March 31, 2009
    -------------------------------------------------------------------------
    Production                        Total        Oil        Gas        NGL
    Core Area(1)                     (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
    -------------------------------------------------------------------------
    Central AB                        7,127      1,390       27.7      1,116
    N.E. BC & N.W. AB                13,619        754       73.4        629
    Northern AB                       9,493      4,353       25.4        907
    Pembina & Redwater               13,798      9,648       19.1        972
    S.E. AB & S.W. Sask.              8,789        994       46.7         15
    S.E. Sask. & MB                  12,046     11,667        1.5        125
    -------------------------------------------------------------------------
    Total                            64,872     28,806      193.8      3,764
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                        Three Months Ended March 31, 2008
    -------------------------------------------------------------------------
    Production                        Total        Oil        Gas        NGL
    Core Area(1)                     (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
    -------------------------------------------------------------------------
    Central AB                        7,770      1,460       30.3      1,263
    N.E. BC & N.W. AB                12,842        852       68.2        626
    Northern AB                      10,632      5,054       28.2        874
    Pembina & Redwater               13,998      9,460       21.6        938
    S.E. AB & S.W. Sask.             10,041        985       54.2         16
    S.E. Sask. & MB                  11,693     11,253        1.8        139
    -------------------------------------------------------------------------
    Total                            66,976     29,064      204.3      3,856
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
        is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is
        northwest, S.E. is southeast and S.W. is southwest.
    

    Revenue

    Revenue decreased to $225.2 million in the first quarter of 2009, $182.7
million lower than 2008 revenues of $407.9 million. While oil volumes were
relatively unchanged year over year, the decrease in realized oil prices
accounted for a $116.9 million decrease in revenues. Natural gas revenue
decreased by $54.4 million, comprising a $48.4 million decrease due to lower
prices realized in 2009 and a $6 million decrease due to lower volumes
produced in 2009.
    A breakdown of revenue is outlined in Table 10:

    
    Table 10
    -------------------------------------------------------------------------
    Revenue                                      Three Months Ended March 31
    ($ millions)                                  2009       2008   % Change
    -------------------------------------------------------------------------
    Oil revenue                                  120.4      237.3        (49)
    Natural gas revenue                           90.6      145.0        (38)
    NGL revenue                                   13.2       24.1        (45)
    -------------------------------------------------------------------------
    Total commodity revenue                      224.2      406.4        (45)
    Other revenue                                  1.0        1.5        (33)
    Total revenue                                225.2      407.9        (45)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Commodity Prices Prior to Hedging

    Table 11
    -------------------------------------------------------------------------
                                                 Three Months Ended March 31
    -------------------------------------------------------------------------
                                                  2009       2008   % Change
    -------------------------------------------------------------------------
    Average Benchmark Prices
    AECO gas ($/mcf)(1)                           5.64       7.13        (21)
    WTI oil (US$/bbl)(2)                         43.21      97.96        (56)
    Cdn$/US$ foreign exchange rate                1.25       1.01         24
    WTI oil (Cdn$/bbl)                           53.85      97.34        (45)
    -------------------------------------------------------------------------
    ARC Realized Prices Prior to Hedging
    Oil ($/bbl)                                  46.44      89.72        (48)
    Natural gas ($/mcf)                           5.20       7.80        (33)
    NGL ($/bbl)                                  38.86      68.54        (43)
    -------------------------------------------------------------------------
    Total commodity revenue before
     hedging ($/boe)                             38.40      66.67        (42)
    Other revenue ($/boe)                         0.17       0.27        (37)
    Total revenue before hedging ($/boe)         38.57      66.94        (42)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents the AECO monthly posting.
    (2) WTI represents West Texas Intermediate posting as denominated in US$.
    

    The sharp decline in oil prices during the fourth quarter of 2008
continued into the first quarter of 2009. US$WTI prices averaged $43.21
throughout the first quarter of 2009, a 56 per cent decrease from the
comparable period in 2008. This dramatic decrease was partially offset by the
weakening of the Canadian dollar compared to the U.S. dollar, however,
widening of the price differentials for the first part of the quarter further
eroded the Trust's realized oil price. The Trust's oil production consists
predominantly of light and medium crude oil while heavy oil accounts for less
than five per cent of the Trust's crude oil production. The realized price for
the Trust's oil, before hedging, was $46.44 per boe, a 48 per cent reduction
over the first quarter 2008 realized price of $89.72 per boe.
    Alberta AECO Hub natural gas prices, which are commonly used as an
industry reference, averaged $5.64 per mcf in the first quarter of 2009
compared to $7.13 per mcf in the same period of 2008. ARC's realized gas
price, before hedging, decreased by 33 per cent to $5.20 per mcf compared to
$7.80 per mcf in the first quarter of 2008. ARC's realized gas price is based
on prices received at the various markets in which the Trust sells its natural
gas. ARC's natural gas sales portfolio consists of gas sales priced at the
AECO monthly index, the AECO daily spot market, eastern and mid-west United
States markets and a portion to aggregators. While natural gas prices softened
in the first quarter of 2009 compared to the fourth quarter of 2008, prices
have continued to decline in the second quarter with posted prices at
approximately $3.30 per mcf for the month of April with no improvement
expected in the near term as a result of record storage volumes and concern
over the state of the North American economy. Unitholders should expect
further deterioration in natural gas revenue in the second quarter and likely
into the third quarter.
    Prior to hedging activities, ARC's total realized commodity price was
$38.40 per boe in the first quarter of 2009, a 42 per cent decrease from the
$66.67 per boe received prior to hedging in the first quarter of 2008.

    Risk Management and Hedging Activities

    ARC maintains an ongoing risk management program to reduce the volatility
of revenues in order to increase the certainty of distributions, protect
acquisition economics, and fund capital expenditures.
    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.
    Lower natural gas prices in the first quarter of 2009 resulted in
realized cash gains of $13.5 million on natural gas risk management contracts.
Realized cash losses of $1.9 million were recorded on the Trust's crude oil
risk management contracts as a result of premiums paid in the first quarter of
2009.
    During the first quarter of 2009 the Trust realized a cash gain of $4.5
million due to the unwinding of an interest rate swap risk management contract
that converted a portion of the Trust's fixed rate debt to floating rate debt.
    ARC's first quarter 2009 results include an unrealized total
mark-to-market loss of $6.6 million with a net unrealized mark-to-market loss
position of $3.1 million as at March 31, 2009. The net loss position is mostly
attributed to losses on the Trust's power and interest contracts. The
mark-to-market values represent the market price to buy-out the Trust's
contracts as of March 31, 2009 and may differ from what will eventually be
realized.
    Table 12 summarizes the total gain (loss) on risk management contracts
for the year-over-year change as of the first quarter of 2009:

    
    Table 12
    -------------------------------------------------------------------------
    Risk Management Contracts     Crude Oil    Natural    Foreign
     ($ millions)                 & Liquids        Gas   Currency    Power(3)
    -------------------------------------------------------------------------
    Realized cash (loss) gain
     on contracts(1)                   (1.9)      13.5          -       (0.1)
    Unrealized (loss) gain
     on contracts(2)                   (0.4)       3.5          -       (4.2)
    -------------------------------------------------------------------------
    Total (loss) gain on risk
     management contracts              (2.3)      17.0          -       (4.3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    --------------------------------------------------------------
    Risk Management Contracts                  Q1 2009    Q1 2008
     ($ millions)                  Interest      Total      Total
    --------------------------------------------------------------
    Realized cash (loss) gain
     on contracts(1)                    4.8       16.3      (29.5)
    Unrealized (loss) gain
     on contracts(2)                   (5.5)      (6.6)     (18.7)
    --------------------------------------------------------------
    Total (loss) gain on risk
     management contracts              (0.7)       9.7      (48.2)
    --------------------------------------------------------------
    --------------------------------------------------------------
    (1) Realized cash gains and losses represent actual cash settlements or
        receipts under the respective contracts.
    (2) The unrealized (loss) gain on contracts represents the change in fair
        value of the contracts during the period.
    (3) Amounts presented in Table 12 exclude a $0.1 million realized gain
        and an unrealized loss of $3 million for the Trust's power contracts
        that have been designated as effective hedges for accounting
        purposes. Realized gains and losses on these contracts are recorded
        in operating costs and unrealized gains and losses are recorded in
        the Consolidated Statement of Comprehensive Income and Accumulated
        Other Comprehensive Income.


    The Trust currently limits the amount of forecast production that can be
hedged to a maximum 50 per cent with the remaining 50 per cent of production
being sold at market prices. The following table is an indicative summary of
the Trust's positions for crude oil and natural gas as at March 31, 2009.

    Table 13
    -------------------------------------------------------------------------
    Hedge Positions
    As at March 31, 2009(1)(2)
                                          Q2 2009               Q3 2009
    -------------------------------------------------------------------------
    Crude Oil                       US$/bbl    bbl/day    US$/bbl    bbl/day
    -------------------------------------------------------------------------
    Sold Call                             -          -          -          -
    Bought Put                        55.00      2,500      55.00      2,500
    Sold Put                          40.00      2,500      40.00      2,500
    -------------------------------------------------------------------------
    Natural Gas                     Cdn$/GJ     GJ/day    Cdn$/GJ     GJ/day
    -------------------------------------------------------------------------
    Sold Call                          6.50     40,000       6.50     40,000
    Bought Put                         5.38     40,000       5.38     40,000
    Sold Put                           4.50     20,000       4.50     20,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Hedge Positions
    As at March 31, 2009(1)(2)
                                          Q4 2009                2010
    -------------------------------------------------------------------------
    Crude Oil                       US$/bbl    bbl/day    US$/bbl    bbl/day
    -------------------------------------------------------------------------
    Sold Call                             -          -
    Bought Put                        55.00      2,500    No hedges in place
    Sold Put                          40.00      2,500
    -------------------------------------------------------------------------
    Natural Gas                     Cdn$/GJ     GJ/day    Cdn$/GJ     GJ/day
    -------------------------------------------------------------------------
    Sold Call                          7.24     26,739
    Bought Put                         5.93     26,739    No hedges in place
    Sold Put                           4.50     20,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The prices and volumes noted above represents averages for several
        contracts and the average price for the portfolio of options listed
        above does not have the same payoff profile as the individual option
        contracts. Viewing the average price of a group of options is purely
        for indicative purposes. The natural gas price shown translates all
        NYMEX positions to an AECO equivalent price.
    (2) In addition to positions shown here, ARC has entered into additional
        basis positions until October 2012, an energy equivalent swap until
        December 31, 2009, as well as a fixed price swap for crude oil for
        the month of April 2009. Please refer to note 9 in the Notes to the
        Consolidated Financial Statements for full details of the Trust's
        risk management positions as of March 31, 2009.


    Table 13 should be interpreted as follows using the second quarter 2009
natural gas hedges as an example. To accurately analyze the Trust's hedge
position, contracts need to be modeled separately as using average prices and
volumes may be misleading.

    -   If the market price is below $4.50, ARC will receive $5.38 less the
        difference between $4.50 and the market price on 20,000 GJ per day.
        For example if the market price is $4.45, the Trust will receive
        $5.33 on 20,000 GJ per day.
    -   If the market price is between $4.50 and $5.38, ARC will receive
        $5.38 on 40,000 GJ per day.
    -   If the market price is between $5.38 and $6.50, ARC will receive the
        market price on 40,000 GJ per day.
    -   If the market price exceeds $6.50, ARC will receive $6.50 on
        40,000 GJ per day.
    

    Operating Netbacks

    The Trust's operating netback, before realized hedging gains and losses,
decreased 53 per cent to $21.16 per boe in the first quarter of 2009 compared
to $44.81 per boe in same period of 2008. The decrease in netbacks is due most
significantly to the reduced commodity prices in the period as well as higher
operating costs and transportation costs and was partially offset by lower
royalties corresponding to the lower commodity prices.
    The Trust's first quarter 2009 netback, after realized hedging gains and
losses, was $23.13 per boe, a 45 per cent decrease from the same period in
2008. The 2009 netback includes net gains recorded on the Trust's crude oil
and natural gas contracts during the quarter of $1.79 per boe compared to a
net loss of $2.63 per boe recorded for the same period in 2008.
    The components of operating netbacks are summarized in Table 14:

    
    Table 14
    -------------------------------------------------------------------------
                                   Heavy                    Q1 2009  Q1 2008
    Netbacks          Crude Oil      Oil      Gas      NGL    Total    Total
    ($ per boe)          ($/bbl)  ($/bbl)  ($/mcf)  ($/bbl)  ($/boe)  ($/boe)
    -------------------------------------------------------------------------
    Weighted average
     sales price          46.76    38.11     5.20    38.86    38.40    66.67
    Other revenue             -        -        -        -     0.17     0.27
    -------------------------------------------------------------------------
    Total revenue         46.76    38.11     5.20    38.86    38.57    66.94
    Royalties             (6.95)   (2.73)   (0.85)  (13.47)   (6.34)  (11.85)
    Transportation        (0.18)   (1.50)   (0.28)       -    (0.95)   (0.73)
    Operating costs(1)   (12.74)  (16.03)   (1.30)   (8.01)  (10.12)   (9.55)
    -------------------------------------------------------------------------
    Netback prior to
     hedging              26.89    17.85     2.77    17.38    21.16    44.81
    Realized gain (loss)
     on risk management
     contracts            (0.76)       -     0.77        -     1.97    (2.63)
    -------------------------------------------------------------------------
    Netback after
     hedging              26.13    17.85     3.54    17.38    23.13    42.18
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Operating expenses are composed of direct costs incurred to operate
        oil and gas wells. A number of assumptions have been made in
        allocating these costs between oil, heavy oil, natural gas and
        natural gas liquids production.
    

    Royalties as a percentage of pre-hedged commodity revenue net of
transportation decreased to 17 per cent ($6.34 per boe) in the first quarter
of 2009 compared to 18 per cent ($11.85 per boe) in 2008. The Alberta
Government's New Royalty Framework ("Framework" or "NRF") was effective
January 1, 2009 which resulted in an overall decrease in the Trust's royalties
that was in line with management's expectations due to the low commodity price
environment. The Trust continues to evaluate the amendments to the new royalty
framework in order to determine the optimal elections that should be made by
the Trust. See Alberta Government New Royalty Framework.
    Operating costs increased to $10.12 per boe compared to $9.55 per boe in
the first quarter of 2008. Total operating costs increased $0.9 million, or
two per cent in the first quarter of 2009. There is a high fixed operating
cost component for the Trust's properties resulting in a trend of increased
operating costs on a per boe basis as production declines over time. The Trust
estimates that full year 2009 operating costs will be approximately $245
million or approximately $10.70 per boe based on annual production of
approximately 62,000 to 64,000 boe per day. This includes a six per cent
increase for costs associated with the increase in total operated wells in
2009 as compared to 2008.

    Alberta Government New Royalty Framework

    On April 10, 2008, the Alberta Government announced revisions to the
Framework that was legislated in November 2008 and took effect on January 1,
2009.
    The revisions to the Framework include the following:

    
    -   Increased royalty rates on conventional and non-conventional oil and
        natural gas production in Alberta whereby royalty rates may increase
        to a maximum rate of 50 per cent;

    -   Sliding scale royalty calculations based on a broader range of
        commodity prices whereby conventional oil and natural gas royalty
        rates may increase up to maximum prices of approximately Cdn$120 per
        barrel and Cdn$16 per GJ, respectively;

    -   The elimination of royalty incentive and royalty holiday programs
        with the exception of specific programs relating to deep oil and
        natural gas drilling programs, innovative technology and enhanced
        recovery programs;
    

    Subsequent to legislation of the NRF, the Alberta Government introduced
the Transitional Royalty Plan ("TRP") in response to the anticipated decrease
in Alberta development activity resulting from the economic downturn and
declining commodity prices. The TRP offers reduced royalty rates for new wells
drilled on or after November 19, 2008 through December 31, 2013 that meet
certain depth criteria. The TRP is in place for a maximum period of five years
to December 31, 2013; all wells will convert to the NRF on January 1, 2014.
The TRP is an "elective plan" whereby an election must be filed on an
individual well basis to qualify for the TRP. The Trust does not anticipate a
significant benefit from the TRP in 2009 as the majority of the Trust's wells
converted to the NRF on January 1, 2009.
    On March 3, 2009, the Alberta Government announced the Energy Incentive
Program ("EIP") in response to the decrease in energy related development
activity in the province. The incentive program will work in tandem with the
NRF and the TRP and includes the following key elements:

    
    -   Drilling Royalty Credit - producers will receive a drilling credit
        for new wells drilled between April 1, 2009 and March 31, 2010. The
        drilling credit is based on a $200 per meter credit on total meters
        drilled, however the maximum drilling credit is limited to
        10 per cent of 2008 Alberta Crown Royalties paid for companies
        producing greater than 25,000 boe per day in Alberta. ARC's estimated
        maximum total drilling credit would be approximately $15 million. The
        drilling credit will be applied to reduce Alberta Crown Royalties
        payable in 2009 and 2010.

    -   New Well Incentive Program - new production brought on-stream between
        April 1, 2009 and March 31, 2010 will qualify for a five per cent
        Alberta Crown Royalty rate for a period of 12 months subject to
        volume caps of 50,000 barrels of crown oil production and 150 Mmcf of
        crown natural gas production.
    

    Approximately 65 per cent of the Trust's production is in Alberta;
consequently, the Framework including the TRP and EIP will have a significant
impact on the Trust's Alberta and corporate royalty rates. The Trust has
completed an assessment of the Framework and has estimated that the Trust's
average corporate royalty rate will change from approximately 18 per cent of
revenue in 2008 to between 14 and 25 per cent of revenue in 2009 depending
upon commodity prices as illustrated in Table 15 and the value of incentives
realized in 2009.

    
    Table 15
    -------------------------------------------------------------------------
                    Royalty Rates - New Royalty Framework
    -------------------------------------------------------------------------
    Edmonton posted oil (Cdn$/bbl)(1)         $40      $60      $80     $100
    AECO natural gas (Cdn$/GJ)(1)              $4       $6       $8      $10
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Alberta royalty rate prior to NRF(2)    17.5%    17.5%    17.5%    17.5%
    NRF Alberta royalty rate before
     incentives(3)                          12.0%    18.0%    24.0%    29.0%
    NRF Alberta royalty after
     incentives(3)(4)                       10.0%    16.5%    22.5%    28.0%
    -------------------------------------------------------------------------
      Per cent increase (decrease)
       - Alberta royalty rate               (43)%     (6)%      29%      60%
    -------------------------------------------------------------------------
    Corporate royalty rate prior to NRF(2)  18.0%    18.0%    18.0%    18.0%
    NRF corporate royalty rate before
     incentives(3)                          15.0%    19.0%    23.0%    26.0%
    NRF corporate royalty rate after
     incentives(3)(4)                       14.0%    18.0%    22.0%    25.0%
    -------------------------------------------------------------------------
      Per cent increase (decrease)
       - Corporate royalty rate             (22)%       0%      22%      39%
    -------------------------------------------------------------------------
      Increase (decrease) in annual
       Corporate royalties ($Millions)     $(30.0)    $0.0    $55.0   $130.0
    -------------------------------------------------------------------------
      Increase (decrease) annual
       cash flow per unit                   $0.13    $0.00   $(0.23)  $(0.55)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Canadian dollar denominated prices before quality differentials.
    (2) Under the previous Alberta Crown Royalty regime, Alberta and
        Corporate royalty rates were consistent across all price scenarios as
        price ceilings were exceeded whereby royalty rates changed only
        marginally across the price scenarios presented.
    (3) Estimated royalty rates based on guidelines that are subject to
        interpretation. Royalty rate includes Crown, Freehold and Gross
        Overriding royalties for all jurisdictions in which the Trust
        operates.
    (4) Based on estimated incentives of $8 million in 2009 under the
        drilling credit program and assuming all wells drilled on Crown lands
        on or after April 1, 2009 will qualify for the five per cent new well
        incentive rate.
    

    General and Administrative Expenses and Trust Unit Incentive Compensation

    G&A net of overhead recoveries on operated properties increased 11 per
cent to $10.3 million in the first quarter of 2009 from $9.3 million in 2008.
Increases in G&A expenses for 2009 were a result of increased staff costs
based on a ten per cent increase in the G&A staff levels on average in the
first quarter of 2009 when compared to the same period in 2008.
    The Trust paid out $7.6 million under the Whole Trust Unit Incentive Plan
("Whole Unit Plan") in the first quarter of 2009 of which $5.6 million was
allocated to G&A with the remainder to operating costs and property, plant and
equipment. There were no cash payments made under the Whole Unit Plan in the
first quarter of 2008, the vesting date occurred in April and as such a $14.5
million cash expense was recorded in the second quarter financial results in
2008. The next cash payment under the Whole Unit Plan is scheduled to occur in
September 2009.
    Table 16 is a breakdown of G&A and trust unit incentive compensation
expense under the Whole Unit Plan:

    
    Table 16
    -------------------------------------------------------------------------
                                                 Three Months Ended March 31
    -------------------------------------------------------------------------
    G&A and Trust Unit Incentive
     Compensation Expense
    ($ millions except per boe)                   2009       2008   % Change
    -------------------------------------------------------------------------
    G&A expenses                                  14.7       13.2         11
    Operating recoveries                          (4.4)      (3.9)        13
    -------------------------------------------------------------------------
    Cash G&A expenses before Whole Unit Plan      10.3        9.3         11
    Cash Expense - Whole Unit Plan                 5.6          -        100
    -------------------------------------------------------------------------
    Cash G&A expenses including Whole Unit Plan   15.9        9.3         71
    -------------------------------------------------------------------------
    Accrued compensation - Whole Unit Plan       (10.8)      11.9       (191)
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense                          5.1       21.2        (76)
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense per boe                 0.87       3.47        (75)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    A non-cash trust unit incentive compensation recovery ("non-cash
compensation recovery") of $10.8 million ($1.85 per boe) was recorded in the
first quarter of 2009 compared to an expense of $11.9 million ($1.95 per boe)
in 2008. The recovery in 2009 relates in part to a reversal of the accrual for
the cash payment made in the quarter as well as a reduction in the liability
for the units outstanding at March 31, 2009 due to the reduction in the trust
unit price relative to the closing price of the trust units at December 31,
2008. The 2008 non-cash amount relates to estimated costs of the Whole Unit
Plan to March 31, 2008 as there were no cash payments during the first quarter
of 2008 and therefore no reversals were recorded in the period.

    Whole Unit Plan

    The Whole Unit Plan results in each employee, officer and director (the
"plan participants") receiving cash compensation in relation to the value of a
specified number of underlying trust units. The Whole Unit Plan consists of
Restricted Trust Units ("RTUs") for which the number of units is fixed and
will vest over a period of three years and Performance Trust Units ("PTUs")
for which the number of units is variable and will vest at the end of three
years.
    Upon vesting, the plan participant is entitled to receive a cash payment
based on the fair value of the underlying trust units plus accrued
distributions. The cash compensation issued upon vesting of the PTUs is
dependent upon the performance of the Trust compared to its peers and
indicated by the performance multiplier. The performance multiplier is based
on the percentile rank of the Trust's total unitholder return compared to its
peers. Total return is calculated as the sum of the change in the market price
of the trust units in the period plus the amount of distributions in the
period. The performance multiplier ranges from zero, if ARC's performance
ranks in the bottom quartile, to two for top quartile performance.
    Table 17 shows the changes to the Whole Unit Plan during the first three
months of 2009 along with the estimated value of the plan at March 31, 2009:

    
    Table 17
    -------------------------------------------------------------------------
    Whole Unit Plan                                                    Total
    (units in thousands and                  Number of  Number of   RTUs and
     $ millions except per unit)                  RTUs       PTUs       PTUs
    -------------------------------------------------------------------------
    Balance, beginning of period                   756        959      1,715
    Granted in the period                          377        244        621
    Vested in the period                          (180)      (154)      (334)
    Forfeited in the period                        (15)       (10)       (25)
    -------------------------------------------------------------------------
    Balance, end of period(1)                      938      1,039      1,977
    -------------------------------------------------------------------------
    Estimated distributions to vesting date(2)     250        377        627
    Estimated units upon vesting after
     distributions                               1,188      1,416      2,604
    Performance multiplier(3)                        -        1.4          -
    -------------------------------------------------------------------------
    Estimated total units upon vesting           1,188      2,031      3,219
    -------------------------------------------------------------------------
    Trust unit price at March 31, 2009          $14.15     $14.15     $14.15
    Estimated total value upon vesting
     ($ millions)                                 16.8       28.7       45.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 1.4 at March 31, 2009 based on an average calculation of all
        outstanding grants. The performance multiplier is assessed each
        period end based on actual results of the Trust relative to its peers
        except during the first year of each grant where a performance
        multiplier of 1.0 is used.
    

    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. In periods where substantial trust unit price fluctuation
occurs, the Trust's G&A expense is subject to significant volatility.
    Table 18 is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier and units
outstanding as at March 31, 2009:

    
    Table 18
    -------------------------------------------------------------------------
    Value of Whole Unit Plan as at
     March 31, 2009                                Performance multiplier
                                               ------------------------------
    (units thousands and $ millions
     except per unit)                                -        1.0        2.0
    -------------------------------------------------------------------------
    Estimated trust units to vest
      RTUs                                       1,188      1,188      1,188
      PTUs                                           -      1,416      2,832
    -------------------------------------------------------------------------
    Total units(1)                               1,188      2,604      4,020
    -------------------------------------------------------------------------
      Trust unit price(2)                       $14.15     $14.15     $14.15
      Trust unit distributions per month(2)      $0.12      $0.12      $0.12
    -------------------------------------------------------------------------
    Value of Whole Unit Plan upon vesting(3)     $16.8      $36.8      $56.9
    -------------------------------------------------------------------------
      2009                                         3.1        5.2        7.3
      2010                                         6.6       13.2       19.9
      2011                                         4.7       11.3       18.0
      2012                                         2.4        7.1       11.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes additional estimated units to be issued for accrued
        distributions to vesting date.
    (2) Values will fluctuate over the vesting period based on the volatility
        of the underlying trust unit price and distribution levels. Assumes a
        future trust unit price of $14.15 and $0.12 per trust unit
        distributions based on the unit price and distribution levels in
        place at March 31, 2009. As a result of the current commodity
        price environment, the monthly distribution has decreased from $0.12
        per unit to $0.10 per unit starting with the distribution declared
        for the month of May and payable on June 15, 2009.
    (3) Upon vesting, a cash payment is made equivalent to the value of the
        underlying trust units. The payment is made on vesting dates in March
        and September of each year and at that time is reflected as a
        reduction of cash flow from operating activities.
    

    Due to the variability in the future payments under the plan, the Trust
estimates that between $16.8 million and $56.9 million will be paid out from
2009 through 2012 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.

    Interest Expense

    Interest expense decreased to $5.8 million in the first quarter of 2009
from $8.8 million in 2008 due to a decrease in short-term interest rates. As
at March 31, 2009, the Trust had $703.8 million of debt outstanding, of which
$267.2 million was fixed at a weighted average rate of 5.1 per cent and $436.6
million, including the working capital facility, was floating at current
market rates plus a credit spread of 60 basis points. Seventy-two per cent (US
$404.5 million) of the Trust's debt is denominated in U.S. dollars.

    Foreign Exchange Gains and Losses

    The Trust recorded a loss of $14.6 million in the first quarter of 2009
on foreign exchange transactions compared to a loss of $15 million in 2008.
These amounts include both realized and unrealized foreign exchange gains and
losses.
    Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements. The 2009 realized foreign exchange loss of $0.2 million relates
to interest payments and hedging settlements in the quarter.
    Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The volatility of the Canadian dollar during
the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain or loss impacts net income
but does not impact cash flow from operating activities as it is a non-cash
amount. From December 31, 2008 to March 31, 2009, the Cdn$/US$ exchange rate
increased from 1.22 to 1.26 resulting in an unrealized loss of $14.4 million
on U.S. dollar denominated debt.

    Taxes

    In the first quarter of 2009, a future income tax recovery of $12.2
million was included in income compared to an expense of $0.5 million in 2008.
    The corporate income tax rate applicable to 2009 is 29 per cent; however
the Trust and its subsidiaries did not pay any material cash income taxes for
the first quarter of 2009. Due to the Trust's structure, currently, both
income tax and future tax liabilities are passed on to the unitholders by
means of royalty payments made between ARC Resources and the Trust.
    Management and the Board of Directors continue to review the impact of
the SIFT rules on our business strategy and while there has not been a final
decision as to ARC's future direction at this time we are of the opinion that
the conversion from a trust to a corporation may be the most logical and tax
efficient alternative for ARC unitholders.
    A conversion to a corporation will require approval of ARC's unitholders,
as well as customary court and regulatory approvals. We currently anticipate
that the closing of a conversion would occur on or before December 31, 2010.
This would require a unitholder meeting to be scheduled for early to
mid-December 2010. To be implemented, a conversion must be approved by not
less than two-thirds of the votes cast by unitholders voting at the meeting.
The intention would be for a conversion to be tax deferred for Canadian and
U.S. income tax purposes.
    For Canadian GAAP, we anticipate that the conversion would be accounted
for on a continuity of interests basis. Under the continuity of interests
method of accounting, the corporation would be recognized as the successor
entity to the Trust and the consolidated financial statements would reflect
financial position, results of operations and cash flows as if the corporation
had always carried on the business formerly carried on by the Trust. Certain
terms such as shareholder, unitholder, dividend, and distribution would be
used interchangeably throughout the consolidated financial statements.
    The corporation would expect to allocate its cash flow among funding a
portion of capital expenditures, periodic debt repayments, site reclamation
expenditures, and dividends, or distributions. Current taxes payable by ARC
after converting to a corporation will be subject to normal corporate tax
rates. Taxable income as a corporation will vary depending on total income and
expenses and vary with changes to commodity prices, costs, claims for both
accumulated tax pools and tax pools associated with current year expenditures.
As ARC has accumulated $2.1 billion of income tax pools, taxable income will
be reduced or potentially eliminated for the initial period post conversion.
The $2 billion of income tax pools (detailed in Table 19) are deductible at
various rates and annual deductions associated with the initial tax pools will
decline over time.

    
    Table 19
    -------------------------------------------------------------------------
                             Cdn $ millions at
    Tax Pool type               March 31, 2009          Annual deductibility
    -------------------------------------------------------------------------
    Canadian Oil and Gas
     Property Expense                    985.8         10% declining balance
    Canadian Development
     Expense                             387.8         30% declining balance
    Canadian Exploration
     Expense                              46.8                          100%
    Un-depreciated Capital Cost          418.1       Primarily 25% declining
                                                                     balance
    Non-Capital Losses                   136.6                          100%
    Research and
     Experimental credits                  0.2                          100%
    Other                                 18.6             Various rates, 7%
                                                    declining balance to 20%
    -------------------------------------------------------------------------
    Total Federal Tax Pools            1,993.9
    -------------------------------------------------------------------------
    Additional Alberta Tax Pools         155.9            Various rates, 25%
                                                   declining balance to 100%
    -------------------------------------------------------------------------
    Total Federal and
     Provincial Pools                  2,149.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Returns to shareholders post conversion will be impacted by the reduction
of cash flow required to pay current income taxes, if any. Over the longer
term, we would expect Canadian investors who hold their trust units in a
taxable account will be relatively indifferent on an after tax basis as to
whether ARC is structured as a corporation or as a trust in 2011. However,
Canadian tax deferred investors (those holding their trust units in a tax
deferred vehicle such as an RRSP, RRIF or pension plan) and foreign investors
will realize a lower after tax return on distributions in 2011 due to the
introduction of the SIFT Tax should ARC stay as a trust, and their inability
to claim the dividend tax credit if ARC converts to a corporation.
    If a conversion from the trust structure to a Corporation is approved by
the unitholders, the income tax payable by unitholders will vary and each
unitholder should consult their own tax advisor for details on the direct
impact to themselves.

    Depletion, Depreciation and Accretion of Asset Retirement Obligation

    The depletion, depreciation and accretion ("DD&A") rate increased to
$16.68 per boe in the first quarter of 2009 from $15.92 per boe in 2008. The
Trust posted a large increase in proved reserves at year-end 2008; however,
these reserves were offset by a significant increase in the future development
costs required to convert proven undeveloped reserves to proven producing
reserves.
    A breakdown of the DD&A rate is summarized in Table 20:

    
    Table 20
    -------------------------------------------------------------------------
                                                 Three Months Ended March 31
    -------------------------------------------------------------------------
    DD&A Rate
    ($ millions except per boe amounts)           2009       2008   % Change
    -------------------------------------------------------------------------
    Depletion of oil & gas assets(1)              95.1       94.7          -
    Accretion of asset retirement obligation(2)    2.3        2.3          -
    -------------------------------------------------------------------------
    Total DD&A                                    97.4       97.0          -
    DD&A rate per boe                            16.68      15.92         5%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes depletion of the capitalized portion of the asset retirement
        obligation that was capitalized to the PP&E balance and is being
        depleted over the life of the reserves.
    (2) Represents the accretion expense on the asset retirement obligation
        during the year.
    

    Capital Expenditures and Net Acquisitions

    Total capital expenditures, excluding acquisitions and dispositions,
totaled $97.2 million in the first quarter of 2009 compared to $111.3 million
in the same period of 2008. This amount was incurred on drilling and
completions, geological, geophysical and facilities expenditures.
    During the first quarter of 2009, the Trust drilled 81 gross wells on
operated properties, 56 of which were completed in the quarter in addition to
six wells that were drilled in the fourth quarter of 2008.
    In addition to capital expenditures on development activities, the Trust
completed net property acquisitions of $6.2 million in the first quarter of
2009 most of which related to the acquisition of undeveloped land in the
Dawson area.
    For the remainder of 2009, the Trust expects to drill 41 gross wells on
operated properties, complete all wells in inventory and construct a
substantial portion of the Dawson gas plant that is now expected to be on
stream by the end of the first quarter of 2010. Total capital expenditures are
forecast to be $350 million in 2009.
    A breakdown of capital expenditures and net acquisitions is shown in
Table 21:

    
    Table 21
    -------------------------------------------------------------------------
                                                 Three Months Ended March 31
    -------------------------------------------------------------------------
    Capital Expenditures ($ millions)             2009       2008   % Change
    -------------------------------------------------------------------------
    Geological and geophysical                     2.8        5.5        (49)
    Drilling and completions                      68.5       64.4          6
    Plant and facilities                          25.1       11.6        116
    Undeveloped land purchased at
     crown land sales                              0.2       28.8        (99)
    Other capital                                  0.6        1.0        (40)
    -------------------------------------------------------------------------
    Total capital expenditures before
     net acquisitions                             97.2      111.3        (13)
    -------------------------------------------------------------------------
    Producing property acquisitions(1)             0.1          -        100
    Undeveloped land property acquisitions         6.1       13.9        (56)
    Producing property dispositions(1)               -       (0.2)      (100)
    Undeveloped land property dispositions           -       (3.6)      (100)
    -------------------------------------------------------------------------
    Total capital expenditures and net
     acquisitions                                103.4      121.4        (15)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Value is net of post-closing adjustments.


    Approximately 45 per cent of the $97.2 million capital program in the
first quarter of 2009 was financed with cash flow from operating activities
compared to 72 per cent in for the same period of 2008. Property acquisitions
were financed through debt and working capital.

    Table 22
    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                            Three Months Ended         Three Months Ended
                              March 31, 2009             March 31, 2008
    -------------------------------------------------------------------------
                          Devel-     Net    Total    Devel-     Net    Total
                         opment   Acquis-  Expend-  opment   Acquis-  Expend-
                        Capital   itions   itures  Capital   itions   itures
    -------------------------------------------------------------------------
    Expenditures           97.2      6.2    103.4    111.3     10.1    121.4
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash flow from
     operating activities   45%        -      42%      72%        -      66%
    Proceeds from
     Distribution re-
     investment plan
     ("DRIP")               19%        -      18%      25%        -      23%
    Debt                    36%     100%      40%       3%     100%      11%
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Asset Retirement Obligation and Reclamation Fund

    At March 31, 2009, the Trust recorded an Asset Retirement Obligation
("ARO") of $142.5 million ($141.5 million at December 31, 2008) for future
abandonment and reclamation of the Trust's properties.
    Included in the March 31, 2009 ARO balance was a $0.4 million increase
related to development activities in the first three months of 2009, $2.3
million for accretion expense in the period and a reduction of $1.7 million
for actual abandonment expenditures incurred in the first quarter of 2009.
    ARC's reclamations funds held $26.6 million as at March 31, 2009. Under
the terms of the Trust's investment policy, reclamation fund investments and
excess cash can only be invested in Canadian or U.S. Government securities,
investment grade corporate bonds, or investment grade short-term money market
securities.

    Capitalization, Financial Resources and Liquidity

    A breakdown of the Trust's capital structure is outlined in Table 23, as
at March 31, 2009 and December 31, 2008:

    
    Table 23
    -------------------------------------------------------------------------
    Capital Structure and Liquidity
    ($ millions except per cent                       March 31,  December 31,
     and ratio amounts)                                   2009          2008
    -------------------------------------------------------------------------
    Net debt obligations(1)                              781.5         961.9
    Market value of trust units and exchangeable
     shares(2)                                         3,339.4       4,405.9
    -------------------------------------------------------------------------
    Total capitalization(3)                            4,120.9       5,367.8
    -------------------------------------------------------------------------
    Net debt as a percentage of total capitalization     19.0%         17.9%
    Net debt to annualized YTD cash flow from
     operating activities                                 1.6           1.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net debt is a non-GAAP measure and therefore it may not be comparable
        with the calculation of similar measures for other entities. It is
        calculated as long-term debt plus current liabilities less the
        current assets as they appear on the Consolidated Balance Sheets. Net
        debt excludes current unrealized amounts pertaining to risk
        management contracts and the current portion of future income taxes.
    (2) Calculated using the total trust units outstanding at March 31 and
        December 31 including the total number of trust units issuable for
        exchangeable shares at March 31 and December 31 multiplied by the
        closing trust unit price of $14.15 and $20.10 at March 31, 2009 and
        December 31, 2008, respectively.
    (3) Total capitalization as presented does not have any standardized
        meaning prescribed by Canadian GAAP and therefore it may not be
        comparable with the calculation of similar measures for other
        entities. Total capitalization is not intended to represent the total
        funds from equity and debt received by the Trust.
    

    At March 31, 2009, the Trust's current credit facilities comprised US$212
million in senior secured notes currently outstanding, a Cdn$800 million
syndicated bank credit facility, of which $434.5 million was outstanding and a
Cdn$25 million demand working capital facility, of which $2.1 million was
outstanding. The credit facility syndicate includes 11 domestic and
international banks. The Trust's debt agreements contain a number of covenants
all of which were met as at March 31, 2009; these agreements are available at
www.SEDAR.com. The major financial covenants are described below:

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

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

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

    On April 14, 2009, the Trust announced the closing of a private placement
of long-term debt in the form of senior secured notes totaling US$125 million
at a blended average interest rate of 7.47 per cent. The notes were offered in
three tranches, one tranche of US$67.5 million senior notes with a five year
average life repayable in years 2012 through 2016 issued at an interest rate
of 7.19 per cent. The second tranche of US$35 million senior notes with a 10
year average life repayable in years 2017 through 2021, issued at an interest
rate of 8.21 per cent. The third tranche of Cdn$29 million senior notes was
issued with a five year average life repayable in years 2012 through 2016,
issued at an interest rate of 6.5 per cent.
    In April 2009, ARC also extended its uncommitted master shelf agreement
from May 2009 to April 2012. The extended agreement allows for an aggregate
draw of up to US$225 million (Cdn$283.5 million) in long term notes at a rate
equal to the related U.S. treasuries corresponding to the term of the notes
plus an appropriate credit risk adjustment at the time of issuance.
    As at the date of this MD&A, the Trust has approximately $610 million of
unused credit available: $445 million under its credit facility, and $165
million available to draw long term notes under the master shelf agreement.
    As a result of the weakened global economic situation, the Trust along
with all other oil and gas entities will have restricted access to capital and
increased borrowing costs. Although the Trust's business and asset base have
not changed, the lending capacity of all financial institutions has been
diminished and risk premiums have increased. These issues will impact the
Trust as it reviews financing alternatives for the 2009 capital program,
assesses potential future acquisition opportunities and manages future cash
flow decremented by lower commodity prices and higher borrowing costs. The
Trust intends to finance its 2009 capital program with cash flow, existing
credit facilities, proceeds from the DRIP, potential asset dispositions and
new borrowings or equity if necessary. Beyond that, the Trust may need to
access additional capital and/or curtail capital expenditure plans and will
look to do so in the most cost effective manner possible.

    Unitholders' Equity

    At March 31, 2009, there were 236 million trust units issued and issuable
for exchangeable shares, an increase of 16.8 million trust units from December
31, 2008.
    On February 6, 2009, the Trust closed its previously announced equity
offering for 15 million trust units. The gross proceeds raised under this
offering were $253 million and proceeds net of underwriter and transaction
fees were approximately $240 million. The proceeds were used to reduce
outstanding indebtedness under the Trust's credit facility.
    Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so at a
five per cent discount to the prevailing market price with no additional fees
or commissions. During the first quarter of 2009, the Trust raised proceeds of
$18.7 million and issued 1.3 million trust units pursuant to the DRIP at an
average price of $14.75 per unit.

    Distributions

    ARC declared distributions of $82 million ($0.36 per unit), representing
66 per cent of 2009 first quarter cash flow from operating activities compared
to distributions of $126.8 million ($0.60 per unit) representing 60 per cent
of cash flow from operating activities in the first quarter of 2008.
    As a result of the current commodity price environment, the monthly
distribution has decreased from $0.12 per unit to $0.10 per unit starting with
the distribution declared for the month of May and payable on June 15, 2009.
The decrease in distributions will provide the Trust with greater financial
flexibility to execute strategic capital projects while maintaining a
conservative debt balance and strong balance sheet.
    The following items may be deducted from cash flow from operating
activities to arrive at distributions to unitholders:

    
    -   The portion of capital expenditures that are funded with cash flow
        from operating activities. In the first quarter of 2009, the Trust
        withheld 34 per cent of cash flow from operating activities to fund
        45 per cent of the capital program excluding acquisitions. The
        remaining portion of capital expenditures was financed by proceeds
        from the DRIP program and debt.

    -   An annual contribution to the reclamation funds, with $12 million
        scheduled to be contributed in 2009. The reclamation funds are
        segregated bank accounts or subsidiary trusts and the balances will
        be drawn on in future periods as the Trust incurs abandonment and
        reclamation costs over the life of its properties.

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

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

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

    -   The Trust has certain obligations for future payments relative to
        employee long-term incentive compensation. Presently, the Trust
        estimates that $16.8 million to $56.9 million will be paid out
        pursuant to such commitments in 2009 through 2012 subject to vesting
        provisions and future performance of the Trust. These amounts will
        reduce cash flow from operating activities and may in turn reduce
        distributions in future periods.

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

    Table 24
    -------------------------------------------------------------------------
                             Three Months Ended         Three Months Ended
                                  March 31                   March 31
    Cash flow from                              %                          %
     operating activities  2009     2008   Change     2009     2008   Change
     and distributions       ($ millions)               ($ per unit)
    -------------------------------------------------------------------------
    Cash flow from
     operating
     activities           124.3    209.9      (41)    0.54     0.98      (45)
    Net reclamation fund
     withdrawals
     (contributions)(1)     1.5     (3.3)     145     0.01    (0.02)     150
    Capital expenditures
     funded with cash
     flow from operating
     activities           (43.8)   (79.8)     (45)   (0.19)   (0.37)     (49)
    Other(2)                  -        -        -        -     0.01     (100)
    -------------------------------------------------------------------------
    Distributions          82.0    126.8      (35)    0.36     0.60      (40)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 period.


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

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

    -   To ensure that the Trust's financial flexibility is maintained by a
        review of the Trust's debt to equity and debt to cash flow from
        operating activities levels. The use of cash flow from operating
        activities and proceeds from equity offerings to fund capital
        development activities reduces the requirements of the Trust to use
        debt to finance these expenditures. In the first quarter of 2009 the
        Trust funded 45 per cent of capital development activities with a
        portion of cash flow from operating activities. Distributions and the
        actual amount of cash flows withheld to fund the Trust's capital
        expenditure program is dependent on the commodity price environment
        and is subject to the approval and discretion of the Board of
        Directors.
    

    The actual amount of future monthly distributions is proposed by
management and is subject to the approval and discretion of the Board of
Directors. The Board reviews future distributions in conjunction with their
review of quarterly financial and operating results.
    Please refer to the Trust's website at www.arcenergytrust.com for details
monthly distribution amounts and distribution dates for 2009.

    Environmental Initiatives Impacting the Trust

    In March of 2009, ARC was selected to receive a portion of the required
funding for the next two phases of its Heartland Area Redwater Project
("HARP") from the ecoENERGY Technology Initiative of the Federal Government of
Canada. This project is designed to demonstrate the feasibility of safe CO(2)
storage in the Redwater Leduc Reef saline water formation, situated northeast
of Edmonton, Alberta. This site is located close to the Alberta Industrial
Heartland region, where there are a number of large industrial sources of
greenhouse gas ("GHG") emissions, including chemical and fertilizer plants and
several oil sands upgraders that are operating, being built or in the planning
stages.
    The Redwater Leduc Reef is also strategically located along a
straight-line path between Fort McMurray and Edmonton, a potential route for a
CO(2) pipeline from Fort McMurray. Preliminary work estimates the total
storage capacity of the saline water formation portion of the reef to be one
gigatonne of CO(2).
    Over the long term, this project will demonstrate the prospect of carbon
capture and storage on a commercial scale (several million tonnes per year),
contributing to a significant reduction in GHG emissions.

    Contractual Obligations and Commitments

    The Trust has contractual obligations in the normal course of operations
including purchase of assets and services, operating agreements,
transportation commitments, sales commitments, royalty obligations, and lease
rental obligations and employee agreements. These obligations are of a
recurring and consistent nature and impact the Trust's cash flows in an
ongoing manner. The Trust also has contractual obligations and commitments
that are of a less routine nature as disclosed in Table 25.

    
    Table 25
    -------------------------------------------------------------------------
                                         Payments due by period
    -------------------------------------------------------------------------
                            2009  2010-2011  2012-2013  Thereafter     Total
    -------------------------------------------------------------------------
    Debt repayments(1)      22.8      492.0       81.4      107.6      703.8
    Interest payments(2)    11.8       22.9       15.9       10.2       60.8
    Reclamation fund
     contributions(3)        5.3        9.5        8.3       67.9       91.0
    Purchase commitments     8.0       13.0        7.1        5.1       33.2
    Transportation
     commitments(4)            -       14.9       21.9       21.0       57.8
    Operating leases         5.7        9.8       14.3       81.8      111.6
    Risk management
     contract premiums(5)   14.1          -          -          -       14.1
    -------------------------------------------------------------------------
    Total contractual
     obligations            67.7      562.1      148.9      293.6    1,072.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Long-term and short-term debt, excluding interest.
    (2) Fixed interest payments on senior secured notes.
    (3) Contribution commitments to a restricted reclamation fund associated
        with the Redwater property.
    (4) Fixed payments for transporting production from the Dawson gas plant,
        expected to be operational in early 2010.
    (5) Fixed premiums to be paid in future periods on certain commodity risk
        management contracts.
    

    The above noted risk management contract premiums are part of the Trust's
commitments related to its risk management program and have been recorded at
fair market value at March 31, 2009 on the balance sheet as part of risk
management contracts. In addition to the premiums, the Trust has commitments
related to its risk management program.
    The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At a given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2009 capital budget has
been approved by the Board at $350 million. This commitment has not been
disclosed in the commitment table (Table 25) as it is of a routine nature and
is part of normal course of operations for active oil and gas companies and
trusts.
    The 2009 capital budget of $350 million includes $11 million for
leasehold development costs related to the Trust's new office space in
downtown Calgary. These costs will be incurred throughout 2009 with additional
costs to be incurred in 2010. The operating lease commitments for the new
space begin in the first quarter of 2010 and are included in Table 25.
    The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the commitment table (Table 25) does not
include any commitments for outstanding litigation and claims.
    The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table
(Table 25) as it is of a routine nature and is part of normal course of
operations.

    Off Balance Sheet Arrangements

    The Trust has certain lease agreements, all of which are reflected in the
Contractual Obligations and Commitments table (Table 25), which were entered
into in the normal course of operations. All leases have been treated as
operating leases whereby the lease payments are included in operating expenses
or G&A expenses depending on the nature of the lease. No asset or liability
value has been assigned to these leases in the balance sheet as of March 31,
2009.

    Critical Accounting Estimates

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

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

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

    Internal Control over Financial Reporting

    ARC is required to comply with National Instrument 52-109 "Certification
of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to
as Canadian SOX ("C-Sox"). The certification of interim filings for the
interim period ended March 31, 2009 requires that the Trust disclose in the
interim MD&A any changes in the Trust's internal control over financial
reporting that occurred during the period that has materially affected, or is
reasonably likely to materially affect the Trust's internal control over
financial reporting. The Trust confirms that no such changes were made to the
internal controls over financial reporting during the first three months of
2009.

    Financial Reporting Update

    Current Year Accounting Changes

    Effective January 1, 2009, the Trust prospectively adopted Section 3064,
Goodwill and Intangible Assets issued by the Canadian Institute of Chartered
Accountants ("CICA"). Section 3064 establishes standards for the recognition,
measurement, presentation and disclosure of goodwill and intangible assets
subsequent to its initial recognition. This new section has no current impact
on the Trust or its Consolidated Financial Statements.

    Future Accounting Changes

    International Financial Reporting Standards ("IFRS")

    In April 2008, the CICA published the exposure draft "Adopting IFRSs in
Canada". The exposure draft proposes to incorporate IFRSs into the CICA
Accounting Handbook effective for interim and annual financial statements
relating to fiscal years beginning on or after January 1, 2011. At this date,
publicly accountable enterprises will be required to prepare financial
statements in accordance with IFRSs. The Trust is currently reviewing the
standards to determine the potential impact on its Consolidated Financial
Statements. The Trust has appointed internal staff to lead the conversion
project along with sponsorship from the senior leadership team. In addition,
an external advisor has been retained to assist the Trust in scoping its
conversion project. The Trust has performed a diagnostic analysis that
identifies differences between the Trust's current accounting policies and
IFRSs. The Trust has evaluated the impact of these differences and is
developing accounting policies in order to comply with IFRS.

    Non-GAAP Measures

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

    Forward-looking Information and Statements

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

    Additional Information

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


    
    QUARTERLY HISTORICAL REVIEW
    -------------------------------------------------------------------------
    (Cdn $ millions, except
     per unit amounts)              2009                 2008
    -------------------------------------------------------------------------
    FINANCIAL                         Q1       Q4       Q3       Q2       Q1

    Revenue before royalties       225.2    300.8    485.7    512.0    407.9
      Per unit(1)                   0.98     1.38     2.24     2.38     1.91
    Cash flow from operating
     activities(2)                 124.3    209.4    251.4    273.4    209.9
      Per unit - basic(1)           0.54     0.96     1.16     1.27     0.98
      Per unit - diluted            0.54     0.96     1.16     1.27     0.98
    Net income                      22.3     82.7    311.7     57.3     81.3
      Per unit - basic(3)           0.10     0.38     1.46     0.27     0.39
      Per unit - diluted            0.10     0.38     1.46     0.27     0.38
    Distributions                   82.0    127.2    171.3    144.7    126.8
      Per unit - basic(4)           0.36     0.59     0.80     0.68     0.60
    Total assets                 3,733.1  3,766.7  3,687.5  3,664.3  3,592.6
    Total liabilities            1,392.1  1,624.6  1,530.8  1,689.6  1,560.4
    Net debt outstanding(5)        781.5    961.9    773.2    756.1    770.1
    Weighted average trust
     units(6)                      228.9    218.3    216.6    215.2    213.8
    Trust units outstanding
     and issuable(6)               236.0    219.2    217.4    215.8    214.7
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical       2.8      3.7      1.3     16.4      5.5
    Land                             0.2     17.1     18.6     57.8     28.8
    Drilling and completions        68.5    117.1     91.4     32.6     64.4
    Plant and facilities            25.1     30.5     24.2     24.1     11.6
    Other capital                    0.6      1.0      0.9      0.4      1.0
    Total capital expenditures      97.2    169.4    136.4    131.3    111.3
    Property acquisitions
     (dispositions) net              6.2     27.6     13.1      0.3     10.1
    Total capital expenditures
     and net acquisitions          103.4    197.0    149.5    131.6    121.4
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)           28,806   28,935   28,509   27,541   29,064
      Natural gas (mmcf/d)         193.8    195.1    192.0    194.7    204.3
      Natural gas liquids (bbl/d)  3,764    3,858    3,822    3,906    3,856
      Total (boe per day 6:1)     64,872   65,313   64,325   63,896   66,976
    Average prices
      Crude oil ($/bbl)            46.44    56.26   114.20   118.32    89.72
      Natural gas ($/mcf)           5.20     7.48     8.68    10.41     7.80
      Natural gas liquids ($/bbl)  38.86    45.22    82.87    82.29    68.54
      Oil equivalent ($/boe)       38.40    49.93    81.42    87.73    66.67
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
     unit prices
    High                           20.90    22.55    33.30    33.95    27.06
    Low                            11.73    15.01    22.33    25.19    20.00
    Close                          14.15    20.10    23.10    33.95    26.38
    Average daily volume
     (thousands)                   1,240    1,523      841      659      863
    -------------------------------------------------------------------------


    -------------------------------------------------------
    (Cdn $ millions, except
     per unit amounts)                      2007
    -------------------------------------------------------
    FINANCIAL                         Q4       Q3       Q2

    Revenue before royalties       338.0    300.2    305.6
      Per unit(1)                   1.59     1.42     1.46
    Cash flow from operating
     activities(2)                 173.7    179.6    179.4
      Per unit - basic(1)           0.82     0.85     0.86
      Per unit - diluted            0.82     0.85     0.86
    Net income                     106.3    120.8    184.9
      Per unit - basic(3)           0.51     0.58     0.90
      Per unit - diluted            0.51     0.58     0.89
    Distributions                  125.8    125.0    124.1
      Per unit - basic(4)           0.60     0.60     0.60
    Total assets                 3,533.0  3,460.8  3,432.8
    Total liabilities            1,491.3  1,421.4  1,415.3
    Net debt outstanding(5)        752.7    699.8    653.9
    Weighted average trust
     units(6)                      212.5    210.9    209.5
    Trust units outstanding
     and issuable(6)               213.2    211.7    210.2
    -------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical       3.0      2.9      4.1
    Land                            42.6     33.0      1.7
    Drilling and completions        75.2     73.4     25.8
    Plant and facilities            17.9     21.1     16.3
    Other capital                    0.6      1.5      0.6
    Total capital expenditures     139.3    131.9     48.5
    Property acquisitions
     (dispositions) net              5.0     27.3     10.0
    Total capital expenditures
     and net acquisitions          144.3    159.2     58.5
    -------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)           28,682   28,437   28,099
      Natural gas (mmcf/d)         187.4    173.3    176.7
      Natural gas liquids (bbl/d)  4,067    3,795    4,088
      Total (boe per day 6:1)     63,989   61,108   61,637
    Average prices
      Crude oil ($/bbl)            77.53    73.40    65.21
      Natural gas ($/mcf)           6.32     5.52     7.38
      Natural gas liquids ($/bbl)  62.75    55.64    52.76
      Oil equivalent ($/boe)       57.26    53.28    54.37
    -------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
     unit prices
    High                           21.55    22.60    23.86
    Low                            18.90    19.00    20.78
    Close                          20.40    21.17    21.74
    Average daily volume
     (thousands)                     624      503      599
    -------------------------------------------------------
    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares.
    (2) This is a GAAP measure and a change from the non-GAAP measure
        reported in prior reports. Refer to non-GAAP section.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Based on number of trust units outstanding at each distribution date.
    (5) Net debt excludes the current unrealized risk management contracts
        asset and liability and the current portion of future income taxes.
    (6) Includes trust units issuable for outstanding exchangeable shares
        based on the period end exchange ratio.



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


    (Cdn$ millions)                                        2009         2008
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Cash and cash equivalents (Note 3)            $         -  $      40.0
      Accounts receivable (Note 4)                        125.1        110.0
      Prepaid expenses                                     17.7         16.8
      Risk management contracts (Notes 4 and 9)            13.9         24.4
      Future income taxes                                   4.0          3.9
    -------------------------------------------------------------------------
                                                          160.7        195.1
    Reclamation funds                                      26.6         28.2
    Risk management contracts (Notes 4 and 9)               3.0          9.2
    Property, plant and equipment                       3,385.2      3,376.6
    Goodwill                                              157.6        157.6
    -------------------------------------------------------------------------
    Total assets                                    $   3,733.1  $   3,766.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities
       (Note 5)                                     $     192.4  $     194.4
      Distributions payable                                28.1         32.5
      Risk management contracts (Notes 4 and 9)            18.8         23.5
    -------------------------------------------------------------------------
                                                          239.3        250.4
    Risk management contracts (Notes 4 and 9)               1.0          3.4
    Long-term debt (Note 6)                               703.8        901.8
    Accrued long-term incentive compensation
     (Note 14)                                              7.0         14.2
    Asset retirement obligations (Note 7)                 142.5        141.5
    Future income taxes                                   298.5        313.3
    -------------------------------------------------------------------------
    Total liabilities                                   1,392.1      1,624.6
    -------------------------------------------------------------------------

    COMMITMENTS AND CONTINGENCIES (Note 15)

    NON-CONTROLLING INTEREST
      Exchangeable shares (Note 10)                        36.4         42.4

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 11)                    2,867.6      2,600.7
      Deficit (Note 12)                                  (562.6)      (502.9)
      Accumulated other comprehensive (loss)
       income (Note 12)                                    (0.4)         1.9
    -------------------------------------------------------------------------
    Total unitholders' equity                           2,304.6      2,099.7
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity       $   3,733.1  $   3,766.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements



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


    (Cdn$ millions, except per unit amounts)               2009         2008
    -------------------------------------------------------------------------

    REVENUES
    Oil, natural gas and natural gas liquids        $     225.2  $     407.9
    Royalties                                             (37.0)       (72.2)
    -------------------------------------------------------------------------
                                                          188.2        335.7
    Gain (loss) on risk management contracts (Note 9)
      Realized                                             16.3        (29.5)
      Unrealized                                           (6.6)       (18.7)
    -------------------------------------------------------------------------
                                                          197.9        287.5
    -------------------------------------------------------------------------

    EXPENSES
      Transportation                                        5.6          4.4
      Operating                                            59.1         58.2
      General and administrative                            5.1         21.2
      Interest on long-term debt (Note 6)                   5.8          8.8
      Depletion, depreciation and accretion                97.4         97.0
      Loss on foreign exchange                             14.6         15.0
    -------------------------------------------------------------------------
                                                          187.6        204.6
    -------------------------------------------------------------------------

    Future income tax recovery (expense)                   12.2         (0.5)
    -------------------------------------------------------------------------
    Net income before non-controlling interest             22.5         82.4
    Non-controlling interest (Note 10)                     (0.2)        (1.1)
    -------------------------------------------------------------------------
    Net income                                      $      22.3  $      81.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Deficit, beginning of period                    $    (502.9) $    (465.9)
    Distributions paid or declared (Note 13)              (82.0)      (126.8)
    -------------------------------------------------------------------------
    Deficit, end of period (Note 12)                $    (562.6) $    (511.4)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income per unit (Note 11)
      Basic                                         $      0.10  $      0.39
      Diluted                                       $      0.10  $      0.39
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements



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


    (Cdn$ millions)                                        2009         2008
    -------------------------------------------------------------------------

    Net income                                      $      22.3  $      81.3

    Other comprehensive (loss) income, net of tax
      Losses on financial instruments designated
       as cash flow hedges(1)                              (2.1)        (2.9)
       De-designation of cash flow hedge(2) (Note 9)          -         10.0
       Gains and losses on financial instruments
        designated as cash flow hedges in prior
        periods realized in net income in the
        current period(3) (Note 9)                         (0.1)        (0.4)
       Net unrealized (losses) gains on available-
        for-sale reclamation funds' investments(4)         (0.1)         0.2
    -------------------------------------------------------------------------
    Other comprehensive (loss) income                      (2.3)         6.9
    -------------------------------------------------------------------------
    Comprehensive income                            $      20.0  $      88.2
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accumulated other comprehensive income (loss),
     beginning of period                                    1.9         (2.9)
    Other comprehensive (loss) income                      (2.3)         6.9
    -------------------------------------------------------------------------
    Accumulated other comprehensive (loss) income,
     end of period (Note 12)                        $      (0.4) $       4.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Amounts are net of tax of $0.7 million for the period ended March 31,
        2009 (net of tax of $1.1 million for the period ended March 31,
        2008).
    (2) Amounts are net of tax of $3.6 million for the period ended March 31,
        2008.
    (3) Nominal future income tax impact for the period ended March 31, 2009
        (net of tax of $0.1 million for the period ended March 31, 2008).
    (4) Nominal future income tax impact for the period ended March 31, 2009
        (net of tax of $0.1 million for the period ended March 31, 2008).

    See accompanying notes to the consolidated financial statements



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


    (Cdn$ millions)                                        2009         2008
    -------------------------------------------------------------------------

    CASH FLOWS FROM OPERATING ACTIVITIES
    Net income                                      $      22.3  $      81.3
    Add items not involving cash:
      Non-controlling interest (Note 10)                    0.2          1.1
      Future income tax (recovery) expense                (12.2)         0.5
      Depletion, depreciation and accretion                97.4         97.0
      Non-cash loss on risk management
       contracts (Note 9)                                   6.6         18.7
      Non-cash loss on foreign exchange                    14.4         15.0
      Non-cash trust unit incentive compensation
       (recovery) expense (Note 14)                       (12.1)        13.8
    Expenditures on site restoration and
     reclamation (Note 7)                                  (1.7)        (3.7)
    Change in non-cash working capital                      9.4        (13.8)
    -------------------------------------------------------------------------
                                                          124.3        209.9
    -------------------------------------------------------------------------

    CASH FLOWS FROM FINANCING ACTIVITIES
    Repayment of long-term debt under revolving
     credit facilities, net                              (212.4)        (9.3)
    Issue of trust units                                  253.5          2.8
    Trust unit issue costs                                (12.9)           -
    Cash distributions paid (Note 13)                     (68.2)      (101.3)
    Change in non-cash working capital                      1.9          0.9
    -------------------------------------------------------------------------
                                                          (38.1)      (106.9)
    -------------------------------------------------------------------------

    CASH FLOWS FROM INVESTING ACTIVITIES
    Acquisition of petroleum and natural gas
     properties                                            (6.2)       (10.1)
    Proceeds on disposition of petroleum and
     natural gas properties                                   -          0.1
    Capital expenditures                                  (99.3)      (109.4)
    Net reclamation fund withdrawals                        1.5          0.2
    Change in non-cash working capital                    (22.2)        11.6
    -------------------------------------------------------------------------
                                                         (126.2)      (107.6)
    -------------------------------------------------------------------------
    DECREASE IN CASH AND CASH EQUIVALENTS                 (40.0)        (4.6)
    CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD         40.0          7.0
    -------------------------------------------------------------------------
    CASH AND CASH EQUIVALENTS, END OF PERIOD        $         -  $       2.4
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements



    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
    March 31, 2009 and 2008
    (all tabular amounts in Cdn$ millions, except per unit amounts)

    1.  SUMMARY OF ACCOUNTING POLICIES

        The unaudited interim consolidated financial statements follow the
        same accounting policies as the most recent annual audited financial
        statements, except as highlighted in Note 2. The interim consolidated
        financial statement note disclosures do not include all of those
        required by Canadian generally accepted accounting principles
        ("GAAP") applicable for annual consolidated financial statements.
        Accordingly, these interim consolidated financial statements should
        be read in conjunction with the audited consolidated financial
        statements included in the Trust's 2008 annual report.

    2.  NEW ACCOUNTING POLICIES

        Current Year Accounting Changes

        Effective January 1, 2009, the Trust adopted Section 3064, Goodwill
        and Intangible Assets issued by the Canadian Institute of Chartered
        Accountants ("CICA"). Section 3064 establishes standards for the
        recognition, measurement, presentation and disclosure of goodwill and
        intangible assets subsequent to its initial recognition. This new
        section has no current impact on the Trust or its consolidated
        financial statements.

        This standard was adopted prospectively.

        Future Accounting Changes

        International Financial Reporting Standards ("IFRS")

        In April 2008, the CICA published the exposure draft "Adopting IFRSs
        in Canada". The exposure draft proposes to incorporate IFRSs into the
        CICA Accounting Handbook effective for interim and annual financial
        statements relating to fiscal years beginning on or after January 1,
        2011. At this date, publicly accountable enterprises will be required
        to prepare financial statements in accordance with IFRSs. The Trust
        is currently reviewing the standards to determine the potential
        impact on its Consolidated Financial Statements. The Trust has
        appointed internal staff to lead the conversion project along with
        sponsorship from the senior leadership team. In addition, an external
        advisor has been retained to assist the Trust in scoping its
        conversion project. The Trust has performed a diagnostic analysis
        that identifies differences between the Trust's current accounting
        policies and IFRSs. The Trust has evaluated the impact of these
        differences and is developing accounting policies in order to comply
        with IFRS.

    3.  CASH AND CASH EQUIVALENTS

        Cash equivalents are nil as at March 31, 2009 ($40 million in
        Canadian Treasury Bills as at December 31, 2008).

    4.  FINANCIAL ASSETS AND CREDIT RISK

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

        -   By entering into sales contracts with only established credit
            worthy counterparties as verified by a third party rating agency,
            through internal evaluation or by requiring security such as
            letters of credit;
        -   By limiting exposure to any one counterparty in accordance with
            the Trust's Credit Policy;
        -   By restricting cash equivalent investments, reclamation fund
            investments, and risk management transactions to counterparties
            that, at the time of transaction are not less than investment
            grade;

        The majority of the credit exposure on accounts receivable at
        March 31, 2009 pertains to accrued revenue for March 2009 production
        volumes. The Trust transacts with a number of oil and natural gas
        marketing companies and commodity end users ("commodity purchasers").
        Commodity purchasers typically remit amounts to the Trust by the 25th
        day of the month following production. Joint interest receivables are
        typically collected within one to three months following production.
        At March 31, 2009, no one counterparty accounted for more than
        20 per cent of the total accounts receivable balance and the largest
        commodity purchaser receivable balance is 50 per cent secured with
        Letters of Credit.

        During the first three months of 2009 the Trust did not record any
        provision for non-collectible accounts receivable. The Trust's
        allowance for doubtful accounts was $32 million as at March 31, 2009
        and December 31, 2008.

        When determining whether amounts that are past due are collectable,
        management assesses the creditworthiness and past payment history of
        the counterparty, as well as the nature of the past due amount. ARC
        considers all amounts greater than 90 days to be past due. As at
        March 31, 2009, $3.9 million of accounts receivable are past due,
        excluding amounts described above, all of which are considered to be
        collectable.

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

    5.  FINANCIAL LIABILITIES AND LIQUIDITY RISK

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

        The following table details the Trust's financial liabilities as at
        March 31, 2009:

        ---------------------------------------------------------------------
                                  1 year    2 - 3    4 - 5   Beyond    Total
                                            years    years  5 years
        ---------------------------------------------------------------------
        Accounts payable and
         accrued liabilities(1)    198.9        -        -        -    198.9
        Distributions payable(2)    22.5        -        -        -     22.5
        Risk management
         contracts(3)               18.0      1.3      0.5        -     19.8
        Senior secured notes
         and interest               33.8     79.9     97.0    117.3    328.0
        Revolving credit
         facilities                    -    436.6        -        -    436.6
        Accrued long-term
         incentive compensation(1)     -     28.1        -        -     28.1
        ---------------------------------------------------------------------
        Total financial
         liabilities               273.2    545.9     97.5    117.3  1,033.9
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Liabilities under the Whole Unit Plan represent the total amount
            expected to be paid out on vesting.
        (2) Amounts payable for the distribution represents the net cash
            payable after distribution reinvestment.
        (3) Amounts payable for the risk management contracts have been
            included at their intrinsic value.

        The Trust actively maintains credit and working capital facilities to
        ensure that it has sufficient available funds to meet its financial
        requirements at a reasonable cost. Refer to Note 6 for further
        details on available amounts under existing banking arrangements and
        Note 8 for further details on capital management.

    6.  LONG-TERM DEBT

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Revolving credit facilities
          Syndicated credit facility -
           Cdn$ denominated                       $      191.9  $      399.5
          Syndicated credit facility -
           US$ denominated                               242.6         240.6
          Working capital facility                         2.1           2.1
        Senior secured notes
          5.42% US$ Note                                  94.5          91.9
          4.94% US$ Note                                  15.1          14.7
          4.62% US$ Note                                  78.8          76.5
          5.10% US$ Note                                  78.8          76.5
        ---------------------------------------------------------------------
        Total long-term debt outstanding          $      703.8  $      901.8
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Revolving Credit Facilities

        The Trust has an $800 million secured, annually extendible, financial
        covenant-based syndicated credit facility. The Trust also has in
        place a $25 million demand working capital facility. The working
        capital facility is secured and is subject to the same covenants as
        the syndicated credit facility.

        Borrowings under the syndicated credit facility bear interest at bank
        prime (2.5 per cent at March 31, 2009, four per cent at December 31,
        2008) or, at the Trust's option, Canadian dollar bankers' acceptances
        or U.S. dollar LIBOR loans, plus a stamping fee. At the option of the
        Trust, the lenders will review the syndicated credit facility each
        year and determine whether they will extend the revolving period for
        another year. In the event that the credit facility is not extended
        at anytime before the maturity date, the loan balance will become
        repayable on the maturity date. The maturity date of the current
        syndicated credit facility is April 15, 2011. All drawings under the
        facility are subject to stamping fees depending on the ratio of
        consolidated long-term debt and letters of credit to annualized net
        income before non-cash items and interest expense. These stamping
        fees vary between a minimum of 60 basis points ("bps") to a maximum
        of 110 bps.

        Debt Covenants

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

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

        In the event that the Trust enters into a material acquisition
        whereby the purchase price exceeds 10 per cent of the book value of
        the Trust's assets, the ratios in the first two covenants above are
        increased to 3.5 and 5.5 times respectively, while the third covenant
        is increased to 55 per cent for the subsequent six month period. As
        at March 31, 2009, the Trust had $1.9 million in letters of credit
        ($1.9 million in 2008), no subordinated debt, and was in compliance
        with all covenants.

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

        During the first quarter of 2009, the weighted-average effective
        interest rate under the credit facility was 1.7 per cent
        (3.8 per cent in 2008).

        Amounts of US$16.4 million due under the senior notes and
        $2.1 million due under the Trust's working capital facility in the
        next 12 months have not been included in current liabilities as
        management has the ability and intent to refinance this amount
        through the syndicated credit facility. The fair value of senior
        secured notes as at March 31, 2009 is $297.8 million ($289.9 million
        as at December 31, 2008), and is calculated as the present value of
        principal and interest payments discounted at the Trust's credit
        adjusted risk free rate.

        Interest paid during the first quarter of 2009 was $1.4 million less
        than interest expense ($0.8 million less than interest expense in the
        first quarter of 2008).

        On April 14, 2009, the Trust closed a private placement of long-term
        debt in the form of senior secured notes totaling US$125 million at a
        blended average interest rate of 7.47 per cent. The notes were
        offered in three tranches, one tranche of US$67.5 million senior
        notes with a five year average life repayable in years 2012 through
        2016 issued at an interest rate of 7.19 per cent. The second tranche
        of US$35 million senior notes with a 10 year average life repayable
        in years 2017 through 2021, issued at an interest rate of 8.21 per
        cent. The third tranche of Cdn$29 million senior notes was issued
        with a five year average life repayable in years 2012 through 2016
        and at an interest rate of 6.5 per cent.

        In April 2009, ARC extended its uncommitted master shelf agreement
        from May 2009 to April 2012. The extended agreement allows for an
        aggregate draw of up to US$225 million (Cdn$283.5 million) in long
        term notes at a rate equal to the related U.S. treasuries
        corresponding to the term of the notes plus an appropriate credit
        risk adjustment at the time of issuance. As at March 31, 2009, the
        Trust has drawn US$87 million (Cdn$ 109.6 million) under this
        agreement. These amounts are reflected in the above table.

        The Trust's long-term debt is secured in the form of a floating
        charge on all lands and assignments and a negative pledge on
        petroleum and natural gas properties.

    7.  ASSET RETIREMENT OBLIGATIONS

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

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Balance, beginning of period              $      141.5  $      140.0
        Increase in liabilities relating to
         development activities                            0.4           2.0
        Increase in liabilities relating to
         change in estimate                                  -           2.6
        Settlement of liabilities during
         the period                                       (1.7)        (12.4)
        Accretion expense                                  2.3           9.3
        ---------------------------------------------------------------------
        Balance, end of period                    $      142.5  $      141.5
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Trust's weighted average credit adjusted risk free rate as at
        March 31, 2009 was 6.6 per cent (6.6 per cent as at December 31,
        2008).

    8.  CAPITAL MANAGEMENT

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

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

        The Trust manages the following capital:

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

        When evaluating the Trust's capital structure, management's objective
        is to limit net debt to less than 2.0 times annualized cash flow from
        operating activities and 20 per cent of total capitalization. As at
        March 31, 2009 the Trust's net debt to annualized cash flow from
        operating activities ratio is 1.6 and its net debt to total
        capitalization ratio is 19 per cent.

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Long-term debt                                   703.8         901.8
        Accounts payable and accrued liabilities         192.4         194.4
        Distributions payable                             28.1          32.5
        Cash and cash equivalents, accounts
         receivable and prepaid expenses                (142.8)       (166.8)
        ---------------------------------------------------------------------
        Net debt obligations(1)                          781.5         961.9
        ---------------------------------------------------------------------

        Trust units outstanding and issuable for
         exchangeable shares (millions)                  236.0         219.2
        Trust unit price                                 14.15         20.10
        ---------------------------------------------------------------------
        Market capitalization(1)                       3,339.4       4,405.9
        Net debt obligations(1)                          781.5         961.9
        ---------------------------------------------------------------------
        Total capitalization(1)                        4,120.9       5,367.8
        ---------------------------------------------------------------------

        Net debt as a percentage of total
         capitalization                                  19.0%         17.9%
        Net debt obligations to annualized cash
         flow from operating activities                   1.6           1.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Market capitalization, net debt obligations and total
            capitalization as presented do not have any standardized meaning
            prescribed by Canadian GAAP and therefore may not be comparable
            with the calculation of similar measures for other entities.


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

        In addition to internal capital management the Trust is subject to
        various covenants under its credit facilities. Compliance with these
        covenants is monitored on a quarterly basis and as at March 31, 2009
        the Trust is in compliance with all covenants. Refer to Note 6 for
        further details.

    9.  MARKET RISK MANAGEMENT

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

        Following is a summary of all risk management contracts in place as
        at March 31, 2009 that do not qualify for hedge accounting:

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

        ---------------------------------------------------------------------
        Financial Cdn$ WTI Crude Oil Swap Contracts(2)
        ---------------------------------------------------------------------
                                                    Sold
                                        Volume      Swap
        Term              Contract       Bbl/d  Cdn$/bbl
        ---------------------------------------------------------------------
        Apr 09                Swap       4,000     62.65
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (2) Monthly average

        ---------------------------------------------------------------------
        Financial AECO Natural Gas Option Contracts(3)
        ---------------------------------------------------------------------
                                                  Bought
                                        Volume       Put  Sold Put Sold Call
        Term              Contract        GJ/d   Cdn$/GJ   Cdn$/GJ   Cdn$/GJ
        ---------------------------------------------------------------------
        Apr 09 -
         Dec 09     3 - Way Collar      20,000      6.50      4.50      8.00
        Apr 09 -
         Oct 09             Collar      20,000      4.25         -      5.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (3) AECO 7a monthly index

        ---------------------------------------------------------------------
        Energy Equivalent Swap Contracts(4)(5)
        ---------------------------------------------------------------------

        Term                        Contract         Volume             Swap
        ---------------------------------------------------------------------
        Financial AECO Natural
         Gas Sales Contract
         Apr 09 - Dec 09                Swap    10,000 GJ/d     Cdn$ 4.67/GJ
        Financial Cdn$ WTI Crude
         Oil Purchase Contract
         Apr 09 - Dec 09                Swap      650 bbl/d   Cdn$ 71.95/bbl
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (4) AECO 5a monthly index
        (5) Monthly average

        ---------------------------------------------------------------------
        Financial Basis Swap Contract(6)
        ---------------------------------------------------------------------
                                                 Volume   Basis Swap
        Term                       Contract     mmbtu/d    US$/mmbtu
        ---------------------------------------------------------------------
        Apr 09 - Oct 10      Basis Swap-L3d      50,000     (1.0430)
        Nov 10 - Oct 11       Basis Swap-Ld      20,000     (0.4850)
        Nov 11 - Oct 12       Basis Swap-Ld      20,000     (0.4050)
        ---------------------------------------------------------------------
        (6) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO
            Monthly 7a

        ---------------------------------------------------------------------
        Financial Electricity Heat Rate Contracts(7)
        ---------------------------------------------------------------------
                                                    AESO   AECO  multi- Heat
                                        Volume     Power   5(a)  plied  Rate
        Term              Contract         MWh     $/MWh   $/GJ  by   GJ/MWh
        ---------------------------------------------------------------------
        Jan 10 -                                 Receive    Pay
         Dec 13     Heat Rate Swap         5.0      AESO   AECO          9.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (7) Alberta Power Pool (monthly average 24x7), AECO Monthly (5a)

        ---------------------------------------------------------------------
        Financial Electricity Contracts(8)
        ---------------------------------------------------------------------
                                                  Bought
                                        Volume      Swap
        Term              Contract         MWh  Cdn$/MWh
        ---------------------------------------------------------------------
        Apr 09 -
         Dec 12               Swap         5.0     72.50
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (8) Alberta Power Pool (monthly average 24x7)

        Following is a summary of all risk management contracts in place as
        at March 31, 2009 that qualify for hedge accounting:

        ---------------------------------------------------------------------
        Financial Electricity Contracts(9)
        ---------------------------------------------------------------------
                                                  Bought
                                        Volume      Swap
        Term              Contract         MWh  Cdn$/MWh
        ---------------------------------------------------------------------
        Apr 09 -
         Dec 09               Swap        15.0     59.33
        Jan 10 -
         Dec 10               Swap         5.0     63.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (9) Alberta Power Pool (monthly average 24x7)

        At March 31, 2009, the fair value of the contracts that were not
        designated as accounting hedges was a loss of $3.2 million. The Trust
        recorded a gain on risk management contracts of $9.7 million in the
        statement of income for the period ended March 31, 2009
        ($48.2 million loss in 2008). This amount includes the realized and
        unrealized gains and losses on risk management contracts that do not
        qualify as effective accounting hedges.

        The following table reconciles the movement in the fair value of the
        Trust's financial risk management contracts that have not been
        designated as effective accounting hedges:

        ---------------------------------------------------------------------
                                                      March 31,     March 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Fair value, beginning of period           $        3.4  $      (64.6)
        Fair value, end of period(1)                      (3.2)        (83.3)
        ---------------------------------------------------------------------
        Change in fair value of contracts
         in the period                                    (6.6)        (18.7)
        Realized gain (loss) in the period                16.3         (29.5)
        ---------------------------------------------------------------------
        Gain (loss) on risk management contracts  $        9.7  $      (48.2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Intrinsic value of risk management contracts not designated as
            effective accounting hedges equals a loss of $5.9 million at
            March 31, 2009 ($57.5 million loss at March 31, 2008).

        During 2007 the Trust entered into treasury rate lock contracts in
        order to manage the Trust's interest rate exposure on future debt
        issuances. During 2008 it was determined that the previously
        anticipated debt issuance was no longer expected to occur and the
        associated treasury rate lock contracts were unwound at a cost of
        $13.6 million. These contracts were originally designated as
        effective accounting hedges on their respective contract dates and
        hedge accounting was applied. During 2008, the $13.6 million loss was
        reclassified from Other Comprehensive Income ("OCI"), net of tax and
        recognized in net income.

        The Trust's electricity contracts are intended to manage price risk
        on electricity consumption. Portions of the Trust's financial
        electricity contracts were designated as effective accounting hedges
        on their respective contract dates. A realized gain of $0.1 million
        for the three months ended March 31, 2009 (gain of $0.5 million in
        2008) has been included in operating costs on these electricity
        contracts. The unrealized fair value gain of $0.3 million on these
        contracts has been recorded on the Consolidated Balance Sheet at
        March 31, 2009 with the movement in fair value recorded in OCI, net
        of tax. The fair value movement for the period ended March 31, 2009
        is an unrealized loss of $3.0 million. As at March 31, 2009
        $0.2 million of the unrealized fair value gain is attributed to
        contracts that will settle over the next twelve months.

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

        ---------------------------------------------------------------------
                                                      March 31,     March 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Fair value, beginning of period           $        3.3  $       (3.4)
        Change in fair value of financial
         electricity contracts                            (3.0)          1.8
        Change in fair value of treasury rate
         lock contracts prior to de-designation              -          (6.2)
        Reclassification of loss on treasury
         rate lock contracts to net income                   -          13.6
        ---------------------------------------------------------------------
        Fair value, end of period(1)              $        0.3  $        5.8
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Intrinsic value of risk management contracts designated as
            effective accounting hedges equals a gain of $0.3 million at
            March 31, 2009 ($5.7 million gain at March 31, 2008).

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

    10. EXCHANGEABLE SHARES

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
        (thousands)                                       2009          2008
        ---------------------------------------------------------------------
        Balance, beginning of period                     1,092         1,310
        Exchanged for trust units(1)                      (159)         (218)
        ---------------------------------------------------------------------
        Balance, end of period                             933         1,092
        Exchange ratio, end of period                  2.57665       2.51668
        Trust units issuable upon conversion,
         end of period                                   2,404         2,748
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) During the first three months of 2009, 159,116 ARL exchangeable
            shares were converted to trust units at an average exchange ratio
            of 2.55441, compared to 218,455 exchangeable shares at an average
            exchange ratio of 2.36901 during the year ended 2008.

        Following is a summary of the non-controlling interest for 2009 and
        2008:

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Non-controlling interest, beginning
         of period                                $       42.4  $       43.1
        Reduction of book value for conversion
         to trust units                                   (6.2)         (7.6)
        Current period net income attributable
         to non-controlling interest                       0.2           6.9
        ---------------------------------------------------------------------
        Non-controlling interest, end of period           36.4          42.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Accumulated earnings attributable to
         non-controlling interest                 $       41.2  $       41.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. UNITHOLDERS' CAPITAL

        ---------------------------------------------------------------------
                              March 31, 2009            December 31, 2008
        ---------------------------------------------------------------------
                         Number of                   Number of
        (thousands)    trust units             $   trust units             $
        ---------------------------------------------------------------------
        Balance,
         beginning
         of period         216,435       2,600.7       210,232       2,465.7
        Issued for cash     15,474         253.0             -             -
        Issued on
         conversion
         of ARL
         exchangeable
         shares (Note 10)      406           6.2           517           7.6
        Issued on exercise
          of employee
          rights                 -             -           238           4.2
        Distribution
         reinvestment
         program             1,269          18.7         5,448         123.2
        Trust unit
         issue costs,
         net of tax(1)           -         (11.0)            -             -
        ---------------------------------------------------------------------
        Balance, end
         of period         233,584       2,867.6       216,435       2,600.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Amount is net of tax of $1.9 million for the period ended
            March 31, 2009.

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

        ---------------------------------------------------------------------
                                                      March 31,     March 31,
        (thousands)                                       2009          2008
        ---------------------------------------------------------------------
        Weighted average trust units(1)                226,477       211,028
        Trust units issuable on conversion of
         exchangeable shares(2)                          2,404         2,746
        Dilutive impact of rights(3)                         -           172
        ---------------------------------------------------------------------
        Diluted trust units and exchangeable shares    228,881       213,946
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Weighted average trust units exclude trust units issuable for
            exchangeable shares.
        (2) Diluted trust units include trust units issuable for outstanding
            exchangeable shares at the year-end exchange ratio.
        (3) There are no rights outstanding as of March 31, 2009 and
            therefore, no dilutive impact. Previously outstanding rights were
            dilutive and therefore were included in the diluted unit
            calculation for 2008.

        Basic net income per unit has been calculated based on net income
        after non-controlling interest divided by weighted average trust
        units. Diluted net income per unit has been calculated based on net
        income before non-controlling interest divided by diluted trust
        units.

    12. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Accumulated earnings                      $    2,746.4  $    2,724.1
        Accumulated distributions                     (3,309.0)     (3,227.0)
        ---------------------------------------------------------------------
        Deficit                                   $     (562.6) $     (502.9)
        Accumulated other comprehensive
         (loss) income                                    (0.4)          1.9
        ---------------------------------------------------------------------
        Deficit and accumulated other
         comprehensive (loss) income              $     (563.0) $     (501.0)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Unrealized gains and losses on
         financial instruments designated as
         cash flow hedges                         $       (0.1) $        2.0
        Net unrealized gains and losses on
         available-for-sale reclamation funds'
         investments                                      (0.3)         (0.1)
        ---------------------------------------------------------------------
        Accumulated other comprehensive (loss)
         income, end of period                    $       (0.4) $        1.9
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    13. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
        DISTRIBUTIONS

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

        ---------------------------------------------------------------------
                                                      March 31,     March 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Cash flow from operating activities       $      124.3  $      209.9
        Deduct:
          Cash withheld to fund current period
           capital expenditures                          (43.8)        (79.8)
          Net reclamation fund withdrawals
           (contributions)                                 1.5          (3.3)
        ---------------------------------------------------------------------
        Distributions(1)                                  82.0         126.8
        Accumulated distributions, beginning
         of period                                     3,227.0       2,657.0
        ---------------------------------------------------------------------
        Accumulated distributions, end of period  $    3,309.0  $    2,783.8
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Distributions per unit(2)                 $       0.36  $       0.60
        Accumulated distributions per unit,
         beginning of period                      $      23.70  $      21.03
        Accumulated distributions per unit,
         end of period(3)                         $      24.06  $      21.63
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Distributions include accrued and non-cash amounts of
            $13.8 million for the period ended March 31, 2009 ($26 million
            for the period ended March 31, 2008).
        (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. WHOLE TRUST UNIT INCENTIVE PLAN

        Compensation expense associated with the Whole Trust Unit Incentive
        Plan ("the Whole Unit Plan") is granted in the form of Restricted
        Trust Units ("RTUs") and Performance Trust Units ("PTUs") and is
        determined based on the intrinsic value of the Whole Trust Units at
        each period end.

        The Trust recorded non-cash compensation (recovery) expense of
        $(10.8) million and $(1.3) million to general and administrative and
        operating expenses, respectively, and capitalized $(2.2) million to
        property, plant and equipment in the three months ended March 31,
        2009 for the estimated change in the Plan liability ($11.9 million,
        $1.9 million, and $2.0 million as expense for the three months ended
        March 31, 2008). The non-cash compensation recovery was based on the
        March 31, 2009 unit price of $14.15 ($26.38 at March 31, 2008),
        accrued distributions, a performance multiplier, and the estimated
        number of units to be issued on maturity.

        The following table summarizes the RTU and PTU movement for the three
        months ended March 31, 2009:

        ---------------------------------------------------------------------
                                                     Number of     Number of
                                                          RTUs          PTUs
                                                    (thousands)   (thousands)
        ---------------------------------------------------------------------
        Balance, beginning of period                       756           959
        Granted                                            377           244
        Vested                                            (180)         (154)
        Forfeited                                          (15)          (10)
        ---------------------------------------------------------------------
        Balance, end of period                             938         1,039
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                                                      March 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Balance, beginning of period              $       31.9  $       30.3
        Change in net liabilities in the period
          General and administrative expense             (10.8)          1.1
          Operating expense                               (1.3)         (0.1)
          Property, plant and equipment                   (2.2)          0.6
        ---------------------------------------------------------------------
        Balance, end of period(1)                 $       17.6  $       31.9
        ---------------------------------------------------------------------
        Current portion of liability                      10.9          18.8
        ---------------------------------------------------------------------
        Accrued long-term incentive compensation  $        7.0  $       14.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Includes $0.3 million of recoverable amounts recorded in accounts
            receivable as at March 31, 2009 ($1.1 million for 2008).

        During the first three months of 2009 cash payments of $7.8 million
        were made to employees relating to the Whole Unit Plan compared to
        $18.5 million paid in April of 2008. In October 2008, vesting periods
        were revised from April and October to March and September of each
        year commencing in 2009.

    15. COMMITMENTS AND CONTINGENCIES

        Following is a summary of the Trust's contractual obligations and
        commitments as at March 31, 2009:

        ---------------------------------------------------------------------
                                             Payments due by period
        ---------------------------------------------------------------------
                                             2010-    2012-   There-
                                    2009     2011     2013    after    Total
        ---------------------------------------------------------------------
        Debt repayments(1)          22.8    492.0     81.4    107.6    703.8
        Interest payments(2)        11.8     22.9     15.9     10.2     60.8
        Reclamation fund
         contributions(3)            5.3      9.5      8.3     67.9     91.0
        Purchase commitments         8.0     13.0      7.1      5.1     33.2
        Transportation
         commitments(4)                -     14.9     21.9     21.0     57.8
        Operating leases             5.7      9.8     14.3     81.8    111.6
        Risk management contract
         premiums(5)                14.1        -        -        -     14.1
        ---------------------------------------------------------------------
        Total contractual
         obligations                67.7    562.1    148.9    293.6  1,072.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Long-term and short-term debt, excluding interest.
        (2) Fixed interest payments on senior secured notes.
        (3) Contribution commitments to a restricted reclamation fund
            associated with the Redwater property.
        (4) Fixed payments for transporting production from the Dawson gas
            plant, expected to be operational in early 2010.
        (5) Fixed premiums to be paid in future periods on certain commodity
            risk management contracts.

        In addition to the above Risk management contract premiums, the Trust
        has commitments related to its risk management program (see Note 9).

        The Trust enters into commitments for capital expenditures in advance
        of the expenditures being made. At a given point in time, it is
        estimated that the Trust has committed to capital expenditures equal
        to approximately one quarter of its capital budget by means of giving
        the necessary authorizations to incur the expenditures in a future
        period. The Trust's 2009 capital budget has been set at $350 million.
        This commitment has not been disclosed in the commitment table as it
        is of a routine nature and is part of normal course of operations for
        active oil and gas companies and trusts.

        The 2009 capital budget of $350 million includes approximately
        $11 million for leasehold development costs related to the Trust's
        new office space in downtown Calgary. These costs will be incurred
        throughout 2009 with additional amounts to be incurred in 2010. The
        operating lease commitments for the new space are included in the
        table above.

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

    %SEDAR: 00001245E          %CIK: 0001029509




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., 2100, 440 - 2nd Avenue S.W., Calgary, AB,
T2P 5E9


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