ARC Energy Trust announces fourth quarter and year-end 2008 results



    CALGARY, Feb. 11 /CNW/ - (AET.UN and ARX - TSX) ARC Energy Trust ("ARC"
or "the Trust") announces the results for the fourth quarter and the year
ended December 31, 2008.

    
                                     Three Months Ended   Twelve Months Ended
                                         December 31           December 31
                                       2008       2007       2008       2007
    -------------------------------------------------------------------------
    FINANCIAL
    (Cdn$ millions, except per
     unit and per boe amounts)
    Revenue before royalties          300.8      338.0    1,706.4    1,251.6
      Per unit(1)                      1.38       1.59       7.90       5.95
      Per boe                         50.06      57.42      71.59      54.67
    Cash flow from operating
     activities(2)                    209.4      173.7      944.4      704.9
      Per unit(1)                      0.96       0.82       4.37       3.35
      Per boe                         34.85      29.51      39.62      30.79
    Net income                         82.7      106.3      533.0      495.3
      Per unit(3)                      0.38       0.51       2.50       2.39
    Distributions                     127.2      125.8      570.0      498.0
      Per unit(1)                      0.59       0.60       2.67       2.40
      Per cent of cash flow from
       operating activities(2)           61         72         60         71
    Net debt outstanding(4)           961.9      752.7      961.9      752.7
    OPERATING
    Production
      Crude oil (bbl/d)              28,935     28,682     28,513     28,682
      Natural gas (mmcf/d)            195.1      187.4      196.5      180.1
      Natural gas liquids (bbl/d)     3,858      4,067      3,861      4,027
      Total (boe/d)                  65,313     63,989     65,126     62,723
    Average prices
      Crude oil ($/bbl)               56.26      77.53      94.20      69.24
      Natural gas ($/mcf)              7.48       6.32       8.58       6.75
      Natural gas liquids ($/bbl)     45.22      62.75      69.71      54.79
      Oil equivalent ($/boe)          49.93      57.26      71.25      54.54
    Operating netback ($/boe)
      Commodity and other revenue
       (before hedging)(5)            50.06      57.42      71.59      54.67
      Transportation costs            (0.86)     (0.69)     (0.80)     (0.72)
      Royalties                       (9.14)    (10.46)    (12.91)     (9.59)
      Operating costs                (10.09)     (9.64)    (10.13)     (9.54)
      Netback (before hedging)        29.97      36.63      47.75      34.82
    -------------------------------------------------------------------------
    TRUST UNITS
    (millions)
    Units outstanding, end
     of period(6)                     219.2      213.2      219.2      213.2
    Weighted average units(7)         218.3      212.5      216.0      210.2
    -------------------------------------------------------------------------
    TRUST UNIT TRADING STATISTICS
    (Cdn$, except volumes) based
     on intra-day trading
    High                              22.55      21.55      33.95      23.86
    Low                               15.01      18.90      15.01      18.90
    Close                             20.10      20.40      20.10      20.40
    Average daily volume (thousands)  1,523        624        975        597
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 fourth quarter of 2008 would be
        $172.9 million ($0.79 per unit) and $936.5 million ($4.34 per unit)
        year-to-date. Distributions as a percentage of Cash Flow would be
        74 per cent for the fourth quarter of 2008 (61 per cent year-to-
        date). 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 2008, includes 1.1 million (1.3 million in 2007) exchangeable
        shares exchangeable into 2.517 trust units (2.250 in 2007) each for
        an aggregate 2.7 million (2.9 million in 2007) trust units.
    (7) Includes trust units issuable for outstanding exchangeable shares at
        period end.


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

    -   The Trust had record cash flow from operating activities of
        $944.4 million ($4.37 per unit) for the full year of 2008 as compared
        to $704.9 million ($3.35 per unit) in 2007. Record high oil prices
        through the majority of the year and record annual production
        contributed to the significant increase in cash flows during 2008.
        While oil prices declined dramatically in the last quarter of 2008,
        the annual average realized oil price was $94.20 per boe as compared
        to $69.24 per boe in 2007. An increase in the Trust's natural gas
        price also contributed to the increase in cash flows, along with an
        increase in natural gas production for the year.

    -   Record production volumes for 2008 averaged 65,126 boe per day, a
        four per cent increase over 2007 volumes, as a result of the Trust's
        active drilling program and growth in gas production in the Dawson
        area. Average daily production per unit has remained constant at
        0.30 boe per one thousand units compared to 2007.

    -   During 2008, the Trust distributed $570 million ($2.67 per unit), a
        record for the Trust. Monthly distribution amounts were revised
        throughout 2008 in response to the unprecedented volatility in the
        commodity price environment observed throughout the year where US$
        West Texas Intermediate Crude Oil prices rose as high as
        US$147.27 per barrel in July and declined as low as US$32.41 per
        barrel in December. The Trust's fourth quarter distributions were
        $127.2 million or $0.59 per unit. Subsequent to year-end, the Trust
        further decreased monthly distributions to $0.12 per unit in light of
        ongoing weak commodity prices and in order to provide the Trust with
        a more appropriate balance between cash retained to fund ongoing
        capital expenditures for the future benefit of unitholders and the
        cash paid out monthly to unitholders.

    -   The Trust executed a $548.6 million capital expenditure program in
        2008 that included the purchase of undeveloped land for
        $122.4 million and $426.2 million of development activities. The
        Trust drilled 178 net wells on operated properties with a 99 per cent
        success rate. The 2008 capital expenditures were 91 per cent funded
        by cash flow from operating activities and proceeds from the DRIP
        program and the remaining portion was funded through debt.

    -   The Trust replaced 248 per cent of annual production with the
        addition of 59.2 million barrels of oil equivalent ("mmboe") of
        proved plus probable reserves in 2008. Total proved reserves
        increased eight per cent to 243 mmboe and total proved plus probable
        reserves increased 12 per cent to 322 mmboe relative to 2007. The
        Trust's all-in annual Finding, Development and Acquisition ("FD&A")
        costs were $10.13 per boe before consideration of future development
        capital ("FDC") for the proved plus probable reserves category. This
        is a 47 per cent reduction from the $19 per boe FD&A cost realized in
        2007. Including FDC, 2008 FD&A cost decreased 15 per cent to $17 per
        boe compared to $20.03 per boe in 2007. This success has been
        achieved through internal development of the Trust's existing asset
        base. Additional information on the reserves evaluation can be found
        in the "ARC Energy Trust Releases 2008 Year-end Reserves Information"
        news release dated February 11, 2009 and filed on SEDAR at
        www.sedar.com.

    -   With the recent global economic downturn and weak commodity price
        environment, the Trust has been challenged with ensuring that
        sufficient funds are available to fund the Trust's capital
        expenditure program. The Trust has been disciplined and kept a strong
        balance sheet with conservative debt levels when compared to cash
        flow and total capitalization. In January 2009, the Trust completed
        an equity offering of 15.5 million trust units for net proceeds of
        $240 million that was used to reduce current indebtedness, freeing up
        credit capacity to fund the 2009 capital budget which is currently
        set at $450 million. The proceeds of the equity offering were
        received on February 6, 2009 reducing debt levels to approximately
        $645 million. The Trust is confident that it is well positioned to
        capitalize on existing opportunities and proceed with growth and
        expansion opportunities in 2009 and 2010.

    -   Montney Resource Play Development

        During the fourth quarter at Dawson, the Trust spent $51.5 million on
        exploration and development activities and a further $43 million on
        the acquisition of crown land and lands from other industry
        participants for a total of $94.5 million. Collectively, the land
        acquisitions added 8.75 sections of highly prospective land in and
        around our core Montney development areas, bringing our total land
        holdings to 186 net sections of Montney rights in the Dawson area of
        British Columbia. For the full year 2008, the Trust spent
        $123.8 million on exploration and development activities,
        $80.3 million on crown land purchases and $51 million on property
        acquisitions from third parties consisting of predominantly
        undeveloped land.

        At the main Dawson field, ARC drilled two wells and completed nine
        wells. With the completion of an NEB regulated sales gas pipeline in
        mid November that transports ARC's production from Dawson to Alberta,
        ARC was able to increase production during the fourth quarter to
        46.5 mmcf per day, with peak rates above 50 mmcf per day. Further
        production growth through the new NEB line is contingent upon the
        completion of a third party compressor installation scheduled for the
        first quarter of 2009. At year-end, the Trust had 12 vertical wells
        and 3 horizontal wells waiting on tie-in.

        ARC drilled a total of six wells on the West Montney exploratory
        acreage during the fourth quarter, with two wells at Sunrise, two
        wells at Saturn and one each at Monias and Sundown. To the end of
        2008, the Trust has drilled three horizontal wells and seven
        vertical wells on the West Montney lands and completed two
        horizontal and three vertical wells, including one well that was
        drilled in 2007. The Trust plans on testing the remaining six wells
        during 2009. The trust is evaluating the processing facility and
        pipeline options required to bring this gas to market.

        The Trust continues to work towards a first quarter 2010 completion
        date for a new 60 mmcf per day gas plant for Dawson. Design work is
        nearing completion, long-lead time items have been ordered and
        public notification letters have been distributed. After the public
        notification process is complete, the applications will be submitted
        to the appropriate regulatory agencies.

    -   Enhanced Oil Recovery Initiatives

        During the fourth quarter, the Trust spent $14.8 million on enhanced
        oil recovery ("EOR") initiatives. The Redwater CO(2) pilot project is
        well underway and on schedule. The Trust expects that it will take
        until at least the first quarter of 2010 before it will know if 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 impact
        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 February 10,
2009 and should be read in conjunction with the audited Consolidated Financial
Statements as at and for the year ended December 31, 2008, the audited
Consolidated Financial Statements and MD&A as at and for the year ended
December 31, 2007, the MD&A and the unaudited Consolidated Financial
Statements as at and for the periods ended March 31, 2008, June 30, 2008 and
September 30, 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. ARC as at December 31, 2008 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 December 31, 2008 was $5.4 billion as shown on
Table 23. Subsequent to year-end, the Trust completed an equity offering of
15.5 million units for net proceeds of $240 million bringing the total
capitalization to approximately $4 billion as at February 10, 2009.
    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 annually. Currently the
        Trust distributes $0.12 per unit per month. 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 December 31, 2008, the Trust has distributed
        $3.3 billion or $23.70 per unit.

    -   Annual replacement of production and reserves through drilling new
        wells and associated oil and natural gas development activities. The
        vast majority of the annual capital budget is being deployed on a
        balanced drilling program of low and moderate risk wells, well tie-
        ins and other related costs, and the acquisition of undeveloped land.
        The Trust continues to focus on major properties with significant
        upside, with the objective to replace production declines through
        internal development opportunities. Calculated on a boe basis, ARC's
        normalized reserves per unit have increased from 1.40 to 1.42;
        production per unit has decreased slightly from 0.31 to 0.29 while
        the Trust has made distributions of $7.47 per unit or $1.6 billion
        from January 1, 2006 through to December 31, 2008. 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.

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

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

    ARC's business plan and operating practices also include the following
strategies and action plans that are being 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 our 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 we live and work.


    Table 1
    -------------------------------------------------------------------------
    Per Trust Unit                                2008       2007       2006
    -------------------------------------------------------------------------
    Normalized production per unit(1)(2)          0.29       0.30       0.31
    Normalized reserves per unit(1)(3)            1.42       1.35       1.40
    Distributions per unit                       $2.67      $2.40      $2.40
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Normalized indicates that all years as presented have been adjusted
        to reflect a net debt to capitalization of 15 per cent. It is assumed
        that additional trust units were issued (or repurchased) at a period
        end price for the reserves per unit calculation and at an annual
        average price for the production per unit calculation in order to
        achieve a net debt balance of 15 per cent of total capitalization
        each year. The normalized amounts are presented to enable
        comparability of annual per unit values.
    (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.
    

    The effectiveness of ARC's business plan can best be measured by
historical results as shown in Table 2. Commodity prices and the ongoing
economic crisis are significant factors in determining profitability and
market returns of the units. The successful execution of ARC's business plan
and operational successes, contributed to our 9.7 per cent annual return for
2008 despite the negative impact of external factors.

    
    Table 2
    -------------------------------------------------------------------------
    Total Returns (1)                       Trailing    Trailing    Trailing
    ($ per unit except for per cent)        One Year  Three Year   Five Year
    -------------------------------------------------------------------------
    Distributions per unit                $     2.67  $     7.47  $    11.26
    Capital appreciation per unit         $    (0.30) $    (6.39) $     5.36
    Total return per unit                 $     2.37  $     1.08  $    16.62
    Annualized total return per unit            9.7%        1.1%       17.9%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Calculated as at December 31, 2008.


    2008 Review and 2009 Guidance

    Table 3 is a summary of the Trust's 2009 Revised Guidance and a review of
2008 actual results compared to guidance:

    Table 3
    -------------------------------------------------------------------------
                                               2008        %
                             2008 Guidance   Actual   Change   2009 Guidance
    -------------------------------------------------------------------------
    Production (boe/d)       64,000-65,000   65,126        -   64,000-65,000
    -------------------------------------------------------------------------
    Expenses ($/boe):
      Operating costs                10.20    10.13       (1)          10.70
      Transportation                  0.80     0.80        -            1.15
      G&A expenses(1)                 2.75     2.57       (7)           2.80
      Interest                        1.50     1.38       (8)           1.85
    Capital expenditures
     ($ millions)                      530    548.6        4             450
    Weighted average trust
     units and units
     issuable (millions)(2)            216      216        -             235
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The components of the $2.80 per boe G&A guidance for the full year
        are as follows: cash G&A - $1.80 per boe; cash component of LTIP -
        $0.85 per boe; non-cash LTIP component - $0.15 per boe
    (2) 2009 guidance for weighted average trust units has been revised to
        include the 15.5 million trust units issued on February 6, 2009 under
        the Trust's equity offering.


    The 2009 Guidance provides unitholders with information of management's
expectations for results of operations for 2009. Readers are cautioned that
the 2009 Guidance may not be appropriate for other purposes.
    Actual results for 2008 were in line with 2008 guidance with some minor
exceptions as follows:

    -   G&A expenses of $2.57 per boe were lower than guidance of $2.75 per
        boe due primarily to the decrease in the trust unit price at year-end
        which resulted in a lower non-cash LTIP expense of $0.05 per boe as
        compared to the guidance amount of $0.15 per boe.

    -   Interest expense for 2008 was $1.38 as compared to guidance of
        $1.50 due to lower short-term interest rates on the Trust's floating
        rates debt. In addition, with record cash flow levels posted, the
        Trust was able to cash fund a higher portion of capital expenditures
        in the year.

    -   Capital expenditures exceeded guidance by $18.6 million due to
        additional expenditures and crown land purchases incurred in the
        Northern area during the fourth quarter of 2008.


    2008 Annual Financial and Operational Results

    Following is a discussion of ARC's 2008 annual financial and operating
results.

    Financial Highlights

    Table 4
    -------------------------------------------------------------------------
    (Cdn $ millions, except
     per unit and volume data)                    2008       2007   % Change
    -------------------------------------------------------------------------
    Cash flow from operating activities          944.4      704.9         34
    Cash flow from operating activities
     per unit(1)                                  4.37       3.35         30
    Net income                                   533.0      495.3          8
    Net income per unit(2)                        2.50       2.39          5
    Distributions per unit(3)                     2.67       2.40         11
    Distributions as a per cent of cash
     flow from operating activities                 60         71        (15)
    Average daily production (boe/d)(4)         65,126     62,723          4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Per unit amounts are based on weighted average trust units
        outstanding plus trust units issuable for exchangeable shares at
        year-end.
    (2) Based on net income after non-controlling interest divided by
        weighted average trust units outstanding excluding trust units
        issuable for exchangeable shares.
    (3) Based on number of trust units outstanding at each cash distribution
        date.
    (4) Reported production amount is based on company interest before
        royalty burdens. Where applicable in this MD&A natural gas has been
        converted to barrels of oil equivalent ("boe") based on 6 mcf: 1 bbl.
        The boe rate is based on an energy equivalent conversion method
        primarily applicable at the burner tip and does not represent a value
        equivalent at the well head. Use of boe in isolation may be
        misleading.


    Net Income

    Net income in 2008 was $533 million ($2.50 per unit), an increase of $37.7
million from $495.3 million ($2.39 per unit) in 2007. While cash flow from
operating activities increased $239.5 million in 2008 compared to the same
period in 2007 (see Table 6 for details), there were several non-cash items
that impacted the Trust's net income in the current year as follows:

    -   The Trust recorded a $68 million unrealized gain on risk management
        contracts, a $123.9 million increase compared to an unrealized loss
        of $55.9 million for the same period of 2007. The unrealized gain was
        attributed to the sharp decline in commodity prices at year-end.

    -   The Trust recorded an $88.5 million non-cash foreign exchange loss on
        its U.S. denominated debt as a result of the weakening of the
        Canadian dollar relative to the U.S. dollar during 2008 compared to a
        non-cash gain of $69.6 million in 2007.

    -   The Trust recorded a non-cash provision for non-recoverable accounts
        receivable of $32 million in 2008 ($nil in 2007) due primarily to a
        provision of $30.6 million recorded for an account receivable from
        one counterparty that marketed a portion of the Trust's production.
        See section titled Provision for Non-recoverable Accounts Receivable
        for details.

    -   The Trust recorded a $4.5 million future income tax recovery for 2008
        compared to a $121.3 million recovery in 2007. The 2007 future income
        tax recovery was attributed to a significant change in the
        Trust's future tax rate that came into effect during the year as
        compared to a small rate change in 2008.
    

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

    
    Table 5
    -------------------------------------------------------------------------
    Net income and Distributions
    ($ millions except per cent)                  2008       2007       2006
    -------------------------------------------------------------------------
    Net income                                   533.0      495.3      460.1
    Distributions                                570.0      498.0      484.2
    -------------------------------------------------------------------------
    Excess (Shortfall)                           (37.0)      (2.7)     (24.1)
    Excess (Shortfall) as per cent
     of net income                                 (7%)       (1%)       (5%)
    -------------------------------------------------------------------------
    Cash flow from operating activities          944.4      704.9      734.0
    Distributions as a per cent of cash
     flow from operating activities                60%        71%        66%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Cash Flow from Operating Activities

    Cash flow from operating activities increased by 34 per cent in 2008 to
$944.4 million from $704.9 million in 2007. The increase in 2008 cash flow
from operating activities is detailed in Table 6.

    Table 6
    -------------------------------------------------------------------------
                                                           ($ per
                                                            trust         (%
                                           ($ millions)      unit)  variance)
    -------------------------------------------------------------------------
    2007 Cash flow from Operating Activities     704.9       3.35          -
    -------------------------------------------------------------------------
    Volume variance                               51.5       0.25          7
    Price variance                               403.3       1.91         57
    Cash losses on risk management contracts     (89.8)     (0.43)       (13)
    Royalties                                    (88.3)     (0.42)       (13)
    Expenses:
      Transportation                              (2.6)     (0.01)         -
      Operating(1)                               (23.5)     (0.11)        (3)
      Cash G&A                                   (14.2)     (0.07)        (2)
      Interest                                     4.0       0.02          1
      Realized foreign exchange loss              (0.7)         -          -
    Weighted average trust units                     -      (0.12)         -
    Non-cash and other items(2)                   (0.2)         -          -
    -------------------------------------------------------------------------
    2008 Cash flow from Operating Activities     944.4       4.37          -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excludes non-cash portion of LTIP expense recorded in operating
        costs.
    (2) Includes the changes in non-cash working capital and expenditures on
        site restoration and reclamation.


    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)             $    48.55  $     1.00  $     0.04
    Natural gas price (Cdn $AECO/mcf)(1)  $     5.95  $     0.10  $     0.02
    Cdn$/US$ exchange rate                      1.27  $     0.01  $     0.02
    Interest rate on debt                 %     5.75  %      1.0  $     0.02
    Operational
    Liquids production volume (bbl/d)         31,500  %      1.0  $     0.03
    Gas production volumes (mmcf/d)            195.0  %      1.0  $     0.02
    Operating expenses per boe            $    10.70  %      1.0  $     0.01
    Cash G&A and LTIP expenses per boe    $     2.65  %     10.0  $     0.03
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Analysis does not include the effect of hedging contracts.
    (2) Assumes constant working capital.


    Production

    Production volumes averaged 65,126 boe per day in 2008 compared to 62,723
boe per day in 2007 as detailed in Table 8. Late in the fourth quarter of
2007, the Trust brought on new production in both the Dawson and Pouce Coupe
areas, achieving exit production of 65,000 boe per day in December 2007 and
maintained that production level throughout the full year of 2008.

    Table 8
    -------------------------------------------------------------------------
    Production                                    2008       2007   % Change
    -------------------------------------------------------------------------
    Light & medium crude oil (bbl/d)            27,239     27,366          -
    Heavy oil (bbl/d)                            1,274      1,316         (3)
    Natural gas (mmcf/d)                         196.5      180.1          9
    NGL (bbl/d)                                  3,861      4,027         (4)
    -------------------------------------------------------------------------
    Total production (boe/d)(1)                 65,126     62,723          4
    % Natural gas production                        50         48          4
    % Crude oil and liquids production              50         52         (4)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Reported production for a period may include minor adjustments from
        previous production periods.
    

    Oil production decreased slightly to 27,239 boe per day from 27,366 boe
per day in 2007. Natural gas production was 196.5 mmcf per day in 2008, an
increase of nine per cent from the 180.1 mmcf per day produced in 2007. The
increased gas production was a result of the Trust's active drilling program
in the Dawson area and the completion of a third party operated gas plant.
    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 2008, the Trust drilled 232 gross wells
(178 net wells) on operated properties; 138 gross oil wells, and 93 gross
natural gas wells with a 99 per cent success rate.
    The Trust expects that 2009 full year production will be approximately
64,000 to 65,000 boe per day and that 191 gross wells (171 net wells) will be
drilled by ARC on operated properties with participation in an additional 112
gross wells to be drilled on the Trust's non-operated properties. The Trust
estimates that the 2009 drilling program will add sufficient production from
new wells to offset production declines on existing properties. The planned
capital expenditures will be 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
    -------------------------------------------------------------------------
                                                        2008
    Production                        Total        Oil        Gas        NGL
    Core Area(1)                     (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
    -------------------------------------------------------------------------
    Central AB                        7,495      1,406       29.2      1,218
    Northern AB & BC                 22,469      5,318       93.7      1,534
    Pembina & Redwater               13,707      9,495       19.7        936
    S.E. AB & S.W. Sask.              9,701        985       52.2         11
    S.E. Sask. & MB                  11,754     11,309        1.7        162
    -------------------------------------------------------------------------
    Total                            65,126     28,513      196.5      3,861
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                                        2007
    Production                        Total        Oil        Gas        NGL
    Core Area(1)                     (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
    -------------------------------------------------------------------------
    Central AB                        7,967      1,596       30.3      1,319
    Northern AB & BC                 19,797      5,773       74.8      1,552
    Pembina & Redwater               13,703      9,474       19.2      1,034
    S.E. AB & S.W. Sask.             10,040      1,044       53.9         10
    S.E. Sask. & MB                  11,216     10,795        1.9        112
    -------------------------------------------------------------------------
    Total                            62,723     28,682      180.1      4,027
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
        is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is
        southwest.
    

    Revenue

    Revenue increased to an historical high of $1.7 billion in 2008, $454.8
million higher than 2007 revenues of $1.3 billion. While oil volumes were
relatively unchanged year over year, the increase in realized oil prices
generated additional oil revenue of $258.3 million. Natural gas revenue
increased by $173.4 million, comprising a $120.6 million increase due to
higher prices realized in 2008 and a $52.8 million increase due to higher
volumes produced in 2008.
    A breakdown of revenue is outlined in Table 10:

    
    Table 10
    -------------------------------------------------------------------------
    Revenue
    ($ millions)                                  2008       2007   % Change
    -------------------------------------------------------------------------
    Oil revenue                                  983.1      724.8         36
    Natural gas revenue                          616.8      443.4         39
    NGL revenue                                   98.5       80.5         22
    -------------------------------------------------------------------------
    Total commodity revenue                    1,698.4    1,248.7         36
    Other revenue                                  8.0        2.9        176
    Total revenue                              1,706.4    1,251.6         36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Commodity Prices Prior to Hedging

    Table 11
    -------------------------------------------------------------------------
                                                  2008       2007   % Change
    -------------------------------------------------------------------------
    Average Benchmark Prices
    AECO gas ($/mcf)(1)                           8.13       6.61         23
    WTI oil (US$/bbl)(2)                         99.66      72.37         38
    Cdn$/US$ foreign exchange rate                1.05       1.06         (1)
    WTI oil (Cdn$/bbl)                          104.30      77.35         35
    -------------------------------------------------------------------------
    ARC Realized Prices Prior to Hedging
    Oil ($/bbl)                                  94.20      69.24         36
    Natural gas ($/mcf)                           8.58       6.75         27
    NGL ($/bbl)                                  69.71      54.79         27
    -------------------------------------------------------------------------
    Total commodity revenue before
     hedging ($/boe)                             71.25      54.54         31
    Other revenue ($/boe)                         0.34       0.13        162
    Total revenue before hedging ($/boe)         71.59      54.67         31
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents the AECO monthly posting.
    (2) WTI represents West Texas Intermediate posting as denominated in US$.
    

    Although oil prices achieved record highs throughout 2008, peaking in
July at US$147.27 per barrel for WTI and averaging US$99.66 per barrel for the
full year, the sharp decline in oil prices during the fourth quarter of 2008
has resulted in exit 2008 oil prices at their lowest level since 2002. The
full impact of the price decline will not be realized until the first quarter
of 2009. The average Cdn$/US$ foreign exchange rate was 1.05 for the full year
of 2008; however, a sharp decline in the fourth quarter resulted in the
Canadian dollar closing at 1.22 per U.S. dollar on December 31, 2008. The
negative correlation between the Canadian dollar and U.S. dollar denominated
West Texas Intermediate oil prices should lessen the impact on the Trust of
any future declines in the price of oil, however, crude oil prices have
remained depressed in the early part of 2009 and investors should expect that
revenues in 2009 will be significantly lower than those recorded in 2008.
    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,
increased 36 per cent to $94.20 from $69.24 for the full year of 2007.
    Alberta AECO Hub natural gas prices, which are commonly used as an
industry reference, averaged $8.13 per mcf in 2008 compared to $6.61 per mcf
in 2007. ARC's realized gas price, before hedging, increased by 27 per cent to
$8.58 per mcf compared to $6.75 per mcf in 2007. 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.
    Prior to hedging activities, ARC's total realized commodity price was
$71.59 per boe in 2008, a 31 per cent increase from the $54.67 per boe
received prior to hedging in 2007.

    Risk Management and Hedging Activities

    ARC continues to maintain an ongoing risk management program to reduce
the volatility of revenues in order to increase the certainty of
distributions, protect acquisition economics, and fund capital expenditures.
The risk management program was revised in 2005 to maintain a significant
portion of upside price participation on production volumes.
    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.
    Strong commodity prices throughout most of 2008 had a significant impact
on the Trust's revenue; however, these strong prices resulted in realized cash
losses of $67.8 million and $11.4 million for the Trust's oil and natural gas
risk management contracts, respectively.
    During 2008, the Trust recorded a $16.2 million realized cash gain due
primarily to the unwinding of foreign exchange risk management contracts,
which had locked in the foreign exchange rates on future principal debt
repayments of US$127.2 million at an average rate of (1.02 Cdn$/US$).
Conversely, the Trust recorded a net cash loss of $12.7 million on its
interest rate risk management contracts. Included in this balance is a loss of
$13.6 million related to treasury lock contracts that were unwound in the
first quarter of 2008.
    ARC's 2008 results include an unrealized total mark-to-market gain of $68
million with a net unrealized mark-to-market gain position of $6.7 million as
at December 31, 2008. The mark-to-market values represent the market price to
buy-out the Trust's contracts as of December 31, 2008 and may be different
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 2008 year-end:

    
    Table 12
    -------------------------------------------------------------------------
    Risk Management Contracts     Crude Oil    Natural    Foreign
     ($ millions)                 & Liquids        Gas   Currency      Power
    -------------------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(1)                  (67.8)     (11.4)      16.2          -
    Unrealized gain (loss)
     on contracts(2)                   50.7       12.4       (2.6)       3.0
    -------------------------------------------------------------------------
    Total gain (loss) on risk
     management contracts             (17.1)       1.0       13.6        3.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    --------------------------------------------------------------
    Risk Management Contracts                     2008       2007
     ($ millions)                  Interest      Total      Total
    --------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(1)                  (12.7)     (75.7)      14.1
    Unrealized gain (loss)
     on contracts(2)                    4.5       68.0      (55.9)
    --------------------------------------------------------------
    Total gain (loss) on risk
     management contracts              (8.2)      (7.7)     (41.8)
    --------------------------------------------------------------
    --------------------------------------------------------------
    (1) Realized cash gains and losses represent actual cash settlements or
        receipts under the respective contracts.
    (2) The unrealized (loss) gain on contracts represents the change in fair
        value of the contracts during the period.

    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, natural gas and related foreign exchange
for the next twelve months as at December 31, 2008.

    Table 13
    -------------------------------------------------------------------------
    Hedge Positions
    As at December 31, 2008(1)(2)
                                          Q1 2009               Q2 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                         10.76     62,202       8.00     20,000
    Bought Put                         8.17     62,202       6.50     20,000
    Sold Put                           4.50     20,000       4.50     20,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Hedge Positions
    As at December 31, 2008(1)(2)
                                          Q3 2009               Q4 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                          8.00     20,000       8.00     20,000
    Bought Put                         6.50     20,000       6.50     20,000
    Sold Put                           4.50     20,000       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. In addition to positions
        shown here, ARC has entered into additional basis positions.
    (2) Please refer to note 13 in the Notes to the Consolidated Financial
        Statements for full details of the Trust's hedging positions as of
        December 31, 2008.


    Table 13 should be interpreted as follows using the first 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 $8.17 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
        $8.12 on 20,000 GJ per day.
    -   If the market price is between $4.50 and $8.17, ARC will receive
        $8.17 on 62,202 GJ per day.
    -   If the market price is between $8.17 and $10.76, ARC will receive the
        market price on 62,202 GJ per day.
    -   If the market price exceeds $10.76, ARC will receive $10.76 on 62,202
        GJ per day.
    

    Operating Netbacks

    The Trust's operating netback, before realized hedging gains and losses,
increased 37 per cent to $47.75 per boe in 2008 compared to $34.82 per boe in
2007. The increase in netbacks in 2008 is as a result of the significant
increase in revenue per boe that was partially offset by increased costs for
royalties, operating costs and transportation costs.
    The Trust's 2008 netback, after realized hedging gains and losses,
decreased to $44.58 per boe as a result of losses recorded on the Trust's
crude oil and natural gas contracts during the year of $3.17 per boe compared
to a small gain of $0.62 per boe recorded in 2007 that increased the 2007
netback to $35.44 per boe.
    The components of operating netbacks are summarized in Table 14:

    
    Table 14
    -------------------------------------------------------------------------
                                   Heavy                       2008     2007
    Netbacks          Crude Oil      Oil      Gas      NGL    Total    Total
    ($ per boe)          ($/bbl)  ($/bbl)  ($/mcf)  ($/bbl)  ($/boe)  ($/boe)
    -------------------------------------------------------------------------
    Weighted average
     sales price          94.97    77.85     8.58    69.71    71.25    54.54
    Other revenue             -        -        -        -     0.34     0.13
    -------------------------------------------------------------------------
    Total revenue         94.97    77.85     8.58    69.71    71.59    54.67
    Royalties            (14.58)   (8.41)   (1.82)  (19.58)  (12.91)   (9.59)
    Transportation        (0.14)   (1.17)   (0.24)       -    (0.80)   (0.72)
    Operating costs(1)   (13.91)  (11.63)   (1.19)   (8.22)  (10.13)   (9.54)
    -------------------------------------------------------------------------
    Netback prior to
     hedging              66.34    56.64     5.33    41.91    47.75    34.82
    Realized gain (loss)
     on risk management
     contracts            (7.03)       -    (0.16)       -    (3.17)    0.62
    -------------------------------------------------------------------------
    Netback after
     hedging              59.31    56.64     5.17    41.91    44.58    35.44
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 were relatively unchanged at 18.2 per cent ($12.91 per boe) in
2008 compared to 17.8 per cent ($9.59 per boe) in 2007. The Trust's typical
royalty rate has been approximately 18 per cent on a consolidated basis. Going
forward into 2009, the Trust expects to see more volatility in the royalty
rates as a result of the Alberta Government's New Royalty Framework. See
Alberta Government New Royalty Framework.
    Operating costs increased to $10.13 per boe compared to $9.54 per boe in
2007. Total operating costs increased $23.1 million, or 11 per cent in 2008.
The increased costs were in line with guidance and reflect the additional
costs associated with the approximately 300 new wells brought on stream during
2008. 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 the properties' production declines over time. The Trust estimates
that full year 2009 operating costs will be approximately $250 million or
approximately $10.70 per boe based on annual production of approximately
64,000 to 65,000 boe per day. This includes a six per cent increase for costs
associated with new drills in 2009.

    Alberta Government New Royalty Framework

    On April 10, 2008, the Alberta Government announced revisions to the New
Royalty Framework ("Framework" or "NRF"). The Framework 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 maximum rates 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 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.
    Approximately 65 per cent of the Trust's production is in Alberta;
consequently, the Framework 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
17 and 26 per cent of revenue in 2009 depending upon commodity prices as
illustrated in Table 15.

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

    -------------------------------------------------------------------------
    Current Alberta royalty rate(2)         17.5%    17.5%    17.5%    17.5%
    NRF Alberta royalty rate(3)             15.5%    20.0%    25.0%    29.0%
      % increase (decrease) -
       Alberta royalty rate                 (10)%      14%      43%      66%
    -------------------------------------------------------------------------
    Current Corporate royalty rate(2)       18.0%    18.0%    18.0%    18.0%
    NRF Corporate royalty rate(3)           17.0%    20.0%    23.0%    26.0%
    -------------------------------------------------------------------------
      % increase (decrease) -
       Corporate royalty rate                (6)%      11%      28%      44%
    -------------------------------------------------------------------------
      Increase (decrease) in annual
       Corporate royalties ($Millions)     $(10.0)   $15.0    $60.0   $125.0
    -------------------------------------------------------------------------
      Decrease (increase) annual
       cash flow per unit                  $(0.05)   $0.07    $0.27    $0.58
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Canadian dollar denominated prices before quality differentials.
    (2) Current Alberta and Corporate royalty rates are consistent across all
        price scenarios as price ceilings have been exceeded under the
        current royalty regime whereby royalty rates change 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
        Override royalties for all jurisdictions in which the Trust operates.
    

    Table 16 illustrates provincial royalty rates following implementation of
the Framework in Alberta. At low prices, royalty rates will be lower in
Alberta, while at moderate to high prices royalty rates will be higher in
Alberta than in the Trust's other operating jurisdictions. Approximately 65
per cent of production comes from Alberta, 22 per cent from Saskatchewan and
11 per cent from British Columbia and one per cent from Manitoba. The Trust
will continue to evaluate projects on the basis of each province's fiscal
regime as well as technical merits and direct its future investment spending
to the most economically favorable projects.

    
    Table 16
    -------------------------------------------------------------------------
              Provincial Royalty Rates - New Royalty Framework
    -------------------------------------------------------------------------
    Edmonton posted oil (Cdn/$/bbl)(1)        $40      $60      $80     $100
    AECO natural gas (Cdn$/GJ)(1)              $6       $6       $8      $10
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Current Alberta royalty rate(2)         17.5%    17.5%    17.5%    17.5%
    -------------------------------------------------------------------------
    NRF Alberta royalty rate(3)             15.5%    20.0%    25.0%    29.0%
    -------------------------------------------------------------------------
    Saskatchewan royalty rate(2)            20.7%    20.7%    20.7%    20.7%
    -------------------------------------------------------------------------
    British Columbia royalty rate(2)        23.5%    23.5%    23.5%    23.5%
    -------------------------------------------------------------------------
    Manitoba royalty rate(2)                17.4%    17.4%    17.4%    17.4%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Canadian dollar denominated prices before quality differentials.
    (2) Royalty rate includes Crown, Freehold and Gross Override royalties
        for all jurisdictions in which the Trust operates.
    

    As royalties under the new Framework are sensitive to both commodity
prices and production levels, the estimated NRF Alberta and corporate royalty
rates will fluctuate with commodity prices, well production rates, production
decline of existing wells, and performance and location of new wells drilled.
    The Trust completed an upgrade to its production accounting system in the
fourth quarter of 2008 to accommodate royalty calculations and reporting
requirements under the Framework effective January 1, 2009.

    General and Administrative Expenses and Trust Unit Incentive Compensation

    G&A net of overhead recoveries on operated properties increased seven per
cent to $38.8 million in 2008 from $36.3 million in 2007. Increases in G&A
expenses for 2008 were a result of increased staff costs based on a six per
cent increase in the staff levels on average in 2008 due to higher levels of
activity.
    The Trust paid out $28.2 million under the Whole Trust Unit Incentive
Plan ("Whole Unit Plan") in 2008 compared to $12.7 million in 2007 ($21.3
million and $9.6 million of the payouts were allocated to G&A in 2008 and
2007, respectively, and the remainder to operating costs and property, plant
and equipment). The increase in payments during 2008 was a result of having
two different performance unit grants vest during the year as compared to only
one grant that vested in 2007. The next cash payments under the Whole Unit
Plan are scheduled to occur in March and September 2009.
    Table 17 is a breakdown of G&A and trust unit incentive compensation
expense:

    
    Table 17
    -------------------------------------------------------------------------
    G&A and Trust Unit Incentive
     Compensation Expense
    ($ millions except per boe)                   2008       2007   % Change
    -------------------------------------------------------------------------
    G&A expenses                                  55.6       52.7          6
    Operating recoveries                         (16.8)     (16.4)         2
    -------------------------------------------------------------------------
    Cash G&A expenses before Whole Unit Plan      38.8       36.3          7
    Cash Expense - Whole Unit Plan                21.3        9.6        122
    -------------------------------------------------------------------------
    Cash G&A expenses including Whole Unit Plan   60.1       45.9         31
    -------------------------------------------------------------------------
    Accrued compensation - Whole Unit Plan         1.1        3.2        (66)
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense                         61.2       49.1         25
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense per boe                 2.57       2.15         20
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $1.1 million ($0.05 per boe) was recorded in 2008
compared to $3.2 million ($0.14 per boe) in 2007. This non-cash amount relates
to estimated costs of the Whole Unit Plan to December 31, 2008.

    Whole Unit Plan

    In March 2004, the Board of Directors approved a new Whole Unit Plan to
replace the Rights Plan for new awards granted subsequent to the first quarter
of 2004. The new Whole Unit Plan results in employees, officers and directors
(the "plan participants") receiving cash compensation in relation to the value
of a specified number of underlying 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 18 shows the changes during the year of RTUs and PTUs outstanding:

    
    Table 18
    -------------------------------------------------------------------------
    Whole Unit Plan                                                    Total
    (units in thousands and                  Number of  Number of   RTUs and
     $ millions except per unit)                  RTUs       PTUs       PTUs
    -------------------------------------------------------------------------
    Balance, beginning of year                     746        903      1,649
    Granted in the year                            403        352        755
    Vested in the year                            (347)      (252)      (599)
    Forfeited in the year                          (46)       (44)       (90)
    -------------------------------------------------------------------------
    Balance, end of year(1)                        756        959      1,715
    -------------------------------------------------------------------------
    Estimated distributions to vesting date(2)     197        328        525
    Estimated units upon vesting after
     distributions                                 953      1,287      2,240
    Performance multiplier(3)                        -        1.6          -
    -------------------------------------------------------------------------
    Estimated total units upon vesting             953      2,110      3,063
    -------------------------------------------------------------------------
    Trust unit price at December 31, 2008       $20.10     $20.10     $20.10
    Estimated total value upon vesting            19.2       42.4       61.6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Based on underlying units before performance multiplier and accrued
        distributions.
    (2) Represents estimated additional units to be issued equivalent to
        estimated distributions accruing to vesting date.
    (3) The performance multiplier only applies to PTUs and was estimated to
        be 1.6 at December 31, 2008 based on an average for all outstanding
        grants. The performance multiplier is assessed each period end based
        on actual results of the Trust relative to its peers.
    

    The value associated with the RTUs and PTUs is expensed in the statement
of income over the vesting period with the expense amount being determined by
the trust unit price, the number of PTUs to be issued on vesting, and
distributions. Therefore, the expense recorded in the statement of income
fluctuates over time.
    Table 19 is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier:

    
    Table 19
    -------------------------------------------------------------------------
    Value of Whole Unit Plan as at
     December 31, 2008                             Performance multiplier
                                               ------------------------------
    (units thousands and $ millions
     except per unit)                                -        1.0        2.0
    -------------------------------------------------------------------------
    Estimated trust units to vest
      RTUs                                         953        953        953
      PTUs                                           -      1,287      2,575
    -------------------------------------------------------------------------
    Total units(1)                                 953      2,240      3,528
    -------------------------------------------------------------------------
      Trust unit price(2)                       $20.10     $20.10     $20.10
      Trust unit distributions per month(2)      $0.15      $0.15      $0.15
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Value of Whole Unit Plan upon vesting        $19.2      $45.0      $70.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 $20.10 and $0.15 per trust unit
        distributions based on the unit price and distribution levels in
        place at December 31, 2008. Subsequent to year-end, the distribution
        level decreased to $0.12 per trust unit.
    (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 $19.2 million and $70.9 million will be paid out from
2009 through 2011 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.

    Provision for Non-recoverable Accounts Receivable

    The Trust recorded a provision for non-recoverable accounts receivable of
$32 million ($23.9 million net of tax) in 2008 (nil in 2007). In July 2008,
SemCanada Crude ("SemCanada"), a counterparty that marketed a portion of the
Trust's production filed for protection under the Companies' Creditors
Arrangement Act ("CCAA"). SemCanada's parent company had continuously rated as
investment grade credit by an external rating agency up until 10 days prior to
filing for credit protection in the United States. The Trust's total exposure
to SemCanada was $30.6 million. Due to uncertainty surrounding the ultimate
recoverable amount and expected timing of recovery, the Trust recorded a
provision for the full SemCanada receivable of $30.6 million in 2008. In
addition, the Trust recorded a provision of $1.4 million for six additional
counterparties that also filed for CCAA protection during 2008 or were
experiencing financial distress. The Trust's allowance for doubtful accounts
was $32 million as at December 31, 2008 (nil as at December 31, 2007).

    Interest Expense

    Interest expense decreased to $32.9 million in 2008 from $36.9 million in
2007 due to a decrease in short-term interest rates. As at December 31, 2008,
the Trust had $901.6 million of debt outstanding, of which $259.6 million was
fixed at a weighted average rate of 5.1 per cent and $642.2 million, including
the working capital facility, was floating at current market rates plus a
credit spread of 60 basis points. Fifty-five per cent (US $408.5 million) of
the Trust's debt is denominated in U.S. dollars.

    Foreign Exchange Gains and Losses

    The Trust recorded a loss of $89.4 million ($3.76 per boe) in 2008 on
foreign exchange transactions compared to a gain of $69.4 million ($3.03 per
boe) in 2007. These amounts include both realized and unrealized foreign
exchange gains and losses.
    Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The volatility of the Canadian dollar during
the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain/loss impacts net income but
does not impact cash flow from operating activities as it is a non-cash
amount. From December 31, 2007 to December 31, 2008, the Cdn$/US$ exchange
rate has increased from 1.01 to 1.22 creating an unrealized loss of $90.8
million on U.S. dollar denominated debt.
    Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements. Included in the 2008 realized foreign exchange gain was a gain of
$2.3 million relating, in part, to a repayment of US$6 million of debt in
October 2008. The debt was issued in 2002 when the Cdn$/US$ foreign exchange
rate was approximately 1.56 and strengthened considerably to 1.04 on repayment
in 2008.

    Taxes

    In 2008, a future income tax recovery of $4.5 million was included in
income compared to $121.3 million in 2007. The future income tax recovery in
2007 included the impact of a legislated reduction in the future corporate
income tax rates in the fourth quarter of 2007 whereby the Trust's expected
future corporate income tax rate decreased from 29.4 per cent to 25.8 per cent
after the rate reduction. In 2008, the Trust's expected future corporate
income tax rate decreased marginally, creating a recovery of $4.5 million for
the year.
    At December 31, 2008, the Trust and the Trust's subsidiaries had tax
pools of approximately $2.1 billion. The tax pools consist of $1.8 billion of
tangible and intangible capital assets, $86.9 million of non-capital loss
carry-forwards that expire at various periods to 2026, and $213.1 million of
other tax pools. Included in the above tax basis are the Trust's tax pools of
approximately $590.2 million.
    On June 22, 2007, the federal legislation (Bill C-52) implementing the
tax on publicly traded income trusts and limited partnerships (the "SIFT
Rules") received Royal Assent. The SIFT Rules are not expected to effect the
Trust until 2011 provided the Trust does not exceed the normal growth
guidelines announced by the Department of Finance. Subsequent to the Trust's
equity issuance that closed on February 6, 2009, the Trust may now increase
its equity by approximately $5.1 billion between now and 2011 without
exceeding the normal growth guidelines. The Trust does not anticipate that the
normal growth guidelines will impair the Trust's ability to annually replace
or grow reserves in the next two years as the guidelines allow sufficient
growth targets.
    On February 26, 2008 the Minister of Finance announced as part of the
federal budget that the provincial component of the tax on the Trust is to be
calculated based on the general provincial rate in each province in which the
Trust has a permanent establishment. This is the same way a corporation would
calculate its provincial tax rate, however it is different than the Provincial
tax component included in the SIFT Rules, which currently provide for a deemed
rate of 13 per cent. At December 31, 2008 the Trust has used the deemed 13 per
cent provincial rate to calculate its future income taxes as the proposed
legislation had not been issued for calculating the provincial rate. On
February 1, 2009 the Minister of Finance tabled a Notice of Ways and Means
that includes the proposed legislation for calculating the provincial tax
rate.
    On November 28, 2008 the Minister of Finance introduced legislation to
facilitate the conversion of existing income trusts into corporations. In
general, the proposed legislation will permit a conversion to be tax deferred
for both the unitholders and the income trust. Due to Parliament being
prorogued on December 4, 2008 this proposed legislation essentially expired.
On February 1, 2009 the Minister of Finance tabled a Notice of Ways and Means
that includes the proposed legislation to facilitate the conversion of
existing income trusts into corporations.
    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
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. ARC expects future technical
interpretations and details will further clarify the legislation. It is
expected that total income taxes payable on distributions in 2011, including
both corporate and personal income taxes, will remain approximately the same
as current levels and thus result in approximately the same after tax
distribution amount to Canadian investors. However, Canadian tax-deferred
investors (those holding their trust units in a tax-deferred vehicle such as
an RRSP, RRIF or pension plan) will realize a lower distribution amount in
2011 due to the introduction of corporate income taxes.
    The corporate income tax rate applicable to 2008 is 29.5 per cent,
however the Trust and its subsidiaries did not pay any material cash income
taxes for fiscal 2008. 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.

    Depletion, Depreciation and Accretion of Asset Retirement Obligation

    The depletion, depreciation and accretion ("DD&A") rate decreased to
$15.88 per boe in 2008 from $16.23 per boe in 2007. The lower DD&A rate was
driven by an increase in the Trust's proved reserves.
    A breakdown of the DD&A rate is summarized in Table 20:

    
    Table 20
    -------------------------------------------------------------------------
    DD&A Rate
    ($ millions except per boe amounts)           2008       2007   % Change
    -------------------------------------------------------------------------
    Depletion of oil & gas assets(1)             370.3      360.0          3
    Accretion of asset retirement obligation(2)    9.3       11.5        (19)
    -------------------------------------------------------------------------
    Total DD&A                                   379.6      371.5          2
    DD&A rate per boe                            15.88      16.23         (2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.
    

    Goodwill

    The goodwill balance of $157.6 million arose as a result of the
acquisition of Star Oil and Gas in 2003. The goodwill balance was determined
based on the excess of total consideration paid plus the future income tax
liability less the fair value of the assets, for accounting purposes, acquired
in the transaction.
    Accounting standards require that the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate that the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. The Trust has determined that there was no goodwill impairment as of
December 31, 2008.

    Capital Expenditures and Net Acquisitions

    Total capital expenditures, excluding acquisitions and dispositions,
totaled $548.6 million in 2008 compared to $397.2 million in 2007. This amount
was incurred on drilling and completions, geological, geophysical and
facilities expenditures, and undeveloped land. The $122.4 million purchase of
undeveloped land in 2008 increased the Trust's land holdings to 534,416 net
acres that will provide drilling opportunities and, if successful, incremental
future production and reserves.
    In addition to capital expenditures on development activities, the Trust
completed net property acquisitions of $51 million in 2008 of which $48.6
million related to the acquisition of undeveloped land and is included in the
net acres quoted above.
    Proved plus probable oil and gas reserves increased 12 per cent to 321.7
million boe at year-end 2008 as a result of the Trust's 2008 capital
expenditure program.
    A breakdown of capital expenditures and net acquisitions is shown in
Table 21:

    
    Table 21
    -------------------------------------------------------------------------
    Capital Expenditures
    ($ millions)                                  2008       2007   % Change
    -------------------------------------------------------------------------
    Geological and geophysical                    27.1       14.9         82
    Drilling and completions                     305.4      229.5         33
    Plant and facilities                          90.4       72.1         25
    Undeveloped land purchased at
     crown land sales                            122.4       77.5         58
    Other capital                                  3.3        3.2          3
    -------------------------------------------------------------------------
    Total capital expenditures before
     net acquisitions                            548.6      397.2         38
    -------------------------------------------------------------------------
    Producing property acquisitions(1)             1.4       47.1        (97)
    Undeveloped land property acquisitions        53.5          -        100
    Producing property dispositions(1)            (0.2)      (4.6)       (96)
    Undeveloped land property dispositions        (3.7)         -        100
    -------------------------------------------------------------------------
    Total capital expenditures and
     net acquisitions                            599.6      439.7         36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Value is net of post-closing adjustments.


    Approximately 68 per cent of the $548.6 million capital program was
financed with cash flow from operating activities in 2008 compared to 49 per
cent in 2007. Property acquisitions were financed through debt and working
capital.

    Table 22
    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                                    2008                       2007
    -------------------------------------------------------------------------
                          Devel-     Net    Total    Devel-     Net    Total
                         opment   Acquis-  Expend-  opment   Acquis-  Expend-
                        Capital   itions   itures  Capital   itions   itures
    -------------------------------------------------------------------------
    Expenditures          548.6     51.0    599.6    397.2     42.5    439.7
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash flow from
     operating activities   68%        -      62%      49%        -      44%
    Proceeds from DRIP
     and Rights Plan        23%        -      21%      28%        -      25%
    Debt                     9%     100%      17%      23%     100%      31%
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    ARC announced a $450 million capital expenditure budget for 2009 funding
a combination of annual production replacement and future growth development
including the development of a 60 mmcf per day gas plant in the Dawson area to
be operational in early 2010. The Trust will continually monitor the capital
expenditure program in the context of the current economic conditions and make
any necessary modifications to the planned expenditures as required.

    Long-Term Investment

    During the second quarter of 2007, the Trust sold its investment in the
shares of a private company that was involved in the acquisition of oil sands
leases. The transaction closed on June 25, 2007. The Trust recorded a cash
gain of $13.3 million with total proceeds of $33.3 million recorded as part of
cash flow from investing activities. The investment in the shares of the
private company was considered to be a related party transaction due to common
directorships of the Trust, the private company and the manager of a private
equity fund that held shares in the private company. In addition, certain
directors and officers of the Trust had minor direct and indirect
shareholdings in the private company.

    Asset Retirement Obligation and Reclamation Fund

    At December 31, 2008, the Trust recorded an Asset Retirement Obligation
("ARO") of $141.5 million ($140 million at December 31, 2007) for future
abandonment and reclamation of the Trust's properties. The estimated ARO
includes assumptions in respect of actual costs to abandon wells or reclaim
the property as well as annual inflation factors in order to calculate the
undiscounted total future liability. The undiscounted total future liability
was unchanged at $1.3 billion at December 31, 2008 and 2007. A significant
portion of the costs are projected to be incurred in years 2049 to 2059.
    Included in the December 31, 2008 ARO balance was a $4.6 million increase
related to development activities in 2008 as well as minor changes in
management's estimate of the existing liabilities. The ARO liability was also
increased by $9.3 million for accretion expense in 2008 ($11.5 million in
2007) and was reduced by $12.4 million ($18.2 million in 2007) for actual
abandonment expenditures incurred in 2008.
    As a result of the Redwater acquisition in December 2005, the Trust set
up a second reclamation fund (the "Redwater Fund") in 2006 to fund future
abandonment obligations attributed solely to the Redwater properties. The
Trust makes annual contributions to the Redwater fund and may utilize the
funds only for abandonment activities for the Redwater property. With the
addition of the Redwater Fund, the Trust now maintains two reclamation funds
that together held $28.2 million at December 31, 2008. Future contributions
for the two funds will vary over time in order to provide for the total
estimated future abandonment and reclamation costs that are to be incurred
upon abandonment of the Trust's properties. Minimum contributions to the
Redwater fund over the next 47 years will be approximately $91 million while
the main fund has no minimum contribution requirements.
    In total, ARC contributed $11.7 million cash to its reclamation funds in
2008 ($12.1 million in 2007) and earned interest of $1.2 million ($1.4 million
in 2007) on the fund balances. The fund balances were reduced by $10.7 million
for cash-funded abandonment expenditures in 2008 ($18.1 million in 2007).
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 December 31, 2008 and 2007:

    
    Table 23
    -------------------------------------------------------------------------
    Capital Structure and Liquidity
    ($ millions except per cent                    December 31,  December 31,
     and ratio amounts)                                   2008          2007
    -------------------------------------------------------------------------
    Net debt obligations(1)                              961.9         752.7
    Market value of trust units and exchangeable
     shares(2)                                         4,405.9       4,349.3
    -------------------------------------------------------------------------
    Total capitalization(3)                            5,367.8       5,102.0
    -------------------------------------------------------------------------
    Net debt as a percentage of total capitalization     17.9%         14.8%
    Net debt to annualized YTD cash flow from
     operating activities                                  1.0           1.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net debt is a non-GAAP measure and is calculated as long-term debt
        plus current liabilities less the current assets as they appear on
        the Consolidated Balance Sheets. Net debt excludes current unrealized
        amounts pertaining to risk management contracts and the current
        portion of future income taxes.
    (2) Calculated using the total trust units outstanding at December 31
        including the total number of trust units issuable for exchangeable
        shares at December 31 multiplied by the closing trust unit price of
        $20.10 and $20.40 for 2008 and 2007, 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.
    

    The Trust's current credit facilities comprise US$212 million in senior
secured notes currently outstanding, a Cdn$800 million syndicated bank credit
facility, of which $640.1 million was outstanding at December 31, 2008 and a
Cdn$25 million demand working capital facility, of which $2.1 million was
outstanding at December 31, 2008. On April 15, 2008 ARC extended the credit
facility to April 2011 under the same terms. 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 December 31, 2008;
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.
    

    As at December 31, 2008 ARC has approximately $300 million of unused
credit available: $160 million under its credit facility and the ability to
issue an additional US$113 million (Cdn$140 million) of long-term notes under
an agreement with one lender. This option, which will expire in May 2009,
unless renewed, would allow the Trust to issue long-term notes at a rate equal
to the related U.S. treasuries corresponding to the term of the notes plus an
appropriate credit risk adjustment at the time of issuance.
    The $240 million of net proceeds from the equity offering that closed on
February 6, 2009, were used to reduce outstanding indebtedness under the
Trust's credit facility (see Unitholders' Equity). This increased the Trust's
unused credit available to approximately $540 million including the option of
issuing US$113 million (Cdn$140 million) of U.S. dollar long-term notes.
    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 if so,
will execute the most cost effective and efficient means of financing its
ongoing operations.

    Unitholders' Equity

    At December 31, 2008, there were 219.2 million trust units issued and
issuable for exchangeable shares, an increase of six million trust units from
December 31, 2007. The increase in number of trust units outstanding is mainly
attributable to the 5.4 million trust units issued pursuant to the DRIP during
2008 at an average price of $22.61 per unit.
    During 2008, the Trust issued 0.2 million trust units under the Trust
Unit Incentive Rights Plan ("the Rights Plan" for total proceeds of $4.2
million. At December 31, 2008 there were no rights outstanding as all rights
issued under the plan have been exercised or cancelled.
    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 2008, the Trust raised proceeds of $123.2 million and
issued 5.4 million trust units pursuant to the DRIP.
    On January 21, 2009 the Trust announced that it entered into an
agreement, on a bought deal basis, with a syndicate of underwriters for an
offering of 13.5 million trust units at $16.35 per trust unit, for gross
proceeds of $220 million as well as an over-allotment option to purchase, on
the same terms and conditions, up to an additional two million trust units.
This option was exercised, in whole prior to closing of the offering on
February 6, 2009. 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.

    Distributions

    ARC declared distributions of $570 million ($2.67 per unit), representing
60 per cent of 2008 cash flow from operating activities compared to
distributions of $498 million ($2.40 per unit) representing 71 per cent of
cash flow from operating activities in 2007.
    As a result of the volatility of oil prices throughout 2008, the Trust
made several changes to the monthly distribution levels declared and paid to
unitholders. During the first seven months of 2008, oil prices soared to
record high amounts causing the Trust to increase monthly distributions to
$0.28 per unit in order to meet the Trust's objective of transferring tax
liabilities to unitholders and minimizing taxes paid by the Trust. In the
third quarter of 2008, oil prices decreased significantly causing the Trust to
reduce distributions to $0.15 per unit. Subsequent to year-end, the Trust
further decreased distributions to $0.12 per unit in light of the continued
weak commodity price environment.
    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 2008, the Trust withheld 40 per cent of
        2008 cash flow from operating activities to fund 68 per cent of the
        capital program excluding acquisitions and to make contributions to
        the reclamation funds. The remaining portion of capital expenditures
        was financed by proceeds from the DRIP program and debt.

    -   An annual contribution to the reclamation funds, with $12.9 million
        being contributed in 2008 including interest earned on the fund
        balances. 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 $19.2 million to $61.6 million will be paid out
        pursuant to such commitments in 2008 through 2010 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
    -------------------------------------------------------------------------
    Cash flow from                              %                          %
     operating activities  2008     2007   Change     2008     2007   Change
     and distributions      ($ millions)               ($ per unit)
    -------------------------------------------------------------------------
    Cash flow from
     operating
     activities           944.4    704.9       34     4.37     3.35       30
    Net reclamation fund
     (contributions)
     withdrawals(1)        (2.2)     4.7     (147)   (0.01)    0.02     (150)
    Capital expenditures
     funded with cash
     flow from operating
     activities          (372.2)  (211.6)      76    (1.72)   (1.01)      70
    Other(2)                  -        -        -     0.03     0.04      (25)
    -------------------------------------------------------------------------
    Distributions         570.0    498.0       14     2.67     2.40       12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes interest income earned on the reclamation fund balances that
        is retained in the reclamation funds.
    (2) Other represents the difference due to distributions paid being based
        on actual trust units outstanding at each distribution date whereas
        per unit cash flow from operating activities, reclamation fund
        contributions and capital expenditures funded with cash flow from
        operated activities are based on weighted average outstanding trust
        units in the year plus trust units issuable for exchangeable shares
        at year-end.


    The Trust continually assesses distribution levels, in light of commodity
prices 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 2008 the Trust funded
        68 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.
    Monthly distributions for the first quarter of 2009 have been set at
$0.12 per unit subject to monthly review based on commodity price
fluctuations. Revisions, if any, to the monthly distribution are normally
announced on a quarterly basis in the context of prevailing and anticipated
commodity prices at that time.

    Historical Distributions by Calendar Year

    Table 25 presents distributions paid and payable for each calendar
period.

    
    Table 25
    -------------------------------------------------------------------------
    Calendar Year        Distributions    Taxable Portion  Return of Capital
    -------------------------------------------------------------------------
    2009 YTD(2)                   0.12               0.12                  -
    2008                          2.67               2.62               0.05
    2007                          2.40               2.32               0.08
    2006(1)                       2.60               2.55               0.05
    2005                          1.94               1.90               0.04
    2004                          1.80               1.69               0.11
    2003                          1.78               1.51               0.27
    2002                          1.58               1.07               0.51
    2001                          2.41               1.64               0.77
    2000                          1.86               0.84               1.02
    1999                          1.25               0.26               0.99
    1998                          1.20               0.12               1.08
    1997                          1.40               0.31               1.09
    1996                          0.81                  -               0.81
    -------------------------------------------------------------------------
    Cumulative                  $23.82             $16.95              $6.87
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Based on distributions paid and payable in 2006.
    (2) Based on distributions declared at January 31, 2008 and estimated
        taxable portion of 2008 distributions of 98 per cent.
    

    Please refer to the Trust's website at www.arcenergytrust.com for details
on 2008 monthly distributions and distribution dates for 2009.

    Taxation of Distributions

    Distributions comprise a return of capital portion (tax deferred) and a
return on capital portion (taxable). The return of capital component reduces
the cost basis of the trust units held. For 2008, distributions declared in
the calendar year will be 98 per cent return on capital or $2.62 per unit for
the year (taxable) and two per cent return of capital or $0.05 per unit for
the year (tax deferred). For a more detailed breakdown, please visit our
website at www.arcenergytrust.com.

    Environmental Legislation Impacting the Trust

    On July 8, 2008 the Alberta government announced two new funds totaling
$4 billion to reduce greenhouse gas emissions. The province will create a $2
billion fund to advance carbon capture and storage projects while a second $2
billion fund will propel energy-saving public transit in Alberta. The Trust is
actively working to gain an understanding of how the carbon capture funds will
be allocated as it may allow the Trust access to additional funding for its
ongoing carbon capture and storage projects at Redwater and may increase the
possibility of achieving commercial viability of the CO(2) injection program
if proper infrastructure is put in place to capture and deliver CO(2) to the
Redwater area.
    On February 19, 2008 the British Columbia government introduced a
consumer-based carbon tax. Effective July 1, 2008, ARC is required to pay tax
on all fuel used in the course of operations in that province. Since July 1,
2008, the Trust paid approximately $0.1 million of carbon tax to the B.C.
Government.

    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 26.

    
    Table 26
    -------------------------------------------------------------------------
                                   Payments Due by Period
    -------------------------------------------------------------------------
                                       2010-      2012-
    ($ millions)            2009       2011       2013  Thereafter     Total
    -------------------------------------------------------------------------
    Debt repayments(1)      22.2      696.0       79.1      104.5      901.8
    Interest payments(2)    12.8       22.2       15.4       10.0       60.4
    Reclamation fund
     contributions(3)        5.2        9.5        8.3       67.9       90.9
    Purchase commitments    13.0       15.4        5.0        4.9       38.3
    Transportation
     commitments(4)            -       14.9       21.9       21.0       57.8
    Operating leases         7.0        9.8       14.3       81.8      112.9
    Risk management
     contract premiums(5)   19.3          -          -          -       19.3
    -------------------------------------------------------------------------
    Total contractual
     obligations            79.5      767.8      144.0      290.1    1,281.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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. In addition to the above
premiums, the Trust has commitments related to its risk management program. As
the premiums are part of the underlying risk management contract, they have
been recorded at fair market value at December 31, 2008 on the balance sheet
as part of risk management contracts.
    The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At a given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2009 capital budget has
been approved by the Board at $450 million. This commitment has not been
disclosed in the commitment table (Table 26) 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 $450 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 26.
    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 26) 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 26) 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 26), 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 December
31, 2008.

    Fourth Quarter Financial and Operational Results

    Strong operational results in the fourth quarter resulted in $209.5
million of cash flow from operating activities despite volatile commodity
prices and the global economic slow down during the fourth quarter. The Trust
successfully executed a $169.4 million capital development program that
contributed to quarterly average production of 65,313 boe per day. The Trust's
distributions were 61 per cent of cash flow from operating activities. The
remaining 39 per cent was used to fund $110.1 million of the fourth quarter
capital development program and make contributions to the reclamation funds.
The fourth quarter was an active one for the Trust with the drilling of 86
gross wells on operated properties. In total 52 natural gas wells and 33 oil
wells were drilled with a 99 per cent success rate.

    
    -   As a result of the sharp decline in commodity prices during the
        quarter, the Trust decreased monthly distributions to $0.15 in an
        effort to preserve the Trust's cash available to fund future capital
        programs. Total revenue decreased by $184.9 million in the fourth
        quarter of 2008 as compared to the third quarter of 2008 despite
        recording slightly higher production in the fourth quarter. The weak
        commodity price environment has continued into 2009 and as a result,
        the Trust decreased monthly distributions further to $0.12 per unit
        in order to provide flexibility for financing the Trust's growth
        development in the Montney in 2009.

    -   The Trust's fourth quarter production was 65,313 boe per day, an
        increase of 1,324 boe per day from the fourth quarter of 2007 where
        production was 63,989. The increased production is attributable, in
        large part, to the development in the Dawson area in northeastern
        British Columbia.

    -   The Trust spent $197 million on capital expenditures and net
        acquisitions in the fourth quarter compared to $144.3 million in
        2007. The Trust had a very active fourth quarter with the drilling of
        86 gross wells (52 net wells) on operated properties with a 99 per
        cent success rate. The Trust expanded its inventory of undeveloped
        land acreage with the purchase of $38.8 million of land in the fourth
        quarter. The land acquired was in core areas where the Trust has
        identified strategic development opportunities.

    -   The fourth quarter netback before hedging decreased 18 per cent to
        $29.97 per boe as compared to $36.63 for the same period of 2007. The
        lower netback is largely attributed to the Trust's realized oil price
        that decreased by 27 per cent in the fourth quarter of 2008 when
        compared to the same period in 2007.

    -   Cash G&A expenses in the fourth quarter increased to $2.93 per boe as
        compared to $1.96 for the same period in 2007. The majority of the
        increase is attributable to a larger whole unit plan payment made in
        October of 2008 that included PTUs granted in 2005. The 2007 October
        payment was only RTUs as no PTUs were issued in October of 2004.

    Table 27
    -------------------------------------------------------------------------
    Fourth Quarter Financial and Operational Highlights
    (Cdn$ millions except per
    unit and per cent)                         Q4 2008    Q4 2007   % Change
    -------------------------------------------------------------------------
    Production (boe/d)                          65,313     63,989          2
    Cash flow from operating
     activities                                  209.4      173.7         21
      Per unit                               $    0.96  $    0.82         17
    Distributions                                127.2      125.8          1
      Per unit                               $    0.58  $    0.60         (3)
      Per cent of cash flow from
       operating activities                         61         72        (15)
    Net income                                    82.7      106.3        (22)
      Per unit                               $    0.38  $    0.51        (25)
    -------------------------------------------------------------------------
    Prices
      WTI (US$/bbl)                              58.75      90.63        (35)
      Cdn$/US$ exchange rate                      1.21       1.02         19
      Realized oil price (Cdn $/bbl)             56.26      77.53        (27)
      AECO gas monthly index (Cdn $/mcf)          6.79       6.00         13
      Realized gas price (Cdn $/mcf)              7.48       6.32         18
    -------------------------------------------------------------------------
    Operating netback ($/boe)
      Revenue, before hedging                    50.06      57.42        (13)
      Royalties                                  (9.14)    (10.46)       (13)
      Transportation                             (0.86)     (0.69)        25
      Operating costs                           (10.09)     (9.64)         5
      Netback (before hedging)                   29.97      36.63        (18)
      Cash hedging gain (loss)                    2.38      (0.20)     1,290
      Netback (after hedging)                $   32.35  $   36.43        (11)
    -------------------------------------------------------------------------
    Capital expenditures                         169.4      139.3         22
    Capital funded with cash flow from
     operating activities (per cent)                65         32        103
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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.

    Disclosure Controls and Procedures

    As of December 31, 2008, an internal evaluation was carried out of the
effectiveness of the Trust's disclosure controls and procedures as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in
Canada by National Instrument 52-109, Certification of Disclosure in Issuers'
Annual and Interim Filings. Based on that evaluation, the President and Chief
Executive Officer and the Senior Vice President Finance and Chief Financial
Officer concluded that the disclosure controls and procedures are effective to
ensure that the information required to be disclosed in the reports that the
Trust files or submits under the Exchange Act or under Canadian Securities
legislation is recorded, processed, summarized and reported, within the time
periods specified in the rules and forms therein. Disclosure controls and
procedures include, without limitation, controls and procedures designed to
ensure that the information required to be disclosed by the Trust in the
reports that it files or submits under the Exchange Act or under Canadian
Securities Legislation is accumulated and communicated to the Trust's
management, including the senior executive and financial officers, as
appropriate to allow timely decisions regarding the required disclosure.

    Internal Control over Financial Reporting

    Internal control over financial reporting is a process designed to
provide reasonable assurance that all assets are safeguarded, transactions are
appropriately authorized and to facilitate the preparation of relevant,
reliable and timely information. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements.
Management has assessed the effectiveness of the Trust's internal control over
financial reporting as defined in Rule 13a-15 under the US Securities Exchange
Act of 1934 and as defined in Canada by National Instrument 52-109,
Certification of Disclosure in Issuers' Annual and Interim Filings. The
assessment was based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Management concluded that the Trust's internal control over
financial reporting was effective as of December 31, 2008. The effectiveness
of the Trust's internal control over financial reporting as of December 31,
2008 has been audited by Deloitte & Touche LLP, as reflected in their report
for 2008. No changes were made to the Trust's internal control over financial
reporting during the year ending December 31, 2008, that have materially
affected, or are reasonably likely to materially affect, the internal controls
over financial reporting.

    Financial Reporting Update

    Current Year Accounting Changes

    Effective January 1, 2008, the Trust adopted three new accounting
standards that were issued by the Canadian Institute of Chartered Accountants
("CICA"): Handbook Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures and Section 3863, Financial Instruments -
Presentation.

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

    B. Financial Instruments - Disclosures, Financial Instruments -
    Presentation
    Sections 3862 and 3863 establish standards for enhancing financial
statements users' understanding of the significance of financial instruments
to an entity's financial position, performance and cash flows. They require
that entities provide disclosures regarding the nature and extent of risks
arising from financial instruments to which they are exposed both during the
reporting period and at the balance sheet date, as well as how the entities
manage those risks.
    These standards were adopted prospectively.

    Future Accounting Changes

    A. Goodwill and Intangible Assets
    In February 2008, the CICA issued Section 3064, Goodwill and Intangible
Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
Section 3450, Research and Development Costs. The new Section will be
effective on January 1, 2009. Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. Standards concerning
goodwill are unchanged from the standards included in the previous Section
3062. The Trust is currently evaluating the impact of the adoption of this new
Section, however does not expect a material impact on its Consolidated
Financial Statements.

    B. 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. At this time, the Trust has appointed internal staff along with
sponsorship from the senior leadership team to review the impact of converting
to IFRS on the accounting policies, information and computer systems, internal
and disclosure controls, financial reporting in addition to the changes in the
Trust's financial statements. In addition, an external advisor has been
retained to assist the Trust in the conversion project.

    Non-GAAP Measures

    Historically, management used the non-GAAP measure Cash Flow or cash flow
from operations to analyze operating performance, leverage and liquidity. We
have now chosen to utilize the GAAP measure cash flow from operating
activities instead of Cash Flow. There are two differences between the two
measures and cash flow from operating activities; positive or negative changes
in non-cash working capital and the deduction of expenditures on site
restoration and reclamation as they appear on the Consolidated Statements of
Cash Flows. Although management feels that Cash Flow is a valued measure of
funds generated by the Trust during the reported quarter, we have changed our
disclosure to only discuss the GAAP measure in the MD&A in order to avoid any
potential confusion by readers of our financial information and in our
opinion, to more fully comply with the intent of certain regulatory
requirements.
    Our historical measure of Cash Flow reflected revenues and costs for the
three months reported in the quarter. This amount, however, comprised accruals
for at least one month of revenue and approximately two months of costs. The
oil and gas industry is designed such that revenues are typically collected on
the 25th day of the month following the actual production month. Royalties are
typically paid two months following the actual production month and operating
costs are paid as the invoices are received. This can take several months;
however, most invoices for operated properties are paid within approximately
two months of the production month. In the event that commodity prices and or
volumes have changed significantly from the last month of the previous
reporting period over the last month of the current reporting period, a
difference could occur between cash flow from operating activities and our
historical non-GAAP measure of Cash Flow or cash flow from operations.
Additionally, periods where the Trust spends a significant amount on site
restoration and reclamation would result in a difference between cash flow
from operating activities and Cash Flow.
    At the time of writing this MD&A, substantially all revenues have been
collected for the production period of December 2008. Management performs
analysis on the amounts collected to ensure that the amounts accrued for
December are accurate. Analysis is also performed regularly on royalties and
operating costs to ensure that amounts have been accurately accrued.
    Management uses certain key performance indicators ("KPIs") and industry
benchmarks such as distributions as a per cent of cash flow from operating
activities, operating netbacks ("netbacks"), total capitalization, finding,
development and acquisition costs, recycle ratio, reserve life index, reserves
per unit and production per unit, 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 reserve 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.

    
    ANNUAL HISTORICAL REVIEW
    -------------------------------------------------------------------------
    For the year ended December 31
    (Cdn $ millions, except
    per unit amounts)           2008      2007      2006      2005      2004
    -------------------------------------------------------------------------
    FINANCIAL
    Revenue before royalties 1,706.4   1,251.6   1,230.5   1,165.2     901.8
      Per unit(1)               7.90      5.95      6.02      6.10      4.85
    Cash flow from operating
     activities(2)             944.4     704.9     734.0     616.7     446.4
      Per unit - basic(1)       4.37      3.35      3.59      3.23      2.40
      Per unit - diluted        4.37      3.35      3.58      3.20      2.38
    Net income                 533.0     495.3     460.1     356.9     241.7
      Per unit - basic(3)       2.50      2.39      2.28      1.90      1.32
      Per unit - diluted        2.50      2.39      2.27      1.88      1.31
    Distributions              570.0     498.0     484.2     376.6     330.0
      Per unit(4)               2.67      2.40      2.40      1.99      1.80
    Total assets             3,766.7   3,533.0   3,479.0   3,251.2   2,305.0
    Total liabilities        1,624.6   1,491.3   1,550.6   1,415.5     755.7
    Net debt outstanding(5)    961.9     752.7     739.1     578.1     264.8
    Weighted average trust
     units (millions)(6)       216.0     210.2     204.4     191.2     186.1
    Trust units outstanding
     and issuable at period
     end (millions)(6)         219.2     213.2     207.2     202.0     188.8
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical  27.1      14.9      11.4       9.2       5.4
    Land                       122.4      77.5      32.4       9.1       4.1
    Drilling and completions   305.4     229.5     240.5     191.8     140.4
    Plant and facilities        90.4      72.1      77.6      55.0      41.1
    Other capital                3.3       3.2       2.6       3.7       2.8
    Total capital expenditures 548.6     397.2     364.5     268.8     193.8
    Property acquisitions
     (dispositions), net        51.0      42.5     115.2      91.3     (58.2)
    Corporate acquisitions(7)      -         -      16.6     505.0      72.0
    Total capital expenditures
     and net acquisitions      599.6     439.7     496.3     865.1     207.6
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)       28,513    28,682    29,042    23,282    22,961
      Natural gas (mmcf/d)     196.5     180.1     179.1     173.8     178.3
      Natural gas liquids
       (bbl/d)                 3,861     4,027     4,170     4,005     4,191
      Total (boe per day 6:1) 65,126    62,723    63,056    56,254    56,870
    Average prices
      Crude oil ($/bbl)        94.20     69.24     65.26     61.11     47.03
      Natural gas ($/mcf)       8.58      6.75      6.97      8.96      6.78
      Natural gas liquids
       ($/bbl)                 69.71     54.79     52.63     49.92     39.04
      Oil equivalent ($/boe)   71.25     54.54     53.33     56.54     43.13
    -------------------------------------------------------------------------
    RESERVES
    (company interest)(8)
    Proved plus probable
     reserves
      Crude oil and NGL
       (mbbl)                153,020   158,341   162,193   163,385   123,226
      Natural gas (bcf)      1,012.2     768.2     743.6     741.7     724.5
      Total (mboe)           321,723   286,370   286,125   286,997   243,974
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
      High                     33.95     23.86     30.74     27.58     17.98
      Low                      15.01     18.90     19.20     16.55     13.50
      Close                    20.10     20.40     22.30     26.49     17.90
    Average daily volume
     (thousands)                 975       597       706       656       420
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares.
    (2) This is a GAAP measure and a change from the non-GAAP measure
        reported in prior quarters. Refer to non-GAAP section.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Based on number of trust units outstanding at each distribution date.
    (5) Net debt excludes the current unrealized risk management contracts
        asset and liability and the current portion of future income taxes.
    (6) Includes trust units issuable for outstanding exchangeable shares
        based on the period end exchange ratio.
    (7) Represents total consideration for the corporate acquisition
        including fees but prior to working capital, asset retirement
        obligation and future income tax liability assumed on acquisition.
    (8) Company interest reserves are the gross interest reserves plus the
        royalty interest prior to the deduction of royalty burdens.


    QUARTERLY HISTORICAL REVIEW
    -------------------------------------------------------------------------
    (Cdn $ millions, except
    per unit amounts)                                   2008
    -------------------------------------------------------------------------
    FINANCIAL                            Q4         Q3         Q2         Q1
    Revenue before royalties          300.8      485.7      512.0      407.9
      Per unit(1)                      1.38       2.24       2.38       1.91
    Cash flow from operating
     activities(2)                    209.4      251.4      273.4      209.9
      Per unit - basic(1)              0.96       1.16       1.27       0.98
      Per unit - diluted               0.96       1.16       1.27       0.98
    Net income                         82.7      311.7       57.3       81.3
      Per unit - basic(3)              0.38       1.46       0.27       0.39
      Per unit - diluted               0.38       1.46       0.27       0.38
    Distributions                     127.2      171.3      144.7      126.8
      Per unit(4)                      0.59       0.80       0.68       0.60
    Total assets                    3,766.7    3,687.5    3,664.3    3,592.6
    Total liabilities               1,624.6    1,530.8    1,689.6    1,560.4
    Net debt outstanding(5)           961.9      773.2      756.1      770.1
    Weighted average trust units(6)   218.3      216.6      215.2      213.8
    Trust units outstanding and
     issuable(6)                      219.2      217.4      215.8      214.7
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical          3.7        1.3       16.4        5.5
    Land                               17.1       18.6       57.8       28.8
    Drilling and completions          117.1       91.4       32.6       64.4
    Plant and facilities               30.5       24.2       24.1       11.6
    Other capital                       1.0        0.9        0.4        1.0
    Total capital expenditures        169.4      136.4      131.3      111.3
    Property acquisitions
     (dispositions) net                27.6       13.1        0.3       10.1
    Total capital expenditures and
     net acquisitions                 197.0      149.5      131.6      121.4
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)              28,935     28,509     27,541     29,064
      Natural gas (mmcf/d)            195.1      192.0      194.7      204.3
      Natural gas liquids (bbl/d)     3,858      3,822      3,906      3,856
      Total (boe per day 6:1)        65,313     64,325     63,896     66,976
    Average prices
      Crude oil ($/bbl)               56.26     114.20     118.32      89.72
      Natural gas ($/mcf)              7.48       8.68      10.41       7.80
      Natural gas liquids ($/bbl)     45.22      82.87      82.29      68.54
      Oil equivalent ($/boe)          49.93      81.42      87.73      66.67
    -------------------------------------------------------------------------
    TRUST UNIT TRADING  (based on
     intra-day trading)
    Unit prices
    High                              22.55      33.30      33.95      27.06
    Low                               15.01      22.33      25.19      20.00
    Close                             20.10      23.10      33.95      26.38
    Average daily volume (thousands)  1,523        841        659        863
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    (1) Per unit amounts (with the exception of per unit distributions) are
        based on weighted average trust units outstanding plus trust units
        issuable for exchangeable shares.
    (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 December 31


    (Cdn$ millions)                                        2008         2007
    -------------------------------------------------------------------------
    ASSETS
      Current assets
      Cash and cash equivalents (Note 4)            $      40.0  $       7.0
      Accounts receivable (Note 5)                        110.0        162.5
      Prepaid expenses                                     16.8         15.0
      Risk management contracts (Notes 5 and 13)           24.4         13.1
      Future income taxes (Note 15)                         3.9          4.0
    -------------------------------------------------------------------------
                                                          195.1        201.6
    Reclamation funds (Note 6)                             28.2         26.1
    Risk management contracts (Notes 5 and 13)              9.2          4.7
    Property, plant and equipment (Note 7)              3,376.6      3,143.0
    Goodwill                                              157.6        157.6
    -------------------------------------------------------------------------
    Total assets                                    $   3,766.7  $   3,533.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities
       (Note 9)                                     $     194.4  $     180.6
      Distributions payable                                32.5         42.1
      Risk management contracts (Notes 5 and 13)           23.5         57.6
    -------------------------------------------------------------------------
                                                          250.4        280.3
    Risk management contracts (Notes 5 and 13)              3.4         28.2
    Long-term debt (Note 10)                              901.8        714.5
    Accrued long-term incentive compensation (Note 21)     14.2         12.1
    Asset retirement obligations (Note 11)                141.5        140.0
    Future income taxes (Note 15)                         313.3        316.2
    -------------------------------------------------------------------------
    Total liabilities                                   1,624.6      1,491.3
    -------------------------------------------------------------------------

    COMMITMENTS AND CONTINGENCIES (Note 22)

    NON-CONTROLLING INTEREST
      Exchangeable shares (Note 16)                        42.4         43.1

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 17)                    2,600.7      2,465.7
      Contributed surplus (Note 20)                           -          1.7
      Deficit (Note 18)                                  (502.9)      (465.9)
      Accumulated other comprehensive income (loss)
       (Note 18)                                            1.9         (2.9)
    -------------------------------------------------------------------------
    Total unitholders' equity                           2,099.7      1,998.6
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity       $   3,766.7  $   3,533.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements


    CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (unaudited)
    For the three and twelve months ended December 31


                                     Three Months Ended   Twelve Months Ended
    (Cdn$ millions, except per           December 31           December 31
     unit amounts)                     2008       2007       2008       2007
    -------------------------------------------------------------------------

    REVENUES
      Oil, natural gas and natural
       gas liquids                $   300.8  $   338.0  $ 1,706.4  $ 1,251.6
    Royalties                         (54.9)     (61.6)    (307.7)    (219.4)
    -------------------------------------------------------------------------
                                      245.9      276.4    1,398.7    1,032.2
    Gain (loss) on risk management
     contracts (Note 13)
      Realized                         32.8       (1.2)     (75.7)      14.1
      Unrealized                       42.0      (47.9)      68.0      (55.9)
    -------------------------------------------------------------------------
                                      320.7      227.3    1,391.0      990.4
    -------------------------------------------------------------------------

    EXPENSES
      Transportation                    5.2        4.0       19.0       16.4
      Operating                        60.7       56.7      241.5      218.4
      General and administrative       14.0       15.0       61.2       49.1
      Provision for non-recoverable
       accounts receivable (Note 5)    14.0          -       32.0          -
      Interest on long-term debt
       (Note 10)                        8.1        9.2       32.9       36.9
      Depletion, depreciation and
       accretion (Notes 7 and 11)      96.2       95.0      379.6      371.5
      Loss (gain) on foreign
       exchange (Note 14)              61.2       (3.2)      89.4      (69.4)
    -------------------------------------------------------------------------
                                      259.4      176.7      855.6      622.9
    -------------------------------------------------------------------------

    Gain on sale of investment
     (Note 8)                             -          -          -       13.3
    Future income tax recovery
     (Note 15)                         22.3       57.2        4.5      121.3
    -------------------------------------------------------------------------
    Net income before
     non-controlling interest          83.6      107.8      539.9      502.1
    Non-controlling interest
     (Note 16)                         (0.9)      (1.5)      (6.9)      (6.8)
    -------------------------------------------------------------------------
    Net income                    $    82.7  $   106.3  $   533.0  $   495.3
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Deficit, beginning of period  $  (458.4) $  (446.4) $  (465.9) $  (463.2)
    Distributions paid or declared
     (Note 19)                       (127.2)    (125.8)    (570.0)    (498.0)
    -------------------------------------------------------------------------
    Deficit, end of period
     (Note 18)                    $  (502.9) $  (465.9) $  (502.9) $  (465.9)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income per unit (Note 17)
      Basic                       $    0.38  $    0.51  $    2.50  $    2.39
      Diluted                     $    0.38  $    0.51  $    2.50  $    2.39
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements


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

                                     Three Months Ended   Twelve Months Ended
    (Cdn$ millions, except               December 31           December 31
     per unit amounts)                 2008       2007       2008       2007
    -------------------------------------------------------------------------

    Net income                    $    82.7  $   106.3  $   533.0  $   495.3

    Other comprehensive income
     (loss), net of tax
      Gains (losses) on financial
       instruments designated as
       cash flow hedges(1)              0.6       (6.4)      (2.2)      (7.4)
      De-designation of cash flow
       hedge(2) (Note 13)                 -          -       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 13)                       (0.9)      (0.5)      (2.9)      (0.3)
      Net unrealized gains (losses)
       on available-for-sale
       reclamation funds'
       investments(4)                     -        0.1       (0.1)      (0.1)
    -------------------------------------------------------------------------
    Other comprehensive (loss)
     income                            (0.3)      (6.8)       4.8       (7.8)
    -------------------------------------------------------------------------
    Comprehensive income          $    82.4  $    99.5  $   537.8  $   487.5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accumulated other
     comprehensive income (loss),
     beginning of period                2.2        3.9       (2.9)         -
    Application of initial
     adoption                             -          -          -        4.9
    Other comprehensive (loss)
     income                            (0.3)      (6.8)       4.8       (7.8)
    -------------------------------------------------------------------------
    Accumulated other
     comprehensive income (loss),
     end of period (Note 18)      $     1.9  $    (2.9) $     1.9  $    (2.9)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Amounts are net of tax of $0.2 million for the three months ended
        December, 2008 and net of tax of $0.8 million for the twelve months
        ended December 31, 2008 (net of tax of $2.4 million and $2.7 million,
        respectively, for the three and twelve months ended December 31,
        2007).
    (2) Amount is net of tax of $3.6 million for the twelve months ended
        December 31, 2008.
    (3) Amounts are net of tax of $0.3 million and $1 million,
        respectively, for the three and twelve months ended December 31, 2008
        (net of tax of $0.2 and $0.1 million, respectively, for the three and
        twelve months ended December 31, 2007).
    (4) Nominal future income tax impact for the three and twelve months
        ended December 31, 2008 (nominal for the three and twelve months
        ended December 31, 2007).

    See accompanying notes to the consolidated financial statements


    CONSOLIDATED STATEMENTS OF CASH FLOWS(unaudited)
    For the three and twelve months ended December 31


                                     Three Months Ended   Twelve Months Ended
                                         December 31           December 31
    (Cdn$ millions)                    2008       2007       2008       2007
    -------------------------------------------------------------------------
    CASH FLOWS FROM OPERATING
     ACTIVITIES
    Net income                    $    82.7  $   106.3  $   533.0  $   495.3
    Add items not involving cash:
      Non-controlling interest
       (Note 16)                        0.9        1.5        6.9        6.8
      Future income tax recovery
       (Note 15)                      (22.3)     (57.2)      (4.5)    (121.3)
      Depletion, depreciation and
       accretion (Notes 7 and 11)      96.2       95.0      379.6      371.5
      Non-cash (gain) loss on
       risk management contracts
       (Note 13)                      (42.0)      47.9      (68.0)      55.9
      Non-cash loss (gain) on
       foreign exchange (Note 14)      61.6       (3.1)      88.5      (69.6)
      Non-cash trust unit
       incentive compensation
       (recovery) expense (Note 21)    (4.2)       3.6        1.0        3.5
      Gain on sale of investment
       (Note 8)                           -          -          -      (13.3)
    Expenditures on site
     restoration and reclamation
     (Note 11)                         (4.7)      (3.6)     (12.4)     (18.2)
    Change in non-cash working
     capital                           41.2      (16.7)      20.3       (5.7)
    -------------------------------------------------------------------------
                                      209.4      173.7      944.4      704.9
    -------------------------------------------------------------------------

    CASH FLOWS FROM FINANCING
     ACTIVITIES
    Issuance of long-term debt
     under revolving credit
     facilities, net                  164.0       99.1      105.9      104.2
    Repayment of senior secured
     notes                             (7.1)      (5.8)      (7.1)      (5.8)
    Issue of trust units                0.5        0.8        4.9        3.7
    Cash distributions paid
     (Note 19)                       (117.6)     (99.1)    (458.8)    (388.4)
    Payment of retention bonuses          -          -          -       (1.0)
    Change in non-cash working
     capital                           (1.5)      (0.9)      (0.4)       0.4
    -------------------------------------------------------------------------
                                       38.3       (5.9)    (355.5)    (286.9)
    -------------------------------------------------------------------------

    CASH FLOWS FROM INVESTING
     ACTIVITIES
    Acquisition of petroleum and
     natural gas properties           (27.6)      (5.1)     (51.2)     (43.7)
    Proceeds on disposition of
     petroleum and natural gas
     properties                           -          -        0.2        1.2
    Capital expenditures             (169.9)    (138.9)    (548.1)    (396.5)
    Long-term investment (Note 8)         -          -          -       33.3
    Net reclamation fund
     (contributions) withdrawals
     (Note 6)                          (1.3)       0.2       (2.2)       4.7
    Change in non-cash working
     capital                            3.5      (17.0)      45.4      (12.8)
    -------------------------------------------------------------------------
                                     (195.3)    (160.8)    (555.9)    (413.8)
    -------------------------------------------------------------------------
    INCREASE IN CASH AND CASH
     EQUIVALENTS                       52.4        7.0       33.0        4.2
    CASH AND CASH EQUIVALENTS,
     BEGINNING OF PERIOD              (12.4)         -        7.0        2.8
    -------------------------------------------------------------------------
    CASH AND CASH EQUIVALENTS,
     END OF PERIOD                $    40.0  $     7.0  $    40.0  $     7.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements



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

    1.  STRUCTURE OF THE TRUST

        ARC Energy Trust (the "Trust") was formed on May 7, 1996 pursuant to
        a Trust indenture (the "Trust Indenture") that has been amended from
        time to time, most recently on May 15, 2006. Computershare Trust
        Company of Canada was appointed as Trustee under the Trust Indenture.
        The beneficiaries of the Trust are the holders of the Trust units.

        The Trust was created for the purposes of issuing trust units to the
        public and investing the funds so raised to purchase a royalty in the
        properties of ARC Resources Ltd. ("ARC Resources") and ARC Oil & Gas
        Fund ("ARC Oil & Gas"). As part of an internal reorganization on
        January 1, 2008 the properties of ARC Oil & Gas Fund were transferred
        to ARC Resources and the royalty in the properties of ARC Oil & Gas
        Fund was assigned to ARC Resources. The Trust Indenture was amended
        on June 7, 1999 to convert the Trust from a closed-end to an open-
        ended investment Trust. The current business of the Trust includes
        the investment in all types of energy business-related assets
        including, but not limited to, petroleum and natural gas-related
        assets, gathering, processing and transportation assets. The
        operations of the Trust consist of the acquisition, development,
        exploitation and disposition of these assets and the distribution of
        the net cash proceeds from these activities to the unitholders.

    2.  SUMMARY OF ACCOUNTING POLICIES

        The Consolidated Financial Statements have been prepared by
        management following Canadian generally accepted accounting
        principles ("GAAP"). The preparation of financial statements requires
        management to make estimates and assumptions that affect the reported
        amounts of assets and liabilities and the disclosure of contingencies
        at the date of the financial statements, and revenues and expenses
        during the reporting year. Actual results could differ from those
        estimated.

        The amounts recorded for depreciation and depletion of petroleum and
        natural gas property and equipment and for asset retirement
        obligations are based on estimates of petroleum and natural gas
        reserves and future costs. Estimates of reserves also provide the
        basis for determining whether the carrying value of property, plant
        and equipment is impaired. Accounts receivable are recorded at the
        estimated net recoverable amount which involves estimates of
        uncollectable accounts. Goodwill impairment tests involve estimates
        of the Trust's fair value. By their nature, these estimates are
        subject to measurement uncertainty, and the impact on the financial
        statements of future periods could be material.

        Principles of Consolidation


        The Consolidated Financial Statements include the accounts of the
        Trust and its subsidiaries. Any reference to "the Trust" throughout
        these Consolidated Financial Statements refers to the Trust and its
        subsidiaries. All inter-entity transactions have been eliminated.

        Revenue Recognition

        Revenue associated with the sale of crude oil, natural gas, and
        natural gas liquids ("NGLs") owned by the Trust are recognized when
        title passes from the Trust to its customers.

        Transportation

        Costs paid by the Trust for the transportation of natural gas, crude
        oil and NGLs from the wellhead to the point of title transfer are
        recognized when the transportation is provided.

        Joint Interests

        The Trust conducts many of its oil and gas production activities
        through jointly controlled operations and the financial statements
        reflect only the Trust's proportionate interest in such activities.

        Depletion and Depreciation

        Depletion of petroleum and natural gas properties and depreciation of
        production equipment are calculated on the unit-of-production basis
        based on:

        (a) total estimated proved reserves calculated in accordance with
            National Instrument 51-101, Standards of Disclosure for Oil and
            Gas Activities;

        (b) total capitalized costs, excluding undeveloped lands, plus
            estimated future development costs of proved undeveloped
            reserves, including future estimated asset retirement costs; and

        (c) relative volumes of petroleum and natural gas reserves and
            production, before royalties, converted at the energy equivalent
            conversion ratio of six thousand cubic feet of natural gas to one
            barrel of oil.

        Unit Based Compensation

        The Trust established a Trust Unit Incentive Rights Plan (the "Rights
        Plan") for employees, independent directors and long-term consultants
        who otherwise meet the definition of an employee of the Trust. The
        exercise price of the rights granted under the Plan may be reduced in
        future periods in accordance with the terms of the Plan. The Trust
        accounts for the rights using the fair value method, whereby the fair
        value of rights is determined on the date on which fair value can
        initially be determined. The fair value is then recorded as
        compensation expense over the period that the rights vest, with a
        corresponding increase to contributed surplus. When rights are
        exercised, the proceeds, together with the amount recorded in
        contributed surplus, are recorded to unitholders' capital.

        Whole Trust Unit Incentive Plan Compensation

        The Trust has established a Whole Trust Unit Incentive Plan (the
        "Whole Unit Plan") for employees, independent directors and long-term
        consultants who otherwise meet the definition of an employee of the
        Trust. Compensation expense associated with 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
        intrinsic valuation method is used as participants of the Whole Unit
        Plan receive a cash payment on a fixed vesting date. This valuation
        incorporates the year end Trust unit price, the number of RTUs and
        PTUs outstanding at each period end, and certain management
        estimates. As a result, large fluctuations, even recoveries, in
        compensation expense may occur due to changes in the underlying trust
        unit price. In addition, compensation expense is amortized and
        recognized in earnings over the vesting period of the Whole Unit Plan
        with a corresponding increase or decrease in liabilities.
        Classification between accrued liabilities and accrued long-term
        incentive compensation is dependent on the expected payout date.

        The Trust charges amounts relating to head office employees to
        general and administrative expense, amounts relating to field
        employees to operating expense and amounts relating to geologists and
        geophysicists to property, plant and equipment.

        The Trust has not incorporated an estimated forfeiture rate for RTUs
        and PTUs that will not vest. Rather, the Trust accounts for actual
        forfeitures as they occur.

        Cash Equivalents

        Cash equivalents include short-term investments, such as money market
        deposits or similar type instruments, with an original maturity of
        three months or less when purchased.

        Reclamation Funds

        Reclamation funds hold investment grade assets and cash and cash
        equivalents. Investments are categorized as either held-to-maturity
        or available-for-sale assets, which are initially measured at fair
        value. Held-to-maturity investments are subsequently measured at
        amortized cost using the effective interest method. Available-for-
        sale investments are subsequently measured at fair value with changes
        in fair value recognized in other comprehensive income, net of tax.

        Investments carried at amortized cost are subject to impairment
        losses in the event of a non-temporary decline in market value.

        Property, Plant and Equipment ("PP&E")

        The Trust follows the full cost method of accounting. All costs of
        exploring, developing and acquiring petroleum and natural gas
        properties, including asset retirement costs, are capitalized and
        accumulated in one cost centre as all operations are in Canada.
        Maintenance and repairs are charged against earnings, and renewals
        and enhancements that extend the economic life of the PP&E are
        capitalized. Gains and losses are not recognized upon disposition of
        petroleum and natural gas properties unless such a disposition would
        alter the rate of depletion by 20 per cent or more.

        Impairment

        The Trust places a limit on the aggregate carrying value of PP&E,
        which may be amortized against revenues of future periods.

        Impairment is recognized if the carrying amount of the PP&E exceeds
        the sum of the undiscounted cash flows expected to result from the
        Trust's proved reserves. Cash flows are calculated based on third
        party quoted forward prices, adjusted for the Trust's contract prices
        and quality differentials.

        Upon recognition of impairment, the Trust would then measure the
        amount of impairment by comparing the carrying amounts of the PP&E to
        an amount equal to the estimated net present value of future cash
        flows from proved plus risked probable reserves. The Trust's risk-
        free interest rate is used to arrive at the net present value of the
        future cash flows. Any excess carrying value above the net present
        value of the Trust's future cash flows would be recorded as a
        permanent impairment and charged against net income.

        The cost of unproved properties is excluded from the impairment test
        described above and subject to a separate impairment test. In the
        case of impairment, the book value of the impaired properties is
        moved to the petroleum and natural gas depletable base.

        Goodwill

        The Trust must record goodwill relating to a corporate acquisition
        when the total purchase price exceeds the fair value for accounting
        purposes of the net identifiable assets and liabilities of the
        acquired company. The goodwill balance is assessed for impairment
        annually at year-end or as events occur that could result in an
        indication of impairment. Impairment is recognized based on the fair
        value of the reporting entity (consolidated Trust) compared to the
        book value of the reporting entity. If the fair value of the
        consolidated Trust is less than the book value, impairment is
        measured by allocating the fair value of the consolidated Trust to
        the identifiable assets and liabilities as if the Trust had been
        acquired in a business combination for a purchase price equal to its
        fair value. The excess of the fair value of the consolidated Trust
        over the amounts assigned to the identifiable assets and liabilities
        is the fair value of the goodwill. Any excess of the book value of
        goodwill over this implied fair value of goodwill is the impairment
        amount. Impairment is charged to earnings in the period in which it
        occurs.

        Goodwill is stated at cost less impairment and is not amortized.

        Asset Retirement Obligations

        The Trust recognizes an Asset Retirement Obligation ("ARO") in the
        period in which it is incurred when a reasonable estimate of the fair
        value can be made. On a periodic basis, management will review these
        estimates and changes, if any, will be applied prospectively. The
        fair value of the estimated ARO is recorded as a long-term liability,
        with a corresponding increase in the carrying amount of the related
        asset. The capitalized amount is depleted on a unit-of-production
        basis over the life of the reserves. The liability amount is
        increased each reporting period due to the passage of time and the
        amount of accretion is charged to earnings in the period. Revisions
        to the estimated timing of cash flows or to the original estimated
        undiscounted cost would also result in an increase or decrease to the
        ARO. Actual costs incurred upon settlement of the obligation are
        charged against the ARO to the extent of the liability recorded.

        Income Taxes

        The Trust follows the liability method of accounting for income
        taxes. Under this method, income tax liabilities and assets are
        recognized for the estimated tax consequences attributable to
        differences between the amounts reported in the financial statements
        of the Trust and the Trust's corporate subsidiaries and their
        respective tax base, using substantively enacted future income tax
        rates. The effect of a change in income tax rates on future tax
        liabilities and assets is recognized in income in the period in which
        the change occurs, provided that the income tax rates are
        substantively enacted. Temporary differences arising on acquisitions
        result in future income tax assets and liabilities.

        Basic and Diluted per Trust Unit Calculations

        Basic net income per unit is computed by dividing the net income by
        the weighted average number of trust units outstanding during the
        period. Diluted net income per unit amounts are calculated based on
        net income before non-controlling interest divided by dilutive trust
        units. Dilutive trust units are arrived at by adding weighted average
        trust units to trust units issuable on conversion of exchangeable
        shares, and to the potential dilution that would occur if rights were
        exercised at the beginning of the period. The treasury stock method
        assumes that proceeds received from the exercise of in-the-money
        rights and the unrecognized trust unit incentive compensation are
        used to repurchase units at the average market price.

        Financial Instruments

        Financial assets, financial liabilities and non-financial derivatives
        are measured at fair value on initial recognition. Measurement in
        subsequent periods depends on whether the financial instrument has
        been classified as held-for-trading, available-for-sale, held-to-
        maturity, loans and receivables, or other financial liabilities.

        a. Held-for-trading

           Financial assets and liabilities designated as held-for-trading
           are subsequently measured at fair value with changes in those fair
           values charged immediately to earnings. With the exception of risk
           management contracts that qualify for hedge accounting, the Trust
           classifies all risk management contracts as held-for-trading. Cash
           and cash equivalents are also classified as held-for-trading.

        b. Available-for-sale assets

           Available-for-sale financial assets are subsequently measured at
           fair value with changes in fair value recognized in Other
           Comprehensive Income ("OCI"), net of tax. Amounts recognized in
           OCI for available-for-sale financial assets are charged to
           earnings when the asset is derecognized or when there is an other
           than temporary asset impairment.

        c. Held-to-maturity investments, loans and receivables and other
           financial liabilities

           Held-to-maturity investments, loans and receivables, and other
           financial liabilities are subsequently measured at amortized cost
           using the effective interest method. The Trust classifies accounts
           receivable to loans and receivables, and accounts payable,
           distributions payable and long-term debt to other financial
           liabilities.

        Transaction costs are expensed as incurred for all financial
        instruments.

        The Trust has elected January 1, 2003 as the effective date to
        identify and measure embedded derivatives in financial and non-
        financial contracts that are not closely related to the host
        contracts.

        The Trust is exposed to market risks resulting from fluctuations in
        commodity prices, foreign exchange rates and interest rates in the
        normal course of operations. A variety of derivative instruments are
        used by the Trust to reduce its exposure to fluctuations in commodity
        prices, foreign exchange rates, and interest rates. The fair values
        of these derivative instruments are based on an estimate of the
        amounts that would have been received or paid to settle these
        instruments prior to maturity. The Trust considers all of these
        transactions to be effective economic hedges; however, most of the
        Trust's contracts do not qualify or have not been designated as
        effective hedges for accounting purposes.

        For transactions that do not qualify for hedge accounting, the Trust
        applies the fair value method of accounting by recording an asset or
        liability on the Consolidated Balance Sheet and recognizing changes
        in the fair value of the instruments in earnings during the current
        period.

        For derivative instruments that do qualify as effective accounting
        hedges, policies and procedures are in place to ensure that the
        required documentation and approvals are in place. This documentation
        specifically ties the derivative financial instruments to their use,
        and in the case of commodities, to the mitigation of market price
        risk associated with cash flows expected to be generated. When
        applicable, the Trust also identifies all relationships between
        hedging instruments and hedged items, as well as its risk management
        objective and the strategy for undertaking hedge transactions. This
        would include linking the particular derivative to specific assets
        and liabilities on the Consolidated Balance Sheet or to specific firm
        commitments or forecasted transactions.

        Where specific hedges are executed, the Trust assesses, both at the
        inception of the hedge and on an ongoing basis, whether the
        derivative used in the particular hedging transaction is effective in
        offsetting changes in fair value or cash flows of the hedged item.
        Hedge accounting is discontinued prospectively when the derivative no
        longer qualifies as an effective hedge, or the derivative is
        terminated or sold, or upon the sale or early termination of the
        hedged item. The Trust has currently designated a portion of its
        financial electricity contracts as effective cash flow hedges.

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

        When hedge accounting is applied to a derivative used to hedge an
        anticipated transaction and it is determined that the anticipated
        transaction will not occur within the originally specified time
        period, hedge accounting is discontinued and the unrealized gains and
        losses are reclassified from AOCI to earnings.

        Foreign Currency Translation

        Monetary assets and liabilities denominated in a foreign currency are
        translated at the rate of exchange in effect at the Consolidated
        Balance Sheet date. Revenues and expenses are translated at the
        period average rates of exchange. Translation gains and losses are
        included in earnings in the period in which they arise.

        Non-Controlling Interest

        The Trust must record non-controlling interest when exchangeable
        shares issued by a subsidiary of the Trust are transferable to third
        parties. Non-controlling interest on the Consolidated Balance Sheet
        is recognized based on the fair value of the exchangeable shares upon
        issuance plus the accumulated earnings attributable to the non-
        controlling interest. Net income is reduced for the portion of
        earnings attributable to the non-controlling interest. As the
        exchangeable shares are converted to Trust units, the non-controlling
        interest on the Consolidated Balance Sheet is reduced by the
        cumulative book value of the exchangeable shares and Unitholders'
        capital is increased by the corresponding amount.

    3.  NEW ACCOUNTING POLICIES

        Current Year Accounting Changes

        Effective January 1, 2008, the Trust adopted three new accounting
        standards that were issued by the Canadian Institute of Chartered
        Accountants ("CICA"): Section 1535, Capital Disclosures, Section
        3862, Financial Instruments - Disclosures and Section 3863, Financial
        Instruments - Presentation.

        A. Capital Disclosures

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

        B. Financial Instruments - Disclosures, Financial Instruments -
        Presentation

        Sections 3862 and 3863 establish standards for enhancing financial
        statements users' understanding of the significance of financial
        instruments to an entity's financial position, performance and cash
        flows. They require that entities provide disclosures regarding the
        nature and extent of risks arising from financial instruments to
        which they are exposed both during the reporting period and at the
        balance sheet date, as well as how the entities manage those risks.

        These standards were adopted prospectively.

        Future Accounting Changes

        A. Goodwill and Intangible Assets

        In February 2008, the CICA issued Section 3064, Goodwill and
        Intangible Assets, replacing Section 3062, Goodwill and Other
        Intangible Assets and Section 3450, Research and Development Costs.
        The new Section will be effective on January 1, 2009. Section 3064
        establishes standards for the recognition, measurement, presentation
        and disclosure of goodwill and intangible assets subsequent to its
        initial recognition. Standards concerning goodwill are unchanged from
        the standards included in the previous Section 3062. The Trust is
        currently evaluating the impact of the adoption of this new Section,
        however does not expect a material impact on its consolidated
        financial statements.

        B. 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. At this time, the Trust is evaluating the impact
        of these differences and assessing the need for amendments to
        existing accounting policies in order to comply with IFRS.

    4.  CASH AND CASH EQUIVALENTS

        Cash equivalents comprise $40 million in Canadian Treasury Bills as
        at December 31, 2008 ($7 million in cash as at December 31, 2007).

    5.  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
        December 31, 2008 pertains to accrued revenue for December 2008
        production volumes. The Trust transacts with a number of oil and
        natural gas marketing companies ("marketers") to sell the Trust's
        production on its behalf. Marketers 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 December 31, 2008, no one
        counterparty accounted for more than 20 per cent of the total
        accounts receivable balance.

        The Trust recorded a provision for non-collectible accounts
        receivable of $32 million in 2008 (nil in 2007). In July 2008,
        SemCanada Crude ("SemCanada"), a counterparty that marketed a portion
        of the Trust's production filed for protection under the Companies'
        Creditors Arrangement Act ("CCAA"). The Trust's total exposure to
        SemCanada was $30.6 million. Due to uncertainty surrounding the
        ultimate recoverable amount and expected timing of recovery, the
        Trust recorded a provision for the full SemCanada receivable of
        $30.6 million in 2008. In addition, the Trust recorded a provision of
        $1.4 million for six additional counterparties that also filed for
        CCAA protection during 2008 or were experiencing financial distress.
        The Trust's allowance for doubtful accounts was $32 million as at
        December 31, 2008 (nil as at December 31, 2007).

        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
        December 31, 2008 $5.5 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.

    6.  RECLAMATION FUNDS

        ---------------------------------------------------------------------
                             December 31, 2008           December 31, 2007
        ---------------------------------------------------------------------
                      Unrestricted    Restricted  Unrestricted    Restricted
        ---------------------------------------------------------------------

        ---------------------------------------------------------------------
        Balance,
         beginning
         of year         $    14.4     $    11.7     $    24.8     $     6.1
        Contributions          5.8           5.9           6.2           5.9
        Reimbursed
         expenditures(1)      (9.7)         (1.0)        (17.5)         (0.6)
        Interest earned
         on funds              0.8           0.4           1.1           0.3
        Net unrealized
         gains and losses
         on available-for-
         sale investments     (0.1)            -          (0.2)            -
        ---------------------------------------------------------------------
        Balance, end
         of year(2)      $    11.2     $    17.0     $    14.4     $    11.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Amount differs from actual expenditures incurred by the Trust due
            to timing differences and discretionary reimbursements.
        (2) As at December 31, 2008 the unrestricted reclamation fund held
            nil in cash and cash equivalents ($1.5 million at December 31,
            2007), with the balance held in investment grade assets.

        An unrestricted reclamation fund was established to fund future asset
        retirement obligation costs. In addition, the Trust has created a
        restricted reclamation fund associated with the Redwater property
        acquired in 2005. Contributions to the restricted and unrestricted
        reclamation funds and interest earned on the balances have been
        deducted from the cash distributions to the unitholders. The Board of
        Directors of ARC Resources has approved voluntary contributions to
        the unrestricted reclamation fund over a 20-year period that
        currently results in minimum annual contributions of $6 million
        ($6 million in 2007) based upon properties owned as at December 31,
        2008. Required contributions to the restricted reclamation fund will
        vary over time and have been disclosed in Note 22. Contributions for
        both funds are continually reassessed to ensure that the funds are
        sufficient to finance the majority of future abandonment obligations.
        Interest earned on the funds is retained within the funds.

        For the years ended December 31, 2008 and December 31, 2007,
        respectively, nominal amounts relating to available-for-sale
        reclamation fund assets were classified from accumulated other
        comprehensive income into earnings. At December 31, 2007 the fair
        value of reclamation fund assets designated as held to maturity
        approximated carrying value. During the fourth quarter of 2008,
        assets previously classified as held-to-maturity were reclassified to
        available-for-sale, as it was determined that the Trust no longer has
        the intention to hold these assets to maturity. As at December 31,
        2008 all reclamation fund assets are reflected at fair value. The
        fair values are obtained from third parties, determined directly by
        reference to quoted market prices.

    7.  PROPERTY, PLANT AND EQUIPMENT

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Property, plant and equipment, at cost       $ 5,668.9     $ 5,065.0
        Accumulated depletion and depreciation        (2,292.3)     (1,922.0)
        ---------------------------------------------------------------------
        Property, plant and equipment, net           $ 3,376.6     $ 3,143.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The calculation of 2008 depletion and depreciation included an
        estimated $872 million ($549 million in 2007) for future development
        costs associated with proved undeveloped reserves and excluded
        $287.5 million ($173.7 million in 2007) for the book value of
        unproved properties.

        The Trust performed a ceiling test calculation at December 31, 2008
        to assess the recoverable value of property plant and equipment
        ("PP&E"). Based on the calculation, the value of future net revenues
        from the Trust's reserves exceeded the carrying value of the Trust's
        PP&E at December 31, 2008. The benchmark prices used in the
        calculation were as follows:

                                     WTI Oil        AECO Gas        Cdn$/US$
        Year                        (US$/bbl)    (Cdn$/mmbtu) Exchange Rates
        ---------------------------------------------------------------------
        2009                           57.50            7.58            1.21
        2010                           68.00            7.94            1.18
        2011                           74.00            8.34            1.14
        2012                           85.00            8.70            1.08
        2013                           92.01            8.95            1.05
        2014                           93.85            9.14            1.05
        2015                           95.73            9.34            1.05
        2016                           97.64            9.54            1.05
        2017                           99.59            9.75            1.05
        2018                          101.59            9.95            1.05
        2019                          103.62           10.15            1.05
        ---------------------------------------------------------------------
        Remainder(1)                    2.0%            2.0%            1.05
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Percentage change represents the change in each year after 2019
            to the end of the reserve life.

    8.  LONG-TERM INVESTMENT

        In 2007 the Trust sold its equity investment in a private oil sands
        company for proceeds of $33.3 million, resulting in a gain on sale of
        investment of $13.3 million. The original investment was purchased in
        2006 for $20 million. The investment in the shares of the private
        company was considered to be a related party transaction due to
        common directorships of the Trust, the private company and the
        manager of a private equity fund that held shares in the private
        company. In addition, certain directors and officers of the Trust had
        minor direct and indirect shareholdings in the private company.

    9.  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
        December 31, 2008:

        ---------------------------------------------------------------------
                              1 year     2 - 3     4 - 5    Beyond
        ($ millions)                     years     years   5 years     Total
        ---------------------------------------------------------------------
        Accounts payable
         and accrued
         liabilities(1)        198.1         -         -         -     198.1
        Distributions
         payable(2)             25.6         -         -         -      25.6
        Risk management
         contracts(3)           24.3       6.4       0.3         -      31.0
        Senior secured notes
         and interest           33.0      78.0     187.6      21.6     320.2
        Revolving credit
         facilities                -     642.2         -         -     642.2
        Accrued long-term
         incentive
         compensation(1)           -      37.1         -         -      37.1
        ---------------------------------------------------------------------
        Total financial
         liabilities           281.0     763.7     187.9      21.6   1,254.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Liabilities under the Whole Trust Unit Incentive 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 10 for further
        details on available amounts under existing banking arrangements and
        Note 12 for further details on capital management.

    10. LONG-TERM DEBT

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Revolving credit facilities
          Syndicated credit facility - Cdn$
           denominated                               $   399.5     $   344.9
          Syndicated credit facility - US$
           denominated                                   240.6         154.1
          Working capital facility(1)                      2.1             -
        Senior secured notes
          5.42% US$ Note                                  91.9          74.1
          4.94% US$ Note                                  14.7          17.8
          4.62% US$ Note                                  76.5          61.8
          5.10% US$ Note                                  76.5          61.8
        ---------------------------------------------------------------------
        Total long-term debt outstanding             $   901.8     $   714.5
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Amount borrowed under the working capital facility comprises
            $2.1 million of outstanding cheques in excess of bank balance.

        Revolving Credit Facilities

        During 2008, the Trust renewed its $800 million secured, annually
        extendible, financial covenant-based syndicated credit facility. The
        revolving credit facility's security is in the form of a floating
        charge on all lands and assignments and a negative pledge on
        petroleum and natural gas properties. The Trust also has in place a
        $25 million demand working capital facility.

        Borrowings under the credit facility bear interest at bank prime
        (four per cent at December 31, 2008 and six percent at December 31,
        2007) 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 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
        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") at a ratio of less than one to a
        maximum of 110 bps at a ratio exceeding 2.5.

        The working capital facility allows for maximum borrowings of
        $25 million and is due and payable immediately upon demand by the
        bank. The facility is secured and is subject to the same covenants as
        the syndicated credit facility.

        5.42 Per Cent and 4.94 Per Cent Senior Secured US$ Notes

        These senior secured notes were issued in two separate issues
        pursuant to an Uncommitted Master Shelf Agreement. The US$12 million
        senior secured notes were issued in 2002, bear interest at 4.94 per
        cent, have a remaining final term of 1.8 years (remaining average
        term of 1.3 years) and require equal principal repayments of
        US$6 million in 2009 and 2010. The US$75 million senior secured notes
        were issued in 2005, bear interest at 5.42 per cent, have a remaining
        final term of nine years (remaining weighted average term of 5.5
        years) and require equal principal repayments of US$9.4 million over
        an eight year period commencing in 2010.

        4.62 Per Cent and 5.10 Per Cent Senior Secured US$ Notes

        These notes were issued on April 27, 2004 via a private placement in
        two tranches of US$62.5 million each. The first tranche of
        US$62.5 million bears interest at 4.62 per cent and has a remaining
        final term of 5.3 years (remaining weighted average term of 2.9
        years) and requires equal principal repayments of US$10.4 million
        over a six year period commencing in 2009. Immediately following the
        issuance, the Trust entered into interest rate swap contracts which
        effectively changed the interest rate from fixed to floating (see
        Note 13). The second tranche of US$62.5 million bears interest at
        5.10 per cent and has a remaining final term of 7.3 years (remaining
        weighted average term of 5.4 years). Repayment of the notes will
        occur in equal principal repayments of US$12.5 million over a five
        year period commencing in 2012.

        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% for the subsequent six month period. As at
        December 31, 2008, the Trust had $1.9 million in letters of credit
        ($4.8 million in 2007), 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 2008, the weighted-average effective interest rate under the
        credit facility was 3.8 per cent (5.5 per cent in 2007).

        Amounts of US$16.4 million due under the senior secured notes 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 December 31, 2008 is $289.9 million
        ($226.1 million as at December 31, 2007), and is calculated as the
        present value of principal and interest payments discounted at the
        Trust's credit adjusted risk free rate.

        Interest paid during 2008 was $1.6 million more than interest
        expense, $1.8 million less in 2007.

    11. ASSET RETIREMENT OBLIGATIONS

        The total future asset retirement obligations were estimated by
        management based on the Trust's net ownership interest in all wells
        and facilities, estimated costs to reclaim and abandon the wells and
        facilities and the estimated timing of the costs to be incurred in
        future periods. The Trust has estimated the net present value of its
        total asset retirement obligations to be $141.5 million as at
        December 31, 2008 ($140 million in 2007) based on a total future
        undiscounted liability of $1.32 billion ($1.29 billion in 2007). At
        December 31, 2008 management estimates that these payments are
        expected to be made over the next 51 years with the majority of
        payments being made in years 2049 to 2059. The Trust's weighted
        average credit adjusted risk free rate of 6.6 per cent (6.6 per cent
        in 2007) and an inflation rate of 2.0 per cent (2.0 per cent in 2007)
        were used to calculate the present value of the asset retirement
        obligations. During the year, no gains or losses were recognized on
        settlements of asset retirement obligations.

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Balance, beginning of year                   $   140.0     $   177.3
        Increase in liabilities relating to
         development activities                            2.0           3.8
        Increase (decrease) in liabilities relating
         to change in estimate                             2.6         (34.4)
        Settlement of liabilities during the year        (12.4)        (18.2)
        Accretion expense                                  9.3          11.5
        ---------------------------------------------------------------------

        ---------------------------------------------------------------------
        Balance, end of year                         $   141.5     $   140.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    12. CAPITAL MANAGEMENT

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

        -  Fund its development and exploration program;

        -  Provide financial flexibility to execute on strategic
           opportunities;

        -  Maintain a level of distributions that, in 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
        December 31, 2008 the Trust's net debt to annualized cash flow from
        operating activities ratio is 1.0 and its net debt to total
        capitalization ratio is 17.9 per cent.

        ---------------------------------------------------------------------
        ($ millions except per unit and            December 31,  December 31,
         per cent amounts)                                2008          2007
        ---------------------------------------------------------------------
        Long-term debt                                   901.8         714.5
        Accounts payable and accrued liabilities         194.4         180.6
        Distributions payable                             32.5          42.1
        Cash and cash equivalents, accounts receivable
         and prepaid expenses                           (166.8)       (184.5)
        ---------------------------------------------------------------------
        Net debt obligations(1)                          961.9         752.7
        ---------------------------------------------------------------------

        Trust units outstanding and issuable for
         exchangeable shares (millions)                  219.2         213.2
        Trust unit price                                 20.10         20.40
        ---------------------------------------------------------------------
        Market capitalization(1)                       4,405.9       4,349.3
        Net debt obligations(1)                          961.9         752.7
        ---------------------------------------------------------------------
        Total capitalization(1)                        5,367.8       5,102.0
        ---------------------------------------------------------------------

        Net debt as a percentage of total
         capitalization                                  17.9%         14.8%
        Net debt obligations to annualized cash
         flow from operating activities                    1.0           1.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (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.

        As a result of the volatility of oil prices throughout 2008, the
        Trust made several changes to the monthly distribution amounts
        declared and paid to unitholders. During the first seven months of
        2008, oil prices soared to record high amounts causing the Trust to
        increase monthly distributions to $0.28 per unit in order to meet the
        Trust's objective of transferring tax liabilities to unitholders and
        minimizing taxes paid by the Trust. In the third quarter of 2008, oil
        prices decreased significantly causing the Trust to reduce
        distributions to $0.15 per unit. Subsequent to year end, the Trust
        further decreased distributions to $0.12 per unit in light of the
        continued weak commodity price environment.

        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 December 31,
        2008 the Trust is in compliance with all covenants. Refer to Note 10
        for further details.

    13. MARKET RISK MANAGEMENT

        The Trust is exposed to a number of market risks that are part of its
        normal course of business. The Trust has a risk management program in
        place that includes financial instruments as disclosed in the risk
        management section of this note. Financial instruments of the Trust
        carried on the Consolidated Balance Sheet are carried at amortized
        cost with the exception of cash and cash equivalents, reclamation
        fund assets classified as available-for-sale and risk management
        contracts, which are carried at fair value. With the exception of the
        Trust's senior secured notes, there were no significant differences
        between the carrying value of financial instruments and their
        estimated fair values as at December 31, 2008. The fair value of the
        Trust's senior secured notes is disclosed in Note 10.

        ARC's risk management program is overseen by its Risk Committee based
        on guidelines approved by the Board of Directors. The objective of
        the risk management program is to support the Trust's business plan
        by mitigating adverse changes in commodity prices, interest rates and
        foreign exchange rates.

        In the sections below, management has prepared sensitivity analyses
        in an attempt to demonstrate the effect of changes in these market
        risk factors on the Trust's net income. For the purposes of the
        sensitivity analyses, the effect of a variation in a particular
        variable is calculated independently of any change in another
        variable. In reality, changes in one factor may contribute to changes
        in another, which may magnify or counteract the sensitivities. For
        instance, trends have shown a correlation between the movement in the
        foreign exchange rate of the Canadian dollar to the U.S. dollar and
        the West Texas Intermediate posting ("WTI") crude oil price.

        Commodity price risk

        The Trust's operational results and financial condition, and
        therefore the amount of distributions paid to unitholders, are
        largely dependent on the commodity prices received for oil and
        natural gas production. Commodity prices have fluctuated widely
        during recent years due to global and regional factors including
        supply and demand fundamentals, inventory levels, weather, economic,
        and geopolitical factors. Movement in commodity prices could have a
        significant positive or negative impact on distributions to
        unitholders.

        ARC manages the risks associated with changes in commodity prices by
        entering into a variety of risk management contracts (see Risk
        Management Contracts below). The following table illustrates the
        effects of movement in commodity prices on net income due to changes
        in the fair value of risk management contracts in place at December
        31, 2008. The sensitivity is based on a $15 increase and $15 decrease
        in the price of US$ WTI crude oil and $2 increase and $2 decrease in
        the price of Cdn$ AECO natural gas. The commodity price assumptions
        are based on management's assessment of reasonably possible changes
        in oil and natural gas prices that could occur between December 31,
        2008 and the Trust's next reporting date (March 31, 2009).

        ---------------------------------------------------------------------
                     Increase in Commodity Price  Decrease in Commodity Price
        ---------------------------------------------------------------------
        ($ millions)     Crude oil   Natural gas     Crude oil   Natural gas
        ---------------------------------------------------------------------
        Net income
         (decrease)
         increase             (2.2)         (1.0)          3.3           1.6
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        Interest Rate Risk

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

        If interest rates applicable to floating rate debt and interest rate
        swaps were to have increased by 100 bps (1 per cent) it is estimated
        that the Trust's net income for the year ended December 31, 2008
        would decrease by $6.4 million, of which $4.8 million is the result
        of increased interest expense and $1.6 million is due to the change
        in fair value of risk management contracts in place at December 31,
        2008. An opposite change in interest rates will result in an opposite
        impact on net income.

        Foreign Exchange Risk

        North American oil and natural gas are based upon U.S. dollar
        denominated commodity prices. As a result, the price received by
        Canadian producers is affected by the Canadian/U.S. dollar exchange
        rate that may fluctuate over time. In addition the Trust has US$
        denominated debt of which future cash repayments are directly
        impacted by the exchange rate in effect on the repayment date.
        Variations in the exchange rate of the Canadian dollar could also
        have a significant positive or negative impact on distributions to
        unitholders.

        As at December 31, 2008 no risk management contracts pertaining to
        foreign exchange were outstanding.

        If foreign exchange rates applicable to U.S. denominated debt were to
        have increased or decreased by $0.10Cdn$/US$ it is estimated that the
        Trust's net income for the year ended December 31, 2008 would
        decrease by $29 million or increase by $32 million, respectively.
        Increases and decreases in foreign exchange rates applicable to US$
        payables and receivables would have a nominal impact on the Trust's
        net income for the year ended December 31, 2008.

        Risk Management Contracts

        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 December 31, 2008 that do not qualify for hedge accounting:

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

        ---------------------------------------------------------------------
        Financial AECO Natural Gas Option Contracts(2)
        ---------------------------------------------------------------------
                                                  Bought
                                        Volume       Put  Sold Put Sold Call
        Term              Contract        GJ/d   Cdn$/GJ   Cdn$/GJ   Cdn$/GJ
        ---------------------------------------------------------------------
        Jan 09 -
         Dec 09     3 - Way Collar      20,000      6.50      4.50      8.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (2) AECO 7a monthly index

        ---------------------------------------------------------------------
        Financial NYMEX Natural Gas Contracts(3)
        ---------------------------------------------------------------------
                                                  Bought
                                        Volume       Put  Sold Put Sold Call
        Term              Contract     mmbtu/d US$/mmbtu US$/mmbtu US$/mmbtu
        ---------------------------------------------------------------------
        Jan 09 - Mar 09     Collar      20,000      8.50         -     11.00
        Jan 09 - Mar 09     Collar      10,000      9.00         -     12.00
        Jan 09 - Mar 09     Collar      10,000      9.25         -     12.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (3) Last 3 Day

        ---------------------------------------------------------------------
        Financial Basis Swap Contract(4)
        ---------------------------------------------------------------------
                                                   Basis
                                        Volume      Swap
        Term              Contract     mmbtu/d US$/mmbtu
        ---------------------------------------------------------------------
        Jan 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)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (4) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO
            Monthly 7a

        ---------------------------------------------------------------------
        Financial Interest Rate Contracts(5)(6)
        ---------------------------------------------------------------------
                                                   Fixed    Spread
                                     Principal    Annual   on 3 Mo.
        Term              Contract      MM US$    Rate %     LIBOR
        ---------------------------------------------------------------------
        Jan 09 - Apr 14       Swap        30.5      4.62    38 bps
        Jan 09 - Apr 14       Swap        32.0      4.62 (25.5 bps)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (5) Starting in 2009, the notional amount of the contracts decreases
            annually until 2014. The Trust pays the floating interest rate
            based on a three month LIBOR plus a spread and receives the fixed
            interest rate.
        (6) Starting in 2009, a mutual put exists where both parties have the
            right to call on the other party to pay the then current mark-to-
            market value of the contract.

        ---------------------------------------------------------------------
        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)
        ---------------------------------------------------------------------
                                        Volume      Swap
        Term              Contract         MWh  Cdn$/MWh
        ---------------------------------------------------------------------
        Jan 09 - Dec 12       Swap         5.0     72.50
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
        Financial Electricity Contracts(8)
        ---------------------------------------------------------------------
                                        Volume      Swap
        Term               Contract        MWh  Cdn$/MWh
        ---------------------------------------------------------------------
        Jan 09 - Dec 09        Swap       15.0     59.33
        Jan 10 - Dec 10        Swap        5.0     63.00
        ---------------------------------------------------------------------
        (8) Contracted volume is based on a 24/7 term.

        At December 31, 2008, the fair value of the contracts that were not
        designated as accounting hedges was a gain of $3.4 million. The Trust
        recorded a loss on risk management contracts of $7.7 million in the
        statement of income for the year ended December 31, 2008
        ($41.8 million loss in 2007). This amount includes the realized and
        unrealized gains and losses on risk management contracts that do not
        qualify as effective accounting hedges.

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Fair value, beginning of year                $   (64.6)    $    (8.7)
        Fair value, end of year(1)                         3.4         (64.6)
        ---------------------------------------------------------------------
        Change in fair value of contracts in the year     68.0         (55.9)
        Realized (loss) gain in the year                 (75.7)         14.1
        ---------------------------------------------------------------------
        Loss on risk management contracts            $    (7.7)    $   (41.8)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Intrinsic value of risk management contracts not designated as
            effective accounting hedges equals a loss of $0.9 million at
            December 31, 2008 ($47.6 million loss at December 31, 2007).

        During 2007 the Trust entered into treasury rate lock contracts in
        order to manage the Trust's interest rate exposure on future debt
        issuances. During 2008 it was determined that the previously
        anticipated debt issuance was no longer expected to occur and the
        associated rate lock contracts were unwound at a cost of
        $13.6 million. These contracts were designated as effective
        accounting hedges on their respective contract dates and hedge
        accounting was applied. During 2008, the $13.6 million loss was
        reclassified from 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 $1.2 million
        and $3.9 million for the three and twelve months ended December 31,
        2008 (loss of $0.1 million and gain of $0.4 million respectively in
        2007) has been included in operating costs on these electricity
        contracts. The unrealized fair value gain of $3.3 million on these
        contracts has been recorded on the Consolidated Balance Sheet at
        December 31, 2008 with the movement in fair value recorded in OCI,
        net of tax. The fair value movement for the year ended December 31,
        2008 is an unrealized loss of $0.7 million. As at December 31, 2008
        $2.5 million of the unrealized fair value gain is attributed to
        contracts that will settle in 2009.

        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:

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Fair value, beginning of year(1)             $    (3.4)    $     7.0
        Change in fair value of financial
         electricity contracts                            (0.7)        (10.4)
        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 year(2)                   $     3.3     $    (3.4)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Includes $7.4 million unrealized loss on treasury rate lock
            contracts and $4 million unrealized gain on electricity
            contracts.
        (2) Intrinsic value of risk management contracts designated as
            effective accounting hedges equals a gain of $3.4 million at
            December 31, 2008 ($3.5 million loss at December 31, 2007).

        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.

    14. (LOSS) GAIN ON FOREIGN EXCHANGE

        The following is a summary of the total (loss) gain on US$
        denominated transactions:

        ---------------------------------------------------------------------
                              Three Months Ended         Twelve Months Ended
                                 December 31                 December 31
        ---------------------------------------------------------------------
                              2008          2007          2008          2007
        ---------------------------------------------------------------------
        Unrealized (loss)
         gain on US$
         denominated debt    (63.9)         (0.6)    $   (90.8)    $    64.6
        Realized gain on
         US$ denominated
         debt repayments       2.3           3.7           2.3           5.0
        ---------------------------------------------------------------------
        Total non-cash
         (loss) gain on
         US$ denominated
         transactions        (61.6)          3.1         (88.5)         69.6
        Realized cash
         gain (loss) on
         US$ denominated
         transactions          0.4           0.1          (0.9)         (0.2)
        ---------------------------------------------------------------------
        Total foreign
         exchange (loss)
         gain                (61.2)          3.2     $   (89.4)    $    69.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    15. INCOME TAXES

        In 2007, Income Trust tax legislation was passed resulting in a two-
        tiered tax structure subjecting distributions to the federal
        corporate income tax rate plus a deemed 13 per cent provincial income
        tax at the Trust level commencing in 2011. On February 26, 2008 the
        Federal Government announced as part of the Federal budget that the
        provincial component of the tax on the Trust is to be calculated
        based on the general provincial rate in each province in which the
        Trust has a permanent establishment. This is the same way that a
        corporation would calculate its provincial tax rate. On February 1,
        2009 the Minister of Finance tabled a Notice of Ways and Means which
        includes the proposed legislation for calculating the provincial tax
        rate. As the proposed rules were not substantively enacted as of
        December 31, 2008, the Trust has not reflected a reduced tax rate in
        the calculation of future income taxes in 2008.

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Income before future income tax recovery and
         non-controlling interest                    $   535.4     $   380.8
        ---------------------------------------------------------------------
        Canadian statutory rate(1)                       32.4%         34.3%
        ---------------------------------------------------------------------
        Expected income tax expense at statutory rates   173.4         130.6
        Effect on income tax of:
          Net income of the Trust                       (181.2)       (163.6)
          Effect of change in corporate tax rate          (8.9)        (41.3)
          Initial recognition of Trust tax pools             -         (24.7)
          Unrealized loss (gain) on foreign exchange      13.4         (10.4)
          Change in estimated pool balances               (1.0)         (7.0)
          Non-taxable portion of gains/losses                -          (2.1)
          Other non-deductible items                      (0.2)         (2.8)
        ---------------------------------------------------------------------
        Future income tax recovery                   $    (4.5)    $  (121.3)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) The statutory rate consists of the combined Trust and Trust's
            subsidiaries statutory tax rate

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Future tax liabilities:
          Capital assets in excess of tax value      $   381.4     $   371.6
          Risk management contracts                        1.7             -
          Other comprehensive income (loss)                0.8          (0.7)
          Long-term debt                                   0.2          11.9
        Future tax assets:
          Asset retirement obligations                   (35.8)        (36.1)
          Non-capital losses                             (24.4)         (3.8)
          Risk management contracts                          -         (16.7)
          Trust unit incentive compensation expense       (8.3)         (7.8)
          Attributed Canadian royalty income              (4.6)         (4.6)
          CEC, SR&ED pools and deductible share issue
           costs                                          (1.6)         (1.6)
        ---------------------------------------------------------------------
        Net future income tax liability              $   309.4     $   312.2
        ---------------------------------------------------------------------
        Future income tax (asset)                    $    (3.9)    $    (4.0)
        Future income tax liability                  $   313.3     $   316.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The petroleum and natural gas properties and facilities owned by the
        Trust have an approximate tax basis of $2.07 billion ($1.84 billion
        in 2007) available for future use as deductions from taxable income.
        Included in this tax basis are estimated non-capital loss carry
        forwards of $86.9 million ($13.8 million in 2007) that expire in the
        years 2010 through 2027. The following is a summary of the estimated
        Trust's tax pools:

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Canadian oil and gas property expenses       $ 1,001.3     $   816.5
        Canadian development expenses                    360.7         326.1
        Canadian exploration expenses                     41.5          52.5
        Undepreciated capital costs                      414.5         460.2
        Non-capital losses                                86.9          13.8
        SR&ED tax pools                                    0.3             -
        Provincial tax pools                             155.9         161.1
        Other                                              7.0          10.3
        ---------------------------------------------------------------------
        Estimated tax basis                          $ 2,068.1     $ 1,840.5
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        No current income taxes were paid or payable in both 2008 and 2007.

    16. EXCHANGEABLE SHARES

        The Trust is authorized to issue an unlimited number of ARL
        Exchangeable Shares that can be converted (at the option of the
        holder) into trust units at any time. The number of Trust units
        issuable upon conversion is based upon the exchange ratio in effect
        at the conversion date. The exchange ratio is calculated monthly
        based on the cash distribution paid divided by the ten day weighted
        average unit price preceding the record date and multiplied by the
        opening exchange ratio. The exchangeable shares are not eligible for
        distributions and, in the event that they are not converted, any
        outstanding shares are redeemable by the Trust for Trust units on
        August 28, 2012. The ARL Exchangeable Shares are publicly traded.

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
        ARL Exchangeable Shares (thousands)               2008          2007
        ---------------------------------------------------------------------
        Balance, beginning of year                       1,310         1,433
        Exchanged for trust units(1)                      (218)         (123)
        ---------------------------------------------------------------------
        Balance, end of year                             1,092         1,310
        Exchange ratio, end of year                    2.51668       2.24976
        Trust units issuable upon conversion, end
         of year                                         2,748         2,947
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) During 2008, 218,455 ARL exchangeable shares were converted to
            trust units at an average exchange ratio of 2.36901, compared to
            123,263 exchangeable shares at an average exchange ratio of
            2.12125 during 2007.

        The non-controlling interest on the Consolidated Balance Sheet
        consists of the fair value of the exchangeable shares upon issuance
        plus the accumulated earnings attributable to the non-controlling
        interest. The net income attributable to the non-controlling interest
        on the Consolidated Statement of Income represents the cumulative
        share of net income attributable to the non-controlling interest
        based on the Trust units issuable for exchangeable shares in
        proportion to total Trust units issued and issuable at each period
        end.

        Following is a summary of the non-controlling interest for 2008
        and 2007:

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Non-controlling interest, beginning of year  $    43.1     $    40.0
        Reduction of book value for conversion to
         trust units                                      (7.6)         (3.7)
        Current year net income attributable to
         non-controlling interest                          6.9           6.8
        ---------------------------------------------------------------------
        Non-controlling interest, end of year             42.4          43.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Accumulated earnings attributable to
         non-controlling interest                    $    41.0     $    34.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    17. UNITHOLDERS' CAPITAL

        The Trust is authorized to issue 650 million Trust units of which
        216.4 million units were issued and outstanding as at December 31,
        2008 (210.2 million as at December 31, 2007).

        The Trust has in place a Distribution Reinvestment and Optional Cash
        Payment Program ("DRIP") in conjunction with the Trusts' transfer
        agent to provide the option for unitholders to reinvest cash
        distributions into additional trust units issued from treasury at a
        five per cent discount to the prevailing market price with no
        additional fees or commissions.

        The Trust is an open ended mutual fund under which unitholders have
        the right to request redemption directly from the Trust. Trust units
        tendered by holders are subject to redemption under certain terms and
        conditions including the determination of the redemption price at the
        lower of the closing market price on the date units are tendered or
        90 per cent of the weighted average trading price for the 10 day
        trading period commencing on the tender date. Cash payments for trust
        units tendered for redemption are limited to $100,000 per month with
        redemption requests in excess of this amount eligible to receive a
        note from ARC Resources Ltd. accruing interest at 4.5 per cent and
        repayable within 20 years.

        ---------------------------------------------------------------------

                               December 31, 2008           December 31, 2007
        ---------------------------------------------------------------------
                         Number of                   Number of
                       trust units                 trust units
                        (thousands)            $    (thousands)            $
        ---------------------------------------------------------------------
        Balance,
         beginning
         of year           210,232       2,465.7       204,289       2,349.2
        Issued on
         conversion of ARL
         exchangeable
         shares (Note 16)      517           7.6           261           3.7
        Issued on exercise
         of employee
         rights (Note 20)      238           4.2           131           2.1
        Distribution
         reinvestment
         program             5,448         123.2         5,551         110.7
        ---------------------------------------------------------------------
        Balance, end
         of year           216,435       2,600.7       210,232       2,465.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                              Three Months Ended         Twelve Months Ended
                                 December 31                 December 31
        ---------------------------------------------------------------------
                              2008          2007          2008          2007
        ---------------------------------------------------------------------
        Weighted average
         trust units(1)      215.6         209.6         213.3         207.3
        Trust units
         issuable on
         conversion of
         exchangeable
         shares(2)             2.7           2.9           2.7           2.9
        Dilutive impact
         of rights(3)            -           0.1           0.1           0.2
        ---------------------------------------------------------------------
        Diluted trust
         units and
         exchangeable
         shares              218.3         212.6         216.1         210.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Weighted average trust units excludes trust units issuable for
            exchangeable shares.
        (2) Diluted trust units include trust units issuable for outstanding
            exchangeable shares at the year-end exchange ratio.
        (3) All outstanding rights were dilutive and therefore have been
            included in the diluted unit calculation for both 2008 and 2007.

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

    18. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE INCOME

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Accumulated earnings                         $ 2,724.1.    $ 2,191.1
        Accumulated distributions                     (3,227.0)     (2,657.0)
        ---------------------------------------------------------------------
        Deficit                                      $  (502.9)    $  (465.9)
        Accumulated other comprehensive income (loss)      1.9          (2.9)
        ---------------------------------------------------------------------
        Deficit and accumulated other comprehensive
         income (loss)                               $  (501.0)    $  (468.8)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Unrealized gains and losses on financial
         instruments designated as cash flow hedges  $     2.0     $    (2.8)
        Net unrealized gains and losses on
         available-for-sale reclamation funds'
         investments                                      (0.1)         (0.1)
        ---------------------------------------------------------------------
        Accumulated other comprehensive income
         (loss), end of year                         $     1.9     $    (2.9)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    19. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
        DISTRIBUTIONS

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

        ---------------------------------------------------------------------
                              Three Months Ended         Twelve Months Ended
                                 December 31                 December 31
                              2008          2007          2008          2007
        ---------------------------------------------------------------------
        Cash flow from
         operating
         activities      $   209.4     $   173.7     $   944.4     $   704.9
        Deduct:
          Cash withheld
           to fund
           current period
           capital
           expenditures      (80.9)        (48.1)       (372.2)       (211.6)
          Net reclamation
           fund
           (contributions)
           withdrawals        (1.3)          0.2          (2.2)          4.7
        ---------------------------------------------------------------------
        Distributions(1)     127.2         125.8         570.0         498.0
        Accumulated
         distributions,
         beginning of
         period            3,099.8       2,531.2       2,657.0       2,159.0
        ---------------------------------------------------------------------
        Accumulated
         distributions,
         end of period   $ 3,277.0     $ 2,657.0     $ 3,227.0     $ 2,657.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Distributions
         per unit(2)     $    0.59     $    0.60     $    2.67     $    2.40
        Accumulated
         distributions
         per unit,
         beginning of
         period          $   23.11     $   20.43     $   21.03     $   18.63
        Accumulated
         distributions
         per unit, end
         of period(3)    $   23.70     $   21.03     $   23.70     $   21.03
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Distributions include accrued and non-cash amounts of
            $9.7 million and $111.2 million for the three and twelve months
            ended December 31, 2008, respectively ($27 million and
            $110 million for the same periods in 2007).
        (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.

    20. TRUST UNIT INCENTIVE RIGHTS PLAN

        The Trust Unit Incentive Rights Plan (the "Rights Plan") was
        established in 1999 and authorized the Trust to grant up to 8,000,000
        rights to its employees, independent directors and long-term
        consultants to purchase Trust units, of which 7,866,088 were granted
        before the plan was discontinued in 2004 and replaced with a Whole
        Unit Plan (See Note 21). During 2008 the remaining 238 thousand
        rights were exercised, at a weighted average exercise price of
        $10.40. As of December 31, 2008 all rights issued under the Rights
        Plan have been exercised or cancelled.

        The Trust did not record any compensation expense for 2008 (a nominal
        amount in 2007) for the cost associated with the rights.

        Upon exercise of the rights, the remaining $1.7 million balance in
        contributed surplus was reduced to $nil and a corresponding increase
        was booked to unitholders' capital.

    21. WHOLE TRUST UNIT INCENTIVE PLAN

        In March 2004, the Board of Directors, upon recommendation of the
        Compensation Committee, approved a new Whole Trust Unit Incentive
        Plan (the "Whole Unit Plan") to replace the existing Trust Unit
        Incentive Rights Plan for new awards granted subsequent to March 31,
        2004. The new Whole Unit Plan results in employees, officers and
        directors (the "plan participants") receiving cash compensation in
        relation to the value of a specified number of underlying notional
        trust units. The Whole Unit Plan consists of Restricted Trust Units
        ("RTUs") for which the number of trust units is fixed and will vest
        evenly over a period of three years and Performance Trust Units
        ("PTUs") for which the number of trust units is variable and will
        vest at the end of three years.

        Upon vesting, the plan participant receives 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 future performance of the Trust compared to its
        peers based on a performance multiplier. The performance multiplier
        is based on the percentile rank of the Trust's Total Unitholder
        Return. The cash compensation issued upon vesting of the PTUs may
        range from zero to two times the value of the PTUs originally
        granted.

        The fair value associated with the RTUs and PTUs is expensed in the
        statement of income over the vesting period. As the value of the RTUs
        and PTUs is dependent upon the trust unit price, the expense recorded
        in the statement of income may fluctuate over time.

        The Trust recorded non-cash compensation expense of $1.1 million and
        $(0.1) million to general and administrative and operating expenses,
        respectively, and capitalized $0.6 million to property, plant and
        equipment in the twelve months ended December 31, 2008 for the
        estimated cost of the plan ($3.2 million, $0.3 million, and
        $0.7 million for the twelve months ended December 31, 2007). The non-
        cash compensation expense was based on the December 31, 2008 unit
        price of $20.10 ($20.40 in 2007), accrued distributions, an average
        performance multiplier of 1.6 (1.7 in 2007), and the estimated number
        of units to be issued on maturity.

        The following table summarizes the RTU and PTU movement for the year
        ended December 31, 2008:

        ---------------------------------------------------------------------
                                                     Number of     Number of
                                                          RTUs          PTUs
                                                    (thousands)   (thousands)
        ---------------------------------------------------------------------
        Balance, beginning of year                         746           903
        Vested                                            (347)         (252)
        Granted                                            403           352
        Forfeited                                          (46)          (44)
        ---------------------------------------------------------------------
        Balance, end of year                               756           959
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2008          2007
        ---------------------------------------------------------------------
        Balance, beginning of year                   $    30.3     $    26.1
        Change in net liabilities in the year
          General and administrative expense               1.1           3.2
          Operating expense                               (0.1)          0.3
          Property, plant and equipment                    0.6           0.7
        ---------------------------------------------------------------------
        Balance, end of year(1)                      $    31.9     $    30.3
        ---------------------------------------------------------------------
        Current portion of liability                      18.8          18.2
        ---------------------------------------------------------------------
        Accrued long-term incentive compensation     $    14.2     $    12.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Includes $1.1 million of recoverable amounts recorded in accounts
            receivable as at December 31, 2008 (nil for 2007).

        During the year cash payments of $28.2 million were made to employees
        relating to the Whole Unit Plan ($12.7 million in 2007).

    22. COMMITMENTS AND CONTINGENCIES

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

        ---------------------------------------------------------------------
                                          Payments Due by Period
        ---------------------------------------------------------------------
                                            2010-    2012-   There-
        ($ millions)                2009     2011     2013    after    Total
        ---------------------------------------------------------------------
        Debt repayments(1)          22.2    696.0     79.1    104.5    901.8
        Interest payments(2)        12.8     22.2     15.4     10.0     60.4
        Reclamation fund
         contributions(3)            5.2      9.5      8.3     67.9     90.9
        Purchase commitments        13.0     15.4      5.0      4.9     38.3
        Transportation
         commitments(4)                -     14.9     21.9     21.0     57.8
        Operating leases             7.0      9.8     14.3     81.8    112.9
        Risk management contract
         premiums(5)                19.3        -        -        -     19.3
        ---------------------------------------------------------------------
        Total contractual
         obligations                79.5    767.8    144.0    290.1  1,281.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (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 13).
        As the premiums are part of the underlying risk management contract,
        they have been recorded at fair market value at December 31, 2008 on
        the balance sheet as part of risk management contracts.

        The Trust enters into commitments for capital expenditures in advance
        of the expenditures being made. At a given point in time, it is
        estimated that the Trust has committed to capital expenditures equal
        to approximately one quarter of its capital budget by means of giving
        the necessary authorizations to incur the expenditures in a future
        period. The Trust's 2009 capital budget has been approved by the
        Board at $450 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 $450 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.

    23. SUBSEQUENT EVENTS

        On January 21, 2009 the Trust announced that it had entered into an
        agreement, on a bought deal basis, with a syndicate of underwriters
        for an offering of 13,456,000 trust units at $16.35 per trust unit,
        for gross proceeds of $220 million as well as an over-allotment
        option to purchase, on the same terms and conditions, up to an
        additional 2,018,400 trust units. This option was exercised in whole
        prior to closing of the offering on February 6, 2009. 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 repay debt, thereby freeing
        up borrowing capacity to fund a portion of the Trust's 2009 capital
        program.


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

    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 reserve 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 plans 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.

    ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with a current enterprise value of approximately $4.1 billion.
The Trust expects full year 2009 oil and gas production to average
approximately 64,000 to 65,000 barrels of oil equivalent per day from six core
areas in western Canada. ARC Energy Trust trades on the TSX under the symbol
AET.UN and its exchangeable shares trade under the symbol ARX.

    
    ARC RE

SOURCES LTD. John P. Dielwart, Chief Executive Officer %SEDAR: 00001245E %CIK: 0001029509

For further information:

For further information: 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, www.arcenergytrust.com


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